q LoSoIHNRIC NUREG-1915

United States Nuclear Regulatory Commission

Protecting People and the Environment

Related to the License RenewaG of

Wof Creek Generating Station

Docket No. 50-482

WoNf Creek Huodear lperaftng Corporat~on

Office of Nuclear Reactor Regulation
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*U.S.NRC

United States Nuclear Regulatory Commission

Protecting People and the Environment

Safety Evaluation Report

Related to the License Renewal of

Wolf Creek Generating Station

Docket No. 50-482

Wolf Creek Nuclear Operating Corporation

Manuscript Completed: October 2008

Date Published: October 2008

NUREG-1915

Office of Nuclear Reactor Regulation

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Wolf Creek

Generating Station (WCGS), Unit 1, license renewal application (LRA) by the United States

(US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated

September 27, 2006, Wolf Creek Nuclear Operating Corporation (WCNOC or the applicant)

submitted the LRA in accordance with Title 10, Part 54, of the Code of Federal Regulations,

"Requirements for Renewal of Operating Licenses for Nuclear Power Plants." WCNOC

requests renewal of the WCGS operating license (Facility Operating License Number NPF-42)

for a period of 20 years beyond the current expiration at midnight March 11, 2025.

WCGS is located approximately 3.5 miles northeast of Burlington, Kansas. The NRC issued the

construction permit for WCGS on May 31, 1977, and operating license on June 4, 1985. WCGS

Unit 1 is of a PWR design. Westinghouse Electric Corporation supplied the nuclear steam

supply system and Daniel International originally designed and constructed the balance of the

plant with the assistance of its agent, Bechtel. The WCGS Unit 1 licensed power output is

3565 megawatt thermal with a gross electrical output of approximately 1228 megawatt electric.

This SER presents the staff's review of information submitted through August 1, 2008, the

cutoff date for consideration in the SER, and the final conclusion on the LRA review.

iii

TABLE OF CONTENTS

A b stra ct . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii

A bbreviations ................................................ ............ xv

1. Introduction and General Discussion .......................................

1.1 Introduction ....................................................

1.2 License Renewal Background .....................................

1.2.1 Safety Review ..........................................

1.2.2 Environmental Review .................................

1.3 Principal Review Matters and Purpose for the SER .....................

1.4 Relevant Interim Staff Guidance for the SER ..........................

1.5 Sum m ary of O pen Item s ..........................................

1.6 Summary of Confirmatory Items ....................................

1.7 Summary of Proposed License Conditions ............................

2. Structures and Components Subject to Aging Management Review ...............

2.1 Scoping and Screening Methodology ................................

2.1.1 Introduction ............................................

2.1.2 Summary of Technical Information in the Application .............

2.1.3 Scoping and Screening Program Review ......................

2.1.3.1 Implementation Procedures and Documentation Sources for

Scoping and Screening .............................

2.1.3.2 Quality Controls Applied to LRA Development ...........

2.1.3.3 Training .....................................

2.1.3.4 Conclusion of Scoping and Screening Program Review ...

2.1.4 Plant Systems, Structures, and Components Scoping Methodology .

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1 ...

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2 ...

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3 ...

2.1.4.4 Plant-Level Scoping of Systems and Structures .........

.1-1

.1-1

1-2

1-3

1-4

1-5

1-6

1-7

1-11

1-11

2-1

2-1

2-1

2-1

2-2

2-3

2-5

2-6

2-6

2-6

2-7

2-10

2-16

2-18

2.1.4.5 Mechanical System Component Scoping ........

2.1.4.6 Structural Component Scoping ................

2.1.4.7 Electrical Component Scoping .................

2.1.4.8 Conclusion for Scoping Methodology ............

2.1.5 Screening Methodology .............................

2.1.5.1 General Screening Methodology ...............

2.1.5.2 Mechanical Component Screening .............

2.1.5.3 Structural Component Screening ...............

2.1.5.4 Electrical Component Screening ...............

2.1.5.5 Conclusion for Screening Methodology ..........

2.1.6 Summary of Evaluation Findings ......................

2.2 Plant-Level Scoping Results .................................

2.2.1 Introduction ......................................

2.2.2 Summary of Technical Information in the Application .......

2.2.3 Staff Evaluation ...................................

2.2.4 C onclusion .......................................

..... 2-22

..... 2-24

..... 2-26

..... 2-27

..... 2-27

..... 2-27

..... 2-28

..... 2-30

..... 2-31

..... 2-32

..... 2-32

..... 2-32

..... 2-32

..... 2-33

..... 2-33

..... 2-33

v
2.3 Scoping and Screening Results: Mechanical Systems ................... 2-33

2.3.1 Reactor Vessel Internals, and Reactor Coolant System ........... 2-34

2.3.1.1 Reactor Vessel and Internals ........................ 2-35

2.3.1.2 Reactor Coolant System ........................... 2-37

2.3.1.3 Steam Generators ................................ 2-40

2.3.1.4 Reactor Core .................................... 2-41

2.3.2 Engineered Safety Features ............................... 2-42

2.3.2.1 Nuclear Sampling System .......................... 2-43

2.3.2.2 Containment Spray System ......................... 2-44

2.3.2.3 Containment Integrated Leak Rate Test System ......... 2-47

2.3.2.4 Decontamination System ........................... 2-49

2.3.2.5 Liquid Radwaste System ............................ 2-51

2.3.2.6 Reactor Makeup Water System ...................... 2-53

2.3.2.7 Containment Purge HVAC System ................... 2-54

2.3.2.8 Breathing Air System .............................. 2-57

2.3.2.9 Hydrogen Control System .......................... 2-59

2.3.2.10 High Pressure Coolant Injection System ............... 2-63

2.3.2.11 Residual Heat Removal System .................... 2-65

2.3.3 Auxiliary Systems ........................................ 2-67

2.3.3.1 Fuel Handling - Fuel Storage and Handling. System ...... 2-68

2.3.3.2 Fuel Pool Cooling and Cleanup System ............... 2-70

2.3.3.3 Essential Service W ater ........................... 2-73

2.3.3.4 Component Cooling Water System ................... 2-74

2.3.3.5 Containment Cooling System ....................... 2-76

2.3.3.6 Compressed Air System .................... .... 2-78

2.3.3.7 Chemical and Volume Control System ................ 2-80

2.3.3.8 Auxiliary Building HVAC System ..................... 2-84

2.3.3.9 Control Building HVAC System ...................... 2-86

2.3.3.10 Fuel Building HVAC System ....................... 2-89

2.3.3.11 Essential Service Water Pumphouse Building HVAC

System .................................. ....... 2-91

2.3.3.12 Miscellaneous Buildings HVAC System ............... 2-93

2.3.3.13 Diesel Generator Building HVAC System ............. 2-95

2.3.3.14 Fire Protection System ........................... 2-97

2.3.3.15 Emergency Diesel Engine Fuel Oil Storage and Transfer

System .................... I .................. 2-114

2.3.3.16 Emergency Diesel Engine System .................. 2-115

2.3.3.17 Floor and Equipment Drains System ................ 2-120

2.3.3.18 Oily W aste System ............................. 2-121

2.3.3.19 Cranes, Hoists and Elevators System ............... 2-123

2.3.3.20 Turbine Building HVAC System .................... 2-124

2.3.3.21 Systems Within the Scope of License Renewal Based Only on

the Criterion of 10 CFR 54.4(a)(2) ................... 2-126

2.3.4 Steam and Power Conversion Systems ...................... 2-136

2.3.4.1 Main Turbine System ............................. 2-136

2.3.4.2 Main Steam System ............................. 2-137

2.3.4.3 Feedwater System ............................... 2-143

2.3.4.4 Condensate System ............................. 2-144

2.3.4.5 Steam Generator Blowdown System ................. 2-147

vi
2.3.4.6 Auxiliary Feedwater System ....................

2.4 Scoping and Screening Results: Structures .......................

2.4.1 Reactor Building .....................................

... 2-148

... 2-150

... 2-151

... 2-151

... 2-152

2.4.1.1 Summary of Technical Information in the Application .

2.4.1.2 Staff Evaluation ..............................

2.4.1.3 Conclusion ..................................

2.4.2 Control Building .....................................

2.4.2.1 Summary of Technical Information in the Application .

2.4.2.2 Staff Evaluation ..............................

2.4.2.3 Conclusion ..................................

2.4.3 Diesel Generator Building ..............................

2.4.3.1 Summary of Technical Information in the Application .

2.4.3.2 Staff Evaluation ..............................

2.4.3.3 Conclusion ...............................

2.4.4 Turbine Building .....................................

2.4.4.1 Summary of Technical Information in the Application .

2.4.4.2 Staff Evaluation ...............................

2.4.4.3 Conclusion ...............................

2.4.5 Auxiliary Building ....................................

2.4.5.1 Summary of Technical Information in the Application .

2.4.5.2 Staff Evaluation ..............................

2.4.5.3 Conclusion ..................................

2.4.6 Radwaste Building ................................

2.4.6.1 Summary of Technical Information in the Application

2.4.6.2 Staff Evaluation ........... ...................

2.4.6.3 Conclusion ..................................

2.4.7 Emergency Fuel Oil Tank Access Vaults ..................

2.4.7.1 Summary of Technical Information in the Application .

2.4.7.2 Staff Evaluation ....................... r .......

2.4.7.3 Conclusion ..................................

2.4.8 Essential Service Water Electrical Duct Banks and Manways

2.4.8.1 Summary of Technical Information in the Application

2.4.8.2 Staff Evaluation ..............................

2.4.8.3 Conclusion ..................................

2.4.9 Communications Corridor .............................

2.4.9.1 Summary of Technical Information in the Application .

2.4.9.2 Staff Evaluation ..............................

2.4.9.3 Conclusion ..................................

... 2-152

... 2-153

... 2-153

... 2-154

... 2-154

... 2-154

... 2-154

... 2-155

... 2-155

... 2-156

... 2-156

... 2-156

... 2-157

... 2-157

... 2-157

... 2-158

... 2-158

... 2-159

... 2-159

... 2-159

... 2-160

... 2-160

... 2-160

... 2-161

.. 2-161

... 2-161

... 2-161

... 2-162

... 2-162

... 2-162

... 2-162

... 2-163

... 2-164

... 2-164

... 2-164

... 2-165

... 2-165

... 2-166

... 2-166

... 2-166

... 2-167

2-167

2-167

2-168

2.4.10 Transmission Towers ........

2.4.10.1 Summary of Technical

2.4.10.2 Staff Evaluation .....

2.4.10.3 Conclusion .........

2.4.11 Essential Service Water Access

Information in

Vaults ......

...... ...... the Application

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

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

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

2.4.11.1 Summary of Technical Information in the Application

2.4.11.2 Staff Evaluation .............................

2.4.11.3 Conclusion .................................

2.4.12 Fuel Building .......................................

2.4.12.1 Summary of Technical Information in the Application

2.4.12.2 Staff Evaluation ..............................

vii
2.4.12.3 Conclusion .................................... 2-168

2.4.13 Essential Service Water Pumphouse ....................... 2-168

2.4.13.1 Summary of Technical Information in the Application ... 2-168

2.4.13.2 Staff Evaluation ................................ 2-169

2.4.13.3 Conclusion .................................... 2-170

2.4.14 Circulating Water Screenhouse ........................... 2-170

2.4.14.1 Summary of Technical Information in the Application ... 2-170

2.4.14.2 Staff Evaluation ................................ 2-171

2.4.14.3 Conclusion . .................................. 2-171

2.4.15 Ultimate Heat Sink ................. ..................... 2-172

2.4.15.1 Summary of Technical Information in the Application ... 2-172

2.4.15.2 Staff Evaluation .............................. 2-172

2.4.15.3 Conclusion .................................. 2-172

2.4.16 Essential Service Water Discharge Structure ................. 2-173

2.4.16.1 Summary of Technical Information in the Application ... 2-173

2.4.16.2 Staff Evaluation ................................ 2-173

2.4.16.3 Conclusion .................................. 2-173

2.4.17 Main Dam and Auxiliary Spillway .......................... 2-174

2.4.17.1 Summary of Technical Information in the Application ... 2-174

2.4.17.2 Staff Evaluation ................................ 2-174

2.4.17.3 Conclusion .................................... 2-174

2.4.18 Essential Service Water Valve House ..................... 2-175

2.4.18.1 Summary of Technical Information in the Application ... 2-175

2.4.18.2 Staff Evaluation ................................ 2-175

2.4.18.3 Conclusion .................................... 2-176

2.4.19 Refueling Water Storage Tank Foundation and Valve House .... 2-176

2.4.19.1 Summary of Technical Information in the Application ... 2-176

2.4.19.2 Staff Evaluation ............................... 2-177

2.4.19.3 Conclusion .................................. 2-177

2.4.20 Condensate Storage Tank Foundation and Valve House ......... 2-177

2.4.20.1 Summary of Technical Information in the Application ... 2-177

2.4.20.2 Staff Evaluation ................................ 2-178

2.4.20.3 Conclusion .................................... 2-178

2.4.21 Concrete Support Structures for Station Transformers ....... .. 2-178

2.4.21.1 Summary of Technical Information in the Application ... 2-178

2.4.21.2 Staff Evaluation .............................. 2-179

2.4.21.3 Conclusion .................................... 2-179

2.4.22 Supports ............................................ 2-180

2.4.22.1 Summary of Technical Information in the Application ... 2-180

2.4.22.2 Staff Evaluation ................................ 2-181

2.4.22.3 Conclusion .................................... 2-181

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

System s ................................................... 2-181

2.5.1 Electrical Component Types ............................. 2-182

2.5.1.1 Summary of Technical Information in the Application .... 2-182

2.5.1.2 Staff Evaluation ................................. 2-183

2.5.1.3 Conclusion ..................................... 2-187

2.6 Conclusion for Scoping and Screening .............................. 2-187

viii
3. Aging Management Review Results ......................................... 3-1

3.0 Applicant's Use of the Generic Aging Lessons Learned Report ............. 3-1

3.0.1 Format of the License Renewal Application ..................... 3-2

3.0.1.1 Overview of Table 1s ............................... 3-2

3.0.1.2 Overview of Table 2s ............................... 3-3

3.0.2 Staff's Review Process .................................... 3-4

3.0.2.1 Review of AMPs ...... ............................ 3-5

3.0.2.2 Review of AMR Results ............................. 3-6

3.0.2.3 USAR Supplement ................................ 3-6

3.0.2.4 Documentation and Documents Reviewed .............. 3-6

3.0.3 Aging Management Programs ............................... 3-6

3.0.3.1 AMPs Consistent with the GALL Report ............... 3-11

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or

Enhancements ................................... 3-42

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the

GALL Report .................................... 3-140

3.0.4 Quality Assurance Program Attributes Integral to Aging Management

Program s ............................................ 3-155

3.0.4.1 Summary of Technical Information in the Application .... 3-155

3.0.4.2 Staff Evaluation ................................. 3-156

3.0.4.3 Conclusion ................................... 3-157

3.1 Aging Management of Reactor Vessel, Reactor Vessel Internals, and Reactor

Coolant System ............................................. 3-158

3.1.1 Summary of Technical Information in the Application ............ 3-158

3.1.2 Staff Evaluation ......................................... 3-158

3.1.2.1 AMR Results That Are Consistent with the GALL Report . 3-179

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ....................... 3-185

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

Report ......................................... 3-207

3.1.3 Conclusion ............................................ 3-212

3.2 Aging Management of Engineered Safety Features .................... 3-212

3.2.1 Summary of Technical Information in the Application ............ 3-212

3.2.2 Staff Evaluation ........ ................................ 3-212

3.2.2.1 AMR Results Consistent with the GALL Report ......... 3-223

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ....................... 3-225

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

R eport ......................................... 3-235

3.2.3 Conclusion . .......................................... 3-243

3.3 Aging Management of Auxiliary Systems ............................ 3-243

3.3.1 Summary of Technical Information in the Application ............ 3-243

3.3.2 Staff Evaluation ............................. ............ 3-244

3.3.2.1 AMR Results Consistent with the GALL Report ......... 3-262

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ....................... 3-269

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

R eport ......................................... 3-291

ix
3.3.3 Conclusion ............................................ 3-310

3.4 Aging Management of Steam and Power Conversion System ............ 3-310

3.4.1 Summary of Technical Information in the Application ............ 3-310

3.4.2 Staff Evaluation ...................................... 3-310

3.4.2.1 AMR Results Consistent with the GALL Report ......... 3-318

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ....................... 3-320

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

Report ......................................... 3-331

3.4.3 Conclusion ........................................ ... 3-336

3.5 Aging Management of Containments, Structures and Component Supports . 3-336

3.5.1 Summary of Technical Information in the Application ............ 3-337

3.5.2 Staff Evaluation ...................................... 3-337

3.5.2.1 AMR Results Consistent with the GALL Report ......... 3-351

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ....................... 3-355

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

Report ......................................... 3-380

3.5.3 Conclusion ................................. ........ 3-388

3.6 Aging Management of Electrical and Instrumentation and Controls ........ 3-389

3.6.1 Summary of Technical Information in the Application ............ 3-389

3.6.2 Staff Evaluation ...................................... 3-389

3.6.2.1 AMR Results Consistent with the GALL Report ......... 3-393

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further

Evaluation is Recommended ...................... 3-397

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL

Report ......................................... 3-402

3.6.3 Conclusion ............................................ 3-402

3.7 Conclusion for Aging Management Review Results .................... 3-402

4. Time-Limited Aging Analysis .............................................. 4-1

4.1 Identification of Time-Limited Aging Analyses .......................... 4-1

4.1.1 Summary of Technical Information in the Application .............. 4-1

4.1.2 Staff Evaluation .......................................... 4-2

4.1.3 Conclusion .............................................. 4-3

4.2 Reactor Vessel Neutron Embrittlement Analysis ......................... 4-3

4.2.1 Neutron Fluence, Upper-Shelf Energy and Adjusted Reference

Tem perature ............................................ 4-3

4.2.1.1 Summary of Technical Information in the Application ...... 4-3

4.2.1.2 Staff Evaluation ................................... 4-4

4.2.1.3 USAR Supplement ................................ 4-6

4.2.1.4 Conclusion ....................................... 4-6

4.2.2 Pressurized Thermal Shock ................................. 4-6

4.2.2.1 Summary of Technical Information in the Application ...... 4-6

4.2.2.2 Staff Evaluation . ................................. 4-7

4.2.2.3 USAR Supplement ................................ 4-8

4.2.2.4 Conclusion ....................................... 4-8

4.2.3 Pressure-Temperature Limits .............................. 4-8

4.2.3.1 Summary of Technical Information in the Application ...... 4-8

x
4.2.3.2 Staff Evaluation ................................... 4-8

4.2.3.3 USAR Supplement ................................ 4-9

4.2.3.4 Conclusion ....................................... 4-9

4.2.4 Low Temperature Overpressure Protection ..................... 4-9

4.2.4.1 Summary of Technical Information in the Application ...... 4-9

4.2.4.2 Staff Evaluation ................................... 4-9

4.2.4.3 USAR Supplement ............................... 4-10

4.2.4.4 Conclusion ...................................... 4-10

4.3 Metal Fatigue Analysis ........................................... 4-10

4.3.1 Fatigue Management Program .............................. 4-11

4.3.1.1 Present WCGS FatigueMonitoring Program ............ 4-11

4.3.1.2 Present Status of Monitored Locations ................ 4-13

4.3.1.3 Program Enhancements for the Period of Extended

O peration ....................................... 4-14

4.3.2 ASME Code Section III Class 1 Fatigue Analysis of Vessels, Piping, and

Components ........................... I ............. 4-17

4.3.2.1 Reactor Pressure Vessel, Nozzles, Head, and Studs ..... 4-18

4.3.2.2 Control Rod Drive Mechanism Pressure Housings, Adapter

Plugs, and Canopy Seals ........................... 4-19

4.3.2.3 Reactor Coolant Pump Pressure Boundary Components .. 4-20

4.3.2.4 Pressurizer and Pressurizer Nozzles .................. 4-21

4.3.2.5 Steam Generator ASME Code Section III Class 1, Class 2

Secondary Side, and Feedwater Nozzle Fatigue Analyses .. 4-23

4.3.2.6 ASME Code Section III Class 1 Valves ................ 4-26

4.3.2.7 ASME Code Section III Class 1 Piping and Piping Nozzles . 4-27

4.3.2.8 Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer Surge

Line for Thermal Cycling and Stratification .............. 4-32

4.3.2.9 Primary Coolant System Heatup Expansion Noise Events . 4-34

4.3.2.10 High Energy Line Break Postulation Based on Fatigue

Cumulative Usage Factor .......................... 4-35

4.3.2.11 Fatigue Crack Growth Assessment in Support of a Fracture

Mechanics Analysis for the Leak-Before-Break Elimination of

Dynamic Effects of Primary Loop Piping Failures ......... 4-36

4.3.3 ASME Code Section III Subsection NG Fatigue Analysis of Reactor

Pressure Vessel Internals ................................. 4-38

4.3.3.1 Summary of Technical Information in the Application ..... 4-38

4.3.3.2 Staff Evaluation ................................ 4-39

4.3.3.3 USAR Supplement ................................ 4-40

4.3.3.4 Conclusion .................................... 4-41

4.3.4 Effects of the Reactor Coolant System Environment on Fatigue Life of

Piping and Components (Generic Safety Issue 190) ............ 4-41

4.3.4.1 Summary of Technical Information in the Application ..... 4-41

4.3.4.2 Staff Evaluation ................................ 4-42

4.3.4.3 USAR Supplement ............................... 4-49

4.3.4.4 Conclusion ...................................... 4-49

4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress Range

Reduction Factor in B31.1 and ASME Code Section III Class 2 and 3

P iping ................................................ 4-50

4.3.5.1 Summary of Technical Information in the Application ..... 4-50

xi
4.3.5.2 Staff Evaluation .................................. 4-50

4.3.5.3 USAR Supplement ....................... I ....... 4-51

4.3.5.4 Conclusion ............................. ....... ' 4-51

4.3.6 Fatigue Design of Spent Fuel Pool Liner and Racks for Seismic

Events ............................................... 4-51

4.3.6.1 Summary of Technical Information in the Application ..... 4-51

4.3.6.2 Staff Evaluation .................................. 4-52

4.3.6.3 USAR Supplement ............................... 4-52

4.3.6.4 Conclusion ...................................... 4-52

4.3.7 Fatigue Design and Analysis of Class IE Electrical Raceway Support

Angle Fittings for Seismic Events ........................... 4-53

4.3.7.1 Summary of Technical Information in the Application ..... 4-53

4.3.7.2 Staff Evaluation .................................. 4-53

4.3.7.3 USAR Supplement ............................... 4-53

4.3.7.4 Conclusion ...................................... 4-54

4.4 Environmental Qualification of Electrical Equipment ..................... 4-54

4.4.1 Summary of Technical Information in the Application ............. 4-54

4.4.2 Staff Evaluation ......................................... 4-55

4.4.3 USAR Supplement ....................................... 4-55

4.4.4 Conclusion ............................................. 4-55

4.5 Concrete Containment Tendon Prestress ............................. 4-55

4.5.1 Summary of Technical Information in the Application ............. 4-55

4.5.2 Staff Evaluation ......................................... 4-56

4.5.3 USAR Supplement ....................................... 4-58

4.5.4 Conclusion ............................................ 4-58

4.6 Containment Liner Plate, Polar Crane Bracket, and Penetration Load Cycles . 4-58

4.6.1 Absence of a TLAA for Containment Liner Plate, Polar Crane Bracket, and

Containment Penetration Design (Except Main Steam

Penetrations) ............................... ......... 4-58

4.6.1.1 Summary of Technical Information in the Application ..... 4-58

4.6.1.2 Staff Evaluation .................................. 4-59

4.6.1.3 USAR Supplement ............................... 4-59

4.6.1.4 Conclusion ...................................... 4-60

4.6.2 Design Cycles for the Main Steam Line Penetrations ............. 4-60

4.6.2.1 Summary of Technical Information in the Application ..... 4-60

4.6.2.2 Staff Evaluation .............. ..... 4-60

4.6.2.3 USAR Supplement ............................... 4-61

4.6.2.4 Conclusion .................................... 4-61

4.7 Plant-Specific Time-Limited Aging Analyses ........................... 4-61

4.7.1 Containment Polar Crane, Fuel Building Cask Handling Crane, Spent Fuel

Pool Bridge Crane, and Fuel Handling Machine CMAA-70 Load Cycle

Lim its ................................................ 4-62

4.7.1.1 Summary of Technical Information in the Application ..... 4-62

4.7.1.2 Staff Evaluation .................................. 4-62

4.7.1.3 USAR Supplement ............................... 4-62

4.7.1.4 Conclusion .................................... 4-63

4.7.2 Absence of a TLAA for Reactor Vessel Underclad Cracking

Analyses ............................... ............. 4-63

4.7.2.1 Summary of Technical Information in the Application ..... 4-63

xii
4.7.2.2 Staff Evaluation .................................. 4-63

4.7.2.3 USAR Supplement ............................... 4-64

4.7.2.4 Conclusion ...................................... 4-64

4.7.3 Absence of a TLAA in a Reactor Coolant Pump Flywheel Fatigue Crack

G rowth Analysis ........................................ 4-64

4.7.3.1 Summary of Technical Information in the Application ..... 4-64

4.7.3.2 Staff Evaluation .................................. 4-65

4.7.3.3 USAR Supplement ............................... 4-65

4.7.3.4 Conclusion ...................................... 4-65

4.8 Conclusion for Time-Limited Aging Analyses .......................... 4-65

5. Review by the Advisory Committee on Reactor Safeguards ...................... 5-1

6 . C onclusion ............................................................ 6-1

Appendices

Appendix A: Commitments for License Renewal ................................. A-1

Appendix B: Chronology ................................................... B-1

Appendix C: Principal Contributors ............................................ C-1

Appendix D: References ................................................... D-1

Tables

Table 1.4-1 Current Interim Staff Guidance ..................................... 1-7

Table 3.0.3-1 WCGS Aging Management Programs .............................. 3-7

Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor

Coolant System Components in the GALL Report .............................. 3-159

Table 3.2-1 Staff Evaluation for Engineered Safety Features Systems Components

in the GALL Report ..................................................... 3-213

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL

R eport ................................................................ 3-245

Table 3.4-1 Staff Evaluation for Steam and Power Conversion Systems Components

in the G ALL Report ...................................................... 3-311

Table 3.5-1 Staff Evaluation for Containments, Structures and Component Supports

in the GALL Report ...................................................... 3-338

xiii
Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the

G A LL Report ........................................................... 3-390

xiv
ABBREVIATIONS

A/C

ACI

ACRS

ACSR

ADAMS

AERM

AFW

AISC

ALARA

AMP

AMR

APCSB

ART

ASME

ASTM

ATWS

BC-TOP

BLA

B&PVC

BTP

BWR

CASS

CCWS

CFR

CISI

CLB

CMAA-70

COB

COMS

CRD

CRDM

CST

CUF

CVCS

DBD

DBE

DWST

1D

ECCS

alternating current

American Concrete Institute

Advisory Committee on Reactor Safeguards

aluminum conductor steel reinforced

Agencywide Document Access and Management System

aging effect requiring management

auxiliary feedwater

American Institute of Steel Construction

as low as reasonably achievable

aging management program

aging management review

Auxiliary and Power Conversion Systems Branch

adjusted reference temperature

American Society of Mechanical Engineers

American Society for Testing and Materials

anticipated transient without scram

Bechtel Topical Report

building, level, or areas

Boiler and Pressure Vessel Codes

Branch Technical Position

boiling water reactor

cast austenitic stainless steel

component cooling water system

Code of Federal Regulations

containment inservice inspection

current licensing basis

Crane Manufacturers Association of America No. 70

Center of Business

cold overpressurization mitigation system

control rod drive

control rod drive mechanism

condensate storage tank

cumulative usage factor

chemical and volume control system

design basis documents

design basis event

demineralized water storage tank

one dimensional

emergency core cooling system

xv
ECT eddy current testing

EDG emergency diesel generator

EFPY effective full-power year

EHC electrohydraulic control

EOL end of life

EPRI Electric Power Research Institute

EQ environmental qualification

EQSD equipment qualification summary document

EQWP equipment qualification work packages

ESF engineered safety feature

ESFS engineered safety feature system

ESW essential service water

ESWS essential service water system

FAC flow-accelerated corrosion

FPCC fuel pool cooling and cleanup

FR Federal Register

FSAR final safety analysis report

FSSD fire safe shutdown

FW feedwater

GALL Generic Aging Lessons Learned

GDC general design criteria or general design criterion

GElS Generic Environmental Impact Statement

GL generic letter

GSI generic safety issue

HELB high-energy line break

HPCI high-pressure coolant injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and controls

IASCC irradiation assisted stress corrosion cracking.

IGSCC intergranular stress corrosion cracking

IN information notice

IPA integrated plant assessment

ISG interim staff guidance

ISI inservice inspection

LBB leak-before-break

LOCA loss of coolant accident

LTOP low-temperature overpressure protection

LRA license renewal application

LRBD license renewal boundary drawing

MIC microbiologically influenced corrosion

MSIV main steam isolation valve

MWt megawatt thermal

xvi
NDE nondestructive examination

NEI Nuclear Energy Institute

NESC National Electrical Safety Code

NFPA National Fire Protection Association

NPS nominal pipe size

NRC Nuclear Regulatory Commission

NSAC Nuclear Safety Analysis Center

NUMARC Nuclear Management and resources Council

OBE operating basis earthquake

OCCW open-cycle cooling water

01 open item

PRM process radiation monitoring

P-T pressure-temperature

PTLR pressure temperature limits reports

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized water reactor

PWSCC primary water stress corrosion cracking

QA quality assurance

RAI request for additional information

RCPB reactor coolant pressure boundary

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RG regulatory guide

RHR residual heat removal

RI-ISI risk informed inservice inspection

RPV reactor pressure vessel

RTNDT reference temperature nil ductility transition

RTPTS reference temperature for pressurized thermal shock

RVI reactor vessel internals

RWST refueling water storage tank

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SER safety evaluation report

SGBS steam generator blowdown system

SRP-LR Standard Review Plan for Review of License Renewal Applications for Nuclear

Power Plants

SSC system, structure, and component

SSE safe-shutdown earthquake

SV safety valve

TLAA time-limited aging analysis

xvii
TS technical specifications

UHS ultimate heat sink

US United States

USAR Updated Safety Analysis Report

USE upper-shelf energy

UT ultrasonic testing

WCAP Westinghouse Commercial Atomic Power

WCGS Wolf Creek Generating. Station

WCNOC Wolf Creek Nuclear Operating Corporation

xviii
SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

This document is a safety evaluation report (SER) on the license renewal application (LRA) for

Wolf Creek Generating Station (WCGS) Unit 1, as filed by the Wolf Creek Nuclear Operating

Corporation (WCNOC or the applicant). By letter dated September 27, 2006, WCNOC

submitted its application to the US Nuclear Regulatory Commission (NRC) for renewal of the

WCGS operating license for an additional 20 years. The NRC staff (the staff) prepared this

report to summarize the results of its safety review of the LRA for compliance with Title 10,

Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the

Code of Federal Regulations (10 CFR Part 54). The NRC project manager for the license

renewal review is Tam Tran. Mr. Tran may be contacted by telephone at 301-415-3617 or by

electronic mail at Tam.Tran @ nrc.gov. Alternatively, written correspondence may be sent to the

following address:

License Renewal and Environmental Impacts Program

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

Attention: Tam Tran, Mail Stop 011-F1

In its September 27, 2006, submission letter, the applicant requested renewal of the operating

license issued under Section 103 (Operating License No. NPF-42) of the Atomic Energy Act of

1954, as amended, for WCGS for a period of 20 years beyond the current expiration at

midnight March 11, 2025. WCGS is located approximately 3.5 miles northeast of Burlington,

Kansas. The NRC issued the construction permit for WCGS on May 31, 1977, and the

operating license on June 4, 1985. WCGS Unit 1 is of a PWR design. Westinghouse Electric

Corporation supplied the nuclear steam supply system and Daniel International originally

designed and constructed the balance of the plant with the assistance of its agent, Bechtel. The

WCGS Unit 1 licensed power output is 3565 megawatt thermal with a gross electrical output of

approximately 1228 megawatt electric. The updated safety analysis report (USAR) shows

details of the plant and the site.

The license renewal process consists of two concurrent reviews, a technical review of safety

issues and an environmental review. The NRC regulations in 10 CFR Part 54 and

10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related

Regulatory Functions," respectively, set forth requirements for these reviews. The safety review

for the WCGS license renewal is based on the applicant's LRA and on its responses to the

staff's requests for additional information (RAIs). The applicant supplemented the LRA and

provided clarifications through its responses to the staff's RAIs in audits, meetings, and

docketed correspondence. Unless otherwise noted, the staff reviewed and considered

information submitted through August 1, 2008. The public may view the LRA and all pertinent

information and materials, including the USAR, at the NRC Public Document Room, located on

the first floor of One White Flint North, 11555 Rockville Pike, Rockville, MD 20852-2738

1-1
(301-415-4737 / 800-397-4209), and at the Coffey County Library, Burlington Branch, located in

410 Juniatta Street, Burlington, KS 66839. In addition, the public may find the LRA, as well as

materials related to the license renewal review, on the NRC Web site at http://www.nrc.gov.

This SER summarizes the results of the staff's safety review of the LRA and describes the

technical details considered in evaluating the safety aspects of the unit's proposed operation for

an additional 20 years beyond the term of the current operating license. The staff reviewed the

LRA in accordance with NRC regulations and the guidance in NUREG-1800, Revision 1,

"Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants"

(SRP-LR), dated September 2005.

SER Sections 2 through 4 address the staff's evaluation of license renewal issues considered

during the review of the application. SER Section 5 is reserved for the report of the Advisory

Committee on Reactor Safeguards (ACRS). The conclusions of this SER are in Section 6.

SER Appendix A is a table showing the applicant's commitments for renewal of the operating

license. SER Appendix B is a chronology of the principal correspondence between the staff and

the applicant regarding the LRA review. SER Appendix C is a list of principal contributors to the

SER and Appendix D is a bibliography of the references in support of the staff's review.

In accordance with 10 CFR Part 51, the staff prepared a draft, plant-specific supplement to

NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear

Plants (GELS)." This supplement discusses the environmental considerations for license

renewal of WCGS. The staff issued the final plant-specific GElS Supplement 32, "Generic

Environmental Impact Statement for License Renewal Plants Regarding Wolf Creek Generating

Station," in May 2008.

1.2 License Renewal Background

Pursuant to the Atomic Energy Act of 1954, as amended, and NRC regulations, operating

licenses for commercial power reactors are issued for 40 years and can be renewed for up to

20 additional years. The original 40-year license term was selected based on economic and

antitrust considerations rather than on technical limitations; however, some individual plant and

equipment designs may have been engineered for an expected 40-year service life.

In 1982, the staff anticipated interest in license renewal and held a workshop on nuclear power

plant aging. This workshop led the NRC to establish a comprehensive program plan for nuclear

plant aging research. From the results of that research, a technical review group concluded that

many aging phenomena are readily manageable and pose no technical issues precluding life

extension for nuclear power plants. In 1986, the staff published a request for comment on a

policy statement that would address major policy, technical, and procedural issues related to

license renewal for nuclear power plants.

In 1991, the staff published 10 CFR Part 54, the License Renewal Rule (Volume 56,

page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). Subsequently,

the staff participated in an industry-sponsored demonstration program to apply 10 CFR Part 54

to a pilot plant and to gain the experience necessary to develop implementation guidance

pursuant to 10 CFR Part 54. To establish a scope of review for license renewal, 10 CFR Part 54

1-2
defined age-related degradation unique to license renewal; however, during the demonstration

program, the staff found that adverse aging effects on plant systems and components are

managed during the period of initial license and that the scope of the review did not allow

sufficient credit for management programs, particularly the implementation of 10 CFR 50.65,

"Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

which regulates management of plant-aging phenomena. As a result of this finding, the staff

amended 10 CFR Part 54 in 1995. As published May 8, 1995, in 60 FR 22461, amended

10 CFR Part 54 establishes a regulatory process that is simpler, more stable, and more

predictable than the previous 10 CFR Part 54. In particular, as amended, 10 CFR Part 54

focuses on the management of adverse aging effects rather than on the identification of

age-related degradation unique to license renewal. The staff made these rule changes to

ensure that important systems, structures, and components (SSCs) will continue to perform

their intended functions during the period of extended operation. In addition, the amended

10 CFR Part 54 clarifies and simplifies the integrated plant assessment process to be

consistent with the revised focus on passive, long-lived structures and components (SCs).

Concurrently with these initiatives, the staff pursued a separate rulemaking effort and amended

10 CFR Part 51 to focus the scope of the review of environmental impacts of license renewal in

order to fulfill NRC responsibilities under the National Environmental Policy Act of 1969.

1.2.1 Safety Review

License renewal requirements for power reactors are based on two key principles:

(1) The regulatory process is adequate to ensure that the licensing bases of all currently

operating plants maintain an acceptable level of safety with the possible exceptions of

the detrimental aging effects on the functions of certain SSCs, as well as a.few other

safety-related issues, during the period of extended operation.

(2) The plant-specific licensing basis must be maintained during the renewal term in the

same manner and to the same extent as during the original licensing term.

In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of license

renewal as including those SSCs that (1) are safety-related, (2) whose failure could affect

safety-related functions, or (3) are relied on to demonstrate compliance with the NRC's

regulations for fire protection, environmental qualification (EQ), pressurized thermal shock

(PTS), anticipated transient without scram (ATWS), and station blackout (SBO).

Pursuant to 10 CFR 54.21 (a), a license renewal applicant must review all SSCs within the

scope of 10 CFR Part 54 to identify SCs subject to an aging management review (AMR). Those

SCs subject to an AMR perform an intended function without moving parts or without change in

configuration or properties and are not subject to replacement based on a qualified life or

specified time period. Pursuant to 10 CFR 54.21 (a), a license renewal applicant must

demonstrate that the aging effects will be managed such that the intended function(s) of those

SCs will be maintained consistent with the current licensing basis (CLB) for the period of

extended operation. However, active equipment is considered to be adequately monitored and

maintained by existing programs. In other words, detrimental aging effects that may affect

active equipment can be readily identified and corrected through routine surveillance,

performance monitoring, and maintenance. Surveillance and maintenance programs for active

1-3
equipment, as well as other maintenance aspects of plant design and licensing basis, are

required throughout the period of extended operation.

Pursuant to 10 CFR 54.21(d), the LRA is required to include a USAR supplement with a

summary description of the applicant's programs and activities for managing aging effects and

an evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.

License renewal also requires TLAA identification and updating. During the plant design phase,

certain assumptions about the length of time the plant can operate are incorporated into design

calculations for several plant SSCs. In accordance with 10 CFR 54.21 (c)(1), the applicant must

either show that these calculations will remain valid for the period of extended operation, project

the analyses to the end of the period of extended operation, or demonstrate that the aging

effects on these SSCs will be adequately managed for the period of extended operation.

In 2005, the NRC revised Regulatory Guide (RG) 1.188, "Standard Format and Content for

Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses Nuclear

Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the

Requirements of 10 CFR Part 54 - The License Renewal Rule," issued in June 2005. NEI 95-10

details an acceptable method of implementing 10 CFR Part 54. The staff used NEI 95-10 in

addition to the SRP-LR (NRC methodology for reviewing LRAs) to review the LRA.

In the LRA, the applicant utilized the process defined in NUREG-1 801, Revision 1, "Generic

Aging Lessons Learned (GALL) Report," dated September 2005. The GALL Report

summarizes staff-approved aging management programs (AMPs) for SCs subject to an AMR. If

an applicant commits to implementing these staff-approved AMPs, the time, effort, and

resources for LRA review can be greatly reduced, improving the efficiency and effectiveness of

the license renewal review process. The GALL Report summarizes the aging management

evaluations, programs, and activities credited for managing aging for most of the SCs used

throughout the industry (except for plant-specific SCs which require plant-specific review

through onsite audit and program reviews addressed in the SER). The report is also a quick

reference for both applicants and staff reviewers to AMPs and activities that can manage aging

adequately during the period of extended operation.

1.2.2 Environmental Review

Part 51 of 10 CFR contains regulations on environmental protection. In December 1996, the

staff revised the environmental protection regulations to facilitate the environmental review for

license renewal. The staff prepared the GElS to document its evaluation of possible

environmental impacts associated with nuclear power plant license renewals. For certain types

of environmental impacts, the GElS contains generic findings that apply to all nuclear power

plants and are codified in Appendix B, "Environmental Effect of Renewing the Operating

License of a Nuclear Power Plant," to Subpart A, "National Environmental Policy

Act - Regulations Implementing Section 102(2)," of 10 CFR Part 51. Pursuant to

10 CFR 51.53(c)(3)(i), a license renewal applicant may incorporate these generic findings in its

environmental report. In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report also

must include analyses of environmental impacts that must be evaluated on a plant-specific

basis.

1-4
In accordance with the National Environmental Policy Act of 1969 and 10 CFR Part 51, the staff

reviewed the plant-specific environmental impacts of license renewal, including whether there

was new and significant information not considered in the GELS. As part of its scoping process,

the staff held public meetings on December 19, 2006, in the Coffey County Library, Burlington

Branch located in 410 Juniatta Street, Burlington, KS 66839, to identify plant-specific

environmental issues. The draft, plant-specific GElS Supplement 32 documents the results of

the environmental review and makes a preliminary recommendation as to the license renewal

action. The staff held another public meeting on November 8, 2007, in the same library, to

discuss the draft, plant-specific GElS Supplement 32. After considering comments on the draft,

the staff published the final, plant-specific GElS Supplement 32 separately from this report in

May 2008.

1.3 Principal Review Matters and Purpose for the SER

Part 54 of 10 CFR describes the requirements for renewal of operating licenses for nuclear

power plants. The staff's technical review of the LRA was in accordance with NRC guidance

and 10 CFR Part 54 requirements. Section 54.29, "Standards for Issuance of a Renewed

License," of 10 CFR sets forth the license renewal standards. This SER describes the results of

the staff's safety review.

Pursuant to 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit general

information, which the applicant provided in LRA Section 1. The staff reviewed LRA Section 1

and finds that the applicant has submitted the required information.

Pursuant to 10 CFR 54.19(b), the NRC requires that the applicant address "conforming

changes to the standard indemnity agreement, 10 CFR 140.92, Appendix B, to account for the

expiration term of the proposed renewed license" in the LRA. On this issue, the applicant stated

in the LRA:

The current indemnity agreement for Wolf Creek states in Article VII that the

agreement shall terminate at the time of expiration of that license specified in

Item 3 of the Attachment to the agreement. Item 3 of the Attachment to the

indemnity agreement, as amended, lists license number NPF-42. The Company

requests that conforming changes be made to the indemnity agreement, and/or

the Attachment to the agreement, as required, to ensure that the indemnity

agreement continues to apply during both the terms of the current license and

the terms of the renewed license. Applicant understands that no changes may

be necessary for this purpose if the current license number is retained.

The staff intends to maintain the original license number upon issuance of the renewed license,

if approved. Therefore, conforming changes to the indemnity agreement need not be made and

this is consistent with 10 CFR 54.19(b) requirements.

Pursuant to 10 CFR 54.21, "Contents of Application - Technical Information," the NRC requires

that the LRA contain (a) an integrated plant assessment, (b) a description of any CLB changes

made during the staff's review of the LRA, (c) an evaluation of TLAAs, and (d) FSAR

supplements. LRA Sections 3 and 4 and Appendix B address the license renewal requirements

1-5
of 10 CFR 54.21 (a), (b), and (c). LRA Appendix A satisfies the license renewal requirements of

10 CFR 54.21(d).

Pursuant to 10 CFR 54.21(b), the NRC requires that, each year following submission of the

LRA and at least three months before the scheduled completion of the staff's review, the

applicant submit an LRA amendment identifying any CLB changes to the facility that affect the

contents of the LRA, including the USAR supplement. By letters dated, September 29,

October 11, October 17, 2007, and April 1, 2008, the applicant submitted an LRA update which

summarizes the CLB changes that have occurred during the staff's review of the LRA. This

submission of an LRA update satisfies 10 CFR 54.21(b) requirements.

Pursuant to 10 CFR 54.22, "Contents of Application - Technical Specifications," the NRC

requires that the LRA include changes or additions to the technical specifications that are

necessary to manage aging effects during the period of extended operation. In LRA

Appendix D, the applicant stated that it had not identified any technical specification changes

necessary for issuance of the renewed WCGS operating license. This statement adequately

addresses the 10 CFR 54.22 requirement.

The staff evaluated-the technical information required by 10 CFR 54.21 and 10 CFR 54.22 in

accordance with NRC regulations and SRP-LR guidance. SER Sections 2, 3, and 4 document

the staff's evaluation of the LRA technical information.

As required by 10 CFR 54.25, "Report of the Advisory Committee on Reactor Safeguards," the

ACRS issued a report documenting its evaluation of the staff's LRA review and SER. SER

Section 5 is reserved for the ACRS report. SER Section 6 documents the findings required by

10 CFR 54.29, "Standard for Issuance of a Renewed License."

1.4 Relevant Interim Staff Guidance for the SER

License renewal is a living program. The staff, industry, and other interested stakeholders gain

experience and develop lessons learned with each renewed license. The lessons learned

address the staff's performance goals of maintaining safety, improving effectiveness and

efficiency, reducing regulatory burden, and increasing public confidence. Interim staff guidance

(ISG) is documented for use by the staff, industry, and other interested stakeholders until

incorporated into such license renewal guidance documents as the SRP-LR and GALL Report.

Table 1.4-1 shows the current set of ISGs, as well as the SER sections in which the staff

addresses them.

1-6
Table 1.4-1 Relevant Interim Staff Guidance

ISG Issue Purposeý SER Section

(prvdISG Number) ______________ ____ __________

Nickel-alloy components in the Cracking of nickel-alloy SER Sections 3.0.3.3.1 and

reactor coolant pressure boundary components in the reactor pressure 3.0.3.3.2

(LR-ISG-1 95) boundary.

ISG under development. NEI and

EPRI-MRP will develop an

augmented inspection program for

GALL AMP XI.M1 1-B. This AMP will

not be completed until the NRC

approves an augmented inspection

program for nickel-alloy base metal

components and welds as

proposed by EPRI-MRP.

Corrosion of drywell shell in Mark I To address concerns related to Not applicable to PWRs

containments corrosion of dryweli shell in Mark I

(LR-ISG-2006-01) containments.

Note: Staff guidance on scoping of equipment relied on to meet the requirements of the station

blackout rule for license renewal was incorporated in SRP-LR Section 2.5.2.1.1.

1.5 Summary of Open Items

As a result of its review of the LRA, including additional information submitted through

December 7, 2007, the staff had identified the following open items (Ols) in the draft SER with

open items which was issued on February 1, 2008. An item is considered open if, in the staff's

judgement, it does not meet all applicable regulatory requirements or the staff has not finished

its review. The staff had assigned a unique identifying number to each 01. As a result of the

submittal of responses by the applicant for closure of Ols, the staff has reviewed these

responses and found them all to be acceptable for closure of the Ols.

01 2.5-1: (SER Section 2.5.1 - Scoping and Screening Results of Electrical Components)

Information provided by the applicant for equipment relied on to meet the requirements of the

station blackout (SBO) rule (10 CFR 50.63) for license renewal (10 CFR 54.4.(a)(3)) is

inconsistent with the staff review criteria. Hence, the applicant should include the circuits up to

and including the switchyard circuit breakers used for SBO recovery within the scope of license

renewal.

By letter dated March 29, 2008, the applicant revised the SBO recovery paths to include circuit

breakers as the scoping boundary. Per teleconference call with the applicant on July 15, it was

further clarified that the control cables for the associated control circuits and structures are

within the scope of license renewal (this was confirmed by the applicant via e-mail on July 16,

as requested). Thus, the change to the SBO recovery paths to include the complete path from

the safety buses to circuit breakers at transmission voltage level resolves 01 2.5-1. 01 2.5-1 is

closed.

1-7
0! 3.0.3.1.10-1: (SER Section 3.0.3.1.10 - Inaccessible Medium Voltage Cables Not Subject to

10 CFR 50.49 Environmental Qualification Requirements Program)

Information provided by the applicant for equipment relied on to meet the requirements of the

SBO Rule (10 CFR 50.63) for license renewal (10 CFR 54.4(a)(3)) are inconsistent with the

staff review criteria. Hence, the applicant should include the circuits up to and including the

switchyard circuit breakers within the scope of license renewal, and managed by the AMP

related to Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49, Environmental

Qualification Requirements.

In response to 01 3.0.3.1.10-1, the applicant submitted Amendment 6 (March 29, 2008) to the

LRA to include the underground cables from circuit breaker 13-48 to disconnect switch 13-23

within the scope of inaccessible medium-voltage cable not subject to 10 CFR 50.49 EQ

requirements AMP. The staff finds the applicant's response to 013.0.3.1.10-1 acceptable

because the applicant has included the underground medium-voltage cables from circuit 13-48

to the disconnect switch 13-23 within the scope of license renewal, as appropriate.

O 3.0.3.1.10-1 is closed.

01 4.3: (SER Section 4.3.3 - ASME Code Section III, Subsection NG, Fatigue Analysis of

Reactor Pressure Vessel Internals and Section 4.3.5 - Assumed Thermal Cycle Count for

Allowable Secondary Stress Range Reduction Factor in B31.1 and ASME Code Section III,

Class 2 and 3 Piping)

The staff evaluation of LRA Sections 4.3.3 and 4.3.5 verified that the fatigue analyses were not

projected for the period of extended operation. Initially, the analyses were not completed for the

staff's review and; therefore, did not satisfy the requirements described in

10 CFR 54.21 (c)(1)(ii).

By letter dated November 30, 2007, the applicant provided its assessment of the impact of

high-cycle fatigue to the total fatigue usage factor for the reactor pressure vessel internals and

the applicant addressed its assumed thermal cycle count for allowable secondary stress range

reduction factor in B31.1 and ASME Code Section III, Class 2 and 3 piping. The staff's audit

that was needed of the plant design and basis documents to verify the validity of the applicant's

assessment was identified as 01 4.3.

The staff audited the applicant's calculation BB-S-029 Revision 0, titled "ASME Code Design

Stress Report for Wolf Creek Generating Station Reactor Vessel Internals" and validation letter

W LTR SAP 07-28. The staff, through its audit, verified that for some locations (representative),

fatigue usage from high-cycle loadings (e.g., flow-induced vibrations) was found to be

negligible. This indicates that vibratory stresses were very small compared to thermal transient

stresses and do not have a contributing effect in the fatigue cumulative usage factor (CUF)

calculation. The staff finds the applicant's approach acceptable and concludes that the part of

01 4.3 which refers to the vessel internals (Section 4.3.3) is resolved.

In the letter dated November 30, 2007, the applicant claimed that based on further review of the

original stress calculations for the reactor coolant sample lines (submitted as supplemental

information), the calculations and related assumptions are valid for the period of extended

operation in accordance with 10 CFR 54.21 (c)(1)(i). The staff audited supporting analyses

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J-SJ16-3, J-SJ16-4, and J-SJ03-1 and verified that, based on SRP-LR Table 4.3-1, a required

Stress Range Reduction Factor of 0.9 is incorporated in the analyses. The staff concludes that

the part of 01 4.3 which refers to the reactor coolant sample lines (Section 4.3.5) is resolved.

Based on the results of the staff's audit, 01 4.3 is closed.

01 4.3-1: (SER Section 4.3.4 - Effects of the Reactor Coolant System Environment on Fatigue

Life of Piping and Components (Generic Safety Issue 190))

By letter dated September 4, 2007, the staff requested that the applicant:

(a) Clearly define 1 D thermal (virtual) stresses for different locations on the

component (nozzle, nozzle inner radius) and thermal conditions (stratification). In

addition, explain how the 1 D thermal stress is derived for the surge line hot leg

nozzle under stratification.

(b) Explain what is the limitation of 1 D virtual stress methodology and describe what

kind of conditions cannot be mathematically proven to be conservative.

(c) Provide a justification that demonstrates ASME Code compliance using the 1 D

thermal (virtual) stress methodology.

In a letter dated October 3, 2007, the applicant provided its response to address 1 D virtual

stress related issues. In the response, the applicant stated that FatiguePro 1 D stress analysis is

demonstrably conservative for all load pairs that include significant transients. However, the

staff noted that FatiguePro was used for another plant, which has demonstrated that 1 D virtual

stress method has limitations, and can generate inaccurately-low stress results. Therefore, the

staff determined that the applicant did not provide sufficient information to address the concerns

raised in the staff's follow-up questions to RAI 4.3-1. This was identified as 01 4.3-1.

By letters dated May 15, 2008 and June 9, 2008, the applicant provided a response and

supplemental information for resolution of 01 4.3-1. The applicant provided the confirmatory

analysis to validate its methodology used in earlier submittals.

This analysis is based on an assumption that is uncertain of the presence of the thermal sleeve

in the charging, nozzle. Because of this uncertain assumption and other reasons, the staff chose

not to review this confirmatory analysis at this time. However, the staff noted that the applicant

supplemented the response by letter dated June 9, 2008 and committed to validate the

presence or absence of a charging nozzle thermal sleeve, and to perform a new analysis if a

thermal sleeve is not present, as a part of the Fatigue Monitoring Program (i.e., Metal Fatigue

of Reactor Coolant Pressure Boundary Aging Management Program). The staff finds this

acceptable for resolution of 01 4.3-1 because the applicant committed to: (a) validate the

configuration of the charging nozzles and perform the updated CUF calculations, as a part of

Metal Fatigue of the Reactor Coolant Pressure Boundary AMP and (b) adjust the CUF values in

the components' stress calculations for the NUREG/CR-6260 locations by the environmental

Fen factors as appropriate. Based on this determination, the staff concludes that aging

management of environmentally-assisted metal fatigue for the charging nozzles is acceptable in

accordance with 10 CFR 54.21 (c)(1)(iii). 014.3-1 is closed.

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01 4.3-3: (SER Sections 4.3.2.7 - ASME Code Section III, Class 1 Piping and Piping Nozzles

and Section 4.3.4 - Effects of the Reactor Coolant System Environment on Fatigue Life of

Piping and Components (Generic Safety Issue 190))

By letter dated September 4, 2007, the staff questioned the applicant's methodology used to

calculate the baseline fatigue usage factors for the surge line hot leg nozzle, charging nozzle,

and alternate charging nozzle locations.

In its response dated October 3, 2007, the applicant committed (Commitment No. 38) to

address the backward projection for the surge line hot leg nozzle, charging nozzles, and

alternate charging nozzles by January 31, 2008. The applicant committed to calculate an

updated baseline fatigue usage factor that adequately bounds transients experienced before

the monitoring of CUFs was started. The existing baseline CUF for all monitored locations will

be increased to bound the potential CUF contribution from the transients that were

under-represented in the existing baseline. This was identified as 01 4.3-3.

By letters dated January 25, 2008, the applicant provided a response to 01 4.3-3. The staff

found the applicant's methodology and process for performing a revised CUF analysis of the

pressurizer spray nozzle, pressurizer lower head and heater penetration, pressurizer surge

nozzle, surge line piping, and steam generator feedwater nozzles to be acceptable for aging

management of metal fatigue of these components, because the applicant appropriately: (a)

accounted for transients that occurred in "Period 1'" prior to the monitoring of CUF (including

those transients that were not accounted for and those transients whose cycles were improperly

counted) and (b) computed the revised baseline CUFs for these components based on the

updated transient information. However, the staff's review of additional information on the

reanalyses for the surge line hot leg nozzle and charging nozzles was needed because the

applicant in its reassessment, did not account for the additional insurge/outsurge cycles from

the pre-MOP (Modified Operating Procedure) environment, nor the differential contribution from

each category of charging events.

The applicant submitted supplemental information on May 15, 2008 and June 9, 2008 for

closure of 01 4.3-3. The staff finds the submittal to be an acceptable basis for managing the

impacts of metal fatigue on the pressure boundary function of the surge line hot leg nozzle and

charging nozzles because the applicant committed to updating of: (a) the baseline for the

pressurizer hot leg nozzle based on the actual pre-MOP environment and (b) the fatigue

monitoring program baseline for the charging nozzles with consideration for differential

contribution of fatigue for each category of charging event. In addition, relative to the presence

of the thermal sleeve with the charging nozzles, the applicant committed to: (a) confirm that

either the design of the charging nozzles includes thermal sleeves and if not, (b) account for the

lack of thermal sleeves in the reanalysis of the charging nozzles. This commitment is also a

part of the performance of a CUF calculation update.

The staff concludes that the applicant has provided an acceptable basis for accepting the aging

management of TLAA related metal fatigue of the components in accordance with

10 CFR 54.21( c)(1)(iii). 014.3-3 is closed.

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1.6 Summary of Confirmatory Items

As a result of its review of the LRA, including additional information submitted to the staff

through December 7, 2007, the staff determined that no confirmatory items exist which would

require a formal response from the applicant as a part of the RAI process and to be captured in

the SER with Ols. The remaining Ols were addressed subsequently as a part of the closure of

Ols in the SER.

1.7 Summary of Proposed License Conditions

Following the staff's review of the LRA, including subsequent information and clarifications from

the applicant, the staff identified three proposed license conditions.

The first license condition requires the applicant to include the USAR supplement required by

10 CFR 54.21 (d) in the next USAR update required by 10 CFR 50.71 (e), following the issuance

of the renewed license.

The second license condition requires future activities described in the USAR supplement to be

completed prior to the period of extended operation.

The third license condition requires that all capsules in the reactor vessel that are removed and

tested meet the requirements of American Society for Testing and Materials (ASTM) E 185-82

to the extent practicable for the configuration of the specimens in the capsule. Any changes to

the capsule insertion and withdrawal schedule, including use of spare capsules, must be

approved by the staff prior to implementation. All capsules placed in storage must be

maintained for future insertion. Any changes to storage requirements must be approved by the

staff, as required by 10 CFR Part 50, Appendix H.

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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

2.1.1 Introduction

Title 10, Section 54.21, "Contents of Application Technical Information," of the Code of Federal

Regulations (10 CFR Part 54.21), requires for each license renewal application (LRA) an

integrated plant assessment (IPA) listing structures and components (SCs) subject to an aging

management review (AMR), as documented in SER Section 1.2.1, from all of the systems,

structures, and components (SSCs) within the scope of license renewal.

LRA Section 2.1, "Scoping and Screening Methodology," describes the methodology for

identifying SSCs at the Wolf Creek Generating Station (WCGS), Unit 1, within the scope of

license renewal and SCs subject to an AMR. The staff of the United States (US) Nuclear

Regulatory Commission (NRC) (the staff) reviewed the Wolf Creek Nuclear Operating

Corporation (WCNOC or the applicant) scoping and screening methodology to determine

whether it meets the scoping requirements of 10 CFR 54.4(a) and the screening requirements

of 10 CFR 54.21.

In developing the scoping and screening methodology for the LRA, the applicant considered the

requirements of 10 CFR Part 54, "Requirements for Renewal of Operating Licenses for Nuclear

Power Plants" (the Rule), statements of consideration on the Rule, and the guidance of Nuclear

Energy Institute (NEI) 95-10, Revision 6, "Industry Guideline for Implementing the

Requirements of 10 CFR Part 54 -The License Renewal Rule," dated June 2005. The applicant

also considered the correspondence between the staff, other applicants, and the NEI.

2.1.2 Summary of Technical Information in the Application

LRA Sections 2 and 3 state the technical information required by 10 CFR 54.4 and 54.21 (a).

LRA Section 2.1 describes the process for identifying SSCs meeting the license renewal

scoping criteria of 10 CFR 54.4(a) and the process for identifying SCs subject to an AMR as

required by 10 CFR 54.21 (a)(1). The applicant provided the results of the process for identifying

such SCs in the following LRA sections:

* Section 2.2, "Plant Level Scoping Results"

* Section 2.3, "Scoping and Screening Results: Mechanical Systems"

• Section 2.4, "Scoping and Screening Results: Structures"

* Section 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Control

Systems"

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LRA Section 3, "Aging Management Review Results," provides the applicant's aging

management results listed in the following LRA sub-sections:

* Section 3.1, "Reactor Vessel, Internals, and Reactor Coolant System"

" Section 3.2, "Engineered Safety Features"

" Section 3.3, "Auxiliary Systems"

* Section 3.4, "Steam and Power Conversion System"

* Section 3.5, "Containments, Structures and Component Supports"

" Section 3.6, "Electrical and Instrumentation and Controls"

LRA Section 4, "Time-Limited Aging Analyses," states the applicant's time-limited aging

analyses.

2.1.3 Scoping and Screening Program Review

The staff evaluated the LRA scoping and screening methodology in accordance with the

guidance in Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, Revision 1,

"Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants"

(SRP-LR), dated September 2005. The following regulations form the basis for the acceptance

criteria for the scoping and screening methodology review:

* 10 CFR 54.4(a) for identification of plant SSCs within the scope of the Rule

0 10 CFR 54.4(b) for identification of the intended functions of plant systems and

structures within the scope of the Rule

0 10 CFR 54.21 (a)(1) and 10 CFR 54.21 (a)(2) for the methods utilized by the applicant to

identify plant SCs subject to an AMR

With the guidance of the corresponding SRP-LR sections, the staff used, as part of the

applicant's scoping and screening methodology, the activities described in the following

sections of the LRA:

* Section 2.1 to ensure that the applicant described a process for identifying SSCs within

the scope of license renewal in accordance with 10 CFR 54.4(a)

* Section 2.2 to ensure that the applicant described a process for identifying SCs subject

to an AMR in accordance with 10 CFR 54.21 (a)(1) and 10 CFR 54.21 (a)(2) (by

examining the SSC listed in this section as within the scope of license renewal)

The staff conducted an onsite scoping and screening methodology audit during the week of

January 8, 2007. The audit focused on whether the applicant had developed and implemented

adequate guidance for the scoping and screening of SSCs by the methodologies in the LRA

and the requirements of the Rule. The staff reviewed implementation of the scoping and

screening methodology described in the applicant's license renewal project instruction and

technical position papers. The staff discussed with the applicant details of the implementation

and control of the license renewal program and reviewed administrative control documentation

and selected design documentation used by the applicant during the scoping and screening

process. The staff reviewed the applicant's processes for quality assurance (QA) for

development of the LRA. The staff reviewed the quality attributes of the applicant's aging

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management program (AMP) activities described in LRA Appendix A, "Updated Safety Analysis

Report Supplement," and LRA Appendix B, "Aging Management Programs" (as documented in

SER Section 1.2.1) and the training and qualification of the LRA development team. The staff

reviewed scoping and screening results reports for the auxiliary feedwater and high pressure

coolant injection systems and the auxiliary building structure for the applicant's appropriate

implementation of the methodology outlined in the administrative controls and for results

consistent with the current licensing basis (CLB) documentation.

2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and

Screening

The staff reviewed the applicant's scoping and screening implementation procedures as

documented in the audit report dated March 21, 2007, to verify whether the process for

identifying SCs subject to an AMR was consistent with the LRA and the SRP-LR. Additionally,

the staff reviewed the scope of CLB documentation sources and the applicant's process for

appropriate consideration of CLB commitments and for adequate implementation of the

procedural guidance during the scoping and screening process.

2.1.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.1 .1.1, the applicant addressed the following information sources for the

license renewal scoping and screening process:

* current licensing basis documents

* maintenance rule database

* engineering drawings

* technical position papers

• master equipment list and 0-List

The license renewal boundary drawings (LRBDs) show the systems within the scope of license

renewal highlighted in color.

2.1.3.1.2 Staff Evaluation

Scoping and Screening Implementation Procedures. The staff reviewed the applicant's scoping

and screening methodology implementation procedures, including license renewal project

instruction for scoping and screening of SSCs, technical position papers, AMR reports, license

renewal drawings, and other reference documents as documented in the audit report, to ensure

the guidance was consistent with the requirements of the Rule, the SRP-LR, and the NEI 95-10,

"Industry Guidelines for Implementing the Requirements of 10 CFR Part 54 - The License

Renewal Rule," Revision 6, (NEI 95-10, which was endorsed by NRC as documented in the

SER Section 1.2.1).

The staff finds that the overall process for implementing 10 CFR Part 54 requirements included

in the license renewal project instruction, position papers, and AMRs is consistent with the Rule

and industry guidance endorsed by the NRC. The staff found guidance for identifying plant

SSCs within the scope of license renewal (including guidelines for identifying SC component

types that are subject to an AMR) in the position papers. The staff's review of the applicant's

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procedures focused on the consistency of the detailed procedural guidance with relevant

information in the LRA which reflects implementation of the staff position (as documented in the

SRP-LR).

After reviewing the LRA and supporting documentation, the staff finds that LRA Section 2.1 is

consistent with the applicant's scoping and screening methodology instructions. Furthermore,

the applicant's methodology has sufficiently detailed guidance for the scoping and screening

implementation process, which are consistent with the documentation in the LRA.

Sources of Current Licensing Basis Information. For WCGS, system safety functions are stated

in the Updated Safety Analysis Report (USAR), technical specifications, safety evaluation

reports, the maintenance rule database, and design basis documents (DBDs). The staff

considered the safety objectives in the USAR system descriptions and identified objectives

meeting the safety-related requirements of 10 CFR 54.4(a)(1).

The staff reviewed the scope and depth of the applicant's CLB information to verify whether the

applicant's methodology had identified all SSCs within the scope of license renewal as well as

component types requiring AMRs. Note, as defined in 10 CFR 54.3(a), the CLB applies NRC

requirements, written licensee commitments for compliance with and operation within applicable

NRC requirements, and plant-specific design bases docketed and in effect. The CLB includes

NRC regulations, orders, license conditions, exemptions, technical specifications, design-basis

information in the most recent USAR, and licensee commitments in docketed correspondence

like licensee responses to NRC bulletins, generic letters, and enforcement actions as well as

commitments in NRC safety evaluations or licensee event reports.

During the audit, the staff reviewed the applicant's CLB information sources, and samples of

such information, including the USAR, DBDs, technical position papers, maintenance rule

information, and license renewal drawings that were utilized when determining whether an SSC

is within the scope of license renewal pursuant to 10 CFR 54.4(a)(1), (a)(2) and (a)(3). The

applicant's license renewal project instruction specifies the use of CLB references for scoping

determination, and primary sources of CLB which include the USAR, site technical

specifications, safety evaluation reports, and NRC orders. Other reference documents that

were used in the scoping determination include the plant equipment list, maintenance rule

database, and technical position papers. The applicant's project instruction states that the

reference documents or databases which are not official CLB documents may be used for

scoping determination; however, their scoping information was confirmed with references to

CLB documents.

In addition, the staff reviewed the applicant's position papers used to support identification of

SSCs relied upon to demonstrate compliance with the nonsafety-related criteria delineated in

10 CFR 54.4(a)(2) and the five regulated events referenced in 10 CFR 54.4(a)(3). The intended

functions for 10 CFR 54.4(a)(1) reference the appropriate USAR section. The position papers

identify the WCGS systems and structures that comply with 10 CFR 54.4(a)(2) and (a)(3). The

applicant's license renewal project instruction and position papers provide a comprehensive

listing of documents used to support scoping and screening evaluations. The staff finds these

design documentation sources to be useful for ensuring that the scope of SSCs identified by

the applicant is consistent with the plant's CLB. The staff determines that LRA Section 2.1

provides a description of the CLB and related documents used during the scoping and

screening process that is consistent with the guidance contained in the SRP-LR.

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The staff finds the overall process for implementing 10 CFR Part 54 requirements described in

the applicant's project instructions, technical position papers, and AMRs is consistent with the

Rule and industry guidance (endorsed by NRC as documented in SER Section 1.2.1).

2.1.3.1.3 Conclusion

Based on its review of LRA Section 2.1, the detailed scoping and screening implementation

procedures, and the results from the scoping and screening audit, the staff concludes that the

applicant's scoping and screening methodology considers CLB information consistently with

SRP-LR and NEI 95-10 guidance and, therefore, is acceptable.

2.1.3.2 Quality Controls Applied to LRA Development

2.1.3.2.1 Staff Evaluation

The staff reviewed the quality controls used by the applicant to ensure that scoping and

screening methodologies used in the LRA were adequately implemented. The staff observed

that the applicant developed the LRA with deviation from a 10 CFR Part 50, Appendix B, QA

program. The applicant applied the following QA processes during the LRA development:

" The scoping and screening methodology was governed by written procedures,

guidelines and position papers.

* The information entered into the license renewal database was controlled by written

procedures and guidelines and reviewed and approved by management.

" All scoping and screening packages were controlled by written procedures and

guidelines, reviewed by the responsible engineers and approved by the discipline lead

and the license renewal project manager.

* The LRA was reviewed by the Site Review Committee, WCGS management and legal

counsel, and system engineers and subject matter experts prior to submittal to the NRC.

* The LRA received a peer review.

• The applicant conducted assessments, performed independent reviews, and

documented lessons learned to verify that the LRA was developed in accordance with

the requirements of 10 CFR 54.4.

2.1.3.2.2 Conclusion

Based on its review of pertinent LRA development guidance, discussions with the applicant's

license renewal personnel, and review of the quality audit reports, the staff concludes that these

QA activities add assurance that LRA development activities have been in accordance with LRA

descriptions.

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2.1.3.3 Training

2.1.3.3.1 Staff Evaluation

The staff reviewed the applicant's training process for consistent and appropriate guidelines

and methodology for the scoping and screening activities.

The training consisted of a combination of reading (self-study), discussions with experts, and

attending training sessions. The indoctrination records specified the level of training which was

required for the various groups participating in the development of the LRA and began with an

orientation session, as documented on personnel's indoctrination record. The training was

required for both the Center of Business (COB) license renewal project personnel who prepared

the application and for the site personnel who reviewed the application. In addition, annual COB

plant aging management training was provided for the COB license renewal project personnel.

This training included information on the license renewal process and information specific to the

site. License renewal project and site personnel were required to review applicable license

renewal regulations and guidance documents, NEI 95-10, and associated procedures.

The staff reviewed representative samples of the training documentation for both the COB and

the site license renewal project personnel, including new employees and utility representatives.

Additionally, after discussions with COB and the applicant's license renewal personnel during

the audit, the staff verified that the COB and the site license renewal project personnel were

knowledgeable of the license renewal process requirements and the specific technical issues

within their areas of responsibility. The staff has no adverse findings.

2.1.3.3.2 Conclusion

Based on discussions with the COB and the site license renewal personnel responsible for the

scoping and screening process, and the staff's review of selected documentation supporting the

process, the staff concludes that the license renewal personnel understood the requirements

and adequately implemented the scoping and screening methodology documented in the LRA.

The staff concludes that the license renewal personnel were adequately trained and qualified

for license renewal activities.

2.1.3.4 Conclusion of Scoping and Screening Program Review

Based on its review of LRA Section 2.1, review of the applicant's detailed scoping and

screening implementation procedures, discussions with the applicant's license renewal

personnel, and review of the scoping and screening audit results, the staff concludes that the

applicant's scoping and screening program is consistent with the guidance in the SRP-LR and

therefore, acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1.3, describes the methodology for scoping SSCs pursuant to 10 CFR 54.4(a)

and the plant scoping process for systems and structures.

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The applicant described the scoping process for the plant in terms of systems and structures.

Specifically, the scoping process consisted of developing a list of plant systems and structures

and identifying their intended functions. Intended functions are those functions that are the

basis for including a system or structure within the scope of license renewal (as defined in

10 CFR 54.4(b)) and are identified by comparing the system or structure function with the

criteria in 10 CFR 54.4(a). The systems list was developed from the WCGS maintenance rule

scoping results, and the structures list from a review of site drawings in conjunction with

walkdowns. Finally, the applicant evaluated the components in the systems and structures that

were within the scope of license renewal. The applicant marked the system and/or structure

boundary of SCs that are within the scope of license renewal and that are subject to an AMR in

colors on the license renewal drawings. The applicant's scoping methodology, as described in

the LRA, is discussed in the sections below.

Additionally, to help facilitate the identification of SSCs within the scope of license renewal

pursuant to 10 CFR 54.4(a), the applicant developed a license renewal data management tool

(LRDMT), or the "license renewal database." The LRDMT contained detailed design description

information about each plant system and structure and the relevant functions of those systems

and structures. By using the LRDMT, the applicant performed scoping of the systems and

structures. The applicant's scoping process consisted of developing a list of plant systems and

structures by using maintenance rule documentation. Each system or structure was assigned a

unique license renewal identification number. After developing a list of systems and structures,

the applicant performed a scoping evaluation was performed which included: identification of

the system and/or structure purpose and functions, comparison of all the functions against the

requirements of 10 CFR 54.4(a)(1), (a)(2) and (a)(3), and identification of intended function(s)

based on its (system) performing or supporting a safety-related function, identification of

support systems, determination of the system evaluation boundary, creation of license renewal

drawings, component level scoping, and final documentation of scoping results including

references.

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1)

2.1.4.1.1 Summary of Technical Information in the Application

LRA Section 2.1.2.1 describes the scoping requirements associated with safety-related criteria

in accordance with 10 CFR 54.4(a)(1). Safety-related classifications for systems and structures

are reported in the USAR or in DBDs, such as engineering drawings, evaluations, or

calculations. The safety-related classifications for components are documented on engineering

drawings and in the Q-List. The safety-related classification as reported in these source

documents is relied upon to identify SSCs satisfying one or more of the criteria of

10 CFR 54.4(a)(1). These SSCs have been identified as within the scope of license renewal.

2.1.4.1.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(1), the applicant must consider all safety-related SSCs relied upon

to remain functional during and following a design-basis event (DBE) to ensure (1) the integrity

of the reactor coolant pressure boundary, (2) the ability to shut down the reactor and maintain it

in a safe shutdown condition, or (3) the ability to prevent or mitigate the consequences of

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accidents that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1),

50.67(b)(2), or 100.11.

With regard to identification of DBEs, SRP-LR Section 2.1.3, "Review Procedures," states:

The set of DBEs as defined in the Rule is not limited to Chapter 15 (or

equivalent) of the USAR. Examples of DBEs that may not be described in this

chapter include external events, such as floods, storms, earthquakes, tornadoes,

or hurricanes, and internal events, such as a high energy line break. Information

regarding DBEs as defined in 10 CFR 50.49(b)(1) may be found in any chapter

of the facility USAR, the Commission's regulations, NRC orders, exemptions, or

license conditions within the CLB. These sources should also be reviewed to

identify SSCs relied upon to remain functional during and following DBEs (as

defined in 10 CFR 50.49(b)(1)) to ensure the functions described in

10 CFR 54.4(a)(1).

During the audit, through discussions with the WCGS license renewal project personnel, the

staff verified that the USAR was reviewed to identify SSCs that are relied upon to remain

functional during and following DBEs as defined in 10 CFR 50.49(b)(1) to ensure the functions

described in 10 CFR 54.4(a)(1). Relevant anticipated operational occurrences and postulated

accidents described in USAR Chapter 15 were reviewed to identify SSCs and their associated

functions as described in 10 CFR 54.4(a)(3). Associated USAR Chapters 1 through 12 were

reviewed to identify SSCs that are relied upon to remain functional during and after DBEs for

which the facility was designed to ensure that the functions described in 10 CFR 54.4(a)(1) are

successfully accomplished.

Additionally, consistent with the definition of DBE described in 10 CFR 50.49(b)(1 )(ii), plant

conditions including normal operation, abnormal operational transients, design basis accidents,

internal and external events, and natural phenomena for which the plant must be designed

were considered for the license renewal pursuant to the 10 CFR 54.4(a)(1) criteria. Also during

the audit, the applicant stated that the review included: (1) seismic design classification;

(2) external events such as ice effects, floods, earthquakes, tornado and wind loading;

(3) internal events such as high energy line breaks, flooding, missile protection, fires; and

(4) regulated events such as anticipated transient without scram (ATWS), station blackout

(SBO), and fire protection. The applicant further stated that in addition to the USAR, other CLB

sources such as the NRC regulations, safety evaluation reports (SERs), and documents

referenced by the USAR were considered. Examples of the consideration of other CLB sources

are noted in the WCGS position papers for the regulated events.

The applicant performed scoping of SSCs pursuant to 10 CFR 54.4(a)(1) in accordance with

the license renewal project instructions which provided guidance for the preparation, review,

verification, and approval of the scoping evaluations to assure the adequacy of the results of

the scoping process. The staff reviewed these guidance documents governing the applicant's

evaluation of safety-related SSCs, and sampled the applicant's scoping results reports to

ensure the methodology was implemented in accordance with the written project instructions. In

addition, during the audit, the staff discussed the methodology and the results with the

applicant's personnel who were responsible for these evaluations.

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Specifically, the staff reviewed a sample of the license renewal scoping results for the auxiliary

feedwater and high pressure coolant injection systems and the auxiliary building structure to

gain assurance that the applicant adequately implemented its scoping methodology in

accordance with 10 CFR 54.4(a)(1). The staff verified that the scoping results for each of the

sampled systems and the structure were developed in a manner that was consistent with the

methodology such that (a) the SSCs credited for performing intended functions were identified,

and (b) the basis for the results as well as the intended functions were adequately described.

The staff verified that the applicant identified and used pertinent engineering and licensing

information to identify the SSCs required to be within the scope of license renewal in

accordance with 10 CFR 54.4(a)(1).

The staff's review of LRA Section 2.1.2.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening methodology. The

applicant responded to the staff's request for additional information (RAI) as discussed below.

During the staff's review, the staff noted that source documents, such as USAR Section 3.2,

and procedures AP 05-007, Section 6.1.4, and AP 23M-001, Section 4.17.1, have differing

definitions for the term safety-related. In addition, these documents cited, at the time,

superseded regulatory text for establishing the scoping criteria to be used in identifying SSCs in

accordance with the requirements of 10 CFR 54.4(a)(1).

In RAI 2.1-1 dated April 4, 2007, the staff requested that the applicant address the impact, if

any, due to the use of various definitions of safety-related. In addition, the staff requested that

the applicant address the impact of not having considered these different definitions in its

scoping methodology for those SSCs that are relied upon to ensure "the capability to prevent or

mitigate the consequences of accidents that could result in potential offsite exposures

comparable to the guidelines in 10 CFR Sections 50.34(a)(1), 50.67(b)(2), or 100.11 of this

chapter, as applicable" (consistent with the facility's CLB for safety-related SSCs and

10 CFR 54.4(a)(1)(iii)).

In its response dated May 2, 2007, the applicant stated:

The term 'safety related' is defined in WCGS USAR Section 3.2 (Classification of

Structures Components and Systems), procedure, AP 23M-001, 'Maintenance

Rule Program,' and procedure, AP 05-007, 'Determination of Safety

Classification,' and WCGS LRA Section 2.1.2.1. The definition provided in LRA

Section 2.1.2.1 is consistent with 10 CFR 54.4(a)(1).

* Design Basis Events are considered in the definition of safety-related in

procedure AP 05-007, Section 6.1.4, and AP 23M-001, Section 6.1.1.1 .a,

which is consistent with 10 CFR 54.4(a)(1).

* USAR Section 3.2 a and b, procedure AP 05-007, Sections 6.1.4 (1)

and (2), and AP 23M-001, Sections 6.1.1.1 .a.1 and 2 require integrity of

reactor coolant pressure boundary and capability to shutdown the reactor

and maintain it in a safe shutdown condition consistent with

10 CFR 54.4(a)(1)(i) and (ii).

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USAR Section 3.2 c, procedure AP 05-007, Section 6.1.4 (3), and AP

23M-001, Section 6.1.1.1 .a.3 definitions refer to capability to prevent or

mitigate accidents that could result in potential offsite exposure

comparable to the guidelines in 10 CFR 100 which is consistent with the

definition in 10 CFR 54.4(a)(1)(iii). WCGS has not revised the current

accident source term in accordance with 10 CFR 50.67 and therefore the

reference to 10 CFR 50.67(b)(1) as stated in 10 CFR 54.4(a)(1)(iii) is not

applicable to WCGS. The reference to 10 CFR 50.34(a)(1) as stated in

10 CFR 54.4(a)(1 )(iii) is intended for applicants for a construction permit,

a design certification or combined license pursuant to 10 CFR 52.

The applicant further stated that site specific definitions for safety-related in the USAR and

referenced plant programs discussed above are consistent with the definition of safety-related

provided in 10 CFR 54.4(a)(1) as referenced in LRA Section 2.1.2.1.

Based on its review, the staff finds the applicant's response to RAI 2.1-1 acceptable because

the site specific definitions for the term safety-related in the source documents meets the

requirements of 10 CFR 54.4(1). In addition, the applicant explained why the requirements of

10 CFR 50.67 and 50.34(a)(1) are not applicable to WCGS. The staff's concern described in

RAI 2.1-1 is resolved.

2.1.4.1.3 Conclusion

Based on its review and discussions with the applicant, the staff determines that the applicant's

methodology for identifying systems and structures meets the requirements of

10 CFR 54.4(a)(1) and, therefore, is acceptable.

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2)

2.1.4.2.1 Summary of Technical Information in the Application

LRA Section 2.1.2.2 describes the scoping methodology (application of Scoping Criteria in

10 CFR 54.4(a)(2)) as it relates to the nonsafety-related criterion described in

10 CFR 54.4(a)(2). The applicant evaluated the SSCs that met the requirements of

10 CFR 54.4(a)(2) using the following three categories.

Initial Nonsafety-Related SSCs Required to Support Safety-Related SSCs. The

nonsafety-related systems or structures credited with supporting satisfactory accomplishment of

a safety-related function were classified as satisfying the requirements of 10 CFR 54.4(a)(2)

and were included within the scope of license renewal. The applicant reviewed the USAR and

other CLB documents for every nonsafety-related plant system and structure to determine

whether the system or structure was credited with supporting satisfactory accomplishment of a

safety-related function.

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. Nonsafety-related

mechanical SSCs that are directly connected to safety-related SSCs were included within the

scope of license renewal, where possible, up to the first seismic anchor past the

nonsafety-related and safety-related interface. These nonsafety-related components are

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required to maintain mechanical and structural integrity to provide structural support to the

attached safety-related piping and components. In cases where seismic anchors were not

available to serve as the license renewal boundary (for structural integrity), the applicant used

other methods, as described in the guidance provided in NEI 95-10, to establish the license

renewal boundary. These methods included the use of an equivalent anchor. An equivalent

anchor was defined as a combination of restraints or supports such that the nonsafety-related

piping and associated SCs attached to safety-related piping is included within the scope of

license renewal up to a boundary point that includes two supports in each of the three

orthogonal directions. Other methods included extending the license renewal boundary to a

base-mounted component that is rugged and designed not to impose loads on connected

piping, or including the entire run of nonsafety-related piping that is connected at both ends to

safety-related piping.

Nonsafety-Related Systems with Spatial Interaction with Safety-Related SSCs.

Nonsafety-related SSCs which are not connected to safety-related piping or which are not

required for structural integrity, but have a spatial relationship such that their failure could

adversely impact the performance of a safety-related SSC intended function, were included

within the scope of license renewal. The applicant considered pipe whip, jet impingement,

flooding, spray, and physical impact when evaluating the potential for spatial interaction

between nonsafety-related and safety-related SSCs.

The applicant considered all safety-related structures as potential locations for safety-related

and nonsafety-related interactions that could result in an intended function for spatial

interaction. The list of all safety-related structures was divided into two groups for further

evaluation. The first group identified was composed of safety-related structures that were

expected to not have nonsafety-related fluid-filled systems or components. These structures

were then confirmed to not contain nonsafety-related fluid-filled systems or components by

walkdowns and reference to other sources, both electronic and otherwise, of equipment

location information. The second group was composed of those structures that were expected

to contain nonsafety-related fluid-filled components that have spatial interaction, for which their

failure could adversely impact the performance of a safety-related SSC intended function

(included within the scope of license renewal). For those safety-related structures determined to

contain nonsafety-related fluid-filled systems, further evaluations were performed.

2.1.4.2.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs the

failure of which could prevent satisfactory performance of safety-related SSCs relied upon to

remain functional during and following a DBE to ensure (a) the integrity of the reactor coolant

pressure boundary, (b) the capability to shut down the reactor and maintain it in a safe

shutdown condition, or (c) the capability to prevent or mitigate the consequences of accidents

that could cause offsite exposures comparable to those of 10 CFR 50.34(a)(1), 50.67(b)(2),

or 100.11.

Regulatory Guide (RG) 1.188, Revision 1, "Standard Format and Content for Applications to

Renew Nuclear Power Plant Operating Licenses," dated September 2005, endorses the use of

NEI 95-10, Revision 6, for methods the staff considers acceptable for compliance with

10 CFR Part 54 in preparing LRAs. NEI 95-10, Revision 6, addresses the staff position on

10 CFR 54.4(a)(2) scoping criteria, nonsafety-related SSCs typically identified in the CLB,

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consideration of missiles, cranes, flooding, high-energy line breaks, nonsafety-related SSCs

connected to safety-related SSCs, nonsafety-related SSCs in proximity of safety-related SSCs,

and the mitigative and preventive options in nonsafety-related and safety-related SSCs

interactions.

NEI 95-10 states that applicants should not consider hypothetical failures that could result from

system interdependencies that are not part of the CLB, but rather base their evaluation on the

plant's CLB, engineering judgement and analyses, and relevant operating experience,

describing operating experience as all documented plant-specific and industry-wide experience

useful in determining the plausibility of a failure. Documentation would include NRC generic

communications and event reports, plant-specific condition reports, industry reports, safety

operational event reports, and engineering evaluations.

The staff reviewed LRA Section 2.1.2.2. In the LRA, the applicant described the scoping

methodology as it relates to the nonsafety-related criteria in accordance with

10 CFR 54.4(a)(2). The applicant evaluated the SSCs that met the requirements of

10 CFR 54.4(a)(2) using three categories. In addition, the staff reviewed the applicant's license

renewal position paper for 10 CFR 54.4(a)(2), which describes the AMR (for additional

information) of nonsafety-related mechanical systems considered to satisfy 10 CFR 54.4(a)(2)

for both structural integrity and spatial interaction issues. The applicant's evaluation was

performed in accordance with the guidance contained in NEI 95-10, Revision 6, for the

identification and the treatment of SSCs which met 10 CFR 54.4(a)(2).

The applicant evaluated 10 CFR 54.4(a)(2) SSCs with the following categories from the NRC

guidance to the industry on identification and treatment of such SSCs:

(1) Nonsafety-Related SSCs Required for Functions that Support Safety-Related SSCs -

The applicant reviewed CLB documents to determine if the failure of any

nonsafety-related SSCs could prevent satisfactory accomplishment of any of the three

safety-related functions listed in 10 CFR 54.4(a)(1). Nonsafety-related systems or

structures explicitly credited in CLB documents with supporting the accomplishment of a

safety-related function were classified as satisfying the 10 CFR 54.4(a)(2) criteria and

were included within the scope of license renewal. This evaluation criterion was

discussed in the applicant's project instruction for scoping and screening. The staff finds

that the applicant implemented an acceptable method for scoping of nonsafety-related

systems that perform a function that supports a safety-related intended function.

(2) Nonsafety-Related Systems Connected to and Structurally Supporting Safety-Related

SSCs - For nonsafety-related SSCs directly connected to safety-related SSCs (typically

piping systems), the applicant included the nonsafety-related piping and supports, up to

and including the first seismic or equivalent anchor beyond the safety-related and

nonsafety-related interface within the scope of license renewal for structural integrity in

accordance with 10 CFR 54.4(a)(2). A seismic anchor was defined by the applicant as a

device or structure that ensures that forces and moments are restrained in three

orthogonal directions. The applicant stated that in approximately 95 percent of the cases

at WCGS, an actual seismic anchor existed and served as the license renewal boundary

for the nonsafety-related structural integrity feature. In cases where a seismic anchor

did not exist, the applicant extended the license renewal boundary to an equivalent

anchor. At WCGS, an equivalent anchor was defined as a boundary point (linear piping)

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that includes two supports in each of three orthogonal directions. When neither a

seismic nor equivalent anchor existed, the applicant extended the license renewal

boundary to:

" a base-mounted component (e.g., pump, heat exchanger, tank, etc.) that is a

rugged component and is designed not to impose loads on connecting piping

* include the entire run of nonsafety-related piping that is connected at both ends

to safety-related piping

* a flexible connection when the flexible connection effectively decouples the

piping system (i.e, does not support loads or transfer loads across it to

connecting piping), or

" a free end of nonsafety-related piping, (e.g., a drain pipe that ends at an open

floor drain)

The above alternative methods are in accordance with the industry's guidance described

in NEI 95-10, Appendix F endorsed by NRC.

(3) Nonsafety-Related SSCs Not Directly Connected to Safety-Related SSCs - The

applicant considered pipe whip, jet impingement, flooding, spray, and physical impact

when evaluating the potential for spatial interaction between nonsafety-related SSCs

and safety-related SSCs. The applicant also applied the guidance in NEI 95-10,

Appendix F. However, the LRA did not clearly indicate how the nonsafety-related SSCs

for this particular category were scoped.

The staff's review of LRA Section 2.1.2.2 identified an area in which additional

information was necessary to complete the review of the applicant's scoping and

screening results. The applicant responded to the staff's RAI as discussed below.

In RAI 2.1-2 dated April 4, 2007, the staff requested that the applicant address the

following:

(1) explain which option was used for the evaluation of nonsafety-related SSCs not

directly connected to safety-related SSCs, and describe the process for scoping

portions of nonsafety-related systems in rooms or building, level, or areas (BLA)

that contain safety-related components

(2) define how a "room" or BLA is used (applied) in the determination of the location

of safety-related equipment, and ultimately how portions of nonsafety-related

systems were scoped for spatial interaction

(3) describe how the effects of a pipe break in a room (that may not contain a

safety-related component) were evaluated for interaction with an adjacent room

that contains safety-related components

-(4) the technical justification and extent of condition for the exclusion of piping

systems containing an insignificant amount of liquid that would not typically be

replenished from the scope of license renewal

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(5) the technical justification and extent of condition for the exclusion of the roof

drain piping that passes through the portions of the above buildings where

safety-related equipment is located

In its response dated May 2, 2007, the applicant stated the following:

(1) With regard to which option was used for the evaluation of nonsafety-related

SSCs not directly connected to safety-related SSCs, the applicant stated that in

accordance with NEI 95-10, Revision 6, it used the preventive option. The

applicant further stated that all fluid-filled nonsafety-related components in a

room or BLA are considered to be within the scope of license renewal for

10 CFR 54.4(a)(2) spatial interaction considerations if the room or BLA contains

any safety-related components. Rooms or BLAs containing fluid-filled

nonsafety-related components were excluded from consideration only if there

were determined to be documented fire zone barriers such that the fluid-filled

nonsafety-related components were isolated from any safety-related

components. The applicant concluded that this consideration accounts for any

potential room to room communication concerns.

Based on its review, the staff finds the applicant's response acceptable because

the applicant clarified which option was used for the evaluation of

nonsafety-related SSCs not directly connected to safety-related SSCs, and that

methodology is consistent with the guidance in NEI 95-10, Revision 6.

Furthermore, the applicant explained that all fluid-filled nonsafety-related

components in a room or BLA are within the scope of license renewal for spatial

interaction considerations if the room or BLA contains any safety-related

components.

(2) With regard to how the applicant defined a "room" or BLA, the applicant stated

that a room is a location shown on the plant drawings with a four digit identifier.

A room may be completely enclosed and isolated (separated) from other

locations to the extent that it includes its own fire zone, or it may be a largely

open area with access to other rooms. A BLA is a three digit code representing

the building, level, and area for a plant location, and could comprise more than

one room. All fluid-filled nonsafety-related components in a room or BLA are

considered to be within the scope of license renewal for 10 CFR 54.4(a)(2)

spatial interaction considerations if the room or BLA contains any safety-related

components.

Based on its review, the staff finds the applicant's response acceptable because

the applicant clarified how the rooms and BLAs are identified, and further

explained that all fluid-filled nonsafety-related components in a room or BLA are

within the scope of license renewal for spatial interaction considerations if the

room or BLA contains any safety-related components.

(3) With regard to communication between adjacent rooms, the applicant stated that

plant locations excluded from consideration for spatial interaction (relative to

interaction with adjacent rooms) were evaluated for potential communication with

other rooms. Between the auxiliary, control, and fuel buildings, fewer than two

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dozen locations were excluded. A majority of these locations were excluded

because they are isolated (separated) from any safety-related components by

fire zone boundaries, or because the fluid-filled nonsafety-related components

were placed within the scope of license renewal for spatial interaction. For the

remaining locations in question, the applicant stated that instead of providing

justification for location exclusion, the nonsafety-related fluid-filled components

will be included within the scope of license renewal for spatial interaction.

Based on its review, the staff finds the applicant's response acceptable because

the applicant provided adequate justification for the location exclusion (of certain

areas). In addition, by letter dated August 31, 2007, the applicant amended the

LRA to include the nonsafety-related fluid-filled components in the remaining

areas within the scope of license renewal.

(4) With regard to the exclusion of portions of piping systems containing an

insignificant amount of liquid that would not typically be replenished, the

applicant stated that portions of small isolated drain lines between a shut valve

and a cap were not considered to be fluid-filled. This was justified by the

insignificant amount of liquid that would be contained in these configurations,

and that the amount is not sufficient to cause aging of mechanical or structural

components. The applicant stated that electrical components are installed in

metal enclosures with the cable entry into the electrical equipment sealed or

installed within conduit, and as such would be unaffected by any atmospheric

pressure leakage from the small isolated segments.

During a telephone conference dated May 15, 2007, the staff noted that the

applicant's response to this RAI required clarification because an adequate

justification regarding the exclusion of portions of piping systems containing an

insignificant amount of liquid was not provided. The staff requested that the

applicant clarify:

(a) if the location of the drain pipe was verified

(b) if the location of the electrical equipment in the vicinity of the drain pipes,

which may be susceptible to leakage was verified, and

(c) how WCGS verified that the electrical equipment would not be affected

by leakage from the drain pipes (e.g., is the equipment designed for a

potentially wet environment.)

In its response dated July 26, 2007, the applicant stated that the drain pipes in

question will be added within the scope of license renewal. By letter dated

August 31, 2007, the applicant amended the LRA to include these drain pipes

within the scope of license renewal.

Based on its review, the staff finds the applicant's response acceptable. The

LRA has been adequately amended to include the drain pipes in question within

the scope of license renewal.

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(5) With regard to roof drains passing through rooms or areas containing

safety-related equipment, the applicant stated that the roof drains will be added

to the scope of license renewal. By letter dated August 31, 2007, the applicant

amended the LRA to include these roof drains within the scope of license

renewal.

Based on its review, the staff finds the applicant's response acceptable because

the applicant adequately included the roof drains that pass through rooms and

areas containing safety-related equipment within the scope of license renewal.

The staff's concern described in RAI 2.1-2 is resolved.

2.1.4.2.3 Conclusion

Based on its review, discussions with the applicant, and consideration of the LRA amendment,

the staff determines that the applicant's methodology for identifying systems and structures

meets the requirements of 10 CFR 54.4(a)(2) and, therefore, is acceptable.

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)

2.1.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.1.2.3, the applicant described the methodology for identifying systems and

structures that are within the scope of license renewal. Section 54.4(a)(3) of 10 CFR requires

including all SSCs relied on in safety analyses or plant evaluations that perform a function

demonstrating compliance with the regulations for fire protection (10 CFR 50.48), environmental

qualification (EQ) (10 CFR 50.49), pressurized thermal shock (PTS) (10 CFR 50.61), ATWS

(10 CFR 50.62), and SBO (10 CFR 50.63), to be within the scope of license renewal review.

Technical position papers were prepared by the applicant to provide input to the SSC scoping

process. The purpose of these position papers was to evaluate the CLB relative to the

regulated events, identify the systems and structures that are relied upon to demonstrate

compliance with each of these regulations, and document the results of this review. Guidance

provided by the technical position papers was used during system and structure scoping to

identify system and structure intended functions for 10 CFR 54.4(a)(3), and again during

component scoping-as necessary to determine which components are credited in the regulated

events. SSCs credited in the regulated events were determined to satisfy the requirements of

10 CFR 54.4(a)(3) and were included within the scope of license renewal.

Fire Protection. Section 54.4(a)(3) of 10 CFR requires that plant SSCs within the scope of

license renewal include all SSCs relied on in safety analyses or plant evaluations to perform a

function that demonstrates compliance with the regulations for fire protection. The LRA states

that fire protection for the purposes of license renewal was an inclusive term to describe a

station's ability to minimize the adverse effects of fires on SSCs important to safety. The LRA

states that the applicant developed a position paper which summarizes and documents the

results of a detailed review performed on the fire protection program documents demonstrating,

compliance with the requirements of 10 CFR 50.48 for the plant. The position paper provided a

list of systems and structures credited in the fire protection program documents. All SSCs

classified as satisfying 10 CFR 54.4(a)(3) related to fire protection were identified as within the

scope of license renewal.

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Environmental Qualification. The LRA states that 10 CFR 54.4(a)(3) requires that plant SSCs

within the scope of license renewal include all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the regulations for EQ.

The WCGS EQ program applies to electrical equipment important to safety that is located in a

harsh environment. USAR, Table 3.11 (B)-3, was used as the basis to create a list of qualified

systems. The LRA states that the applicant developed an EQ position paper that provides lists

of systems that include EQ components. All components within the scope of the EQ program

which demonstrate compliance with 10 CFR 50.49, and the systems containing those

components in pursuant to the requirements of 10 CFR 54.4(a)(3) were identified by the

applicant as within the scope of license renewal.

Pressurized Thermal Shock. The LRA states that 10 CFR 54.4(a)(3) requires that plant SSCs

within the scope of license renewal include all SSCs relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with the regulations for PTS.

The LRA states that the applicant developed a position paper to document the review of the

licensing basis for PTS at WCGS. The applicant determined that the only component within the

scope of the license renewal rule for PTS is the reactor pressure vessel.

Anticipated Transient Without Scram. The LRA lists the equipment required for reduction of risk

from an ATWS event at WCGS. The ATWS equipment was described in USAR

Section 7.7.1.11, and the accident analysis for ATWS is discussed in USAR Section 15.8. The

LRA states that all ATWS SSCs were included within the scope of license renewal.

Station Blackout. The LRA states that the equipment needed to cope with and recover from an

SBO is identified in the WCGS Coping Assessment and is included in USAR Appendix 8.3A.

The plant system portion of the offsite power system is within the scope of license renewal. The

applicant created a technical position paper to summarize the results of a detailed review of the

SBO documentation for WCGS. The position paper identified the SSCs credited with coping

and recovering from an SBO. The SSCs identified in the SBO technical position paper were

used in scoping evaluations to identify SSCs that demonstrate compliance with 10 CFR 50.63.

All SSCs classified as satisfying the requirements of 10 CFR 54.4(a)(3) related to an SBO were

identified by the applicant and included within the scope of license renewal.

2.1.4.3.2 Staff Evaluation

Fire Protection. The staff reviewed USAR Section 9.5.1, the Fire Hazards Analysis, the fire

protection position paper and selected results of the applicant's fire protection review. The staff

confirmed that the applicant developed a position paper which summarizes and documents the

results of a detailed review performed on the fire protection program documents demonstrating

compliance with the requirements of 10 CFR 50.48. The applicant reviewed the applicable CLB

sources such as the USAR and developed a list of the required equipment for the event and

any applicable recovery path. The position paper provides a list of systems and structures

credited in the fire protection program documents and the applicable CLB sources. All SSCs

classified as satisfying 10 CFR 54.4(a)(3) requirements related to fire protection were identified

as within the scope of license renewal. Based on the staff's review, the staff concludes that the

applicant's method for identifying SSCs within the scope of license renewal that satisfy the fire

protection requirement of 10 CFR 54.4(a)(3) is adequate.

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Environmental Qualification. The staff reviewed USAR Table 3.11 (B)-3, the EQ position paper,

and selected results of the applicant's EQ review. The staff confirmed that USAR

Table 3.11 (B)-3 was used as the basis to create a list of SSCs within the scope of license

renewal. The applicant developed an EQ position paper that lists all systems that include EQ

components. All components within the scope of the EQ program that demonstrate compliance

with 10 CFR 50.49, and the systems containing those components which met the requirements

of 10 CFR 54.4(a)(3), were included within the scope of license renewal. Based on the staff's

review, the staff concludes that the method for identifying SSCs within the scope of license

renewal that satisfy the EQ requirement of 10 CFR 54.4(a)(3) is adequate.

Pressurized Thermal Shock. The staff reviewed the CLB information and selected results of the

applicant's review. The staff confirmed that the applicant reviewed the CLB information related

to PTS, including the regulations and guidance, the USAR and correspondence with the NRC,

and documented the review in a position paper. The applicant had determined that the only

component within the scope of the license renewal for PTS is the reactor pressure vessel.

Based on the staff's review, the staff concludes that the method for identifying SSCs within the

scope of license renewal that satisfy the PTS requirement of 10 CFR 54.4(a)(3) is adequate.

Anticipated Transient Without Scram. The staff reviewed USAR Section 7.7.1.11, the ATWS

position paper and selected results of the applicant's review. The staff confirmed that the

applicant reviewed the applicable CLB sources including USAR Section 7.7.1.11 and developed

a list of the required equipment for the event and any applicable recovery path. The applicant

then identified the systems which contained the identified SCs and determined the system

intended functions and included the system within the scope of license renewal. Based on the

staff's review, the staff concludes that the method for identifying SSCs within the scope of

license renewal that satisfy the ATWS requirement of 10 CFR 54.4(a)(3) is adequate.

Station Blackout. The staff reviewed USAR Appendix 8.3, the SBO position paper, recovery

procedures, electrical diagrams and selected results of the applicant's review. The staff

confirmed that the applicant reviewed USAR Appendix 8.3A which lists the equipment required

to cope and recover from an SBO and documented the results in a position paper for SBO

recovery. Based on the staff's review, the staff concludes that the method for identifying SSCs

within the scope of license renewal that satisfy the SBO requirement of 10 CFR 54.4(a)(3) is

adequate.

2.1.4.3.3 Conclusion

Based on its review, and discussions with the applicant, the staff determines that the applicant's

methodology for identifying systems and structures meets the requirements of

10 CFR 54.4(a)(3) and, therefore, is acceptable.

2.1.4.4 Plant-Level Scoping of Systems and Structures

2.1.4.4.1 Summary of Technical Information in the Application

System and Structure Level Scoping. In LRA Section 2.1, the applicant described the scoping

methodology for systems and structures that are safety-related, nonsafety-related, and

equipment relied upon to perform a function for applicable regulated events described in

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10 CFR 54.4(a)(3). The scoping methodology is consistent with the guidance provided in

SRP-LR and by the industry in NEI 95-10. In LRA Section 2.2, the applicant evaluated systems

and structures (at plant-level scoping) to determine whether they were within the scope of

license renewal, using the methodology described in LRA Section 2.1. The results of plant level

scoping are provided in LRA Table 2.2-1 for mechanical systems, electrical and instrumentation

and controls (I&C) systems, and structures. LRA Table 2.2-1 lists all WCGS systems and

structures and whether it is in-scope, and the "Section 2 scoping results." For mechanical

systems and structures within the scope of license renewal, a reference is given to the

appropriate section of the application that provides a description and screening results of the

system or structure. For electrical and I&C systems, no description is provided as these

systems were evaluated based on the "spaces approach" and described in LRA Section 2.5.

LRA Table 2.2-1 also provides the systems and structures that do not meet the criteria

specified in 10 CFR 54.4(a) and; therefore, are not within the scope of license renewal.

Component Level Scopina. After the applicant identified all the systems and structures within

the scope of license renewal, a review of mechanical systems and structures was performed to

determine the components in each system and structure. The structural and mechanical

components that supported intended functions were considered within the scope of license

renewal and screened to determine if an AMR was required. The electrical and I&C

components from all plant systems and structures were scoped collectively. All electrical and

I&C components found within the evaluation boundary of mechanical systems were included

within the scope of license renewal and evaluated using the spaces approach described in LRA

Section 2.1.3.3. The applicant considered three component classifications during this stage of

the scoping methodology: mechanical, structural, and electrical and I&C.

Insulation. LRA Section 2.1.4.1 states that insulation was treated as a passive and long-lived

component. For systems where insulation has an intended function (i.e., to reduce heat transfer

for individual room heat load calculations in support of accident analyses or safe shutdown for

regulated events, or to prevent heat-up of entrapped liquid during a design basis accident so

that over-pressurization will not occur), the insulation was included within the scope of license

renewal and was subject to an AMR.

Consumables. LRA Section 2.1.4.1 discusses consumables. The guidance in SRP-LR

Table 2.1-3 and NEI 95-10 Table 4.1-2 were used to evaluate consumables. Consumables

were divided into the following four categories for the purpose of license renewal: (1) packing,

gaskets, component seals, and O-rings; (2) structural sealants; (3) oil, grease, and component

filters; and (4) system filters, fire extinguishers, fire hoses, and air packs.

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant's methodology for performing the scoping of plant systems and

structures to ensure it was consistent with 10 CFR 54.4(a). The methodology used to determine

the systems and structures within the scope of license renewal was documented in license

renewal. project instructions and other documents that are referenced in the audit report. The

applicant's approach to systems and structures scoping provided in these documents was

consistent with the methodology described in LRA Section 2.1. Specifically, the guidelines

specified that the personnel performing license renewal scoping use CLB documents and

describe the purpose of the system or structure (including a list of functions that the system or

structure is required to accomplish). The description of purpose includes the function. Sources

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of information regarding the CLB for systems included the USAR, DBDs, Q-List component

database, maintenance rule scoping reports, control drawings, and docketed correspondence.

The applicant then compared the identified system or structure's function lists to the scoping

criteria to determine whether the functions met the scoping criteria of 10 CFR 54.4(a). The

applicant documented the results of the plant-level scoping in the systems and structures

scoping reports on individual system and structure basis. The scoping reports contained

information including a description of the system or structure, function summary, scope

determination, scoping questions, identification of intended functions, CLB documents and

license renewal boundary diagrams, identification of support systems, and comments.

During the scoping methodology audit, the staff performed a sampling of scoping results and

concludes that the applicant's scoping reports contained an appropriate level of details to

document the scoping process. Unique license renewal identification numbers were used to

identify each system or structure. For example, "AB" represents main steam system and "EM"

represents high pressure coolant injection system.

On the basis of its review of the LRA, the scoping and screening implementation procedures,

and a sampling review of system and structure scoping results during the audit, the staff

concludes that the applicant's scoping methodology for systems and structures was adequate.

In particular, the staff determines that the applicant's methodology reasonably identified

systems and structures within the scope of license renewal and their associated intended

functions.

Component Level Scopinq. The applicant performed a component level scoping by using the

license renewal drawings in conjunction with the LRDMT or database. The LRDMT was utilized

to electronically search for the components shown on the license renewal drawings. All

mechanical, structural, and electrical and I&C components that perform or support an intended

function, as described in 10 CFR 54.4 were included within the scope of license renewal. The

components within the scope of license renewal were further evaluated during the screening

process to determine whether they were subject to an AMR. The results of the applicant's

Scoping review were documented in license renewal scoping and screening reports. The staff

reviewed these reports and finds that the methodology used by the applicant is acceptable.

Insulation. The staff reviewed the applicant's evaluation of plant insulation as documented in the

applicant's position paper. The applicant identified certain insulation as being within the scope

of license renewal and subject to an AMR based on it providing intended functions of mitigating

the heat load into rooms or providing thermal protection for isolated piping segments inside the

containment. Stainless steel reflective, asbestos, fiberglass fiber, and similar material insulation

types were evaluated. During the audit, the applicant stated that it applied the same justification

provided in NEI 95-10, Appendix F, Section 5.2.2.3, to exclude a section of insulation from the

scope of license renewal for 10 CFR 54.4(a)(2) due to the physical impact hazard. The

insulation is supported by insulation supports that are designed to withstand a seismic event for

piping and equipment that are of seismic design, or fall within the Category Il/I classification.

However, the applicant did not indicate whether the insulation supports are within the scope of

license renewal. As stated in NEI 95-10, Appendix F, piping supports for Seismic Il/I piping

need to be intact in order to prevent physical impacts on safety-related equipment during a

seismic event and as a result must be included within the scope of license renewal.

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The staff's review of LRA Section 2.1.4.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.1-3 dated April 4, 2007, the staff requested that the applicant explain how the

insulation supports, that are designed to withstand a seismic event and located in areas

containing safety-related equipment, were reviewed for possible inclusion within the scope of

license renewal.

In its response dated May 2, 2007, the applicant stated that insulation supports designed to

withstand a seismic event, and that are located in areas containing safety-related equipment

within the scope of license renewal, will be added to the scope of license renewal and evaluated

as non-American Society of Mechanical Engineers (ASME) component supports in accordance

with NUREG-1801, Section Ill.B2.

By letter dated August 31, 2007, the applicant amended the LRA to include these supports

within the scope of license renewal.

Based on its review, the staff finds the applicant's response acceptable because the applicant

adequately included the insulation supports in question within the scope of license renewal. The

staff's concern described in RAI 2.1-3 is resolved.

Consumables. The staff reviewed the applicant's evaluation of the consumables as documented

in the LRA and the applicant's implementing procedures. Group (a) subcomponents are not

credited with maintaining the integrity of the pressure boundary function of valve, pump and

similar component housings and; therefore, are not subject to an AMR. Group (b)

subcomponents are structural sealants associated with structures within the scope of license

renewal that require an AMR. The structural AMR will evaluate the use of these components.

Group (c) subcomponents are short-lived consumables that are periodically replaced and;

therefore, not subject to an AMR. Group (d) system filters are periodically replaced based on

manufacturers' requirements. Fire extinguishers, fire hoses and air packs are periodically

inspected and tested in accordance with the requirements of site-specific instructions that

implement applicable National Fire Protection Association guidelines as documented in the Fire

Hazards Analysis and; therefore, not subject to an AMR.

Based on its review, the staff finds that the applicant followed the process consistent with

SRP-LR, and appropriately identified and categorized the various consumables in accordance

with the guidance. Plant consumables were initially identified and evaluated to determine if any

met the criteria requiring an AMR. Additionally, the applicant identified all pertinent industry

guidelines which were used as the basis for replacement of the item.

2.1.4.4.3 Conclusion

Based on its review of the LRA, scoping and screening implementation procedures, and a

sampling of system scoping results during the audit, the staff concludes that the applicant's

scoping methodology for plant SSCs, commodity groups, insulation, and consumables is

acceptable. In particular, the staff determines that the applicant's methodology reasonably

identifies systems, structures, component types, and commodity groups within the scope of

license renewal and their intended functions.

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2.1.4.5 Mechanical System Component Scoping

2.1.4.5.1 Summary of Technical Information in the Application

LRA Section 2.1.3.1 describes the methodology for identifying mechanical system components

that are within the scope of license renewal. A component was determined to be within the

scope of license renewal, if it meets any of the scoping criteria of 10 CFR 54.4(a)(1), (a)(2),

or (a)(3). In performing the mechanical component scoping, the applicant used the license

renewal database in conjunction with the license renewal drawings. A list of components was

developed from the plant component database downloading into the license renewal database

component table. The drawings for each mechanical system within the scope of license renewal

were reviewed to identify those components, within the system, that are needed to perform or

support a system intended function. Also, each of these components was evaluated individually

to determine whether the component supports a system level intended function and meets any

of the three 10 CFR 54.4(a) criteria. Components meeting any of the three criteria were

identified in the license renewal database as within the scope of license renewal. Components

not meeting any of these three criteria were identified in the license renewal database as

outside the scope of license renewal. Also, not all the components on the drawings are included

in the plant component and license renewal database. The results of the component scoping

are documented in the license renewal database. LRA Section 2.3 describes the scoping

results of each mechanical system and associated component that is within the scope of

license renewal.

2.1.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.1, the guidance in the license renewal project instruction, and

the scoping reports to complete the review of the mechanical scoping process. The license

renewal project instruction provides guidance for identifying and evaluating individual

mechanical system components as required by 10 CFR 54.4. The CLB documents were utilized

when determining whether a system or component is within the scope of license renewal.

Examples of these sources included, but were not limited to, the USAR, maintenance rule

database, position papers for ATWS, EQ, fire protection and SBO documents, technical

specifications, and safety evaluation reports. Additional sources of mechanical component

information included the WCGS component database and individual license renewal drawings.

Mechanical system drawings were evaluated to create license renewal boundaries for each

system showing the components within the scope of license renewal. Each license renewal

drawing was evaluated to identify the components that perform a safety-related intended

function or support a regulated event. These drawings were further evaluated during the

screening process to determine if the component should be subject to an AMR.

Nonsafety-related components that are connected to safety-related components and provide

structural support at the safety-related and nonsafety-related interface, or components whose

failure could prevent satisfactory accomplishment of a safety-related function due to spatial

interaction are included within the scope of license renewal. As part of the applicant's

verification process, the list of mechanical components identified as within the scope of license

renewal were compared to data in the license renewal database to confirm the scope of

components in the system.

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The staff reviewed the implementation guidance provided in license renewal project instruction,

the scoping reports, and the CLB documents associated with mechanical system scoping, and

found that the guidance and CLB source information noted above were acceptable to identify

mechanical components and support structures in mechanical systems that are within the

scope of license renewal. The project instruction for scoping and screening describes the

applicant's process for identifying systems and structures that are within the scope of license

renewal. If a component was determined to perform an intended function that met any of the

criteria in 10 CFR 54.4(a), then the component was determined to be within the scope of

license renewal. The results of the scoping review were documented in the license renewal

database, and the scoping results were documented in individual scoping reports.

The staff conducted detailed discussions with the applicant's license renewal project personnel

and reviewed documentation pertinent to the scoping process. The staff assessed whether the

applicant had appropriately applied the scoping methodology outlined in the LRA and

implementation procedures and whether the scoping results were consistent with CLB

requirements. The staff also reviewed scoping evaluation results for auxiliary feedwater and

high pressure coolant injection systems to verify proper implementation of the scoping process.

Based on these audit activities, the staff did not identify any discrepancies between the

methodology documented and the implementation results. Further, the staff determines that the

applicant's proceduralized methodology is consistent with the description provided in LRA

Section 2.1 and the guidance contained in SRP-LR Section 2.1, and was adequately

implemented. The staff's scoping review (based on a sample of the applicant's scoping results)

of the auxiliary feedwater system is provided below:

Scoping Methodology for the Auxiliary Feedwater System. In LRA Section 2.3.4.6, the applicant

provided the scoping and screening methodology results for SSCs within the auxiliary feedwater

system. The auxiliary feedwater system is a safety-related system and is relied upon as the

source of feedwater supply to the steam generators to maintain a secondary heat sink for DBE

mitigation. The auxiliary feedwater system is within the scope of license renewal based on the

criteria of 10 CFR 54.4(a)(1). Also, portions of the auxiliary feedwater system support fire

protection, SBO, and ATWS requirements. During the audit, the staff's review of the applicant's

scoping results for the auxiliary feedwater system identified the safety-related functions

discussed below.

The auxiliary feedwater system has the following intended functions meeting the scoping

requirements of 10 CFR 54.4(a)(1):

* Perform automatic transfer to essential service water (ESW) for auxiliary feedwater

system supply on low suction pressure from the condensate storage tank (CST) to

maintain a heat sink for decay heat removal

• Limit feedwater flow to a faulted steam generator during accident conditions

• Supply dedicated safety grade feedwater to steam generators during accidents,

transients, plant trips and loss of offsite power to ensure adequate heat sink for the

reactor coolant system

The auxiliary feedwater system has no intended functions meeting the scoping requirements of

.10 CFR 54.4(a)(2).

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The auxiliary feedwater system has the following intended functions meeting the scoping

requirements of 10 CFR 54.4(a)(3):

* The system is relied on to demonstrate compliance with the fire protection requirements

described in 10 CFR 50.48.

* The system is relied on to demonstrate compliance with the ATWS requirements

described in 10 CFR 50.62.

* The system is relied on to demonstrate compliance with the SBO requirements

described in10 CFR 50.63. Provides feedwater to steam generators using the CST as

the water source for decay heat removal.

Also, during the audit, the staff reviewed the applicant's methodology for identifying auxiliary

feedwater mechanical component types meeting the scoping criteria as defined in the Rule. The

staff reviewed the scoping methodology implementation procedures and discussed the

methodology and the results with the applicant. The staff verified that the applicant identified

and used pertinent engineering and licensing information in order to determine the auxiliary

feedwater mechanical component types required to be within the scope of license renewal. As

part of the review process, the staff evaluated each system intended function identified for the

auxiliary feedwater system, the basis for inclusion of the intended function, and the process

used to identify each of the system components credited with performing the intended function.

The staff verified that the applicant had identified and highlighted system drawings to develop

the system boundaries in accordance with the procedural guidance. The applicant was

knowledgeable about the process and conventions for establishing boundaries as defined in the

license renewal implementation procedures. Additionally, the staff verified that the applicant had

independently verified the scoping results in accordance with the governing procedures.

2.1.4.5.3 Conclusion

Based on its review of the LRA, scoping implementation procedures, and the system sample

and discussions with the applicant, the staff concludes that the applicant's methodology for

identifying mechanical -components for 10 CFR 54.4(a) scoping criteria is acceptable.

2.1.4.6 Structural Component Scoping

2.1.4.6.1 Summary of Technical Information in the Application

LRA Section 2.1.3.2 describes the methodology for identifying structures that are within the

scope of license renewal. A list of all structures at WCGS was developed through review of site

drawings in conjunction with a walkdown of the property. These structures are listed in LRA

Table 2.2-1. The USAR was relied upon to identify the safety classifications of structures and

structural components. The structure descriptions were prepared and the structure boundaries

were determined. This information was included in the license renewal database. All structure

functions were evaluated against the requirements of 10 CFR 54.4(a)(1), (a)(2) and (a)(3) and

the results of this evaluation were documented in the license renewal database. LRA

Section 2.4 describes the scoping results for the individual structures that are within the scope

of license renewal. For example, LRA Section 2.4.5 describes the purpose, intended functions

and seismic classification for the auxiliary building. The auxiliary building is a safety-related,

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seismic Category I structure that provides support, shelter, and protection to engineered safety

features and nuclear auxiliary systems equipment.

2.1.4.6.2 Staff Evaluation

The staff reviewed the applicant's approach for identifying structures relied upon to perform the

functions described in 10 CFR 54.4(a). As part of this review, the staff discussed the

methodology with the applicant, reviewed the documentation developed to support the review,

and evaluated the scoping results for several structures that were identified within the scope of

license renewal.

The project instruction for scoping and screening describes the applicant's process for

identifying systems and structures that are within the scope of license renewal. If a structure

was determined to perform an intended function that met any of the criteria in 10 CFR 54.4(a),

then the structure was determined to be within the scope of license renewal. The results of the

scoping review were documented in the LRDMT or database, and the scoping results were

documented in individual scoping reports.

The staff reviewed the applicant's project instruction and scoping reports. Structural scoping

was performed in a manner to ensure that all plant buildings and yard structures were

considered. The scoping reports identified the intended functions for each structure required for

compliance with 10 CFR 54.4(a). The structural intended functions were identified based on the

guidance provided in NEI 95-10, Appendix B. For structures, the evaluation boundaries were

determined by developing a complete description of each structure and its intended functions.

The results of the review were documented in the scoping reports which contain a description of

the structure, evaluation results for each of the 10 CFR 54.4(a) criteria, a description of

structural intended functions and source reference information for the functions. Sources of

information for structure identification and intended functions include the USAR, drawings,

position papers developed for the regulated events, and other CLB sources such as the fire

hazards analysis and flood analysis.

The staff conducted detailed discussions with the applicant's license renewal team and

reviewed documentation pertinent to the scoping process. The staff assessed if the scoping

methodology outlined in the LRA and procedures were appropriately implemented and if the

scoping results were consistent with CLB requirements. The staff also reviewed structural

scoping evaluation results for the auxiliary building, for example, to verify proper implementation

of the scoping process. Based on its review, the staff did not identify any discrepancies

between the methodology documented and the implementation results.

2.1.4.6.3 Conclusion

Based on its review of the LRA, the applicant's detailed scoping implementation procedures,

and a sampling of structural scoping results, the staff concludes that the applicant's

methodology for identification of structural component types within the scope of license renewal

meets the requirements of 10 CFR 54.4(a) and; therefore, is acceptable.

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2.1.4.7 Electrical Component Scoping

2.1.4.7.1 Summary of Technical Information in the Application

The LRA states that the USAR descriptions, maintenance rule database records, CLB

documents and DBDs were reviewed to determine the system safety classification and to

identify all of the system functions. All system level functions were evaluated against the

requirements of 10 CFR 54.4(a)(1), (a)(2) and (a)(3). The supporting systems needed to

maintain the system intended functions were identified and evaluated against the requirements

of 10 CFR 54.4(a)(2). The results of the system level scoping along with a list of references

supporting the evaluation of each electrical and instrument and control system were

documented in the license renewal database.

The LRA states that all electrical and I&C components that perform an intended function as

described in 10 CFR 54.4 were included within the scope of license renewal. The installed

electrical components were identified by reviewing documents such as plant drawings and

databases. Additionally industry documents, such as NEI 95-10, provided a list of typical

electrical components found in nuclear power plants. These lists were reviewed against

engineering information for the plant to determine which electrical component types were

installed at WCGS.

2.1.4.7.2 Staff Evaluation

The staff evaluated LRA Section 2.1.3.3 and the program guidelines to complete the review of

the electrical scoping process. The program guidelines provide instructions for identifying and

evaluating individual electrical systems with respect to the scoping criteria including specific

information on the electrical systems credited for the regulated events of 10 CFR 54.4(a)(3).

Various CLB documents were utilized when determining whether a system is within the scope

of 10 CFR 54.4(a) which included the USAR descriptions, maintenance rule database records,

CLB documents and DBDs. The applicant identified all electrical systems which met the

requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3), identified the specific intended functions,

and documented the results in a system scoping package and the license renewal database. If

an electrical system was considered to be within the scope of license renewal, all its

components were also included within the scope of license renewal.

The staff reviewed the implementation guidance and the CLB documents associated with

electrical scoping, and finds that the guidance and CLB source information noted above were

acceptable to identify if the electrical components were within the scope of license renewal. The

staff conducted detailed discussions with the applicant's license renewal project management

personnel and reviewed documentation pertinent to the scoping process. The staff assessed

whether the applicant had appropriately applied the scoping methodology outlined in the LRA

and implementation procedures and whether the scoping results were consistent with CLB

requirements. The staff determines that the applicant's proceduralized methodology is

consistent with the description provided in LRA Section 2.1.3.3 and the guidance contained in

SRP-LR Section 2.1 and was adequately implemented.

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2.1.4.7.3 Conclusion

Based on its review of the LRA, the applicant's detailed scoping implementation procedures,

and a sampling of electrical scoping results, the staff concludes that the applicant's

methodology for identification of electrical components within the scope of license renewal

meets the requirements of 10 CFR 54.4(a) and; therefore, is acceptable.

2.1.4.8 Conclusion for Scoping Methodology

Based on its review of the LRA and the scoping implementation procedures, the staff

determines that the applicant's scoping methodology is consistent with the guidance described

in SRP-LR and has identified SSCs within the scope of license renewal in accordance with the

requirements of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). Therefore, the staff concludes that the

applicant's methodology meets the requirements of 10 CFR 54.4(a).

2.1.5 Screening Methodology

2.1.5.1 General Screening Methodology

After identifying systems and structures within the scope of license renewal, the applicant

implemented a process for identifying SCs subject to an AMR in accordance with

10 CFR 54.21.

2.1.5.1.1 Summary of Technical Information in the Application

In LRA Section 2.1.4, the applicant discussed the method of identifying components from

systems and structures that are within the scope of license renewal and that are subject to an

AMR. The applicant's screening process consisted of identifying and listing the SCs that are

subject to an AMR. All of the SCs categorized as within the scope of the license renewal were

screened against the criteria of 10 CFR 54.21 (a)(1)(i) and (a)(1)(ii) to determine whether they

are subject to an AMR. Section 54.21 of 10 CFR states that the SCs subject to an AMR shall

encompass those SCs within the scope of license renewal rule if they perform an intended

function, as described in 10 CFR 54.4, without moving parts or without a change in

configuration or properties; and are not subject to replacement based on a qualified life or

specified time period. Active components were screened out and; therefore, did not require an

AMR. The screening process also identified short-lived components and consumables. The

short-lived components are not subject to an AMR. Also, in its screening process, the applicant

incorporated the industry guidance provided in NEI 95-10, Appendix B. The screening of

system SCs at WCGS was performed using the LRDMT.

2.1.5.1.2 Staff Evaluation

Pursuant to 10 CFR 54.21, each LRA must contain an IPA that identifies SCs within the scope

of license renewal that are subject to an AMR. The IPA must identify components that perform

an intended function without moving parts or a change in configuration or properties (i.e.,

passive), as well as components that are not subject to periodic replacement based on a

qualified life or specified time period (i.e., long-lived). The IPA includes a description and

justification of the methodology used to determine the passive and long-lived SCs, and a

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demonstration that the effects of aging on those SCs will be adequately managed so that the

intended function(s) will be maintained under all design conditions imposed by the plant-specific

CLB for the period of extended operation.

The staff reviewed the methodology used by the applicant to determine if mechanical, electrical

and structural component types within the scope of license renewal should be subject to an

AMR. The applicant implemented a process for determining which SCs were subject to an AMR

in accordance with the requirements of 10 CFR 54.21 (a)(1). In LRA Section 2.1.4, the applicant

discussed these screening activities as they relate to the component types and commodity

groups within the scope of license renewal. The screening process evaluated these component

types to determine which ones were long-lived and passive and; therefore, subject to an AMR.

For verification purpose, the staff reviewed LRA Sections 2.3, 2.4, and 2.5 that provide the

results of the process used to identify component types and subject to an AMR.

During the audit, the applicant provided the staff with detailed discussion and demonstrations of

the screening processes used for each discipline and provided documentation that described

the screening methodology and screening results. Also as part of the audit, the staff reviewed

the screening results reports for the auxiliary feedwater and high pressure coolant injection

systems and the auxiliary building structure. Specific methodology for mechanical, electrical,

and structural is discussed the following sections.

2.1.5.1.3 Conclusion

Based on its review of the LRA, the screening implementation procedures, and a sampling of

screening results, the staff determines that the applicant's screening methodology is consistent

with the guidance described in the SRP-LR and capable of identifying passive, long-lived

components within the scope of license renewal and subject to an AMR. The staff determines

that the applicant's process for identifying component types and commodity groups subject to

an AMR meets the requirements of 10 CFR 54.21 and; therefore, is acceptable.

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

LRA Section 2.1.4.1 describes the screening methodology for identifying passive and long-lived

mechanical components that are subject to an AMR. After the mechanical systems and the

component scoping was performed, the applicant initiated the screening process for the

mechanical components. After a mechanical system component was categorized in the license

renewal database as within the scope of license renewal, the classification as an active or

passive component was determined based on evaluation of the component description and

type. In this determination, the applicant used the guidance provided in NEI 95-10, Appendix B.

Components within the scope of license renewal that are determined to be passive and

long-lived were identified in the license renewal database as subject to an AMR. Each

component that was identified as subject to an AMR was evaluated to determine its intended

function, which was based on an evaluation of its type and support of the system intended

function. The results of the component screening are recorded in the screening reports of the

license renewal database. Components that were determined to be short-lived were eliminated

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from the AMR process and the basis for the classification as short-lived was recorded in the

license renewal database.

The screening of mechanical components includes utilization of the license renewal drawings

and the license renewal database. Components subject to an AMR (i.e., passive, long-lived

components that support system intended functions) are highlighted on the drawings to indicate

that the component is subject to an AMR. LRA Section 2.3 summarizes the screening results of

the mechanical components.

2.1.5.2.2 Staff Evaluation

The staff evaluated the mechanical screening methodology in LRA 2.1.4.1, the license renewal

project instruction for screening methodology, the license renewal drawings, and the screening

and AMR reports, as referenced in the audit report. The mechanical system screening process

began with the results from the scoping process. The applicant reviewed mechanical system

drawings to identify passive and long-lived components. To identify system components

required to perform a system's intended function, the applicant initially generated a listing of

mechanical system components based on information derived from the drawings and the

license renewal database. The system boundaries are determined based on the drawings,

which depict the system principal functional components. Components that are within the scope

of license renewal are evaluated for active and passive functions following the guidance of

NEI 95-10, Appendix B. The components that are within the scope of license renewal pursuant

to 10 CFR 54.4(a)(1) and (a)(3) are highlighted in green on the license renewal drawings,

whereas, those components that are within the scope of license renewal pursuant to

10 CFR 54.4(a)(2) are highlighted in red.

The applicant's project instruction provides detailed implementation guidance on the applicant's

process for identifying and screening mechanical components that are subject to an AMR. The

project instruction delineates that all mechanical components that perform or support an

intended function and are passive and long-lived are subject to an AMR. In addition, the

screening results for each system within the scope of license renewal are presented in separate

screening reports.

The staff reviewed the applicant's methodology used for mechanical component screening as

described in the LRA, and reviewed the applicant's implementing guidance and screening

reports. The applicant performed the screening review in accordance with the implementation

guidance and captured pertinent component information such as materials, environments, and

references. The staff verified that the applicant implemented the guidance in SRP-LR and

NEI 95-10 and had followed that guidance in performing the screening effort. The staff

confirmed that the applicant developed sufficiently detailed procedures for the screening of

mechanical systems, implemented those procedures, and adequately documented the results

in the associated AMR reports.

Additionally, the staff reviewed the screening activities associated with the auxiliary feedwater

and the high pressure coolant injection systems. The staff reviewed the system intended

functions and associated source documents identified for these systems, the drawings, and the

associated screening documented in the screening results and AMR reports. The staff did not

identify any discrepancies with the evaluation, and determines that the applicant adequately

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followed the process documented in the license renewal project instruction, and adequately

documented the results in the screening and AMR reports for the above systems.

2.1.5.2.3 Conclusion

Based on its review of the LRA, the screening implementation procedures, and a sample of

auxiliary feedwater and the high pressure coolant injections systems screening results, the staff

determines that the applicant's mechanical component screening methodology is consistent

with the guidance described in the SRP-LR. The staff concludes that the applicant's

methodology for identification of passive, long-lived mechanical components within the scope of

license renewal and subject to an AMR meets the requirements of 10 CFR 54.21 (a)(1).

2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

LRA Section 2.1.4.2 describes the screening methodology for identifying passive and long-lived

structural components that typically perform their functions without moving parts and without a

change in configuration or properties. When a structure or structural component was

determined to be within the scope of license renewal, the structure screening methodology

classified the component as passive. During the structural screening process, the intended

function(s) of structural components were determined and recorded in the license renewal

database. Additionally, an evaluation was performed to determine whether structural

components within the scope of license renewal are subject to replacement based on a

qualified time period. If a structural component was determined to be subject to replacement

based on a qualified time period, the component was identified as short-lived and was excluded

from an AMR. The basis for determining that the structural component was short-lived was

documented in the license renewal database. LRA Section 2.4 provides the screening results

for structures.

2.1.5.3.2 Staff Evaluation

The staff reviewed the applicant's methodology for identifying structural components that are

subject to an AMR pursuant tol 0 CFR 54.21 (a)(1). As part of this review, the staff discussed

the methodology with the applicant, reviewed the documentation developed to support the

activity, and evaluated the screening results for the auxiliary building that was identified as

within the scope of license renewal.

The applicant's project instruction provides detailed implementation guidance on the applicant's

process for identifying and screening structural components that are subject to an AMR. The

project instruction delineates that all structural components that perform an intended function

and are passive and long-lived are subject to an AMR. In addition, the screening results for

each structure within the scope of license renewal are presented in separate screening reports.

The staff reviewed the applicant's methodology used for structural component screening

described in the LRA, and in the applicant's implementing guidance and screening reports. The

applicant performed the screening review in accordance with the implementation guidance and

captured pertinent component information such as materials, environments, and references.

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The staff verified that the applicant used the lists of passive SCs embodied in the regulatory

guidance as a starting point and supplemented the lists with additional items either unique to

the site or as generic components (e.g., concrete, non-containment isolation penetrations) for

which a direct match to the generic lists did not exist.

The staff also evaluated the applicant's results from the implementation of this methodology by

reviewing the auxiliary building which was identified as being within the scope of license

renewal. In addition, the staff reviewed the screening report associated with the screening

methodology to verify if the applicant performed a comprehensive evaluation and identified the

relevant structural components as part of their evaluation. The review included the evaluation of

components within the scope of license renewal, the corresponding component-level intended

functions, and the resulting list of components subject to an AMR. The staff also discussed the

process and results with the applicant. The staff did not identify any discrepancies between the

methodology documented and the implementation results.

2.1.5.3.3 Conclusion

Based on its review of the LRA, the applicant's detailed screening implementation procedures,

and a sampling of structural screening results, the staff concludes that the applicant's

methodology for identification of passive, long-lived structural component types within the scope

of license renewal and subject to an AMR meets the requirements of 10 CFR 54.21 (a)(1).

2.1.5.4 Electrical Component Screening

2.1.5.4.1 Summary of Technical Information in the Application

The LRA states that the screening of electrical and I&C components had been accomplished by

identifying electrical components within the scope of license renewal as passive and long-lived

based on the determinations documented in NEI 95-10, Appendix B. The passive, long-lived

electrical and I&C components that perform an intended function without moving parts or

without change in configuration or properties were grouped into component types such as

cable, connections, fuse holders, terminal blocks, high-voltage transmission conductor,

connections and insulators, switchyard bus and connections. Component-level intended

function(s) were determined for each passive electrical component group within the scope of

license renewal and recorded in the license renewal database. The passive, long-lived electrical

component types within the scope of license renewal were identified in the license renewal

database as subject to an AMR.

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant's methodology used for electrical screening in LRA

Section 2.1.4.3 and the applicant's guidance, implementation procedures and reports. The staff

confirmed that the applicant had assembled a table of commodities which were determined to

meet the passive criteria which were grouped in accordance with the guidance contained in

NEI 95-10 which included cable, connections, fuse holders, terminal blocks, high-voltage

transmission conductor, connections and insulators, switchyard bus and connections. The

applicant evaluated the identified passive commodities to determine whether they were subject

to replacement based on a qualified life or specified time period (i.e., short-lived), or not subject

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to replacement based on a qualified life or specified time period (i.e., long-lived). The remaining

passive, long-lived components were determined to be subject to an AMR. The staff reviewed

the screening of selected components to verify the correct implementation of the applicant's

implementing procedures and reports.

2.1.5.4.3 Conclusion

The staff reviewed the LRA, procedures, electrical drawings, and a sample of the results of the

screening methodology. The staff determines that the applicant's methodology is consistent

with the description provided in LRA and the applicant's implementing procedures. On the basis

of a review of information contained in the LRA, the applicant's screening implementation

procedures, and a sampling review of electrical screening results, the staff concludes that the

applicant's methodology for identification of electrical commodity groups subject to an AMR is

consistent with the requirements of 10 CFR 54.21 (a)(1) and, therefore, is acceptable.

2.1.5.5 Conclusion for Screening Methodology

Based on its review of the LRA and the screening implementation procedures, discussions with

the applicant's staff, and a sample review of screening results, the staff determines that the

applicant's screening methodology is consistent with the guidance described in the SRP-LR and

has identified passive, long-lived components within the scope of license renewal and subject to

an AMR. The staff concludes that the applicant's methodology is consistent with the

requirements of 10 CFR 54.21 (a)(1) and, therefore, is acceptable.

2.1.6 Summary of Evaluation Findings

The information in LRA Section 2.1, the supporting information in the scoping and screening

implementation procedures and reports, and the information presented during the scoping and

screening methodology audit formed the basis of the staff's determination that the applicant's

scoping and screening methodology is consistent with the requirements of the Rule. Based on

its review, the staff concludes that the applicant's methodology for identifying SSCs within the

scope of license renewal and SCs requiring an AMR is consistent with the requirements of

10 CFR 54.4 and 54.21 (a)(1) and, therefore, is acceptable.

2.2 Plant-Level Scoping Results

2.2.1 Introduction

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to

determine which SSCs must be included within the scope of license renewal. The staff reviewed

the plant-level scoping results to determine whether the applicant has properly identified all

systems and structures relied upon to remain functional during and following DBEs, as required

by 10 CFR 54.4(a)(1), systems and structures the failure of which could prevent satisfactory

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2), and systems

and structures relied on in safety analyses or plant evaluations to perform functions required by

regulations referenced in 10 CFR 54.4(a)(3).

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2.2.2 Summary of Technical Information in the Application

In LRA Tables 2.2.1, 2.2.2, and 2.2.3, the applicant listed plant mechanical systems, structures,

and electrical and I&C systems within the scope of license renewal. From DBEs factored into

the plant CLB, other CLB information on nonsafety-related systems and structures, and certain

regulated events, the applicant identified plant-level systems and structures within the scope of

license renewal as defined by 10 CFR 54.4.

2.2.3 Staff Evaluation

In LRA Section 2.1, the applicant described its methodology for identifying systems and

structures within the scope of license renewal and subject to an AMR. The staff reviewed the

scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify

that the applicant properly implemented its methodology as a part of the staff's evaluation of the

applicant's plant-level scoping results, the staff's review focused on the implementation results

shown in LRA Table 2.2-1, to confirm that there were no omissions of plant-level systems and

structures within the scope of license renewal.

The staff determined whether the applicant properly identified the systems and structures within

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected

systems and structures that the applicant did not identify as within the scope of license renewal

to verify whether the systems and structures have any intended functions requiring their

inclusion within the scope of license renewal. The staff's review of the applicant's

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2,

"Plant-Level Scoping Results."

The staff sampled the contents of the USAR based on the systems and structures listed in LRA

Table 2.2-1 to determine if there were any systems or structures that may have intended

functions within the scope of license renewal, as defined by 10 CFR 54.4, but were omitted

from the scope of license renewal. The staff did not identify any omissions.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2 and the USAR supporting information to determine if the

applicant failed to identify any systems and structures within the scope of license renewal. The

staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified in accordance with

10 CFR 54.4 the systems and structures within the scope of license renewal.

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff's review of the applicant's scoping and screening results for

mechanical systems. Specifically, this section discusses:

* reactor vessel and internals (RVI), and reactor coolant system (RCS)

* engineered safety features (ESFs)

* auxiliary systems

* steam and power conversion systems

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In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must list passive,

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the

applicant properly implemented its methodology, the staff's review focused on the

implementation results. This focus allowed the staff to confirm that there were no omissions of

mechanical system components that meet the scoping criteria and are subject to an AMR.

The staff's evaluation of the information in the LRA was the same for all mechanical systems.

The objective was to determine whether the applicant has identified, in accordance with

10 CFR 54.4, components and supporting structures for mechanical systems that appear to

meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's

screening results to verify that all passive, long-lived components were subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections and drawings, focusing

on components that have not been identified as within the scope of license renewal. The staff

reviewed relevant licensing basis documents, including the USAR, for each mechanical system

to determine whether the applicant has omitted from the scope of license renewal components

with intended functions delineated pursuant to 10 CFR 54.4(a). The staff also reviewed the

licensing basis documents to determine whether the LRA specified all intended functions

delineated pursuant to 10 CFR 54.4(a). The staff requested additional information to resolve

any omissions or discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant's screening results. For

those SCs with intended functions, the staff sought to determine whether (1) the functions are

performed with moving parts or a change in configuration or properties or (2) the SCs are

subject to replacement after a qualified life or specified time period, as described in

10 CFR 54.21 (a)(1). For those meeting neither of these criteria, the staff sought to confirm that

these SCs were subject to an AMR, as required by 10 CFR 54.21 (a)(1). The staff requested

additional information to resolve any omissions or discrepancies identified.

2.3.1 Reactor Vessel Internals, and Reactor Coolant System

LRA Section 2.3.1 identifies the RVI and RCS SCs subject to an AMR for license renewal.

The applicant described the supporting SCs of the RVI -and RCS in the following LRA sections:

* 2.3.1.1 reactor vessel and internals

* 2.3.1.2 reactor coolant system

* 2.3.1.3 steam generators

• 2.3.1.4 reactor core

The staff's findings on review of LRA Sections 2.3.1.1 - 2.3.1.4 are in SER

Sections 2.3.1.1 - 2.3.1.4, respectively.

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2.3.1.1 Reactor Vessel and Internals

2.3.1.1 .1 Summary of Technical Information in the Application

LRA Section 2.3.1.1 describes the RVI which support the reactor core and control rod drive

mechanisms and provide a pressure boundary for reactor coolant. The RVI support the core,

maintain fuel alignment, direct coolant flow, and provide gamma and neutron shielding. The

nozzle-supported, cylindrical reactor vessel has a welded, hemispherical bottom head and a

removable, flanged, hemispherical upper head. The vessel contains the core, core-supporting

structures, control rods, and other parts directly associated with the core. The top head also

has penetrations for the control rod drive mechanisms and the head vent pipe. O-ring

leak-monitoring tube penetrations are located in the vessel flange. The vessel has inlet and

outlet nozzles located in a horizontal plane just below the reactor vessel flange but above the

top of the core. The bottom head of the vessel has penetration nozzles for connection and entry

of the nuclear in-core instrumentation.

The RVI have safety-related components relied upon to remain functional during and following

DBEs. In addition, the RVI perform functions that support fire protection, PTS, and SBO as

documented in the LRA.

LRA Table 2.3.1-1 identifies reactor vessel and internals component types within the scope of

license renewal and subject to an AMR:

* RV closure head

* RV control rod drive head penetration

" RV core support pads

* RV nozzle safe ends and welds

* RV nozzles

* RV penetrations

" RV shell

* RV shell head

* RVI baffle/former assembly

* RVI control rod guide tube assembly

* RVI core barrel assembly

" RVI instrumentation support structures

" RVI lower internals assembly

" RVI upper internals assembly

The intended functions of the RVI component types within the scope of license renewal include:

* spray shield, curbs, or mechanical components for directing flow

" pressure boundary

* structural and/or functional support to safety-related components

* shielding against radiation

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2.3.1.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.1 and USAR Sections 3.9(N).5, 5.1, 5.2, and 5.3 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3, "Scoping and Screening Results: Mechanical Systems."

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.1.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.1.1-1 dated May 6, 2007, the staff noted that USAR Figures 18.2-1 and 18.2-13

show the reactor head vent system and the reactor vessel level instrumentation system,

respectively. The staff requested that the applicant indicate which portions of the reactor head

vent system are within the scope of license renewal. In addition, the staff requested that the

applicant clarify if the spare head penetration of the level instrumentation system is within the

scope of license renewal.

In its response dated June 1, 2007, the applicant stated that the portions of the reactor head

vent system that are within the scope of license renewal are shown in drawing

LR-WCGS-BB-M-12BB04. The applicant clarified that the boundary starts from the connection

with the vessel head, located at coordinate E-4, up to the second isolation valves, located at

coordinates F-2 and G-2. The applicant stated that these components have an intended

function of pressure boundary and are within the scope of license renewal pursuant to

10 CFR 54.4(a)(1).

The applicant further stated that the reactor vessel level instrumentation system used a spare

vessel head penetration for the upper level tap. The vessel head still has several blind flanged

spare penetrations, all of which have the intended function of pressure boundary and are within

the scope of license renewal pursuant to 10 CFR 54.4(a)(1). The applicant clarified that the

portions of the reactor vessel instrumentation system that are within the scope of license

renewal are also shown on drawing LR-WCGS-BB-M-12BB04, from coordinates E-4 to F-5.

The applicant clarified that the head penetration of the level instrumentation system and the

spares are addressed in LRA Table 2.3.1-1 as a component type of reactor vessel penetrations.

Based on its review, the staff finds the applicant's response to RAI 2.3.1.1-1 acceptable

because it clarified that the components in question are within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.1.1-1 is resolved.

Based on its review, the staff finds that the reactor vessel is within the scope of license renewal.

It is the key Class 1 component in the pressure-retaining boundary because it enables proper

cooling of the core under normal and accident conditions. Many of the reactor vessel and

internals and reactor vessel level instrumentation system are also within the scope of license

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renewal because they perform functions as delineated in 10 CFR 54.4(a)(1). Reactor vessel

internals such as seals and gaskets are typically not within the scope of license renewal since

those components are periodically replaced.

The staff finds long-lived, passive, and pressure-retaining components, that are within the

scope of license renewal in accordance with the requirements of 10 CFR 54.4(a), are incore

instrumentation components. Among these are the incore neutron flux detector thimbles, the

pressure-retaining incore thermocouples, and various pressure-retaining tubes and tube fittings.

Unlike the surrounding fuel element assemblies, these incore instrumentation system

components are not replaced periodically. They provide guidance and pathways through which

instrument sensors are routed, and these pathways constitute part of the pressure-retaining

boundary. Basically, the incore instrumentation system components are pressure-retaining

tubes made of a stainless steel and nickel based alloy that must withstand a borated water

environment.

The staff also finds that many of the reactor vessel internals are identified as components that

provide structural support to safety-related components. For example, they can provide the

structural support needed to maintain a coolable core geometry during a design basis loss of

coolant accident (LOCA). Unlike many other long-lived, passive components, certain reactor

internals are normally moved (i.e., removed and set aside) to allow the movement of fuel

assemblies during refueling. This provides occasional opportunities to detect and remedy

aging-related problems that might affect these reactor vessel internals. Although these

components have the benefit of periodic examination, they should be and are included within

the scope of license renewal and subject to an AMR.

No omissions of SSCs, that are within the scope of license renewal and subject to an AMR,

were found.

2.3.1.1.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the reactor vessel internals components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21(a)(1).

2.3.1.2 Reactor Coolant System

2.3.1.2.1 Summary of Technical Information in the Application

LRA Section 2.3.1.2 describes the RCS, which is designed to maintain the reactor coolant at

adequate conditions of temperature, pressure, and flow to protect the core from damage (in

conjunction with the reactor control and protection systems). The RCS is designed to maintain

boron homogeneity and reactor coolant temperature such that uncontrolled reactivity changes

do not occur. The RCS pressure boundary is designed to provide a barrier to limit leakage of

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reactor coolant and release of radioactive isotopes. The RCS provides containment isolation for

penetrations P-22, P-39, P-40, P-41, P-59, P-62 and P-91. The RCS transfers the heat

generated in the reactor core and by the reactor coolant pumps (RCPs) to the steam

generators for further transfer to the main steam system to produce steam to drive the

turbine-generator. The borated demineralized water circulated in the RCS acts as a neutron

moderator and reflector, as a neutron absorber for chemical shim control in the reactor core,

and as a heat transfer medium.

The RCS has safety-related components relied upon to remain functional during and following

DBEs. The failure of nonsafety-related SSCs in the RCS could prevent the satisfactory

accomplishment of a safety-related function. In addition, the RCS performs functions that

support fire protection, SBO, and EQ.

LRA Table 2.3.1-2 identifies RCS component types within the scope of license renewal and

subject to an AMR:

• Class 1 piping (less than or equal to 4-inch)

* closure bolting

• flow element

• heat exchanger shell side

• heat exchanger tube side

• "instrument bellows

• piping

• pressurizer relief tank

* pump

• pressurizer heater bundle diaphragm plate

* pressurizer heater sheaths and sleeves

* pressurizer instrument penetrations

* pressurizer integral support

* pressurizer manways and covers

• pressurizer nozzles

* pressurizer shells/heads

• pressurizer safe ends

• rupture disc

• thermowell

" tubing

• valve

The intended functions of the RCS component types within the scope of license renewal

include:

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* structural and/or functional support to safety-related components

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

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2.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.2 and USAR Sections 5.1, 5.2, 5.4, and 9.5B using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1). The staff confirmed agreement with

the applicant's results with the following observations.

Based on its review, the staff finds that the applicant included the pressurizer relief tank in the

pressure-retaining boundary. The pressure-retaining boundary of the pressurizer relief tank will

be maintained until the tank's rupture disks give way, as designed, at about 100 psid. Upstream

of the pressurizer relief tank, the pressurizer relief and safety valves protect the

pressure-retaining boundary, as they open and reseat, to limit RCS pressure by discharging

steam to the pressurizer relief tank (e.g., during a transient). Since, during normal operation,

the pressurizer relief tank also collects the steam that may leak through the pressurizer relief

and safety valves, it is included within the scope of license renewal. Therefore, the staff finds

this acceptable.

The staff noted that the pressurizer nozzles are included within the scope of license renewal;

however, the pressurizer spray head is not. The spray head distributes normal and auxiliary

pressurizer spray water into the pressurizer steam bubble, which tends to depressurize the

pressurizer and the RCS (subsequently). Since the normal and auxiliary pressurizer sprays are

not safety systems, they cannot be relied upon to function during any of the accident analyses,

unless, in some postulated analysis cases, pressurizer spray could have an aggravating effect

upon the transient results. Therefore, the spray function is not credited for the mitigation of any

accidents addressed in the USAR accident analyses. However, in a manual mode, the spray

function can be used to reduce RCS pressure following a steam generator tube rupture event,

in order to end the primary-to-secondary side tube break flow. The staff referred this issue to

the Region IV staff for their evaluation during its scoping and screening inspection.

'The Region IV staff performed its scoping and screening inspection during the weeks of

September 10 and October 22, 2007. As documented in its inspection report dated

December 5, 2007, the staff noted that the pressurizer spray head is used by operators to

reduce and control reactor pressure during some accident scenarios. The inspectors reviewed

the applicant's justification for not including the pressurizer spray head within the scope of

license renewal. The staff interviewed plant personnel and reviewed basis documents provided

by the applicant that support its position that the pressurizer spray head does not perform any

pressure boundary function, is not a component critical to perform a safe shut down of the plant

during an accident, and is isolated in response to a control room fire. The staff finds that, since

the pressurizer spray head has no safety function, the applicant's position of not including this

component within the scope of license renewal is consistent with the guidance provided in the

GALL Report and 10 CFR 54.4(a).

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2.3.1.2.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

RCS components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.3 Steam Generators

2.3.1.3.1 Summary of Technical Information in the Application

LRA Section 2.3.1.3 describes the steam generators, which remove heat by generating steam

for normal operation, DBE mitigation, SBO, and fire safe shutdown requirements. The steam

generators are also an assured source of steam for the turbine-driven auxiliary feedwater

pump. The primary channel head and tubes form part of the reactor coolant pressure boundary.

The steam generators form part of the containment pressure boundary to prevent the release of

fission products to the environment. The steam generators system consists of primary and

secondary pressure boundaries including all pieces and parts within the pressure boundary and

all penetrations out to and including the safe ends of the penetration nozzles.

The steam generators have safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SSCs in the steam generators could

prevent the satisfactory accomplishment of a safety-related function. In addition, the steam

generators perform functions that support fire protection and SBO.

LRA Table 2.3.1-3 identifies steam generators component types within the scope of license

renewal and subject to an AMR:

* steam generator closure bolting

* steam generator feedring

* steam generator flow distribution baffle

* steam generator internal structures

* steam generator plugs

" steam generator primary head and divider plate

" steam generator primary manways and flanges

* steam generator primary nozzles and safe ends

* steam generator secondary manways and flanges

* steam generator secondary nozzles and safe ends

* steam generator secondary shell

" steam generator tube support plates

* steam generator tubes

* tubing

The intended functions of the steam generators component types within the scope of license

renewal include:

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0 flow restriction

* spray shield, curbs, or mechanical components for directing flow

* heat transfer

" pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

" structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

2.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.3 and USAR Sections 5.4.2 and 10.3.1.1 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.1.3.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any components subject to an

AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified the steam generators

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.1.4 Reactor Core

2.3.1.4.1 Summary of Technical Information in the Application

LRA Section 2.3.1.4 describes the reactor core, which allows efficient heat transfer to the

coolant and provides a fission product barrier through its fuel assemblies. The reactor core

includes an array of fuel assemblies similar in mechanical design but different in fuel

enrichment. Fuel assemblies contain the fissionable material that sustains a nuclear reaction

when the reactor core is critical. Each fuel assembly consists of 264 fuel rods, 24 guide thimble

tubes, and one instrumentation thimble tube arranged within a supporting structure. The fuel

assembly structure consists of a bottom nozzle, thimble screws, top nozzle, guide thimbles,

inserts, lock tubes, and grids.

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The reactor core is within the scope of license renewal based on the criteria of

10 CFR 54.4(a)(1).

The applicant concludes that relative to license renewal review, the reactor core does not have

components with intended functions within the scope of license renewal (short-lived).

LRA Table 2.3.1-4 shows no reactor core component types within the scope of license renewal

and subject to an AMR.

2.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.1.4 and USAR Section 4.2 using the evaluation

methodology described in SER Section 2.3 and the guidance described in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

Based on its review, the staff finds that the applicant adequately included the reactor core within

the scope of license renewal as required by 10 CFR 54.4(a)(1). The core figures prominently in

plant safety considerations, during normal operation and also during accidents and transients,

since it contains the source of fission products and the first fission product barrier. However, the

core components (e.g., fuel assemblies, rod cluster control assemblies and burnable absorber

assemblies) are not subject to an AMR, since they are short-lived, and periodically replaced

during the plant lifetime.

2.3.1.4.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any components subject to an

AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified the reactor core

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2 Engineered Safety Features

LRA Section 2.3.2 identifies the ESFs subject to an AMR for license renewal. The applicant

described the supporting SCs of the ESFs in the following LRA sections:

* 2.3.2.1 nuclear sampling system

* 2.3.2.2 containment spray system

" 2.3.2.3 containment integrated leak rate test system

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0 2.3.2.4 decontamination system

* 2.3.2.5 liquid radwaste system

" 2.3.2.6 reactor makeup water system

" 2.3.2.7 containment purge heating, ventilating, and air conditioning (HVAC)

system

* 2.3.2.8 breathing air system

• 2.3.2.9 hydrogen control system

* 2.3.2.10 high pressure coolant injection system

" 2.3.2.11 residual heat removal (RHR) system

The staff's findings on review of LRA Sections 2.3.2.1-2.3.2.11 are in SER

Sections 2.3.2.1-2.3.2.11, respectively.

2.3.2.1 Nuclear Sampling System

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the nuclear sampling system, which provides automatic isolation

functions for the system containment penetrations. The nuclear sampling system obtains and

analyzes samples from various systems and locations in the nuclear steam supply system for

radiological monitoring and control of chemistry parameters. The system consists of piping,

tubing, valves, coolers and analysis equipment necessary to collect and analyze process

stream samples. Sample station rooms are located in the auxiliary building, radwaste building,

and turbine building to service nuclear steam supply system, radwaste, and secondary sample

points, respectively.

The nuclear sampling system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the nuclear sampling

system could prevent the satisfactory accomplishment of a safety-related function. In addition,

the nuclear sampling system performs functions that support EQ.

LRA Table 2.3.2-1 identifies nuclear sampling system component types within the scope of

license renewal and subject to an AMR:

* closure bolting

" flow indicator

* piping

* tubing

* valve

The intended functions of the nuclear sampling system component types within the scope of

license renewal include:

* pressure boundary

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" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

" maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1 and USAR Sections 5.1, 5.4, and 9.3.2 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.1.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any components subject to an

AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified the nuclear sampling

system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.2 Containment Spray System

2.3.2.2.1 Summary of Technical Information in the Application

LRA Section 2.3.2.2 describes the containment spray system, which removes decay heat and

radioactive iodine from the containment atmosphere in post-accident conditions to maintain

containment pressure below design limits and offsite release less than 10 CFR Part 100 limits.

Containment isolation valves, suction line guard pipes, and valve encapsulations maintain

containment integrity in single-failure scenarios. Borated alkaline water from the containment

spray system removes decay heat and iodine from the containment atmosphere in

post-accident conditions. The system consists of two redundant trains, each with a containment

spray pump, spray nozzles, valves, and piping. There are suction paths coming from the

refueling water storage tank (RWST) for initial system flow and from the containment

recirculation sumps for long-term operation. Each train has a discharge path through the spray

nozzles in the upper containment. A common spray additive tank provides sodium hydroxide via

eductors to both trains to ensure a basic pH that promotes absorption of iodine from the

containment atmosphere.

The containment spray system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the containment spray

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system could prevent the satisfactory accomplishment of a safety-related function. In addition,

the containment spray system performs functions that support fire protection and EQ.

LRA Table 2.3.2-2 identifies containment spray system component types within the scope of

license renewal and subject to an AMR:

• closure bolting

• eductor

• expansion joint

• flow element

• orifice

* piping

* pump

• spray nozzle

• tank

• tubing

" valve

* vortex breaker

The intended functions of the containment spray system component types within the scope of

license renewal include:

" spray shield, curbs, or mechanical components for directing flow

* pressure boundary

• maintains mechanical and structural integrity maintenance to prevent spatial interactions

that could cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

" conversion of fluid into spray

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and USAR Section 6.5.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.2 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

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In RAI 2.3.2.2-1 dated April 18, 2007, the staff requested that the applicant clarify if the pump

casings and valve bodies in the containment spray system are within the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in LRA drawing LR-WCGS-EN-12EN01 are included in

the component types listed in LRA Table 2.3.2-2. The applicant identified that LRA

Section 2.1.4.1 states that the active or passive component determinations are based on the

guidance provided in NEI-95-10, Appendix B. NEI-95-10, Appendix B, clarifies that for a pump

category, the structure, component, or commodity group that meets the criterion of

10 CFR 54.21 (a)(1)(i) is the pump casing. It also states that for a valve category, the structure,

component, or commodity group that meets the criterion of 10 CFR 54.21 (a)(1 )(i) is the valve

body. The applicant clarified that the pump casings and valve bodies that are subject to an

AMR have been included within the scope of license renewal as component types of pump and

valve in LRA Table 2.3.2-2.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.2-1 acceptable

because it clarified that all applicable pump casings and valve bodies of the containment spray

system are included within the scope of license renewal and are subject to an AMR. Therefore,

the staff's concern described in RAI 2.3.2.2-1 is resolved.

In RAI 2.3.2.2-2 dated April 18, 2007, the staff stated that USAR Section 6.2.2.1.2.2 describes

the mechanical components in the containment recirculation sumps. It states that a "baffle

arrangement of grating, coarse screening and fine screening that completely surrounds the

sumps to prevent floating debris and high density particles from entering." However, the staff

noted that these baffle arrangements and their intended functions are not listed in LRA

Table 2.3.2-2. The staff requested that the applicant justify the exclusion of these components

from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the associated components are

addressed in LRA Section 2.3.2.11 under the residual heat removal (RHR) system. The baffle

arrangements of screens for the containment recirculation sumps are included within the scope

of license renewal and are listed in LRA Table 2.3.2-11 under the component type of screen

with an intended function of filter. The applicant stated that each train of RHR and containment

spray uses the same containment recirculation sump. The WCGS drawings and equipment list

assign the screens to the RHR system.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.2-2 acceptable

because it clarified that all applicable screen baffle arrangements of the containment spray

system are within the scope of license renewal and are subject to an AMR. Therefore, the

staff's concern described in RAI 2.3.2.2-2 is resolved.

In RAI 2.3.2.2-3 dated April 18, 2007, the staff stated that USAR Section 6.2.5.2.2.2 indicates

that the containment spray system is one element of a complement of factors and systems that

ensure uniform mixing of hydrogen within the containment atmosphere following a LOCA.

However, the staff noted that LRA Section 2.3.2.2 does not mention this function. The staff

requested that the applicant clarify this inconsistency.

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In its response dated May 2, 2007, the applicant stated that a sentence will be added to the

system function description in LRA Section 2.3.2.2 to state that the containment spray system

cools containment air and causes it to drop to lower elevations causing some hydrogen mixing

to occur. By letter dated August 31, 2007, the applicant amended the LRA to included this

statement.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.2-3 acceptable

because it clarified that the system function in question was inadvertently omitted from the LRA.

The applicant amended the LRA accordingly. Therefore, the staff's concern described in

RAI 2.3.2.2-3 is resolved.

2.3.2.2.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the containment spray system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.3 Containment Integrated Leak Rate Test System

2.3.2.3.1 Summary of Technical Information in the Application

LRA Section 2.3.2.3 describes the containment integrated leak rate test system, which has a

containment integrity function accomplished by normally-installed blank flanges inboard and

outboard of all containment integrated leak rate test system penetrations (through the

containment wall) and by manual valves in lines branching from the volume between the

inboard and outboard blank flanges. The containment integrated leak rate test system is used

periodically to test containment leakage by pressurizing the containment building and

monitoring leakage to the atmosphere. The system consists of air compressors, filters, dryers,

instrumentation, piping, and valves for delivering compressed air to the containment to conduct

the test; however, the applicant has decided to use temporary air compressors as

pressurization sources for containment leak rate testing. The system containment penetrations

are isolated with blank flanges during normal plant operation and form part of the containment

boundary.

The containment integrated leak rate test system has safety-related components relied upon to

remain functional during and following DBEs.

LRA Table 2.3.2-3 identifies containment integrated leak rate test system component types

within the scope of license renewal and subject to an AMR:

* closure bolting

" piping

" valve

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The intended function of the containment integrated leak rate test system component types

within the scope of license renewal is to provide a pressure boundary.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3 and USAR Sections 6.2, 6.2.4, and 6.2.6.2 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.3 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.2.3-1 dated April 18, 2007, the staff requested that the applicant clarify if the valve

bodies in the containment integrated leak rate test system are within the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GP-M-12GP01

are included in the component types listed in LRA Table 2.3.2-3. The applicant clarified that

"valve body" was included within the category or commodity group of valve.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.3-1 acceptable

because it clarified that all applicable valve bodies in the containment integrated leak rate

testing system are within the scope of license renewal and are subject to an AMR. Therefore,

the staff's concern described in RAI 2.3.2.3-1 is resolved.

2.3.2.3.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the containment integrated leak rate test system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

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2.3.2.4 Decontamination System

2.3.2.4.1 Summary of Technical Information in the Application

LRA Section 2.3.2.4 describes the decontamination system, which (portions of the

decontamination system) provides containment isolation for reactor vessel head

decontamination penetration P-43. The system decontaminates removable components in the

hot machine shop in the auxiliary building and supplies water to the cask wash-down pit in the

fuel building. The decontamination system consists of a cask wash-down pit in the fuel building,

wash tanks, pumps, filters, spray booth, ultrasonic generator, turbulator, piping, and valves.

The decontamination system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the decontamination

system could prevent the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.2-4 identifies decontamination system component types within the scope of

license renewal and subject to an AMR:

* closure bolting

" piping

* valve

The intended functions of the decontamination system component types within the scope of

license renewal include:

* pressure boundary

• maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4 and USAR Section 12.3.1.1.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.4 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.2.4-1 dated April 18, 2007, the staff requested that the applicant clarify if the valve

bodies in the decontamination system are within the scope of license renewal.

2-49
In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-HD-M-12HDO1

are included in the component types listed in LRA Table 2.3.2-4. The applicant clarified that

"valve body" was included within the category or commodity group of valve.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.4-1 acceptable

because it clarified that all applicable valve bodies in the decontamination system are within the

scope of license renewal and are subject to an AMR. Therefore, the staff's concern described in

RAI 2.3.2.4-1 is resolved.

In RAI 2.3.2.4-2 dated April 18, 2007, the staff stated that LRA drawing

LR-WCGS-HD-M-12HDO1 shows 1-inch test connections (attached to 016-HBD-2 and

01 7-HBD-2) not highlighted in green. The staff noted that this would indicate that these 1-inch

test connections are not within the scope of license renewal and not subject to an AMR. The

two 2-inch pipes shown in the drawing have an intended function of structural integrity. The

staff requested that the applicant clarify whether the 1 -inch test connections have the same

intended function as the 2-inch pipes. If yes, the staff requested that the applicant justify their

exclusion from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the red highlighted 2-inch piping on

the boundary drawing is within the scope of license renewal for structural integrity. The

structural integrity intended function ends at a seismic anchor on the 2-inch piping. The 1-inch

test connection piping attaches to the 2-inch structural integrity piping and is unsupported,

independent of the structural integrity piping. The applicant clarified that the 1-inch test

connection piping does not perform a structural integrity intended function but only adds load

for the 2-inch structural integrity piping. This piping configuration has been analyzed in the

2-inch structural integrity piping support calculation.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.4-2 acceptable

because it explains that the 1 -inch test connections perform no structural integrity intended

function and; thus, are not within the scope of license renewal. Therefore, the staff's concern

described in RAI 2.3.2.4-2 is resolved.

2.3.2.4.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the decontamination system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.2.5 Liquid Radwaste System

2.3.2.5.1 Summary of Technical Information in the Application

LRA Section 2.3.2.5 describes the liquid radwaste system, which provides containment isolation

for penetrations P-26 (reactor coolant drain tank discharge) and P-44 (reactor coolant drain

tank vent). The liquid radwaste system collects, segregates, processes, and recycles both

reactor-grade and nonreactor-grade liquid wastes during plant power, refueling, and

maintenance operations. Specifically, it handles potentially radioactive floor and equipment

drains, laundry, and chemical waste. The processed liquid radwaste may be either stored for

reuse within the plant or discharged to the environment.

The liquid radwaste system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the liquid radwaste system

could prevent the satisfactory accomplishment of a safety-related function. In addition, the liquid

radwaste system performs functions that support EQ.

LRA Table 2.3.2-5 identifies liquid radwaste system component types within the scope of

license renewal and subject to an AMR:

* closure bolting

• flow element

* heat exchanger shell side

* heat exchanger tube side

* heater

* instrument bellows

* piping

* pump

* tank

* thermowell

* tubing

* valve

The intended functions of the liquid radwaste system component types within the scope of

license renewal include:

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.5 and USAR Section 11.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

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During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.5 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.2.5-1 dated April 3, 2007, the staff stated that the piping from the discharge of the

reactor makeup water transfer pump is highlighted in the license renewal drawings as a

nonsafety-related component affecting a safety-related component based on structural integrity

of the piping lines. The staff noted that it is unclear where the boundary ends in the piping run

going to the demineralized water degasifier. The staff requested that the applicant identify

where the piping physically transitions from piping that is within the scope of license renewal to

piping that is outside the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that license renewal boundary drawing

LR-WCGS-HB-M-12HB03 showing the liquid radwaste system components in question,

indicates that the piping and associated valves at coordinates A-5 and B-5 are within the scope

of license renewal based upon the 10 CFR 54.4(a)(2) criteria for spatial interaction (vs.

structural integrity consideration). The applicant further explained that the liquid radwaste

system piping line 211 -HCD-3 leaves the auxiliary building BLA 134 and enters the turbine

building BLA 431. Additionally, the applicant stated that-since the turbine building has no

safety-related components, the spatial interaction ends where the piping leaves the auxiliary

building.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.5-1 acceptable

because it adequately explains the reasons for terminating the scoping boundaries at the

various points in question. Therefore, the staff's concern described in RAI 2.3.2.5-1 is resolved.

2.3.2.5.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the liquid radwaste system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.2.6 Reactor Makeup Water System

2.3.2.6.1 Summary of Technical Information in the Application

LRA Section 2.3.2.6 describes the reactor makeup water system, which provides containment

isolation for penetration P-25. The reactor makeup water system stores deaerated water for use

upon demand within the plant and receives filtered, deaerated, demineralized water from the

demineralized water storage and transfer system. The reactor makeup water system consists of

one storage tank, two transfer pumps, a tank steam coil heater, piping, valves, and

instrumentation.

The reactor makeup water system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the reactor

makeup water system could prevent the satisfactory accomplishment of a safety-related

function. In addition, the reactor makeup water system performs functions that support EQ.

LRA Table 2.3.2-6 identifies the reactor makeup water system component types within the

scope of license renewal and subject to an AMR:

• closure bolting

* orifice

* piping

• pump

* tubing

• valve

The intended functions of the reactor makeup water system component types within the scope

of license renewal include:

* pressure boundary

• maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 and USAR Section 9.2.7 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2-53
The staff's review of LRA Section 2.3.2.6 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.2.6-1 dated May 6, 2007, the staff noted that in LRA Section 2.3.2.6, the applicant

states that the reactor makeup water system provides containment isolation for penetration

P-25. The staff requested that the applicant identify the components affected by the

containment isolation. In addition, the staff requested that the applicant clarify if these

components are within the scope of license renewal.

In its response dated June 1, 2007, the applicant stated that the components affected by the

containment isolation associated with penetration P-25 are the line segment and the associated

drain between the isolation valves. These components are shown as green on drawing

LR-WCGS-BLM-1 2BL01. The applicant clarified that the components affected by containment

isolation have a pressure boundary intended function and are within the scope of license

renewal based on the requirements of 10 CFR 54.4(a)(1 ). The applicant further stated that

other portions of the reactor water makeup system are within the scope of license renewal for

structural integrity and spatial interaction based on the requirements of 10 CFR 54.4(a)(2) and

are shown in red in the drawing.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.6-1 acceptable

because it clarified that the line segment and the associated drain between the isolation valves

are within the scope of license renewal. In addition, the applicant demonstrated that it

considered components that could be affected due to structural integrity and spatial interaction

as required by 10 CFR 54.4(a)(2). Therefore, the staff's concern described in RAI 2.3.2.6-1 is

resolved.

2.3.2.6.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the reactor makeup water system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.7 Containment Purge HVAC System

2.3.2.7.1 Summary of Technical Information in the Application

LRA Section 2.3.2.7 describes the containment purge HVAC system, which provides

containment isolation through two valves at each penetration for isolation function redundancy.

The common intake provides air and tornado isolation. The unit vent provides a common

monitored vent path and tornado protection, for various essential and nonessential HVAC

systems. The containment purge HVAC system ventilates the containment for habitability when

required and provides a vent path to equalize containment and atmospheric pressures. The

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containment mini-purge subsystem removes noble gas from the containment before and during

personnel access to the containment in modes 1, 2, 3 and 4 and equalizes containment internal

pressure with the external pressure in modes 1, 2, 3 and 4.

The containment purge HVAC system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the containment

purge HVAC system could prevent the satisfactory accomplishment of a safety-related function.

In addition, the containment purge HVAC system performs functions that support EQ.

LRA Table 2.3.2-7 identifies containment purge HVAC system component types within the

scope of license renewal and subject to an AMR:

* closure bolting

• damper

* ductwork

• flex connector

" heat exchanger tube side

" piping

* pump

* tubing

* valve

The intended functions of the containment purge HVAC system component types within the

scope of license renewal include:

• rated fire barrier to confine or retard a fire from spreading

" spray shield, curbs, or mechanical components for directing flow

* pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.7 and USAR Sections 7.3.2, 9.4.1.2.2, 9.4.3.1.1,

and 9.4.6.1.1 using the evaluation methodology described in SER Section 2.3 and the guidance

in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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The staff's review of LRA Section 2.3.2.7 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.2.7-1 dated April 18, 2007, the staff requested that the applicant clarify if the damper

housings, pump casings, and valve bodies in the containment purge HVAC system are within

the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GT-M-12GTO1

are included in the component types listed in LRA Table 2.3.2-7. The applicant clarified that the

pump casing and valve body are included within the categories or commodity groups of pump

and valve, respectively. It also clarified that the dampers are included within the valve category

and that the structure, component, or commodity group that meets the requirements of

10 CFR 54.21 (a)(1)(i) is the damper housing.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.7-1 acceptable

because it clarified that all applicable pump casings, valve bodies, and damper housings in the

containment purge HVAC system are within the scope of license renewal and are subject to an

AMR. Therefore, the staff's concern described in RAI 2.3.2.7-1 is resolved.

In RAI 2.3.2.7-2 dated April 18, 2007, the staff noted that LRA drawing

LR-WCGS-GT-M-12GTO1 does not highlight the safety-related and nonsafety-related interfaces

(i.e., green to red) as within the scope of license renewal. However, LRA Table 2.3.2-7 shows

structural integrity as an intended function for piping components in the system. The staff

requested that the applicant explain why this interface is not highlighted in the drawing. If this

interface is not within the scope of license renewal, the staff requested that the applicant

provides a justification for its exclusion.

In its response dated May 2, 2007, the applicant stated that there are seven locations on

drawing LR-WCGS-GT-M-1 2GTO1, at coordinates D-7, F-2, F-6, F-7, and G-6, that depict

green HVAC ducting attached to non-highlighted HVAC ducting. The applicant clarified that this

is correct as shown. The green HVAC ducting is safety-related Seismic Category 1 and is

self-supporting under accident conditions. The applicant also stated that the attached

nonsafety-related (non-highlighted) HVAC ducting does not provide additional support for the

safety-related ducting because sheet metal ducting does not have the strength capability and,

therefore, does not have a structural integrity intended function.

The applicant further stated that there are six locations on boundary drawing

LR-WCGS-GT-M-1 2GTO1, at coordinates A-5, A-6, C-4, C-5, C-6, and E-4, that depict green

HVAC piping attached to non-highlighted HVAC piping. The attached nonsafety-related piping

should have been shown in the drawing as structural integrity and highlighted in red. On

boundary drawing LR-WCGS-GT-M-12GTO1 the additional nonsafety-related piping that should

be highlighted in red is piping up to the 5NL boundary, which is the point where

nonsafety-related HVAC ducting begins. Valves V0017, V0018, V0019, V0020, V0021, and

V0022 and associated 3/4-inch piping have no supports on these sections that contribute to the

structural integrity intended function. The applicant clarified that an LRA amendment is not

necessary because the LRA already lists the component types in question in LRA

Tables 2.3.2-7 and 3.2.2-7.

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Based on its review, the staff finds the applicant's response to RAI 2.3.2.7-2 acceptable

because it clarified that these components are within the scope of license renewal, that this was

a highlighting error, and that license renewal drawing LR-WCGS-GT-M-1 2GTO1 will be revised

accordingly. Therefore, the staff's concern described in RAI 2.3.2.7-2 is resolved.

In RAI 2.3.2.7-3 dated April 18, 2007 the staff noted that LRA Table 2.3.2-7 lists pressure

boundary as an intended function for the component type of tubing. However, LRA drawing

LR-WCGS-GT-M-12GTO1 shows a 3/8-inch tubing located at heat exchanger No. 14 (at valves

V0220 and V0221) which suggests a leakage boundary (spatial) intended function. The staff

requested that the applicant clarify this discrepancy.

In its response dated May 2, 2007, the applicant agreed with the staff and stated that the

3/8-inch tubing and the associated valves V0220 and V0221, located at coordinate C-3, have

an intended function of leakage boundary (spatial). LRA Tables 2.3.2-7 and 3.2.2-7 will be

revised to include the intended function of leakage boundary (spatial) for the component type of

tubing. By letter dated August 31, 2007, the applicant amended the application to include these

changes.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.7-3 acceptable

because it clarified the discrepancies. In addition, the applicant adequately amended the LRA to

incorporate these changes. Therefore, the staff's concern described in RAI 2.3.2.7-3 is

resolved.

2.3.2.7.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the containment purge HVAC system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.8 Breathing Air System

2.3.2.8.1 Summary of Technical Information in the Application

LRA Section 2.3.2.8 describes the breathing air system, which provides containment isolation

for piping penetration P-98 and clean, purified breathing air for personnel using respiratory

protection and body cooling equipment in radiologically-controlled areas. The system consists

of compressors, receivers, filters, dryers, instrumentation, piping, and valves.

The breathing air system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SSCs in the breathing air system could

prevent the satisfactory accomplishment of a safety-related function.

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LRA Table 2.3.2-8 identifies breathing air system component types within the scope of license

renewal and subject to an AMR:

• closure bolting

* piping

• valve

The intended functions of the breathing air system component types within the scope of license

renewal include:

• pressure boundary

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.8 and USAR Section 9.5.10 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.8 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAls as discussed below.

In RAI 2.3.2.8-1 dated April 18, 2007, the staff requested that the applicant clarify if the valve

bodies in the breathing air system are within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-KB-M-12KBO1 are

included in the component types listed in LRA Table 2.3.2-8. The applicant clarified that the

valve bodies are included within the category or commodity group of valve.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.8-1 acceptable

because it clarified that all the applicable valve bodies in the breathing air system are within the

scope of license renewal and are subject to an AMR. Therefore, the staff's concern described in

RAI 2.3.2.8-1 is resolved.

In RAI 2.3.2.8-2 dated April 18, 2007, the staff stated that license renewal drawing

LR-WCGS-KB-M-1 2KBO1 shows 1-inch test connections 004-HCD-1 and 005-HCD-1 not

highlighted, indicating that these are not within the scope of license renewal and not subject to

an AMR. The staff noted that test connection 004-HCD-1 attaches to 002-HCD-2, and test

connection 005-HCD-1 attaches to 003-HCD-2. As indicated in LRA Table 2.3.2-8 and by the

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red highlight shown in the drawing, pipes 002-HCD-2 and 003-HCD-2 have an intended function

of structural integrity (connection attachment) in accordance with 10 CFR 54.4(a)(2). The staff

requested that the applicant explain why test connections 004-HCD-1 and 005-HCD-1 and their

attendant valves are not within the scope of license renewal and, therefore, subject to an AMR.

In its response dated May 2, 2007, the applicant stated that the red highlighted 2-inch piping on

the boundary drawing is within the scope of license renewal for structural integrity. The

structural integrity intended function ends at a seismic anchor on the 2-inch piping. The 1-inch

test connection piping attaches to the 2-inch structural integrity piping and is unsupported

independent of the structural integrity piping. The applicant clarified that the 1-inch test

connection piping does not perform a structural integrity intended function but only adds load

for the 2-inch structural integrity piping. This piping configuration has been analyzed in the

2-inch piping support calculation.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.8-2 acceptable

because it clarified that the 1-inch test connections perform no structural integrity intended

function. Thus, these 1-inch test connections should not be within the scope of license renewal

and should not be subject to an AMR. Therefore, the staff's concern described in RAI 2.3.2.8-2

is resolved.

2.3.2.8.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the breathing air system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.2.9 Hydrogen Control System

2.3.2.9.1 Summary of Technical Information in the Application

LRA Section 2.3.2.9 describes the hydrogen control system, which maintains the containment

atmosphere hydrogen concentration less than 4.0 percent by volume following a LOCA with two

redundant thermal hydrogen recombiners located in containment. A sampling subsystem

monitors the containment atmosphere and draws samples. A purge path provides a backup in

the unlikely event the recombiners are unable to maintain the containment atmosphere

hydrogen concentration of less than 4 percent by volume. The containment design assures

adequate mixing to prevent formation of hydrogen pockets without reliance on mixing fans.

Containment isolation is provided by two valves each at penetrations P-56, P-65, P-97, P- 99,

and P-101. The system consists of the electric hydrogen recombiners, the hydrogen analyzers,

the hydrogen purge exhaust path, and the hydrogen mixing fans. The electric recombiners,

located in containment, heat the containment atmosphere causing hydrogen to recombine

thermally with oxygen. Hydrogen monitoring is performed by hydrogen analyzers and sample

lines with their containment isolation valves. The hydrogen purge exhaust path consists of one

penetration through which the containment atmosphere is vented and filtered. Hydrogen mixing

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fans draw air from each steam generator compartment and discharge it toward the upper

regions of the containment.

The hydrogen control system has safety-related components relied upon to remain functional

during and following DBEs. In addition, the hydrogen control system performs functions that

support EQ.

LRA Table 2.3.2-9 identifies hydrogen control system component types within the scope of

license renewal and subject to an AMR:

* closure bolting

* orifice

* piping

* recombiner

* sample vessel

* tubing

* valve

The intended functions of the hydrogen control system component types within the scope of

license renewal include:

* spray shield, curbs, or mechanical components for directing flow

* pressure boundary

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.9 and USAR Section 6.2.5 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.2.9 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.2.9-1 dated April 18, 2007, the staff requested that the applicant clarify if the valve

bodies or recombiner housings in the hydrogen control system are within the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GS-M-12GS01

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are included in the component types listed in LRA Table 2.3.2-9. The applicant clarified that the

valve bodies are included within the category or commodity group of valve.

The applicant also stated that USAR Section 6.2.5.2.2.1 indicates that the function of the

hydrogen recombiners is based on passive natural circulation of the air flow. The applicant

clarified that in accordance with the guidance provided in NEI 95-10, Appendix B, item 66, the

portions of the recombiners, including the enclosure that have the passive intended function of

maintaining natural circulation flow, were included within the scope of license renewal and listed

in LRA Table 2.3.2-9 under the component type of recombiner, with an intended function of

direct flow.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.9-1 acceptable

because it clarified that all applicable valve bodies and recombiner housings associated with the

hydrogen control system are within the scope of license renewal and are subject to an AMR.

Therefore, the staff's concern described in RAI 2.3.2.9-1 is resolved.

In RAI 2.3.2.9-2 dated April 18, 2007, the staff stated that USAR 6.2.5.2.2.2 states that one of

the hydrogen control system functions is to uniformly mix the hydrogen within the containment

atmosphere following a LOCA. However, the staff noted this is not addressed in the system

description of LRA Section 2.3.2.9. Furthermore, there is no mention of this uniform mixing of

hydrogen function in LRA Section 2.3.3.5, "Containment Cooling System." The staff requested

that the applicant clarify these inconsistencies.

In its response dated May 2, 2007, the applicant noted that USAR Section 6.2.5.2.2.2 and LRA

Section 2.3.2.9 state that the containment design is such that mixing, adequate to prevent

formation of hydrogen pockets, is assured without reliance of the hydrogen control system

mixing fans. The applicant stated that a sentence will be added to the system function

description in LRA Section 2.3.3.5 stating that some hydrogen mixing will occur as the

containment air coolers take suction from above the operating floor level and discharge to the

lower levels of the containment. By letter dated August 31, 2007, the applicant amended the

LRA to incorporate this change.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.9-2 acceptable. Upon

further review the staff agrees with the applicant and finds that the comprehensive wording of

LRA Section 2.3.2.9 captures the containment uniform mixing hydrogen function. In addition,

the applicant has adequately amended LRA Section 2.3.3.5 to include a uniform mixing

hydrogen function in the system description. Therefore, the staff's concerns described in

RAI 2.3.2.9-2 is resolved.

In RAI 2.3.2.9-3 dated April 18, 2007, the staff stated that LRA Table 2.3.2-9 indicates that

portions of the piping subject to an AMR have a structural integrity (attached) intended function.

However, the staff noted that the system function described in LRA Section 2.3.2.9 does not

indicate that portions of the hydrogen control system are within the scope of license renewal in

accordance with the 10 CFR 54.4(a)(2) criteria. The staff requested that the applicant clarify

this inconsistency.

In its response dated May 2, 2007, the applicant stated that the scoping results of the hydrogen

control system will be amended to clarify that portions of the hydrogen control system are within

the scope of license renewal as nonsafety-related component affecting safety-related

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components based on the criterion of 10 CFR 54.4(a)(2). By letter dated August 31, 2007, the

applicant amended LRA Section 2.3.2.9 to include this change.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.9-3 acceptable

because it adequately amended the scoping results of the hydrogen control system. Therefore,

the staff's concern described in RAI 2.3.2.9-3 is resolved.

In RAI 2.3.2.9-4 dated April 18, 2007, the staff noted that LRA drawing

LR-WCGS-GS-M-12GS01 appears to have at least one piping segment that has a structural

integrity (attached) intended function pursuant to 10 CFR 54.4(a)(2). For example, pipe

026-HBO-6, located at coordinate F-4 downstream of the seismic flag at butterfly valve V021,

appears to be a carbon steel pipe with a structural integrity (attached) intended function. This

would be in agreement with LRA Table 2.3.2.9. However, there are multiple occurrences of

what appears to be stainless steel test connections beyond the seismic anchor point identified

on the drawing. The staff noted that in most cases it is not obvious whether the test connection

is stainless steel pipe or tubing. At coordinates B-3 and B-7, there is stainless steel tubing

connected beyond the seismic anchor valves V01 09 and V01 0, which appear to be

safety-related to nonsafety-related interfaces. The staff requested that the applicant clarify

whether the component type tubing should also include a structural integrity (attachment)

intended function. In addition, the staff requested that the applicant clarify similar

inconsistencies in LRA Section 2.3.2.9 and its drawing.

In its response dated May 2, 2007, the applicant stated that the piping segment 026-HBO-6,

located at coordinate F-4 downstream of the butterfly valve V021, has an intended function of

structural integrity (attached). The drawing should have shown the correct intended function for

this piping segment. However, the applicant clarified that LRA Table 2.3.2-9 will not be affected

as a result of this change.

The applicant also stated that the piping segment downstream of valve V0041, located at

coordinate F-4, has no function of structural integrity (attached). Therefore, the segment is not

highlighted. The applicant stated that most of the test connection piping segment downstream

of the isolation valves with intended function of structural integrity (attached) are stainless steel

pipe Class HCD. However, two segments, at coordinates B-3 and B-7 downstream of the valves

V01 09 and V01 08, are stainless steel tubing. The applicant stated that LRA Tables 2.3.2-9 and

3.2.2.-9 will be revised to include the function of structural integrity (attached) for component

type of tubing. By letter dated August 31, 2007, the applicant amended the LRA to include

these changes.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.9-4 acceptable

because it clarified that the missing intended function for piping segment 026-HBO-6 was a

drawing highlighting error. In addition, the applicant amended the LRA to include the intended

function of structural integrity (attached) for the component type of stainless steel tubing.

Therefore, the staff's concern described in RAI 2.3.2.9-4 is resolved.

2.3.2.9.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

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components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the hydrogen control system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.2.10 High Pressure Coolant Injection System

2.3.2.10.1 Summary of Technical Information in the Application

LRA Section 2.3.2.10 describes the high pressure coolant injection system, which provides core

cooling, inventory control, and reactivity control to the RCS in DBEs. The high pressure coolant

injection system provides containment isolation for penetrations P-45, P-48, P-49, P-58, P-87,

P-88 and P-92. The high pressure coolant injection system includes the borated refueling water

storage and the accumulator safety injection systems. The high pressure coolant injection

system is a portion of the emergency core cooling system (ECCS) and consists of the safety

injection pumps, boron injection tank, piping, valves, and instrumentation. The borated refueling

water storage system provides treated borated water for the ECCS and the containment spray

system during DBEs and refueling operations. The borated refueling water storage system

consists of the RWST, piping, valves, and instrumentation. The accumulator safety injection

system, which injects treated borated water into the RCS by pressurized nitrogen gas, consists

of four tanks (accumulators) containing borated water pressurized with nitrogen, piping, valves,

and instrumentation.

The high pressure coolant injection system has safety-related components relied upon to

remain functional during and following DBEs. The failure of nonsafety-related SSCs in the high

pressure coolant injection system could prevent the satisfactory accomplishment of a

safety-related function. In addition, the high pressure coolant injection system performs

functions that support fire protection and EQ.

LRA Table 2.3.2-10 identifies high pressure coolant injection system component types within

the scope of license renewal and subject to an AMR:

* accumulator

" Class 1 piping (less than or equal to 4 inches)

* closure bolting

* filter

" flow element

* heat exchanger shell side

" heat exchanger tube side

" instrument bellows

* orifice

• piping

* pump

* sight gauge

" tank

• thermowell

* tubing

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0 valve

The intended functions of the high pressure coolant injection system component types within

the scope of license renewal include:

* filtration

* heat transfer

• pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.10 and USAR Section 6.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff finds that large portions of the high pressure coolant injection system, especially the

sections that are connected to the RCS, are within the scope of license renewal as required by

10 CFR 54.4(a)(1), since the system performs important safety functions needed to mitigate

certain DBAs. Also, the nonsafety-related components are within the scope of license renewal

since they could affect safety-related components for structural integrity and spatial interaction.

In addition, the high pressure coolant injection system supports fire protection and EQ

requirements, which are considered within the scope of license renewal as required by

10 CFR 54.4(a)(3).

The staff's review of LRA Section 2.3.2.10 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.2.10-1 dated May 6, 2007, the staff noted that license renewal drawing

LR-WCGS-EM-M-12EM01 shows the RWST within the scope of license renewal. However, the

piping and components EBNO1 A, EBNO1 B and EBNO1 C, which are surrounded by this tank,

are not. The staff requested that the applicant justify why these components are not within the

scope of license renewal in accordance with the requirements of 10 CFR 54.4(a)(2).

In its response dated June 1, 2007, the applicant noted that USAR 6.3.2.2 states that the heat

exchangers (i.e., steam heating coils EBNO1A, EBNO1 B, and EBNO1C) are wrapped around the

exterior shell of the tank. The steam heating coils are under the insulation that is also wrapped

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around the outside of the tank. The applicant clarified that steam heating coils are not enclosed

internally in the tank (enclosed by insulation). The applicant clarified that the nonsafety-related

steam heating coils attached to the exterior shell of the tank may have spatial interactions with

the safety-related tank and its associated instrumentation in an event of heating coil leak. The

applicant stated that the steam heating coils will be included within the scope of license renewal

as required by 10 CFR 54.4(a)(2). The applicant also stated that drawing

LR-WCGS-EM-M-1 2BNO1 will be revised to show the steam heating coils EBNO1 A, EBNO1 B,

and EBNO1 C and their associated piping within the scope of license renewal.

By letter dated August 31, 2007, the applicant amended LRA Table 2.3.2-10 to include the

steam heating coils under the component type of heat exchanger tube side with an intended

function of leakage boundary. In addition, LRA Table 3.2.2-10 was amended to include the

aging evaluation for the component type of heat exchanger tube side.

Based on its review, the staff finds the applicant's response to RAI 2.3.2.10-1 acceptable

because the applicant adequately included these heating coils within the scope of license

renewal. Therefore, the staff's concern described in RAI 2.3.2.10-1 is resolved.

2.3.2.10.3 Conclusion

The staff reviewed the LRA as amended, USAR, drawings, and RAI response to determine

whether the applicant failed to identify any SSCs within the scope of license renewal. The staff

finds no such omissions. In addition, the staff's review determined whether the applicant failed

to identify any components subject to an AMR. The staff finds no such omissions. On the basis

of its review, the staff concludes that there is reasonable assurance that the applicant has

adequately identified the high pressure coolant injection system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.2.11 Residual Heat Removal System

2.3.2.11.1 Summary of Technical Information in the Application

LRA Section 2.3.2.11 describes the RHR system, which provides borated water for RCS

makeup in LOCA conditions and for decay heat removal in post-accident conditions.

Containment isolation valves, suction line guard pipes, and valve encapsulations maintain

containment integrity in single-failure scenarios. The system is also used for shutdown cooling

in nonaccident conditions to remove decay heat. The system consists of two redundant trains,

each of which has a containment recirculation sump, RHR pump, heat exchanger, valves, and

piping. Suction paths are provided from the RWST for safety injection flow and from the

containment recirculation sumps for long-term post-LOCA decay heat removal. Each train has a

discharge path to both hot and cold legs.

The RHR system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related SSCs in the RHR system could prevent the

satisfactory accomplishment of a safety-related function. In addition, the RHR system performs

functions that support fire protection and EQ.

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LRA Table 2.3.2-11 identifies RHR system component types within the scope of license renewal

and subject to an AMR:

* Class 1 piping (less than or equal to 4 inches)

" closure bolting

* expansion joint

" flow element

" heat exchanger shell side

* heat exchanger tube side

* insulation

* orifice

* piping

* pump

* screen

* spacer ring

* tank

* thermowell

* tubing

* valve

* vortex breaker

The intended functions of the RHR system component types within the scope of license

renewal include:

* flow restriction

* spray shield, curbs, or mechanical components for directing flow

* filtration

" heat transfer

* heat loss control

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

• structural and/or functional support to safety-related components

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.2.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.11 and USAR Sections 5.4.7 and 6.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

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the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.2.11.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any components subject to an

AMR. The staff finds no such omissions. On the basis of its review, the staff concludes that

there is reasonable assurance that the applicant has adequately identified the RHR system

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3 Auxiliary Systems

In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems that are subject

to an AMR for license renewal.

The applicant described the supporting SCs of the auxiliary systems in the following LRA

sections:

* 2.3.3.1

" 2.3.3.2

* 2.3.3.3

" 2.3.3.4

* 2.3.3.5

" 2.3.3.6

* 2.3.3.7

* 2.3.3.8

* 2.3.3.9

* 2.3.3.10

* 2.3.3.11

* 2.3.3.12

" 2.3.3.13

" 2.3.3.14

* 2.3.3.15

* 2.3.3.16

• 2.3.3.17

* 2.3.3.18

fuel handling - fuel storage and handling system

fuel pool cooling and cleanup system

essential service water

component cooling water system

containment cooling system

compressed air system

chemical and volume control system

auxiliary building HVAC system

control building HVAC system

fuel building HVAC system

essential service water pumphouse building HVAC system

miscellaneous buildings HVAC system

diesel generator building HVAC system

fire protection system

emergency diesel engine fuel oil storage and transfer system

emergency diesel engine system

floor and equipment drains system

oily waste system

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0 2.3.3.19 cranes, hoists, and elevators system

• 2.3.3.20 turbine building HVAC system

* 2.3.3.21 systems within the scope of license renewal based only on the criterion of

10 CFR 54.4(a)(2)

The staff's review findings regarding LRA Sections 2.3.3.1 - 2.3.3.21 are presented in SER

Sections 2.3.3.1 - 2.3.3.21, respectively.

2.3.3.1 Fuel Handling - Fuel Storage and Handling System

2.3.3.1.1 Summary of Technical Information in the Application

LRA Section 2.3.3.1 describes the fuel handling - fuel storage and handling system, which

provides onsite storage of new and spent fuel assemblies to maintain a sub-critical

arrangement under normal and postulated accident conditions. The fuel handling system allows

for manipulation of the fuel during receipt, inspection, storage, refueling, and ship-out. Reactor

servicing consists of those operations necessary to support refueling, maintenance, and

inservice inspection. The system consists of machines, devices, cranes, elevators, transfer

systems, fixtures, tooling, and storage racks. Crane rails and their supports are evaluated with

their appropriate structures.

The fuel handling - fuel storage and handling system has safety-related components relied

upon to remain functional during and following DBEs. The failure of nonsafety-related SSCs in

the fuel handling - fuel storage and handling system could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.3-1 identifies fuel handling - fuel storage and handling system component types

within the scope of license renewal and subject to an AMR:

" crane

" fuel handling equipment

* neutron absorbers (Boral)

" new fuel racks

" spent fuel racks

The intended functions of the fuel handling - fuel storage and handling system component types

within the scope of license renewal include:

" absorb neutrons

" missile barrier

* pressure boundary

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

" structural and/or functional support to safety-related components

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2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1 and USAR Sections 9.1.1, 9.1.2, 9.1.4, 15.7.4, and

15.7.5 using the evaluation methodology described in SER Section 2.3 and the guidance in

SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.1 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.1-1 dated April 3, 2007, the staff stated that a license renewal drawing depicts the

layout of the spent fuel pool, cask loading pit, and the fuel transfer canal. Additionally, these

three areas are shown to be adjacent and separated by walls, except in two slots that are

sealed off by spent fuel gates. The staff noted that USAR Section 9.1.2.2, describes the

leaktight gates in the spent fuel pool and their functions which includes allowing drainage of the

cask loading pit and fuel transfer canal while maintaining the proper water inventory in the spent

fuel pool. The staff noted that the USAR states that an acceptable minimum water level will be

maintained in the event of loss of integrity of the gate while either the cask loading pit or fuel

transfer canal is drained. Additionally, the staff noted that LRA Section 2.3.3.1 does not include

the spent fuel gates within the scope of license renewal. As the spent fuel gates appear to be

required as a pressure boundary to maintain correct water level above the spent fuel when the

cask loading pit and the fuel transfer canal are drained, the staff requested that the applicant

justify the exclusion of the spent fuel gates and their sealing mechanisms from the scope of

license renewal.

In its response dated May 2, 2007, the applicant stated that the WCGS Engineering

Department has verified that simultaneous loss of both spent fuel gates, while both adjacent

fuel-handling areas are drained, would not result in draining the pool down to an unacceptable

limit. Further, the applicant explained that this evaluation conforms with the Regulatory Position

C.6 described in RG 1.13, Revision 1, which states that systems for maintaining water quantity

should be designed so that any mal-operation or failure of such systems will not cause fuel to

be uncovered. The applicant explained that USAR Table 9.1-3, paragraph 6, confirms that the

WCGS design complies with this guidance and that the spent fuel gates are not required as a

pressure boundary component to maintain correct water level above the spent fuel when the

cask loading pit and the fuel transfer canal are drained, and aging management of the gates

and seals is not required.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.1-1 acceptable

because it provided clarification to the statement in the USAR that adequately addresses the

question regarding the spent fuel gates. Therefore, the staff's concern described in

RAI 2.3.3.1-1 is resolved.

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2.3.3.1.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the fuel handling - fuel storage and handling system components that are within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.3.3.2 Fuel Pool Cooling and Cleanup System

2.3.3.2.1 Summary of Technical Information in the Application

LRA Section 2.3.3.2 describes the fuel pool cooling and cleanup (FPCC) system, which

maintains the fuel storage pool water temperature below prescribed limits by removing decay

heat generated by stored spent fuel assemblies. Heat is transferred from the fuel storage pool

water to the component cooling water system (CCWS). If system cooling is lost, two redundant

feeds from the emergency service water system can provide water directly to the spent fuel

pool to maintain level (pool water boils off) and cool the spent fuel assemblies. FPCC system

components for containment isolation include the fuel transfer tube and three piping

penetrations for the refueling pool supply, suction, and skimmer. The FPCC system removes

decay heat from the stored spent fuel and maintains purity and optical clarity of the water in the

spent fuel pool, the fuel transfer canal, and the refueling canal. The system consists of a fuel

pool cooling loop with pumps, heat exchangers, strainers, piping, and valves, a fuel pool

cleanup loop with pumps, filters, demineralizer, strainers, piping, and valves, and a fuel pool

surface skimmer loop with skimmers, pump, piping, and valves.

The FPCC system has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related SSCs in the FPCC system could prevent the

satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-2 identifies FPCC system component types within the scope of license renewal

and subject to an AMR:

* closure bolting

* flow element

* expansion joint bellows

* heat exchanger shell side

• heat exchanger tube side

• penetrations mechanical

* piping

• pump

* thermowell

* tubing

• valve

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The intended functions of the FPCC system component types within the scope of license

renewal include:

• heat transfer

• pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

" maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2 and USAR Section 9.1.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.2 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.2-1 dated April 3, 2007, the staff stated that a normally closed valve (V0995) at the

spent fuel pool fuel end of the fuel transfer tube is shown on a license renewal drawing. Further,

the staff noted that the fuel transfer tube is designated as being safety-related and within the

scope of license renewal for providing a pressure boundary. However, the staff stated that the

valve is not listed as being within the scope of license renewal. The staff requested that the

applicant justify the exclusion of this valve from the scope of license renewal as it provides

structural support for the fuel transfer tube and meets the criterion of 10 CFR 54.4(a)(2).

In its response dated May 2, 2007, the applicant stated that the nonsafety-related valve V0995,

which is attached to the fuel transfer tube in the fuel building, does not provide structural

integrity to the fuel transfer tube. The applicant further stated that a floating saddle provides

support for the fuel transfer tube and for valve V0995, which is attached to the end of the fuel

transfer tube. Therefore, valve V0995 does not provide structural integrity to attached

safety-related equipment and has no intended functions in accordance with 10 CFR 54.4(a).

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-1 acceptable

because it adequately explained the structural support mechanism and that the saddle is

designed to support the fuel transfer tube, not the valve V0995. Therefore, the staff's concern

described in RAI 2.3.3.2-1 is resolved.

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In RAI 2.3.3.2-2 dated April 3, 2007, the staff stated that removable spools with spacer rings

installed are shown on a license renewal drawing. The staff noted that the spacer rings are

replacements for startup strainers. Additionally, the staff noted that although the piping lines in

which the spacer rings are installed are highlighted in the drawing as being within the scope of

license renewal, the spacer rings are not listed in LRA Table 2.3.3-2. The staff requested that

the applicant justify the exclusion of these components from LRA Table 2.3.3-2.

In its response dated May 2, 2007, the applicant stated that spacer rings ECSS001 SR and

ECSS002SR were incorrectly excluded from the scope of license renewal. The applicant further

explained that the spacer rings will be included within the scope of license renewal and will be

given an intended function of pressure boundary, which is the intended function of their

surrounding piping. By letter dated August 31, 2007, the applicant amended the LRA to include

the component type spacer ring with an intended function of pressure boundary in LRA

Tables 2.3.3-2 and 3.3.2-2.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-2 acceptable

because it adequately explained that the spacer rings were inadvertently omitted from the

scope of license renewal. Because the spacer rings have an intended function pursuant to

10 CFR 54.4(a) the applicant has made the appropriate changes in the LRA. Therefore, the

staff's concern described in RAI 2.3.3.2-2 is resolved.

In RAI 2.3.3.2-3 dated April 3, 2007, the staff stated that strainers in the suction piping from the

spent fuel pool to the spent fuel pool cooling pumps are shown on a license renewal drawing.

Additionally, the staff noted that although the strainers are installed on lines that are highlighted

in the drawing as within the scope of license renewal in accordance with 10 CFR 54.4(a)(1), the

strainers are not highlighted. The staff requested that the applicant justify the exclusion of the

strainers from the scope of license renewal even though failure of the strainers could cause

damage to the pumps or valves and could prevent performance of the FPCC system intended

functions.

In its response dated May 2, 2007, the applicant stated that strainers ECIS0001 and ECIS0002

must maintain their structure to prevent the potential damage of safety-related equipment. The

applicant further explained that the strainers will be included within the scope of license

renewal. By letter dated August 31 2007, the applicant amended the LRA to include the

component type strainer with an intended function of nonsafety-related structural support in

LRA Tables 2.3.3-2 and 3.3.2-2.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.2-3 acceptable

because the strainers were inadvertently omitted from the scope of license renewal. In addition,

the applicant has made the appropriate changes in the LRA. Therefore, the staff's concern

described in RAI 2.3.3.2-3 is resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA as amended, USAR, drawings, and the RAI responses to determine

whether the applicant failed to identify any SSCs within the scope of license renewal. The staff

finds no such omissions. In addition, the staff's review determined whether the applicant failed

to identify any components subject to an AMR. The staff finds no such omissions. On the basis

of its review, the staff concludes that there is reasonable assurance that the applicant has

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adequately identified the FPCC system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.3 Essential Service Water

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 describes the essential service water system (ESWS), which provides

filtered cooling water to transfer heat from plant components requiring cooling for safe reactor

shutdown to the ultimate heat sink (UHS). The ESWS provides emergency makeup from the

UHS to the fuel storage pool and CCWSs and is the backup water supply to the auxiliary

feedwater system when CST water is unavailable. The ESWS also provides containment

isolation for four system piping penetrations. The ESWS is an open-cycle system with two

separate 100-percent capacity trains of traveling screens, pumps, pump pre-lube storage tanks,

self-cleaning strainers, piping, valves, and instrumentation. One pump supplies cooling water to

each flow path. Each flow path is fed from the UHS intake channel via separated forebays in

the ESW pump house. Each train of the ESWS provides cooling water to the associated train of

safety-related components. The heated water is discharged to the UHS via the ESWS

discharge structure. Each system train connects with the nonsafety-related service water

system. There are two motor-operated isolation valves for each crosstie header where it

connects to the service water system.

The ESWS has safety-related components relied upon to remain functional during and following

DBEs. The failure of nonsafety-related SSCs in the ESWS could prevent the satisfactory

accomplishment of a safety-related function. In addition, the ESWS performs functions that

support fire protection and EQ.

LRA Table 2.3.3-3 identifies ESWS component types within the scope of license renewal and

subject to an AMR:

* closure bolting

* filter

" flow element

" orifice

* piping

" pump

* strainer

* strainer element

* tank

* thermowell

* tubing

* valve

The intended functions of the ESWS component types within the scope of license renewal

include:

• flow restriction

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0 filtration

" pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

* conversion of fluid into spray

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3 and USAR Sections 1.2.9.4.2, 9.2.1.2, and 9.4.8 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.3.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

ESWS components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.4 Component Cooling Water System

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 describes the CCWS, which provides cooling water to transfer heat from

engineered safety feature components requiring cooling for safe reactor shutdown to the

ESWS. The CCWS also provides cooling water to the safety-related spent fuel pool heat

exchangers and transfers sufficient heat energy to the ESWS for freeze protection for the

ESWS intake structure. Frazil ice formation is inhibited by a warming line branching from each

ESW return line supplying heated water to the intake structure. The CCWS also provides

containment isolation for three system pipings penetrating containment barriers. The CCWS

provides cooling water to engineered safety feature systems following DBEs and transfers the

heat to the ESWS. The CCWS also provides cooling water to the safety-related spent fuel pool

heat exchangers and transfers sufficient heat energy to the ESWS to protect the ESWS inlet

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trash racks from blockage by frazil ice. The CCWS consists of four circulating pumps, two heat

exchangers, two surge tanks, one chemical addition tank, piping, valves, and instrumentation.

The CCWS has safety-related components relied upon to remain functional during and

following DBEs. The failure of nonsafety-related SSCs in the CCWS could prevent the

satisfactory accomplishment of a safety-related function. In addition, the CCWS performs

functions that support fire protection, SBO, and EQ.

LRA Table 2.3.3-4 identifies CCWS component types within the scope of license renewal and

subject to an AMR:

" closure bolting

" flow element

" heat exchanger shell side

* heat exchanger tube side

" piping

" pump

" sight gauge

* tank

* thermowell

" tubing

* valve

The intended functions of the CCWS component types within the scope of license renewal

include:

* heat transfer

" pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4 and USAR Section 9.2.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.4.3 Conclusion

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The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

CCWS components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.5 Containment Cooling System

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 describes the containment cooling system, which with the containment

spray system removes decay heat from the containment atmosphere following a design basis

LOCA or main steam line break inside the containment to keep the containment below the

design pressure. Heat removed from the containment atmosphere by the containment coolers

and transferred to the ESWS provides sufficient heat energy to protect the ESWS inlet trash

racks from blockage by frazil ice. Freeze protection for the ESWS intake structure is by a

warming line which branches from each ESW return line. The containment cooling system,

which also provides containment isolation, consists of four containment coolers, cooling water

piping, and valves.

The containment cooling system has safety-related components relied upon to remain

functional during and following DBEs. In addition, the containment cooling system performs

functions that support fire protection and EQ.

LRA Table 2.3.3-5 identifies containment cooling system component types within the scope of

license renewal and subject to an AMR:

" closure bolting

" heat exchanger shell side

" heat exchanger tube side

" instrument bellows

" piping

" thermowell

" tubing

" valve

The intended functions of the containment cooling system component types within the scope of

license renewal include:

* heat transfer

* pressure boundary

" structural and/or functional support to safety-related components

2.3.3.5.2 Staff Evaluation

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The staff reviewed LRA Section 2.3.3.5 and USAR Sections 6.2.2.2, 9.2.1.2.2.3, and 9.4.6

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.5 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.5-1 dated April 3, 2007, the staff stated that the containment coolers shown on a

license renewal drawing are within the scope of license renewal because they are

safety-related. Additionally, the staff noted that LRA Section 2.3.3.5 states that the containment

cooling system, in conjunction with the containment spray system, removes sufficient energy

and subsequent decay heat from the containment atmosphere following a design basis LOCA

or a main steam line break inside the containment to maintain it below the design pressure.

However, the staff noted that each of the containment coolers has drain lines attached to the

cooler shell (air side) of the heat exchanger. Each of the drain lines pass through a drain trap

and are not shown to be within the scope of license renewal, although they appear to support

the system intended function of the containment coolers. The staff requested that the applicant

justify the exclusion of the drain lines from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the containment cooling system

design is described in USAR Section 6.2.2.2.3 which identifies adequate redundancy and that

no single failure will compromise the system's safety functions. The applicant further stated that

the three drain lines associated with each containment cooler are nonsafety-related and

non-seismic and therefore cannot be credited to remain functional after a design basis accident.

Additionally the applicant identified that the drain lines are sized to prevent flooding of cooling

coils from condensation of the air-water vapor mixture and that the volume of water condensed

by the cooling coils during a LOCA or main steam line break in containment does not hinder the

cooling coil's ability to perform their intended function. The applicant also described the

containment cooling unit's physical dimensions which supported its response.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-1 acceptable

because it adequately explained that the design of the containment cooling coil drain lines do

not perform any intended function pursuant to 10 CFR 54.4(a) and that their failure does not

affect the containment cooling system's ability to perform its intended function. Therefore, the

staff's concern described in RAI 2.3.3.5-1 is resolved.

In RAI 2.3.3.5-2 dated April 3, 2007, the staff noted that LRA Section 2.3.3.5 states that

portions of the system support EQ in accordance with 10 CFR 54.4(a)(3). The staff also noted

that although the containment coolers are within the scope of license renewal, the discharge

ductwork from the containment coolers are excluded from the scope of license renewal. The

staff believes that during normal operation the containment cooler discharge ductwork supplies

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cooled air to areas that contain safety-related equipment such as instrumentation adjacent to

the steam generator compartments. The staff requested that the applicant justify the exclusion

of the containment cooler discharge ductwork from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the containment cooler discharge

ductwork is not credited in the USAR with a safety-related function and that the discharge

ductwork is designed to remain functional during normal operation only. The applicant further

explained that during accident conditions, the discharge ductwork is designed to automatically

detach from the containment cooling fan through actuation of fusible link. Additionally, the

applicant described the containment cooler's discharge ductwork's design specifications that

confirmed the information in the USAR. In its response the applicant identified that containment

temperatures are monitored and actuate alarms in the control room and that any failure of the

discharge duct that resulted in elevated containment temperatures would be easily detected

through technical specification surveillance.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.5-2 acceptable

because it adequately explained that the containment cooler's discharge ductwork is not

credited with supporting EQ requirements and that temperature monitoring is performed

through technical specification surveillance. Therefore, the staff's concern described in

RAI 2.3.3.5-2 is resolved.

2.3.3.5.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the containment cooling system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.6 Compressed Air System

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 describes the compressed air system, which provides a safety-related

backup supply of compressed nitrogen from the service gas system for operation of the

auxiliary feedwater control valves and main steam atmospheric relief valves in case

compressed air system instrument air is lost. Portions of the compressed air system provide

containment isolation for instrument air piping penetration P-63 and service air penetration

P-30. The compressed air system supplies both instrument air and service air for plant use. The

system provides a continuous supply of filtered, oil-free air to a common header that branches

into the instrument air and service air subsystems. Service air is distributed throughout the plant

for normal maintenance services. Instrument air first passes through a drying and filtering train

prior to delivery to plant instrumentation and control components and containment air lock

operations.

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The compressed air system also provides a backup supply of compressed gas for the main

feedwater control valves and a safety-related backup air supply for the auxiliary feedwater

control valves and main steam atmospheric relief valves. The backup compressed gas

accumulators for the main feedwater control valves, auxiliary feedwater control valves, and

main steam atmospheric relief valves are filled and pressurized with nitrogen from the service

gas system. The normal source of air for operation of these components is instrument air. The

compressed air system is nonsafety-related except for the safety-related backup compressed

gas accumulators, containment penetration piping, and containment personnel air lock air

piping. The system consists of four compressors, receivers, filters, desiccant dryers,

instrumentation, piping, and valves.

The compressed air system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the system could prevent

the satisfactory accomplishment of a safety-related function. In addition, the compressed air

system performs functions that support fire protection, SBO, and EQ.

LRA Table 2.3.3-6 identifies compressed air system component types within the scope of

license renewal and subject to an AMR:

• accumulator

• closure bolting

•* orifice

* piping

• tubing

• valve

The intended functions of the compressed air system component types within the scope of

license renewal include:

• pressure boundary

• maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and USAR Sections 9.3.1 and 9.3.5 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.6 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

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In RAI 2.3.3.6-1 dated April 3, 2007, the staff stated that relief valve V0706 is shown on a

license renewal drawing as not being within the scope of license renewal; however, is within the

safety-related boundary flagging. The staff requested that the applicant explain why the relief

valve is not within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that valve V0706 should be highlighted

green on the license renewal boundary drawing. The applicant further stated that V0706 was

evaluated as within the scope of license renewal and subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-1 acceptable

because it adequately explained that the relief was already evaluated as within the scope of

license renewal even though it was inadvertently excluded from the scoping boundary on its

license renewal boundary drawing. Therefore, the staff's concern described in RAI 2.3.3.6-1 is

resolved.

In RAI 2.3.3.6-2 dated April 3, 2007, the staff stated that some test connections attached to

components within the scope of license renewal are not within the scope of license renewal as

shown on a license renewal drawing. The staff requested that the applicant describe what is the

license renewal intended function of the test connections attached to components within the

scope of license renewal. The staff also requested that the applicant explain why it does not

apply to the test connections excluded from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the test connections for valves

V0683, V0684, V0685 and V0686 should be highlighted red on the license renewal boundary

drawing. The applicant further stated that the test connections were evaluated as within the

scope of license renewal and subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.6-2 acceptable

because adequately explained that the test connections were already evaluated as within the

scope of license renewal even though they were inadvertently excluded from the scoping

boundary on their license renewal boundary drawing. Therefore, the staff's concern described

in RAI 2.3.3.6-2 is resolved.

2.3.3.6.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the compressed air system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.7 Chemical and Volume Control System

2.3.3.7.1 Summary of Technical Information in the Application

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LRA Section 2.3.3.7 describes the chemical and volume control system (CVCS), which

maintains the RCS pressure boundary, supplies water to the RCP seals, provides injection flow

to the RCS for safety injection, and varies boron concentration for reactivity control. The CVCS,

which provides containment isolation for penetrations P-23, P-24, and P-80, consists of the

following subsystems: (1) charging, letdown, and seal water subsystem which maintains a

programmed water level in the pressurizer as a proper reactor coolant inventory during all

phases of plant operation, (2) the reactor coolant purification and chemistry control subsystem

which maintains desired RCS water chemistry conditions for radioactivity control, (3) the reactor

makeup control subsystem which provides makeup water to the RCS, and (4) the boron thermal

regeneration subsystem which adjusts boron concentration when needed.

The CVCS has safety-related components relied upon to remain functional during and following

DBEs. The failure of nonsafety-related SSCs in the CVCS could prevent the satisfactory

accomplishment of a safety-related function. In addition, the CVCS performs functions that

support fire protection, SBO, and EQ.

LRA Table 2.3.3-7 identifies CVCS component types within the scope of license renewal and

subject to an AMR:

* Class 1 piping (less than or equal to 4 inches)

" closure bolting

" filter

* flexible hoses

* flow element

* heat exchanger shell side

" heat exchanger tube side

* instrument bellows

* insulation

* orifice

" piping

* pump

* sight gauge

" tank

* thermowell

* tubing

" valve

The intended functions of the CVCS component types within the scope of license renewal

include:

* flow restriction

" heat transfer

* heat loss

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

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maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and USAR Section 9.3.4 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff finds that since part of the CVCS (e.g., the charging pumps) is shared with the ECCS,

certain components of the CVCS are used to perform the safety-related functions required by

10 CFR 54.4(a)(1). The CVCS operates in conjunction with the refueling water, RHR and ECCS

to deliver borated emergency core cooling water to the RCS following a LOCA. During the

injection phase, the centrifugal charging pumps in the CVCS, along with the RHR pumps, draw

suction from the RWST and inject borated water directly into the RCS.

The staff's review of LRA Section 2.3.3.7 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.7-1 dated May 6, 2007, the staff noted that license renewal drawing

LR-WCGS-BG-M-12BG03 shows the volume control tank (TBG05) within the scope of license

renewal. The staff requested that the applicant explain why the piping and spray nozzles are

not included within the scope of license renewal in accordance with the requirements of

10 CFR 54.4(a)(2).

In its response dated June 1, 2007, the applicant stated that the volume control tank has an

intended function of pressure boundary. As described in USAR Section 9.3.4, the volume

control tank spray nozzle assembly (i.e., nozzle and pipe stub) does not have an intended

function. The applicant clarified that the failure of the nozzle assemblies does not support the

structural integrity of the tank nor its intended functions. The applicant further stated that the

nozzle assemblies do not have an intended function for any of the license renewal regulated

events and are not within the scope of license renewal based on the requirements of

10 CFR 54.4(a)(1), (a)(2) or (a)(3).

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-1 acceptable

because it adequately explains why the volume control tank piping and nozzles are not within

the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.7-1 is

resolved.

In RAI 2.3.3.7-2 dated May 6, 2007, the staff noted that LRA Table 2.3.3-7 does not list

component types of pumps and tanks supports. The staff requested that the applicant clarify if

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the pumps and tanks supports are within the scope of license renewal. If the supports are not

within the scope of license renewal the staff requested that the applicant justify its response.

In its response dated June 1, 2007, the applicant stated that the CVCS supports are within the

scope of license renewal and addressed as structural commodities in LRA Section 2.4.22. The

applicant clarified that, depending upon the classification of the component, the pump and tank

supports in the CVCS are shown in LRA Table 2.4-22 as Class 2 and 3 supports and

mechanical equipment or as non-ASME supports and mechanical equipment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-2 acceptable

because it clarified that the CVCS pumps and tanks supports are within the scope of license

renewal and evaluated within the structural commodity groups in LRA Section 2.4. The staff's

evaluation of these commodity groups is documented in SER Section 2.4.22. Therefore, the

staff's concern described in RAI 2.3.3.7-2 is resolved.

In RAI 2.3.3.7-3 dated May 6, 2007, the staff noted that license renewal drawing

LR-WCGS-BG-M-12BG04 shows the spent resin storage tanks outside the scope of license

renewal; however, all their connecting lines were included within the scope. The staff requested

that the applicant explain this inconsistency.

In its response dated June 1, 2007, the applicant stated that the portion of the CVCS shown in

drawing LR-WCGS-BG-M-12BG04 is the boron thermal regeneration system. The spent resin

storage tanks referenced in the staff's RAI are the thermal regeneration demineralizers

FBG02A, FBG02B, FBG02C, FBG02D, and FBG02E. The applicant clarified that the piping

shown in the drawing is within the scope of license renewal due to spatial interaction in the

auxiliary building. The applicant stated that each thermal regeneration demineralizer tank is

located in a concrete compartment and that these compartments have no safety-related

components. Therefore, the demineralizer tanks are not within the scope of license renewal as

pursuant to10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant's response to RAI 2.3.3.7-3 acceptable

because it explained why the storage tanks are outside the scope of license renewal. The staff

finds that the applicant adequately classified the adjacent piping within the scope of license

renewal due to potential spatial interaction. Therefore, the staff's concern described in

RAI 2.3.3.7-3 is resolved.

2.3.3.7.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the CVCS components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.8 Auxiliary Building HVAC System

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 describes the auxiliary building HVAC system, which must maintain a

suitable environment for safety-related equipment under normal conditions and during DBEs.

Portions of the auxiliary building HVAC system are isolated upon a safety injection signal. The

portion of the auxiliary building/fuel building normal exhaust subsystem serving the fuel building

is isolated automatically and the exhaust fan flow maintained in a radioactive release from a

fuel-handling event. Individual pump room coolers maintain a suitable ambient environment for

the safety-related pump electric motor drivers. The penetration room coolers maintain a suitable

atmosphere for the safety-related electrical equipment in the electrical penetration rooms. The

auxiliary building HVAC system consists of the following four subsystems:

" auxiliary building supply subsystem

" auxiliary building/fuel building normal exhaust subsystem

* emergency exhaust subsystem

* access tunnel transfer fan

The auxiliary building supply subsystem provides conditioned outside air to the auxiliary building

for ventilation and for cooling of safety-related equipment rooms in each building level. The

auxiliary building supply subsystem is isolated upon a safety injection signal. The auxiliary and

fuel buildings share the auxiliary building/fuel building normal exhaust subsystem that exhausts

clean air to the environment. This subsystem also exhausts decontamination tank scrubber air

to the environment. The auxiliary building/fuel building normal exhaust subsystem is isolated

upon a safety injection signal or in the event of a radioactive release from a fuel-handling

accident in the fuel building. The emergency exhaust subsystem collects and processes

airborne particulates in the auxiliary building/fuel building. This subsystem also exhausts air

purged from the containment via the containment hydrogen control system. Air is exhausted to

the vent stack. The access tunnel transfer fan transfers air from the auxiliary building to the

radwaste tunnel. This subsystem is split between the auxiliary building HVAC system and the

miscellaneous building HVAC system.

The auxiliary building HVAC system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the auxiliary

building HVAC system could prevent the satisfactory accomplishment of a safety-related

function. In addition, the auxiliary building HVAC system performs functions that support fire

protection and EQ.

LRA Table 2.3.3-8 identifies auxiliary building HVAC system component types within the scope

of license renewal and subject to an AMR:

* closure building

* damper

* ductwork

* fan

" flex connector

* heat exchanger shell side

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" heat exchanger tube side

* piping

* pump

" tank

" tubing

* valve

The intended functions of the auxiliary building HVAC system component types within the scope

of license renewal include:

" rated fire barrier to confine or retard a fire from spreading

* heat transfer

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8 and USAR Sections 9.4.2 and 9.4.3 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.8 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.8-1 dated April 18, 2007, the staff requested that the applicant clarify if the damper

housings, heating coil housings, pump casing, valve bodies, and fan housings in the auxiliary building HVAC system are within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawings LR-WCGS-GL-M-12GLO1,

LR-WCGS-GL-M-12GL02, and LR-WCGS-GL-M-12GL03 are included in the component types

listed in LRA Table 2.3.3-8. The applicant clarified that the pump casings, valve bodies, fan

housings, and damper housings are included within the category or commodity groups of pump,

valve, fan, and damper, respectively. The applicant also stated that the auxiliary building HVAC

system heaters are provided by the plant heating system through heat exchangers. They are

included within the scope of license renewal and are listed in LRA Table 2.3.3-8 as component

types of heat exchanger shell side and heat exchanger tube side. The applicant clarified that

there are no heater housings involved in this system that are subject to an AMR.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.8-1 acceptable

because it clarified that the pump casings, valve bodies, fan housings, damper housings and

the shell and tube side of the heat exchangers are within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.3.8-1 is resolved.

2.3.3.8.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the auxiliary building HVAC system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.9 Control Building HVAC System

2.3.3.9.1 Summary of Technical Information in the Application

LRA Section 2.3.3.9 describes the control building HVAC system, which has several

safety-related subsystems required to function following DBEs to achieve and maintain the

plant in a safe shutdown condition. These subsystems must maintain a suitable environment for

the control room and for Class 1 E electrical equipment under normal conditions and during

DBEs. The control building HVAC system also isolates nonsafety-related portions of the HVAC

system on a control room ventilation isolation signal so that habitability of the control room is

not compromised. The control building HVAC system consists of seven subsystems:

* control building supply subsystem

" control building exhaust subsystem

" access control exhaust subsystem

* control room air conditioning subsystem

" Class 1 E electrical equipment air conditioning subsystem

* secondary alarm station room air conditioning subsystem

* counting room recirculation subsystem

The control building supply subsystem supplies outside conditioned air to the control building

under normal conditions and is isolated in accident conditions. The control building exhaust

subsystem exhausts air from clean areas of the control building under normal conditions and is

isolated in accident conditions. The access control exhaust subsystem exhausts air from

potentially contaminated portions of control building. Air is filtered and then exhausted through

the unit vent. This subsystem is isolated in accident conditions. The control room air

conditioning subsystem maintains a suitable environment for personnel and equipment during

normal and accident conditions. The Class 1 E electrical equipment air conditioning subsystem

maintains a suitable environment for Class 1 E electrical equipment during normal and accident

conditions. The secondary alarm station room air conditioning subsystem provides a suitable

environment for the secondary alarm station during normal conditions. The counting room

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recirculation subsystem provides a suitable environment for the counting room personnel and

equipment during normal conditions.

The control building HVAC system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the control

building HVAC system could prevent the satisfactory accomplishment of a safety-related

function. In addition, the control building HVAC system performs functions that support fire

protection and EQ.

LRA Table 2.3.3-9 identifies control building HVAC system component types within the scope of

license renewal and subject to an AMR:

" adsorber

* closure bolting

* compressor

* damper

* ductwork

* fan

• flex connectors

* heat exchanger shell side

• heat exchanger tube side

* piping

* pump

* tubing

" valve

The intended functions of the control building HVAC system component types within the scope

of license renewal include:

* rated fire barrier to confine or retard a fire from spreading

* heat transfer

* pressure boundary

• maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9 and USAR Sections 6.4, 6.5.1, 7.3.4, and 9.4.1 using

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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The staff's review of LRA Section 2.3.3.9 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.9-1 dated April 18, 2007, that staff requested that the applicant clarify if the

housings for filter adsorption units, compressor housings, fire dampers, damper housings

including fire damper housings, heating coil housings, pump casings, valve bodies, and

pressure boundary sealants in the control building HVAC system are within the scope of license

renewal.

In its response May 2, 2007, the applicant stated that the component types that are subject to

an AMR and are highlighted in license renewal drawings LR-WCGS-GK-M-12GK01,

LR-WCGS-GK-M-12GK02, LRWCGS-GK-M-12GK03, and LR-WCGS-GK-M-12GK04 are

included in the component types listed in LRA Table 2.3.3-9. The applicant clarified that pump

casings, valve bodies, fan housings, damper housings, and filter adsorber housings are

included within the scope of license renewal under the categories or commodity groups of

pumps, valves, fan, damper, and adsorber, respectively.

The applicant also stated that the compressor housings are within the scope of license renewal

and addressed as component type of compressor. Also, the heaters of the control building

HVAC system are provided by the plant heating system through heat exchangers. They are

included within the scope of license renewal and listed in LRA Table 2.3.3-9 as component

types of heat exchanger shell side and heat exchanger tube side. However, there are no heater

housings involved in this system that are subject to an AMR.

The applicant clarified that the fire barrier seals and structural pressure boundary sealant are

evaluated within the structures scoping and screening results in LRA Table 2.4-2. Also, the air

intake louvers are addressed as generic structural steel in LRA Table 2.4-2.

The applicant also clarified that the mechanical boundaries in the HVAC system terminate

where the duct meets the interior wall. Entry and exit plenums shown on the drawings are those

plenums that penetrate the building walls to the outside. The concrete associated with these

plenums is included within the scope of license renewal as a generic concrete component in

LRA Table 2.4-2.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.9-1 acceptable

because it clarified that the pump casings, valve bodies, fan housings, damper housings, filter

adsorber housings, compressor housings, shell and tube side heat exchangers, and air intake

louvers are within the scope of license renewal. Therefore, the staff's concern described in

RAI 2.3.3.9-1 is resolved.

2.3.3.9.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the control building HVAC system components that are within the scope of license

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renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.10 Fuel Building HVAC System

2.3.3.10.1 Summary of Technical Information in the Application

LRA Section 2.3.3.10 describes the fuel building HVAC system, which isolates the fuel building

normal ventilation system upon a high radiation or LOCA signal and processes air via the

emergency exhaust system to maintain the fuel building at a negative pressure. The fuel

building HVAC system spent fuel pool cooling pump room coolers maintain a suitable ambient

temperature for the spent fuel cooling pump motors. The fuel building HVAC system provides

fresh air, heated or cooled as required, for the fuel building; isolates the fuel building upon

receipt of a high-radiation or LOCA signal; and processes airborne particulate in the fuel

building when required. The fuel building HVAC system consists of the emergency exhaust

system, the fuel storage pool cooling pump room coolers, and fuel building HVAC normal

supply system fans and ducting.

The fuel building HVAC system has safety-related components relied upon to remain functional

during and following DBEs. The failure of nonsafety-related SSCs in the fuel building HVAC

system could prevent the satisfactory accomplishment of a safety-related function.

LRA Table 2.3.3-10 identifies fuel building HVAC system component types within the scope of

license renewal and subject to an AMR:

" adsorber

* closure bolting

* damper

" ductwork

* fan

* flex connectors

" heat exchanger shell side

* heat exchanger tube side

* heater

* piping

" pump

* tubing

* valve

The intended functions of the fuel building HVAC system component types within the scope of

license renewal include:

* rated fire barrier to confine or retard a fire from spreading

* heat transfer

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

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2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and USAR Sections 7.3.3 and 9.4.2 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.10 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.10-1 dated April 18, 2007, the staff requested that the applicant clarify if the

housings for filter adsorber units, damper housings, fire dampers and associated housings,

heating coil housings, pump casings, valve bodies, pressure boundary sealants, and fan

housings in the fuel building HVAC system are within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawings LR-WCGS-GG-M-1 2GG01,

and LR-WCGS-GG-M-12GG02 are included in the component types listed in LRA

Table 2.3.3-10. The applicant clarified that the pump casings, valve bodies, fan housings,

damper housings, and filter adsorber housings are included within the scope of license renewal

within the categories or commodity groups of pump, valve, fan, damper, and adsorber,

respectively.

The applicant stated that heaters in the fuel handling HVAC system are mounted on the

ductwork or provided by the plant heating system through in-line heat exchangers. The portion

of the duct-mounted heaters that has an intended function of maintaining ductwork pressure

boundary are included within the scope of license renewal in LRA Table 2.3.3-10 as a

component type of heater. The portion of the in-line heaters that has an intended function of

maintaining ductwork pressure boundary are included as component types of heat exchanger

shell side and heat exchanger tube side.

The applicant clarified that fire barrier seals, structural pressure boundary sealants,

miscellaneous caulking, and sealants in the fuel building are evaluated within the structures

scoping and screening results in LRA Table 2.4-12. Also, air intake louvers have been included

within the scope of license renewal as generic structural steel in LRA Table 2.4-12.

The applicant also stated that mechanical boundaries in the HVAC system terminate where the

duct meets the interior wall. Entry and exit plenums shown on the drawings are those plenums

that penetrate the building walls to the outside. The concrete associated with these plenums is

included within the scope of license renewal as a generic concrete component in LRA

Table 2.4-12.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.10-1 acceptable

because it clarified that the pump casings, valve bodies, fan housings, damper housings, filter

adsorber housings, shell and tube side heat exchangers, fire barrier seals, and miscellaneous

caulking are included within the scope of license renewal. Therefore, the staff's concern

described in RAI 2.3.3.10-1 is resolved.

2.3.3.10.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the fuel building HVAC system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.11 Essential Service Water Pumphouse Building HVAC System

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 describes the ESW pumphouse building HVAC system, which maintains

an environment suitable for operation of the ESW pump motors and electrical equipment. The

ESW pumphouse building HVAC system, excluding the unit heaters, is safety-related and must

function following DBEs. The ESW pumphouse building HVAC system cools the ESW pump

motors, using outside air as the cooling medium. Air is supplied to and vented from the building

through exhaust louvers. Each ESW pumproom has a separate system. Electric unit heaters

provide heating during winter months.

The ESW pumphouse building HVAC system has safety-related components relied upon to

remain functional during and following DBEs. In addition, the ESW pumphouse building HVAC

system performs functions that support fire protection.

LRA Table 2.3.3-11 identifies ESW pumphouse building HVAC system component types within

the scope of license renewal and subject to an AMR:

* closure bolting

* damper

* ductwork

* fan

* flex connector

The intended function of the ESW pumphouse building HVAC system component types within

the scope of license renewal is to provide a pressure boundary.

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2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and USAR Section 9.4.8 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.11 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.11-1 dated April 18, 2007, the staff requested that the applicant clarify if the

damper housings, intake and exhaust louvers with their associated housings and plenums, and

fan housings in the ESW pumphouse building HVAC system are within the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GD-M-K2GDO1

are included in the component types listed in LRA Table 2.3.3-11. The applicant clarified that

the fan housings, damper housings, including fire damper housings, are included within the

scope of license renewal within the categories or commodity groups of fan and damper,

respectively.

The applicant clarified that air intake louvers have been included within the scope of license

renewal as generic structural steel in LRA Table 2.4-13. Also, mechanical boundaries in the

HVAC system terminate where the duct meets the interior wall. Entry and exit plenums shown

on the drawings are those plenums that penetrate the building walls to the outside. The

concrete associated with these plenums is included within the scope of license renewal as a

generic concrete component in LRA Table 2.4-13.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.11-1 acceptable,

because it clarified that the damper housings, intake and exhaust louvers with their associated

housings and plenums, and fan housings are within the scope of license renewal. Therefore,

the staff's concern described in RAI 2.3.3.11-1 is resolved.

2.3.3.11.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

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identified the ESW pumphouse building HVAC system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.12 Miscellaneous Buildings HVAC System

2.3.3.12.1 Summary of Technical Information in the Application

LRA Section 2.3.3.12 describes the miscellaneous buildings HVAC system, which is relied upon

to isolate the miscellaneous buildings HVAC system from the auxiliary building ventilation

system upon a safety injection signal. In addition, the auxiliary feedwater pump room coolers

must maintain a suitable environment for safety-related equipment in the auxiliary feedwater

pump rooms under normal conditions and DBEs.

The miscellaneous buildings HVAC system consists of the following subsystems:

" tendon access gallery supply and exhaust subsystem

" main steam enclosure building supply and exhaust subsystem

* auxiliary feedwater pump room coolers

* access tunnel supply and exhaust subsystem

" auxiliary boiler room supply and exhaust subsystem

* RWST valve house

* reactor makeup water storage tank valve house

" condensate and demineralized water pipe tunnel

The tendon access gallery supply and exhaust subsystem utilizes conditioned air from the

auxiliary building for ventilation, heating, and cooling during periods of personnel access. The

main steam enclosure building supply and exhaust subsystem provides outside air for

ventilation, heating, and cooling of the main steam enclosure building and exhausts air through

the unit vent stack. The auxiliary feedwater pump room coolers maintain a suitable environment

for safety-related equipment in the auxiliary feedwater pump rooms. The access tunnel supply

and exhaust subsystem maintains a suitable environment for personnel and equipment within

the access tunnel. The auxiliary boiler room supply and exhaust subsystem maintains a suitable

environment for personnel and equipment within the auxiliary boiler room. The RWST valve

house unit heaters, the reactor makeup water storage tank valve house unit heaters, and the

condensate and demineralized water pipe tunnel unit heaters provide heating in respective

areas.

The miscellaneous buildings HVAC system has safety-related components relied upon to

remain functional during and following DBEs. The failure of nonsafety-related SSCs in the

miscellaneous buildings HVAC system could prevent the satisfactory accomplishment of a

safety-related function. In addition, the miscellaneous buildings HVAC system performs

functions that support fire protection and EQ.

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LRA Table 2.3.3-12 identifies miscellaneous buildings HVAC system component types within

the scope of license renewal and subject to an AMR:

* closure bolting

* damper

* ductwork

* fan

* flex connector

* heat exchanger shell side

* heat exchanger tube side

* piping

* pump

* tubing

* valve

The intended functions of the miscellaneous buildings HVAC system component types within

the scope of license renewal include:

" rated fire barrier to confine or retard a fire from spreading

• heat transfer

• pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and USAR Section 9.4.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.11 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.12-1 dated April 18, 2007, the staff requested that the applicant clarify if the

damper housings, heating coil housings, pump casings, valve bodies, and fan housings in the

miscellaneous building HVAC system are within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GF-M-12GFO1

are included in the component types listed in LRA Table 2.3.3-12. The applicant clarified that

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the pump casings, valve bodies, fan housings, damper housings, including fire damper

housings, are included within the scope of license renewal in the categories or commodity

groups of pump, valve, fan, and damper, respectively.

The applicant stated that the heaters in the miscellaneous buildings HVAC system are provided

by the plant heating system through heat exchangers. They are included within the scope of

license renewal in LRA Table 2.3.3-12 as component types of heat exchanger shell side and

heat exchanger tube side. The applicant clarified that there are no heater housings involved in

this system that are subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.12-1 acceptable

because it clarified that the damper housings, pump casings, valve bodies, fan housings, and

shell and tube side heat exchangers are within the scope of license renewal. Therefore, the

staff's concern described in RAI 2.3.3.12-1 is resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the miscellaneous buildings HVAC system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.13 Diesel Generator Building HVAC System

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 describes the diesel generator building HVAC system, which provides

combustion air and maintains an environment suitable for the operation of the diesel

generators. The diesel generator building HVAC system, excluding the unit heaters, is

safety-related and must function following DBEs. The diesel generator building HVAC system

provides combustion air and cooling for the diesel generators, using outside air as the cooling

medium. Outside air is supplied to the building, circulated, and returned outside through

exhaust louvers. Each diesel generator room has a separate cooling system and an electric unit

heater for heating.

The diesel generator building HVAC system has safety-related components relied upon to

remain functional during and following DBEs. In addition, the diesel generator building HVAC

system performs functions that support fire protection.

LRA Table 2.3.3-13 identifies diesel generator building HVAC system component types within

the scope of license renewal and subject to an AMR:

• closure bolting

• damper

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" ductwork

" fan

* flex connector

The intended function of the diesel generator building HVAC system component types within

the scope of license renewal is to provide a pressure boundary.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and USAR Section 9.4.7 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.13 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.13-1 dated April 18, 2007, the staff requested that the applicant clarify if the

damper housings, fan housings, valve bodies, intake and exhaust louvers and associated

housings and plenums in the diesel generator building HVAC system are within the scope of

license renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawing LR-WCGS-GM-M-12GMOI

are included in the component types listed in LRA Table 2.3.3-13. The applicant clarified that

the fan housings and damper housings are included within the scope of license renewal in the

categories or commodity groups of fan and damper, respectively.

The applicant stated that air intake louvers have been included within the scope of license

renewal as generic structural steel in LRA Table 2.4-3. Also, mechanical boundaries in the

HVAC system terminate where the duct meets the interior wall. Entry and exit plenums shown

on the drawings are those plenums that penetrate the building walls to the outside. The

concrete associated with these plenums is within the scope of license renewal as a generic

concrete component in LRA Table 2.4-3. The applicant clarified that there are no valves

involved in this system.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.13-1 acceptable

because it clarified that the damper housings, intake and exhaust louvers and associated

housings and plenums, and fan housings are within the scope of license renewal. Therefore,

the staff's concern described in RAI 2.3.3.13-1 is resolved.

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2.3.3.13.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the diesel generator building HVAC system components that are within the scope of

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1). subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.14 Fire Protection System

2.3.3.14.1 Summary of Technical Information in the Application

LRA Section 2.3.3.14 describes the fire protection system.

The fire protection system minimizes the effects of fire on plant SSCs. The failure of

nonsafety-related fire protection systems could potentially prevent the satisfactory

accomplishment of a safety-related function of SSCs.

The fire protection system consists of four subsystems: (1) the fire water pumps, fire water

pump drivers, and underground distribution system including outside loop, hydrants, sectional

control valves, and isolation valves, (2) hose stations, standpipes, Halon, deluge, and pre-action

systems within the power block, including control valves, spray nozzles, and sprinkler heads, (3)

diesel fuel oil supply to the 100-percent capacity engine-driven fire pump, and (4) water supply

to the jockey pump from the plant service water system.

The fire protection system includes components relied on in safety analyses or plant

evaluations to perform a function that demonstrates compliance with NRC regulation.

LRA Table 2.3.3-14 identifies fire protection system component types within the scope of

license renewal and subject to an AMR:

" closure bolting

" filter

• flexible hoses

* hose station

" piping

* pump

* spray nozzle

* sprinkler head

" strainer

* tank

" tubing

• valve (including fire hydrant)

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The intended functions of the fire protection system component types within the scope of

license renewal include:

* filtration

• pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* converts fluid into spray

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14, USAR Section 9.5.1, "Fire Protection System," and

the NRC supplemental SER dated March 1985, approving the WCGS fire protection program

described in the WCGS Operating License Condition 2C(5)(a), using the evaluation

methodology described in SER Section 2.3, "Scoping and Screening Results: Mechanical

Systems," and the guidance in SRP-LR Section 2.3.

The staff also reviewed WCGS commitments to 10 CFR 50.48, using the Branch Technical

Position (BTP) Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, "Guidelines for

Fire Protection for Nuclear Power Plants," May 1, 1976, and Appendix A to BTP APCSB 9.5-1,

August 23, 1976, documented in USAR Tables 9.5A-1 and 9.5E-1. The staff also reviewed the

"TR 3, Fire Protection License Renewal Position Paper," Revision 1, dated August 2, 2006, that

describes the WCGS fire protection regulatory requirements.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant had not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant had identified as being within the scope of license renewal to

verify that the applicant had not omitted any passive or long-lived components that should be

subject to an AMR in accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.14 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.14-1 dated April 3, 2007, the staff stated that the seven LRA drawings listed below

show fire protection system components not highlighted in green indicating that they are outside

the scope of license renewal. The staff requested that the applicant verify whether these

components are within the scope of license renewal in accordance with 10 CFR 54.4(a) and

subject to an AMR in accordance with 10 CFR 54.21 (a)(1). If not, the staff requested that the

applicant provides a justification for their exclusion.

(1) LR-WCGS-KC-M-0022-1, "Plant Service Water System," shows the following

components outside the scope of license renewal:

* one of the four vertical pumps (1WS002P) and its associated components

• several flow drains (1W30102, 1W30103, etc.)

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(2) LR-WCGS-KC-M-0023-1, "Fire Protection Water System," shows the following

components outside the scope of license renewal:

• • fire hydrant (1 FPO138) and its associated components

* , several flow drains

(3) LR-WCGS-KC-M-0023-2, "Fire Protection System," shows the following components

outside the scope of license renewal:

• several valves

(4) LR-WCGS-KC-M-0028, "Diesel Oil System," shows the following components outside

the scope of license renewal:

• flame arrester vent line

• fill cap assembly

(5) LR-WCGS-KC-M-12KC01, "Fire Protection Turbine Building," shows the following

components outside the scope of license renewal:

• several line valves

* several sprinkler heads

(6) LR-WCGS-KC-M-12KC02, "Fire Protection System," shows the following components

outside the scope of license renewal:

• several flow drains (reactor building, communications corridor, and auxiliary

feedwater pipe chase area)

* valves V0281 and V04323 (communications corridor)

" sprinkler system (auxiliary boiler room)

• drain valve V0859 (auxiliary feedwater pipe chase area)

• several drains and valves (reactor building)

" lines and two valves (generator rooms A and B)

(7) LR-WCGS-KC-M-12KC03, "Fire Protection System," shows the following components

outside the scope of license renewal:

* several drain valves

In its response dated May 3, 2007, the applicant stated that the portions of the fire protection

system that do not support WCGS post-fire safe-shutdown requirements or are not identified in

the WCGS response to APCSB 9.5-1, Appendix A, in USAR Table 9.5A-1 are identified as

having no license renewal intended functions based on the fire protection criteria described in

10 CFR 54.4(a)(3). The applicant indicated that interactions of fire protection system

components with safety-related equipment were also evaluated to determine if the components

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have a license renewal intended function and should be added to the scope of license renewal.

The applicant provided the following responses:

(1) LR-WCGS-KC-M-0022-1, "Plant Service Water System"

* vertical pump. Pump 1WS002P is a low flow, low capacity pump called the low

flow and startup pump. The low flow and startup pump is used during startup

conditions or low flow conditions to maintain the service water system header at

a minimum pressure to prevent service water pump run out as described in

USAR Section 9.2.1.1.2.3. The low flow and startup pump has no license

renewal intended function.

* several flow drains. There is no safety-related equipment in the circulating water

screenhouse that can be affected by fluid-filled piping spatial interaction of the

flow drains. The flow drains do not have a license renewal intended function.

(2) LR-WCGS-KC-M-0023-1, "Fire Protection Water System"

* fire hydrant. Fire Hydrant 1 FP01 38 and its associated components located

outside the circulating water screenhouse do not have a license renewal

intended function.

" several flow drains. There are no safety-related equipment in the circulating

water screenhouse that can be affected by fluid-filled piping spatial interaction of

the flow drains. The flow drains do not have a license renewal intended function.

(3) LR-WCGS-KC-M-0023-2, "Fire Protection System"

several valves. These valves supply water to portions of the fire water

suppression system (e.g., security building, shop building, etc.) that do not

support WCGS post-fire safe-shutdown requirements nor are they identified in

the WCGS response to APCSB 9.5-1, Appendix A, in USAR Table 9.5A-1. The

valves do not have a license renewal intended function.

(4) LR-WCGS-KC-M-0028, "Diesel Oil System"

flame arrestor vent line and fill cap assembly. Flame arrestors vent line

1 DO008A-2, diesel fire pump engine oil-return flame arrestor vent line

1 DO0016A-1/2, and fill cap line 1DO007A-3 will be added to the scope of license

renewal. LRA Tables 2.3.3-14 and 3.3.3-14 will be revised to include these new

components.

(5) LR-WCGS-KC-M-12KCO1, "Fire Protection Turbine Building"

several line valves and sprinkler heads. The response to RAI 2.3.3.14-5

describes the portions of the fire suppression system that are excluded from the

scope of license renewal and the justification for the exclusion.

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(6) LR-WCGS-KC-M-12KC02, "Fire Protection System"

" communication corridor. These vent and drain valves are located in the

communications corridor. There is no safety-related equipment in the

communications corridor that can be affected by fluid-filled piping spatial

interaction. The components within the scope of license renewal in the

communications corridor are only those components with a fire protection

intended function. The communication corridor components that are within the

scope of license renewal are piping and piping components associated with fire

hose reels and fire hose connections. Valves V0281 and V0423 do not have a

license renewal intended function.

* auxiliary boiler room. The response to RAI 2.3.3.14-5 describes portions of the

fire suppression system that are excluded from the scope of license renewal.

auxiliary feedwater pipe chase. Drain valve V0859 does not have a license

renewal intended function. There is no safety-related equipment outside of the

auxiliary feedwater pipe chase area (in the vicinity of V0859) that can be affected

by fluid-filled piping spatial interaction. The only components within the scope of

license renewal that are outside of the auxiliary feedwater pipe chase area are

fire protection components.

• reactor buildingi. The hose stations and sprinkler systems in the reactor building

are isolated and drained during normal plant operation. Failure of the vent and

drain valves would not affect safety-related equipment through spatial

interaction. The components within the scope of license renewal in the reactor

building are only those components with a fire protection intended function. The

vent and drain components in the reactor building do not have a license renewal

intended function.

diesel generator rooms. The lines and valves are part of the service air system.

There is no potential for spatial interaction with this air-filled piping. The service

air system is evaluated in LRA Section 2.3.3.6.

(7) LR-WCGS-KC-M-12KC03, "Fire Protection System"

several drain lines. These vent and drain valves are located in the radwaste

building. There is no safety-related equipment in the radwaste building that can

be affected by fluid-filled piping spatial interaction. The components within the

scope of license renewal in the radwaste building are only those components

with a fire protection intended function. The radwaste building components that

are within the scope of license renewal are piping and piping components

associated with fire hose reels, sprinklers and fire hose connections. Vent, drain

valves and piping in the radwaste building do not have a license renewal

intended function.

Based on its review, the staff did not agree with the justification for excluding portions of fire

protection systems and components on the bases that these fire suppression systems and

components are not required for achieving a safe shutdown in the event of a fire. The staff

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found that the applicant's analysis of fire protection regulations does not completely capture the

fire protection SSCs required for compliance with 10 CFR 50.48. The scope of SSCs required

for compliance with 10 CFR 50.48 (and associated 10 CFR Part 50, Appendix A, General

Design Criteria (GDC) 3) goes beyond preserving the ability to maintain safe shutdown in the

event of a fire. GDC 3 states in part, that "fire detection and fighting systems of appropriate

capacity and capability shall be provided and designed to minimize the adverse effects of fires

on structures, systems, and components important to safety." Furthermore, the general

requirements provided in GDC 3 to "minimize the adverse effects of fires on SSC's important to

safety" are stated to provide a general level of protection which is afforded to all systems, not

only where required to prevent a loss of safe-shutdown capability. Section 50.48(a) of

10 CFR states that, "each operating nuclear power plant must have a fire protection plan that

satisfies Criterion 3 of Appendix A of this part." The term "important to safety" encompasses a

broader scope of equipment than safety-related and safe shutdown equipment. Though there is

a focus on the protection of safety-related equipment or safe shutdown equipment, this does

not imply that there is an exclusion of any equipment which protects nonsafety-related

equipment. For example, in accordance with 10 CFR 50.48, some portions of suppression

systems may be required in plant areas where a fire could result in the release of radioactive

materials to the environment, even if no safety-related or safe shutdown equipment is located in

that particular fire area.

Subsequently, the staff reviewed commitments made by the applicant to satisfy to BTP APCSB

9.5-1, Appendix A. The staff found that pump 1 WS002P, fire hydrant 1 FP01 38, the flow drains

in circulating water screenhouse, and the valves in security and shop buildings have no

intended functions associated with 10 CFR 54.4(a)(2), and that these systems and components

were correctly excluded from the scope of license renewal and not subject to an AMR. In

addition, by letter dated August 31, 2007, the applicant added the flame arrestor vent line and

fill cap assembly within the scope of license renewal. Therefore, they are subject to an AMR. As

discussed in the RAI response, the flame arrestors were added to LRA Tables 2.3.3-14 and

3.3.3-14. The staff finds that these components will be adequately managed during the period

of extended operation. Therefore, the staff's concern described in RAI 2.3.3.14-1 is resolved.

In RAI 2.3.3.14-2 dated April 3, 2007, the staff noted that the NUREG-0881, Supplement 5,

Section 9.5.1.1, states that the fire pumps take suction from a common wet pit sump in the

circulating water screenhouse. Two traveling water screens and the bar grill are located at the

inlet to the sump serving the fire pumps. LRA Section 2.3.3.14 and Table 2.3.3.14 do not clearly

state whether the traveling water screens and bar grill are included within the scope of license

renewal. The staff requested that the applicant verify whether the traveling water screens and

bar grill and their associated components are within the scope of license renewal in accordance

with 10 CFR 54.4(a) and subject to an AMR in accordance with 10 CFR 54.21 (a)(1). If not, the

staff requested that the applicant provides a justification for their exclusion.

In its response dated May 2, 2007, the applicant stated that the traveling screens and bar grill

are part of service water system. The service water system is not required for safe shutdown of

the plant. Traveling screens remove debris from the circulating and service water system flow

path to prevent plugging of the condenser water box inlets and loss of service water flow.

The applicant stated that during emergency operations, the circulating water pumps are

unnecessary and, in fact, may be unavailable due to a loss of offsite power. For normal and

emergency operations without the circulating water pumps operating, a much lower volume of

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water flows through the traveling screens. The lower flow rates make it unlikely that debris

could clog the traveling screens and prevent them from passing adequate flow. An open pipe

connecting to the adjacent sump in the circulating water screenhouse is provided as a second

source of water to the pumps. There are four 12-inch diameter pipe connections between the

fire pump screenhouse sump and the adjacent circulating water screenhouse sump. In the

event of blockage of water through the traveling screens in the fire pump sump, one connection

between bays and one operational traveling screen is all that is required to provide adequate

fire water.

The applicant also stated that the traveling screens perform their function with moving parts and

can be rotated and backwashed, manually or automatically, due to differential pressure across

the screens. These components are considered active. Therefore, the applicant concluded that

the traveling screens and bar grill are not within the scope of 10 CFR 54.4(a) and are not

subject to an AMR.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-2 acceptable

because it adequately described that the intended function supporting the fire pump suction

supply is accomplished by the redundant traveling screen and bar grill. If a blockage were to

occur, one connection out of four 12-inch diameter pipes provides adequate fire water to

bypass the blockage and continue to supply water to the pump suctions. Additionally, the fire

pump suction headers have their own strainers in-line, such that the loss of the trash racks or

traveling screens would not challenge the operation of these pumps until repair or replacement

of the damaged component could be performed. Therefore, the staff's concern described in

RAI 2.3.3.14-2 is resolved.

In RAI 2.3.3.14-3 dated April 3, 2007, the staff noted that NUREG-0881, Supplement 5,

Section 9.5.1.2, states that where safe shutdown equipment is enclosed by a fire barrier, all

walls, ceilings, floors, and associated penetrations that enclose the equipment have a minimum

fire rating of three hours. LRA Section 2.3.3.14 and Table 2.3.3.14 do not clearly state whether

fire barrier walls, ceilings, floor, slabs, and associated penetration seals are included within the

scope of license renewal. The staff requested that the applicant verify whether these fire barrier

walls, ceilings, floor, slabs, and associated penetration seals are within the scope of license

renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If not, the staff requested that the applicant provides a justification for their

exclusion.

In its response dated May 3, 2007, the applicant stated that as noted in LRA Section 2.3.3.14,

"Other passive fire barriers are screened as part of the structure." Each structure within the

scope of license renewal is discussed separately in LRA Section 2.4. Those structures that are

required to support fire protection include a statement to that effect in the structure function

discussion. The component-function relationship tables in LRA Section 2.4 show fire barriers as

one of the intended functions for the component types that are credited as part of the fire

protection system. For example, LRA Table 2.4.2, lists the fire barrier function for component

types concrete block (masonry walls), concrete elements, fire barrier coatings and wraps, fire

barrier doors, and fire barrier seals. Therefore, fire barrier elements are within the scope of

license renewal and subject to an AMR.

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Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-3 acceptable

because the structural fire barriers in question were identified to be within the scope of license

renewal and subject to an AMR. The applicant stated that the structural fire barriers ( i.e., walls,

ceilings, and floors) are discussed separately in LRA Section 2.4, and that LRA Table 2.4.2 lists

fire barrier functions for these component types. Therefore, the staff's concern described in

RAI 2.3.3.14-3 is resolved.

In RAI 2.3.3.14-4 dated April 3, 2007, the staff stated that LRA Table 2.3.3-14 excludes several

types of fire protection components that are listed in NUREG-0881, Supplement 5, and/or the

WCGS USAR. In addition, the LRA drawings -highlighted them in green as components within

the scope of license renewal. The staff requested that the applicant verify whether the

components listed below should be included in LRA Table 2.3.3.14. If they are excluded from

the scope of license renewal and not subject to an AMR, the staff requested that the applicant

provides a justification for the exclusion.

* hose connections

* hose racks

* pipe fittings

* pipe supports

* couplings

" threaded connections

* restricting orifices

* interface flanges

* chamber housings

* heat-actuated devices

* gauge snubbers

* tank heaters

* Halon 1301 storage cylinders

* thermowells

* water motor alarms

* expansion joint

* filter housing

* gear box housing

* ,heat exchanger (bonnet)

* heat exchanger (shell)

• heat exchanger (tube)

* heater housing

* engine muffler (diesel driven fire pump)

* engine intake and exhaust silencers (diesel driven fire pump)

* orifice

* sight glass

* strainer housing

" turbocharger housing

* flexible hose

* latch door pull box

" pneumatic actuators

* actuator housing

* dikes

• storage tanks (fire water system)

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* buried underground fuel oil tanks

* expansion tank

* jacket cooling water keepwarm pump and heater

* lubricating oil collection system components (reactor coolant pumps)

* lubricating oil cooler

* auxiliary lubricating oil makeup tank

* rocker lubricating oil pump

* water floor drains

* flame retardant coating for cables

* fire barrier penetration seals

• fire barrier walls, ceilings, floor, and slabs

• fire doors

* fire rated enclosures

* fire retardant coating for structural steel supporting wall and ceiling

In its response dated May 3, 2007, the applicant stated that the fire protection system includes

components from the fire protection system (power block), the fire protection system

(non-power block), the diesel oil system and the service water system. The applicant stated the

following:

" Hose connections. Hose connections are included in the valve line item in LRA

Table 2.3.3-14.

• Hose racks. Hose racks are included in the hose station line item in LRA Table 2.3.3-14.

" Pipe fittings. The component type of piping used in LRA Table 2.3.3-14 includes piping

fittings. This is consistent with the definition of piping, piping components, and piping

elements noted in the GALL Report, Chapter IX.B.

* Pipe supports. Pipe supports were evaluated as a structural commodity group. Fire

protection pipe supports are included as supports, mechanical equipment non-ASME

component type on LRA Table 2.4-22.

* Coupling. The component type of piping used in LRA Table 2.3.3-14 includes couplings.

This is consistent with the definition of piping, piping components, and piping elements

noted in the GALL Report, Chapter IX.B.

* Threaded connections. The component type of piping used in LRA Table 2.3.3-14

includes threaded connections. This is consistent with the definition of piping, piping

components, and piping elements noted in the GALL Report, Chapter IX.B.

* Restricting orifices. Restricting orifices with unique component numbers are identified as

a component type of orifice. There are no orifices in the fire protection system with

unique component identification numbers.

* Interface flanges. The component type of piping used in LRA Table 2.3.3-14 includes

interfacing flanges. This is consistent with the definition of piping, piping components,

and piping elements noted in the GALL Report, Chapter IX.B.

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Chamber housing. The component type of piping used in LRA Table 2.3.3-14 includes

chamber housing. This is consistent with the definition of piping, piping components,

and piping elements noted in the GALL Report, Chapter IX.B. The only component in

the fire protection component list specifically identified as a chamber is the foam maker

chamber housing. The foam maker chamber housing is part of the foam suppression

system for the fuel oil storage tank. The foam fire suppression system is a manually

operated foam extinguishing system located in the fuel oil pumphouse. The fuel oil

pumphouse is protected to satisfy Nuclear Electric Insurance Limited property protection

requirements, has no intended function and is not within the scope of license renewal.

" Heat actuated devices. Heat actuated devices are active electrical components within

the scope of license renewal but not subject to an AMR. Electrical component

evaluations are described in LRA Section 2.5.

* Gauge snubbers. Gauge snubbers are integral parts of tubing runs that protect

instrumentation from pressure surges. Gauge snubbers in tubing runs to instruments

are included as a component type of tubing in LRA Table 2.3.3-14.

* Tank heaters. Tank heaters are active electrical components within the scope of license

renewal but not subject to an AMR. Electrical component evaluations are described in

LRA Section 2.5. Tank heater housings are subject to an AMR if they serve a pressure

boundary function. There are no tank heaters with a pressure boundary function in the

fire protection system.

" Halon 1301 storage cylinders. The component type of tank used in LRA Table 2.3.3-14

includes Halon 1301 storage cylinders. This is consistent with the definition of piping,

piping components, and piping elements noted in the GALL Report, Chapter IX.B.

" Thermowells. The component type of piping used in LRA Table 2.3.3-14 includes

thermowells. This is consistent with the definition of piping, piping components, and

piping elements noted in the GALL Report, Chapter IX.B.

" Water motor alarms. Water motor alarms are water flow alarms used to provide positive

indication of fire water system operation. Water motor alarms are active electrical

components within the scope of license renewal but not subject to an AMR. Electrical

component evaluations are described in LRA Section 2.5.

* Expansion boints. Expansion joints with unique component numbers are identified as a

component type of expansion joint. There are no expansion joints in the fire protection

system with unique component identification numbers.

* Filter housing. Filter housings within the scope of licence renewal in the fire protection

system are evaluated as part of the component type of filter in LRA Table 2.3.3-14 and

include intended functions for both pressure boundary and filter.

* Gear box housing. Gear boxes associated with the fire protection system do not have

unique component identification numbers. Gear boxes that may be part of a large skid

assembly (e.g., fire pump diesel) are evaluated as part of that larger component.

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* Heat exchanger. The diesel driven fire pump engine has an integral oil cooler. The oil

cooler is integral to the diesel engine and is evaluated as part of the engine. The diesel

engine is an active component and not subject to an AMR.

* Heater housings. Heater housings are subject to review if they serve a pressure

boundary function. There are no heater housings in the fire protection system.

* Engine muffler (diesel driven fire pump). The diesel driven fire pump engine muffler will

be added to the scope of license renewal as a component type of piping in LRA

Table 2.3.3-14.

Engine intake and exhaust silencers (diesel driven fire pump). Intake and exhaust

silencers associated with the fire protection system do not have unique component

identification numbers. The fire pump diesel engine is an active component and not

subject to an AMR. The diesel engine air intake is integral to the engine and evaluated

as part of the engine. The diesel fire pump engine exhaust has unique component

numbers (further discussed in engine muffler response above).

Orifice. Orifices with unique component numbers are identified as a component type of

orifice. There are no orifices in the fire protection system with unique component

identification numbers.

Sight glass. Sight glasses are included in the component type of sight gauge. Sight

gauge 1 LIDO001 diesel oil day tank level indicator was inadvertently scoped as an

electrical instrument. The sight gauge will be removed from the electrical system and

included within the scope of license renewal as a mechanical component in the diesel oil

and fire protection (power block) systems. The component type sight gauge will be

added to LRA Tables 2.3.3-14 and 3.3.2-14.

Strainer housing. Strainer housings within the scope of license renewal in the fire

protection system are evaluated as component type Strainer.

* Turbocharger housing. The diesel driven fire pump is not turbocharged.

* Flexible hose. Flexible hoses within the scope of license renewal in the fire protection

system are listed as a generic component type of flexible hoses.

* Latch door pull box. The latch door pull box on a carbon dioxide and Halon system is

used to provide mechanical operation of the stop/selector valve and/or the local lever

actuator from a remote location. The latch door pull box has a door that must be opened

in order to access the pull handle. The latch door pull box is within the scope of license

renewal but is an active component and not subject to an AMR.

* Pneumatic actuator. The statements of consideration of the license renewal rule provide

the basis for excluding SCs that perform their intended functions with moving parts or

with a change in configuration or properties. Although the valve body is subject to an

AMR" the pneumatic actuator is not.

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* Actuator housing. The component type of valve (including hydrant) used in LRA

Table 2.3.3-14 includes the actuator housing.

* Dikes. No outdoor tanks fall under the D (augmented) classification as established by

RG 1.26, and no associated dikes are provided for the tanks.

* Storage tanks (fire water system). The only fire water tank used at WCGS is located in

administration building B. The administration building fire water tank has no intended

function and is not within the scope of license renewal.

Buried underqround fuel tanks. The fuel oil tank for the diesel driven fire pump is located

above ground.

* Expansion tank. The fire protection system includes many tanks including the diesel oil

day tanks, Halon storage tanks, foam concentrator tank, and propane tanks. There are

no tanks specifically called an "expansion" tank. Tanks within the scope of license

renewal are included under the component type of tank in LRA Table 2.3.3-14.

* Jacket cooling water keepwarm pump and heater. There are no jacket cooling water

keepwarm pumps and heaters associated with the fire protection system.

" Lubricating oil collection system components (reactor coolant pumps). The reactor

coolant pump lubricating oil collection system components will be added to the scope of

license renewal.

* Lubricatinq oil cooler. The diesel driven fire pump engine has an integral oil cooler. The

oil cooler is integral to the diesel engine and is evaluated as part of the engine. The

diesel engine is an active component and not subject to an AMR.

" Auxiliary lubricating oil makeup tank. The fire protection system includes the diesel oil

day tank. The diesel oil day tank is within the scope of license renewal and is included

under the component type of tank in LRA Table 2.3.3-14.

* Rocker lubricating oil pump. There are no rocker lubricating oil pumps associated with

the diesel fire pump engine. Rocker oil pumps associated with the emergency diesel

engine system are within the scope of license renewal and are included under the

component type of pump in LRA Table 2.3.3-16.

* Water floor drains. Floor drains are evaluated in the floor and equipment drains system

and oily waste system in LRA Sections 2.3.3.17 and 2.3.3.18.

* Flame retardant coating for cables. There are no flame retardant coatings for cables at

WCGS. Cables are protected by ceramic fiber wraps, which are evaluated as a

structural component type of fire barrier coatings and /or wraps included in the

structures evaluations of LRA Section 2.4.

* Fire barrier penetration seals. Fire barrier penetration seals are evaluated as a structural

component type of fire barrier seals included in the structures evaluations of LRA

Section 2.4.

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* Fire barrier walls, ceilings, floor and slabs. These are structural component type group

elements and are evaluated as a structural component type of concrete elements

included in the structures evaluations of LRA Section 2.4.

* Fire doors. Fire doors are evaluated as a structural component type of fire barrier doors

included in the structures evaluations of LRA Section 2.4.

* Fire rated enclosures. Fire rated enclosures that protect individual component, such as

cable tray, are evaluated as a structural component type of fire barrier coatings and/or

wraps. Fire rated enclosures that protect rooms or buildings are evaluated as a

structural component type of concrete elements or concrete block (masonry walls). All of

these component types are included in the structures evaluations of LRA Section 2.4.

* Fire retardant coating for structural steel supporting wall and concrete. Fire retardant

coating for structural steel supporting wall and concrete are evaluated as a structural

component type of fire barrier coatings and/or wraps included in the structures

evaluations of LRA Section 2.4.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-4 acceptable

because the applicant considered some of these components to be included within commodity

groups. Therefore, the LRA does not list (or is not required to list) all these components

specifically. For example, the applicant grouped the pipe fitting, couplings, threaded

connections, interfaces flanges, and chamber housings under the component type of piping in

LRA Table 2.3.3.-14. The applicant also explained that only components with an intended

function (other than pressure boundary) are listed separately.

In addition, by letter dated August 31, 2007, the applicant amended LRA Tables 2.3.3-14 and

3.3.3.14 to include the engine muffler, sight gauge, and the lubricating oil connection system

(reactor coolant pump) within the scope of license renewal. Therefore, the staff finds that these

components will be adequately managed during the period of extended operation.

The staff finds that the following components were not included in the line item descriptions in

the LRA: heat-actuated devices, tank heaters, water motor alarms, latch door pull box,

pneumatic actuator, and lubricating oil cooler. However, the staff recognizes that the applicant

considers these components as active, which will result in more vigorous oversight of the

condition and performance of the components. The staff concludes that these components

were correctly excluded from the scope of license renewal and are not subject to an AMR.

Therefore, the staff's concern described in RAI 2.3.3.14-4 is resolved.

In RAI 2.3.3.14-5 dated April 3, 2007, the staff noted that the USAR Table 9.5.1-2 lists various

types of fire water suppression systems. The staff requested that the applicant verify whether

the fire water suppression systems in the areas listed below are within the scope of license

renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If not, the staff requested that the applicant provides a justification for their

exclusion.

Manual pre-action sprinkler system:

• north cable penetration (inside containment)

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• south cable penetration (inside containment)

Automatic pre-action sprinkler system:

• fuel building rail road bay

• lower cable spreading room

• upper cable spreading room

* cable trays (auxiliary building elevation 1974'-0," 2000'-0," 2026'-0")

• diesel generator rooms

" area below turbine generator (operating floor and mezzanine floor)

• turbine generator

Manual water spray system:

• auxiliary feedwater pump (turbine driven)

* steam generator feed pump

Automatic wet-pipe sprinkler system:

* turbine lube oil storage room

• auxiliary boiler room

* turbine lube oil reservoir room

" condenser pit (area beneath the main condensers)

" dry waste compactor (radwaste building)

* access control area (control building)

" pipe space and tank area (control building)

* cable area above access control area

* vertical cable chases (auxiliary building)

• vertical cable chases (control building)

* auxiliary feedwater pipe chase area (auxiliary building)

• turbine building outage office

Automatic water spray system:

• hydrogen seal oil unit

* main transformer

* startup transformer

* auxiliary transformer

* station service transformer

• engineered safety feature transformer

In its response dated May 3, 2007, the applicant stated that the various types of fire water

suppression systems are listed below. The first group are those within the scope of license

renewal. The second group are those not within the scope of license renewal. The following fire

water suppression systems are within the scope of license renewal:

Manual pre-action sprinkler system:

* north cable penetration (inside the containment) M-1 2KC02 (C-4)

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0 south cable penetration (inside the containment) M-1 2KC02 (C-4)

Automatic pre-action sprinkler system:

* fuel building rail road bay

" lower cable spreading room

• upper cable spreading room

* cable trays (aux bldg El.1974'-0," 2000', 2026')

* diesel generator rooms

M-12KC03 (A-3)

M-12KC05 (F-3)

M-12KC05 (H-3)

M-12KC05 (D-3, F-6, G-6)

M-12KC02 (G-7, F-7)

Manual water spray system:

0 auxiliary feedwater pump (turbine driven) M-12KC02 (B-2)

Automatic wet-pipe sprinkler system:

0

0

0

S

S

S

0

0

0

0

turbine lube oil storage room

turbine lube oil reservoir room

dry waste compactor (radwaste building)

access control area (control building)

pipe space and tank area (control building)

cable area above access control area

vertical cable chases (auxiliary building)

vertical cable chases (control building)

auxiliary feedwater pipe chase area (auxiliary building)

radwaste storage (not listed in RAI)

M-12KC01 (C-5)

M-12KC01 (C-6)

M-12KC03 (D-3)

M-12KC02 (G-4)

M-12KC05 (E-2)

M-12KC05 (B-7)

M-12KC05 (B-6, B-7)

M-12KC05 (D-3)

M-12KC02 (B-i)

M-12KC03 (G-5)

The following fire water suppression systems are not within the scope of license renewal. These

portions of the fire water suppression system do not support WCGS post-fire safe-shutdown

requirements nor are they identified in the WCGS responses to APCSB 9.5-1, Appendix A, in

USAR Table 9.5A-1.

Automatic Dre-action sprinkler system:

* area below turbine generator (oper. fir & mezz. fir)

* turbine generator

M-12KC01 (A-7, D-4, D-5, D-7)

M-12KC01 (A-5)

Manual water sorav system:

• steam generator feed pump

Automatic wet-pipe sprinkler system:

M-12KC01 (E-5, E-7)

• auxiliary boiler room

* condenser pit (area beneath the main condensers)

• turbine building outage office

M-12KC01 (A-3)

M-12KC01 (A-6)

M-12KC01 (E-5)

Automatic water spray system:

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* hydrogen seal oil unit M-12KC01 (D-3)

* main transformer M-12KC01 (E-2)

* startup transformer M-12KC01 (H-2)

* auxiliary transformer M-12KC01 (D-2)

* station service transformer M-12KC01 (H-5)

* engineered safety feature transformer M-12KC01 (H-7)

The applicant stated that the second group of water suppression systems do not support

WCGS post-fire safe-shutdown requirements nor are they identified in the WCGS responses to

APCSB 9.5-1, Appendix A, in USAR Table 9.5A-1 .The staff finds this contrary to the WCGS

USAR and fire protection SER. WCGS committed to BTP APCSB 9.5-1, Appendix A,

Table 9.5A-1, to satisfy Regulatory Position A.4, "Fire Suppression Systems," by providing

certain equipment for the fire protection program that are also considered important to safety.

The staff finds that the applicant's analysis of the fire protection regulation does not completely

capture the fire protection SSCs required for compliance with 10 CFR 50.48. The scope of

SSCs required for compliance of 10 CFR 50.48 and GDC 3 goes beyond preserving the ability

to maintain safe-shutdown in the event of a fire. GDC 3 states in part, that "fire detection and

fighting systems of appropriate capacity and capability shall be provided and designed to

minimize the adverse effects of fires on structures, systems, and components important to

safety." Furthermore, the general requirements provided in GDC 3 to "minimize the adverse

effects of fires on SSC's important to safety" are stated to provide a general level of protection

which is afforded to all systems, not only where required to prevent a loss of safe-shutdown

capability. Section 50.48(a) of 10 CFR states that, "each operating nuclear power plant must

have a fire protection plan that satisfies Criterion 3 of Appendix A of this part." The term

"important to safety" encompasses a broader scope of equipment than safety-related and

safe-shutdown equipment. Though there is a focus on the protection of safety-related

equipment or safe shutdown equipment, this does not imply that there is an exclusion of any

equipment which protects nonsafety-related equipment. For example, in accordance with

10 CFR 50.48, some portions of suppression systems may be required in plant areas where a

fire could result in the release of radioactive materials to the environment, even if no

safety-related or safe-shutdown equipment is located in that particular fire area.

During a telephone conference dated June 14, 2007, the staff requested that the applicant

justify why these components were not included within the scope of license renewal pursuant to

10 CFR 54.4(a)(3), as some of them are required for compliance with 10 CFR 50.48 and

GDC 3.

In its response dated July 11, 2007, the applicant explained that there are two groups of water

suppression systems. The applicant stated that the group of fire water suppression systems

that are within the scope of license renewal as identified in RAI 2.3.3.14-5 are the systems

required for compliance with 10 CFR 50.48 and GDC 3. The group of fire water suppression

systems that are not within the scope of license renewal as identified in RAI 2.3.3.14-5 are

systems that are used for property protection.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-5 acceptable

because the applicant explained that the second group of water suppression systems are not

credited for 10 CFR 50.48 and GDC 3. These systems are for property protection and for loss

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prevention (not required to be within the scope of license renewal). Therefore, the staff's

concern described in RAI 2.3.3.14-5 is resolved

In RAI 2.3.3.14-6 dated April 3, 2007, the staff noted that the LRA Section 2.3.3.14 discusses

the total flooding Halon 1301 fire suppression system for control room trenches and chases,

switchgear rooms, engineered safety feature switchgear rooms, motor-generator sets room,

and electrical penetration rooms. USAR Table 9.5.1-2 also discusses the total flooding

Halon 1301 fire suppression system for non-vital switchgear and transformer rooms, control

cabinets, and load centers. However, the total flooding Halon 1301 fire suppression system for

non-vital switchgear and transformer rooms, control cabinets, and load centers does not appear

in LRA Section 2.3.3.14 as within the scope of the license renewal. The staff requested that the

applicant verify whether the total flooding Halon 1301 fire suppression system for non-vital

switchgear and transformer rooms, control cabinets, and load centers are within the scope of

license renewal in accordance with 10 CFR 54.4(a) and subject to an AMR in accordance with

10 CFR 54.21 (a)(1). If not, the staff requested that the applicant provides a justification for their

exclusion.

In its response dated May 3, 2007, the applicant stated that the Halon 1301 fire suppression

system for non-vital switchgear and transformer room, control cabinets, and load centers was

evaluated and is within the scope of license renewal in accordance with 10 CFR 54.4(a) and

subject to an AMR in accordance with 10 CFR 54.21 (a)(1). License renewal boundary drawing

LR-WCGS-KC-M12KC04 (locations E-2 & E-6) show the non-vital switchgear and transformer

rooms. License renewal drawing LR-WCGS-KC-M12KC06 (location B-8) show the control

cabinet and load centers.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.14-6 acceptable

because the total flooding Halon 1301 fire suppression systems for the non-vital switchgear and

transformer room, control cabinets, and load centers were identified to be within the scope of

license renewal and subject to an AMR. The staff has reasonable assurance that the total

flooding Halon 1301 systems for the non-vital switchgear and transformer room, control

cabinets, and load centers used for fire suppression will be adequately managed during the

period of extended operation. Therefore, the staff's concern described in RAI 2.3.3.14-6 is

resolved.

2.3.3.14.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the fire protection system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.3.15 Emergency Diesel Engine Fuel Oil Storage and Transfer System

2.3.3.15.1 Summary of Technical Information in the Application

LRA Section 2.3.3.15 describes the emergency diesel engine fuel oil storage and transfer

system, which stores fuel oil onsite, delivers it to the emergency diesel engines as required for

operation during DBEs. The system consists of an underground storage tank with a transfer

pump, day tank, strainers, filters, piping, and valves for each emergency diesel engine.

The emergency diesel engine fuel oil storage and transfer system has safety-related

components relied upon to remain functional during and following DBEs. The failure of

nonsafety-related SSCs in the emergency diesel engine fuel oil storage and transfer system

could prevent the satisfactory accomplishment of a safety-related function. In addition, the

emergency diesel engine fuel oil storage and transfer system performs functions that support

fire protection.

LRA Table 2.3.3-15 identifies emergency diesel engine fuel oil storage and transfer system

component types within the scope of license renewal and subject to an AMR:

* closure bolting

* instrument

" piping

* pump

* strainer

* tank

* tubing

* valve

The intended functions of the emergency diesel engine fuel oil storage and transfer system

component types within the scope of license renewal include:

* filtration

* pressure boundary

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and USAR Section 9.5.4 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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The staff's review of LRA Section 2.3.3.15 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

in RAI 2.3.3.15-1 dated April 3, 2007, the staff stated that a license renewal drawing shows

flame arresters on the emergency fuel oil storage tanks and the emergency fuel oil day tanks

not highlighted as within the scope of license renewal. The staff requested that the applicant

clarify whether these flame arresters should be within the scope of license renewal in

accordance with 10 CFR 54.4(a). If not, the staff requested that the applicant justify their

exclusion.

In its response dated May 2, 2007, the applicant stated that flame arrestors FA-0001A,

FA-0001 B, FA-0002A and FA-0002B, will be added to the scope of license renewal. By letter

dated August 31, 2007, the applicant amended the LRA to include the component type flame

arrestor to LRA Tables 2.3.3-15 and 3.3.2-15.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.15-1 acceptable

because it adequately identified that the flame arrestors should have been included within the

scope of license renewal. The applicant amended the LRA to identify these components as

component types meeting the criteria of 10 CFR 54.4(a). Therefore, the staff's concern

described in RAI 2.3.3.15-1 is resolved.

2.3.3.15.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the emergency diesel engine fuel oil storage and transfer system components that are

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.16 Emergency Diesel Engine System

2.3.3.16.1 Summary of Technical Information in the Application

LRA Section 2.3.3.16 describes the emergency diesel engine system, which supplies

emergency power for the essential loads necessary to shut down, cool, and isolate the reactor.

The emergency diesel engine system provides emergency power in the event of a loss of

offsite power and includes the following four subsystems: emergency diesel engine cooling

water system, emergency diesel engine starting system, emergency diesel engine lubrication

system, and emergency diesel engine combustion air intake and exhaust system.

The emergency diesel engine system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the emergency

diesel engine system could prevent the satisfactory accomplishment of a safety-related

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function. In addition, the emergency diesel engine system performs functions that support fire

protection.

LRA Table 2.3.3-16 identifies emergency diesel engine system component types within the

scope of license renewal and subject to an AMR:

• expansion joint

• filter

* heat exchanger shell side

• heat exchanger tube side

* heater

" insulation

" piping

• pump

" separator

* sight gauge

• silencer

* strainer

" tank

" tubing

" thermowell

* valve

The intended functions of the emergency diesel engine system component types within the

scope of license renewal include:

• filtration

* pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and USAR Sections 8.3.1.1.2, 8.3.1.1.3, 9.5.5, 9.5.6,

9.5.7, and 9.5.8 using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

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The staff's review of LRA Section 2.3.3.16 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.3.16-1 dated April 3, 2007, the staff stated that the standby diesel generator jacket

water expansion tanks are within the safety-related boundary and are highlighted in green in the

license renewal-drawing for meeting the requirements of 10 CFR 54.4(a)(1). Additionally, the

staff noted that each tank has several lines extending from it that appear to be safety-related;

however, these lines are not highlighted and are not shown as within the scope of license

renewal. The staff requested that the applicant justify the exclusion of these lines from the

scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the LRBDs on which the subject

piping is shown are the chemical addition fittings inside of safety-related boundary flags. The

applicant further identified that actual piping lines however, are not safety-related because the

safety-related boundary is at the tank itself. Additionally the applicant stated that, the function of

the piping lines are to provide tank makeup water, an overflow path, and vents. The applicant

stated that these piping connections are above the tank's normal water level and that the tank is

vented to atmosphere. Failure of the piping would not create a leakage path that could drain the

tanks.

During a telephone conference dated June 8, 2007, the staff noted that in the LRA, the standby

diesel generator jacket water expansion tank vents are excluded from the scope of license

renewal and are not subject to an AMR. The staff explained that this is not consistent with the

requirements of 10 CFR 54.4(a)(2) because the tank vents are nonsafety-related components

whose failure could prevent the satisfactory accomplishment of safety functions. On the basis

that the vents allow the exchange of air in response to tank level changes, the staff believes

that they should be within the scope of license renewal and managed to prevent their plugging.

In its response dated July 11, 2007, the applicant stated that it agreed with the staff's position

discussed during the telephone conference. Further, the applicant stated that the vent line for

the emergency diesel engine jacket water expansion tanks will be included within the scope of

license renewal. By letter dated August 31, 2007, the applicant amended LRA Table 2.3.3.16 to

reflect the addition of the vents as generic piping with an intended function of leakage boundary

spatial. The applicant also amended LRA Table 3.3.2-16 to reflect the addition of the vents as

generic piping with an internal environment of wetted gas (internal).

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-1 acceptable

because the applicant adequately included the standby emergency diesel generator jacket

water expansion tank vent piping within the scope of license renewal. Therefore, the staff's

concern described in RAI 2.3.3.16-1 is resolved.

In RAI 2.3.3.16-2 dated April 3, 2007, the staff stated that flexible connections in the standby

diesel generator cooling water system are shown on a license renewal drawing. Additionally,

the staff noted that the flexible connections are within the safety-related boundary and are

shown to be within the scope of license renewal; however, they are not identified in LRA

Tables 2.3.3-16 and 3.3.2-16. The staff requested that the applicant justify the exclusion of the

flexible connections from the scope of license renewal in the jacket cooling water portion of the

emergency diesel engine system.

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In its response dated May 2, 2007, the applicant stated that flexible connections associated with

the standby diesel engine system cooling water system will be added to LRA Tables 2.3.3-16

and 3.3.2-16. By letter dated August 31, 2007, the applicant amended the LRA to include the

component type of flex connectors with an intended function of pressure boundary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-2 acceptable

because the applicant adequately included the flexible connections in question within the scope

of license renewal. Therefore, the staff's concern described in RAI 2.3.3.16-2 is resolved.

In RAI 2.3.3.16-3 dated April 3, 2007, the staff stated that flow orifices in the standby diesel

generator cooling water system are shown on a license renewal drawing. The staff also noted

that the flow orifices are within the safety-related boundary and are shown to be within the

scope of license renewal; however, they are not identified on LRA Tables 2.3.3-16 and

3.3.2-16. The staff requested that the applicant justify the exclusion of the flow orifices from the

scope of license renewal in the jacket cooling water portion of the emergency diesel engine

system.

In its response dated May 2, 2007, the applicant stated that orifices FO0001A, F00101 A,

FO0003A, FO0003B, FO0004A, FO0004B, FO0005A, and FO0005B associated with the

standby diesel engine system meeting the requirements of 10 CFR 54.4(a)(1) will be added to

the scope of license renewal. By letter dated August 31, 2007, the applicant amended LRA

Tables 2.3.3-16 and 3.3.2-16 to include the component type orifice with an intended function of

pressure boundary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-3 acceptable

because it adequately included the flow orifices in question within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.3.16-3 is resolved.

In RAI 2.3.3.16-4 dated April 3, 2007, the staff stated that lube oil auxiliary tanks for the standby

diesel generator lube oil system are shown on license renewal drawings. Additionally, the staff

noted that although these tanks are within the safety-related boundary and are shown as within

the scope of license renewal; however, several lines extending from these tanks are not shown

as within the scope of license renewal. The staff requested that the applicant justify the

exclusion of these lines from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the LRBDs on which the subject

piping is shown are the nonsafety-related tank oil fill, tank overflow, and tank vent lines and that

the safety-related boundary is at the tank itself. The applicant stated that because these piping

lines are not included in this boundary, they are excluded from the scope of license renewal.

The applicant also stated that failure of the piping would not create a leakage path that could

drain the tanks. Additionally, in its response to RAI 2.3.3.16-5 on a related topic, the applicant

explained that the auxiliary lubricating oil makeup tank is not required for at least seven days

after the onset of continuous standby diesel engine operation and that the main engine sump is

designed to provide sufficient oil for at least seven days without replenishment as identified in

USAR Section 9.5.7.2.1.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-4, along with the

information provided in the response to RAI 2.3.3.16-5, acceptable because it adequately

explained that the tank's function is only required beyond seven days after onset of continuous

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standby diesel engine operation. Therefore, the staff's concern described in RAI 2.3.3.16-4 is

resolved.

In RAI 2.3.3.16-5 dated April 3, 2007, the staff stated that standby diesel generator lube oil

expansion tanks are shown on a license renewal drawing as within the safety-related boundary

and within the scope of license renewal. The staff also noted that each tank has a vent line

supporting the operation of the tanks that are excluded from the scope of license renewal. The

staff requested that the applicant justify the exclusion of the vent lines from the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the auxiliary lubricating oil makeup

tank (makeup capability) is not required for at least seven days after the onset of continuous

standby diesel engine operation and that the main engine sump is designed to provide sufficient

oil for at least seven days without replenishment consistent with USAR Section 9.5.7.2.1. The

applicant confirmed that the tank's vent lines have no intended function and are not within the

scope of license renewal. Additionally, the applicant described the tank's configuration and

design basis which provided information that was not available in the LRA.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-5 acceptable

because it adequately explained the design basis for the tank's construction, configuration, and

functions. Therefore, the staff's concern described in RAI 2.3.3.16-5 is resolved.

In RAI 2.3.3.16-6 dated April 3, 2007, the staff stated that flexible connections in the standby

diesel generator lube oil system are shown on a license renewal drawing. The staff noted that

the flexible connections are within the safety-related boundary and are shown to be within the

scope of license renewal. However, they are not identified in LRA Tables 2.3.3-16 and 3.3.2-16.

The staff requested that the applicant justify the exclusion of the flexible connections from the

scope of license renewal in the lube oil portion of the emergency diesel engine system.

In its response dated May 2, 2007, the applicant stated that flexible connections associated with

the standby diesel engine system lube oil system will be added to LRA Tables 2.3.3-16 and

3.3.2-16. By letter dated August 31, 2007, the applicant amended the LRA to include the

component type of flex connectors with an intended function of pressure boundary.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.16-6 acceptable

because it adequately included the flexible connections in question within the scope of license

renewal. Therefore, the concern described in RAI 2.3.3.16-6 is resolved.

2.3.3.16.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the emergency diesel engine system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

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2.3.3.17 Floor and Equipment Drains System

2.3.3.17.1 Summary of Technical Information in the Application

LRA Section 2.3.3.17 describes the floor and equipment drains system, which warns or

activates alarms of potential flooding conditions in the containment, RHR pump rooms, control

building, fuel building, and auxiliary building, and isolates discharge of RHR, auxiliary building,

and control building sumps on the safety injection signal to prevent the pumping of potentially

radioactive water to other parts of the plant. Additionally, the system provides containment

isolation for one piping penetration and collects RCP oil to prevent an oil fire in the reactor

building. The floor and equipment drains system identifies gross pipe ruptures or failures that

could raise the water levels and flood safety-related systems. Safety-related level

instrumentation for the sumps in the auxiliary building, RHR pump rooms, control building, and

containment together with the plant computer determine leak rates in the subject buildings.

Redundant safety-related sump pump discharge isolation valves isolate on any safety injection

system signal and prevent discharge of the control building, auxiliary building, and RHR pump

room sump pumps from leaving the auxiliary building. The floor and equipment drains system

consists of three subsystems: the dirty radwaste drain subsystem, the clean radwaste drain

subsystem, and the leak detection subsystem, piping, valves, and instrumentation.

The floor and equipment drains system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the floor and

equipment drains system could prevent the satisfactory accomplishment of a safety-related

function. In addition, the floor and equipment drains system performs functions that support fire

protection, SBO, and EQ.

LRA Table 2.3.3-17 identifies floor and equipment drains system component types within the

scope of license renewal and subject to an AMR:

* bellows

* closure bolting

* flame arrestor

* piping

* sight gauge

* tank

• tubing

* valve

The intended functions of the floor and equipment drains system component types within the

scope of license renewal include:

• pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

" maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

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2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17 and USAR Section 9.3.3 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.17.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

floor and equipment drains system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.3.18 Oily Waste System

2.3.3.18.1 Summary of Technical Information in the Application

LRA Section 2.3.3.18 describes the oily waste system, which has safety-related indicators in the

basement of the control building and in the diesel generator room to indicate potential flooding

conditions in those areas. These level indicators indicate events which could prevent the

capability to shut down the reactor and maintain it in a safe shutdown condition. The oily waste

system collects nonradioactive potentially oily liquid waste from the turbine building, diesel

generator building, communications corridor, control building, and selected areas of the

auxiliary building. Other floor and equipment drains are scoped as part of the floor and

equipment drains system and miscellaneous drains system. The oily waste system detects

gross water leakage and/or accumulation in the diesel generator and control building oily waste

sumps and alerts station operators. The portion of the oily waste system serving the control

room includes a loop seal that facilitates control room pressurization. The portion of the oily

waste system serving the containment mini-purge supply unit includes a loop seal that prevents

flow of air through the oily waste system. The loop seals and piping are classified as

nonsafety-related.

The oily waste system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SSCs in the oily waste system could

prevent the satisfactory accomplishment of a safety-related function.

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LRA Table 2.3.3-18 identifies oily waste system component types within the scope of license

renewal and subject to an AMR:

* closure bolting

* piping

* valve

The intended function of the oily waste system component types within the scope of license

renewal is to maintain mechanical and structural integrity to prevent spatial interactions that

could cause failure of safety-related SSCs.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and USAR Section 9.3.3.2.1.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.18 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.18-1 dated April 3, 2007, the staff stated that license renewal drawings show piping

from the discharge of the auxiliary feed pump room sump pumps and the diesel generator

building sump pumps as nonsafety-related components affecting safety-related components

due to spatial interaction. However, the staff noted that the pumps themself are not designated

as nonsafety-related components affecting safety-related components even though they appear

to be in close proximity to safety-related components. The staff requested that the applicant

provides a description of the portions of the nonsafety-related oily waste system that are within

the scope of license renewal in accordance with 10 CFR 54.4(a)(2) due to spatial interaction. In

addition, the staff requested that the applicant discuss the reason for terminating the scoping

boundaries where indicated.

In its response dated May 2, 2007, the applicant stated that the discharge of the auxiliary feed

pump room sump pumps is within the scope of license renewal from the floor between area 115

(room 1128) and area 125, and ends at the wall between the auxiliary building and the turbine

building. The applicant stated, for the auxiliary feed pump room sump pump discharge piping,

that there are no safety-related components in the turbine building that would be affected by

spatial interactions with the auxiliary feed pump room sump pump discharge piping.

Additionally, the applicant explained that the sump pumps are submerged below the floor

elevation of room 1128 and are enclosed by the sump covers; therefore, do not have spatial

interaction with safety-related components above the floor. The applicant explained that

although there are no safety-related components in room 1128 that would be affected by the

sump pumps discharge lines, it was determined that the oily waste system piping in room 1128

will be added to the scope of license renewal due to potential interaction with safety-related

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components in the adjacent room 1122 and will include piping from the sump covers to the

piping currently highlighted on drawing LR-WCGS-LE-M-1 2LE01.

For the discharge of diesel generator building sump pumps PLE06A/B/C/D, the applicant

explained that piping is within the scope of license renewal from the sump covers in area 511

through area 132 in the auxiliary building where the discharge lines are merged, and ends at

the penetration between area 132 and area 332. Additionally, the applicant explained that there

are no safety-related components in area 332 that would be affected by the sump pump

discharge lines and that the diesel generator building sump pumps are submerged below the

floor elevation and are enclosed by the sump covers. Therefore, they do not have spatial

interaction with safety-related components above the floor.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.18-1 acceptable

because it adequately explained the reasons for terminating the scoping boundaries for the

auxiliary feedwater pump room sump pump discharge piping and the diesel generator building

sump pump discharge piping indicated on the LRBDs. Additionally the applicant expanded the

scoping boundaries on the discharge piping of the auxiliary feedwater pump room sump pumps

due to potential spatial interaction. Therefore, the staff's concern described in RAI 2.3.3.18-1 is

resolved.

2.3.3.18.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the oily waste system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.3.3.19 Cranes, Hoists and Elevators System

2.3.3.19.1 Summary of Technical Information in the Application

LRA Section 2.3.3.19 describes the cranes, hoists, and elevators system, which supports and

restrains the equipment hatch missile shield for containment to be operable. The reactor

building houses and supports the reactor, reactor coolant piping, steam generators, pressurizer,

RCPs, accumulators, and the containment air coolers. It protects these SSCs from external

hazards and contains radioactive material after a design-basis accident. The reactor building

must prevent and mitigate the consequences of accidents that could cause offsite exposure.

The cranes, hoists, and elevators system provides lifting and maneuvering capacity in the

containment building, fuel building, diesel generator building, auxiliary building, and various

nonsafety-related buildings and shops about the site. This system is composed of multiple

cranes, doors, elevators, hoists, monorails, man-lifts, and trolleys.

The cranes, hoists and elevators system has safety-related components relied upon to remain

functional during and following DBEs. The failure of nonsafety-related SSCs in the cranes,

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hoists, and elevators system could prevent the satisfactory accomplishment of a safety-related

function.

LRA Table 2.3.3-19 identifies cranes, hoists and elevators system component types within the

scope of license renewal and subject to an AMR:

* crane

* hoist (including monorail)

* trolley

The intended functions of the cranes, hoists, and elevators system component types within the

scope of license renewal include:

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 and USAR Section 3.8.2.1.1 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.3.19.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

cranes, hoists, and elevators system components that are within the scope of license renewal,

as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.20 Turbine Building HVAC System

2.3.3.20.1 Summary of Technical Information in the Application

LRA Section 2.3.3.20 describes the turbine building HVAC system, which isolates the auxiliary

building HVAC system upon receipt of a safety injection signal, and as such is safety-related.

The turbine building HVAC system consists of the following nine subsystems:

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* main building HVAC

• lube oil room HVAC

* computer room HVAC

* instrument shop HVAC

" condenser air removal filtration subsystem

* battery room HVAC

• electrohydraulic control cabinet alternating current (A/C)

* oxygen control and pH control chemical storage A/C subsystem

* turbine deck office mezzanine room A/C

The main building HVAC provides outside air for ventilation and cooling of the turbine building.

The lube oil room HVAC provides outside air for ventilation, cooling, and heating as required for

equipment in the lube oil room. The computer room and instrument shop HVAC maintains a

suitable environment for personnel and equipment. The condenser air removal filtration

subsystem collects and processes the noncondensable gases from the condenser. The battery

room HVAC is used for dilution of hydrogen emitted by the batteries. The electrohydraulic

control cabinet A/C provides room air-conditioning for a suitable environment for equipment.

The oxygen control and pH control chemical storage A/C subsystem provides room cooling and

exhausts air from fume hoods. The turbine deck office mezzanine room A/C provides a suitable

environment for personnel comfort.

The turbine building HVAC system has safety-related components relied upon to remain

functional during and following DBEs. In addition, the turbine building HVAC system performs

functions that support fire protection and EQ.

LRA Table 2.3.3-20 identifies turbine building HVAC system component types within the scope

of license renewal and subject to an AMR:

* closure bolting

" damper

* ductwork

" flex connector

The intended functions of the turbine building HVAC system component types within the scope

of license renewal include:

" rated fire barrier to confine or retard a fire from spreading

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20 and USAR Section 9.4.4 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

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intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.3.20 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.20-1 dated April 18, 2007, the staff requested that the applicant clarify if the

damper housings, fire dampers, and fire damper housings are within the scope of license

renewal.

In its response dated May 2, 2007, the applicant stated that the component types that are

subject to an AMR and are highlighted in license renewal drawings LR-WCGS-GE-M-12GE01

and LR-WCGS-GE-M-12GE02 are included in the component types listed in LRA

Table 2.3.3-20. The applicant clarified that the damper housings, including the fire damper

housings, are included within the category or commodity group of damper.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.20-1 acceptable

because it clarified that the damper housings are within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.3.20-1 is resolved.

2.3.3.20.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI response to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the turbine building HVAC system components that are within the scope of license

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by

10 CFR 54.21 (a)(1).

2.3.3.21 Systems Within the Scope of License Renewal Based Only on the Criterion of

10 CFR 54.4(a)(2)

2.3.3.21.1 Summary of Technical Information in the Application

LRA Section 2.3.3.21 describes the miscellaneous auxiliary systems within the scope of license

renewal only for criterion 10 CFR 54.4(a)(2) (for nonsafety-related SSC), including:

* service water system

• ESW chemical addition system

* chemical and detergent waste system

* gaseous radwaste system

* demineralized water makeup storage and transfer system

* domestic water system

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" plant heating system

* boron recycle system

" central chilled water system

" yard drainage system

* secondary liquid waste system

The service water system provides cooling water to plant auxiliary equipment during normal

plant operations and normal plant shutdown and transfers the heat to the circulating water

system, the UHS, and the ESWS. The ESW chemical addition system provides for the chemical

treatment of the ESWS to prevent organic fouling. The chemical and detergent waste system

collects chemical, wash-down, and detergent waste from plant facilities and transfers the waste

for processing and recycling. The gaseous radwaste system controls, collects, processes,

stores, and disposes of gaseous radioactive wastes generated by normal operation, including

anticipated operational occurrences.

The demineralized water makeup storage and transfer system stores water for use upon

demand for makeup within the plant. The domestic water system provides chlorinated potable

water for drinking, cooking, showers, laundry, and toilet facilities within the standardized power

block. The plant heating system heats air to maintain a suitable environment for personnel and

equipment. The boron recycle system receives reactor coolant effluent for storage until its

reuse or disposal by processing through the liquid radwaste system. The central chilled water

system cools air handling equipment so plant ventilation can maintain a suitable environment

for personnel and equipment.

The yard drainage system transfers accumulated water in-leakage from various below-grade

electrical manholes, the ESW "B" train valve house, and the turbine building cable pit sump to

the site storm drainage system. The secondary liquid waste system processes and recycles

turbine building waste and condensate demineralizer regeneration waste products back to the

condenser or discharges waste to the environment if within the limits of release.

The failure of nonsafety-related SSCs in the miscellaneous auxiliary systems in-scope only for

criterion 10 CFR 54.4(a)(2) could prevent the satisfactory accomplishment of a safety-related

function.

LRA Table 2.3.3-21 identifies miscellaneous auxiliary, systems in-scope only for criterion

10 CFR 54.4(a)(2) component types within the scope of license renewal and subject to an AMR:

* closure bolting

* flow element

* orifice

" piping

* pump

" strainer

* tank

* tubing

* valve

The intended functions of the miscellaneous auxiliary systems in-scope only for criterion

10 CFR 54.4(a)(2) component types within the scope of license renewal include:

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" pressure boundary

" maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* structural and/or functional support to safety-related components

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.3.21.2 Staff Evaluation

The staff reviewed the service water system, as described in LRA Section 2.3.3.21 and USAR.

Sections 9.2.1, using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the service water system as described in LRA Section 2.3.3.21A, identified

areas in which additional information was necessary to complete the review of the applicant's

scoping and screening results. The applicant responded to the staff's RAIs as discussed below.

in RAI 2.3.3.21-1 dated April 3, 2007, the staff noted that LRA Section 2.3.3.21 states that

systems meeting the criterion of 10 CFR 54.4(a)(2) are within the scope of license renewal and

that each mechanical system was reviewed to determine whether safety-related systems could

be impacted adversely by nonsafety-related portions of systems. In part 1 of the RAI, the staff

noted that a license renewal drawing for the nonsafety-related service water system shows

system portions highlighted in red and ending with no further explanation. The staff requested

that the applicant provides a description of the portions of the nonsafety-related service water

system that are within the scope of license renewal for meeting the requirements of

10 CFR 54.4(a)(2) due to spatial interaction.

In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawing LR-WCGS-EA-M-12EA01, service water system components are within the scope of

license renewal for meeting the requirements for 10 CFR 54.4(a)(2) due to spatial interaction

and that fluid-filled service water components have spatial interaction with safety-related

components in the auxiliary building and in the control building. The applicant further explained

that service water system piping lines EA002HBD-30, EA003HBD-30, EA058HBD-30 and

EA059HBD-30 shown on this license renewal drawing are within the scope of license renewal

because they provide structural integrity to attached safety-related piping in the control building.

The boundary for this piping ends where they become buried between the control building and

the communication corridor.

The applicant also stated that service water system piping lines EA004HBD-6 and

EA005HBD-6 shown on license renewal drawing LR-WCGS-EA-M-12EA01 have their spatial

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interaction termination points where the fluid-filled piping exits the auxiliary building and enters

the turbine building since the turbine building contains no safety-related components.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 1,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Therefore, the staff's concern described in RAI 2.3.3.21-1,

part 1, is resolved.

The staff reviewed the ESWS chemical addition system as described in LRA Section 2.3.3.21

and USAR Section 9.2.1 using the evaluation methodology described in SER Section 2.3 and

the guidance in SRP-LR Section 2.3.

During its review, the staff verified the system functions described in the LRA and USAR to

ensure that the applicant has not omitted from the scope of license renewal any components

with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then verified those

components that the applicant has identified as within the scope of license renewal to ensure

that the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff reviewed the chemical and detergent waste system as described in LRA

Section 2.3.3.21 and USAR Section 9.3.3 using the evaluation methodology described in SER

Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the chemical and detergent waste system as described in LRA

Section 2.3.3.21 C, identified an area in which additional information was necessary to complete

the review of the applicant's. scoping and screening results. The applicant responded to the

staff's RAI as discussed below.

In RAI 2.3.3.21-1, part 2, dated April 3, 2007, the staff noted that a license renewal drawing for

the chemical and detergent waste system shows system portions highlighted in red and ending

with no further explanation. The staff requested that the applicant provides a description of the

portions of the chemical and detergent waste system that are within the scope of license

renewal for meeting the requirements of 10 CFR 54.4(a)(2) due to spatial interaction.

In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawing LR-WCGS-LD-M-12LD01, chemical and detergent waste system components are

within the scope of license renewal for meeting the requirements of 10 CFR 54.4(a)(2) due to

spatial interaction and that fluid-filled chemical and detergent waste system components have

spatial interaction with safety-related components in the auxiliary building and in the control

building.

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The applicant also stated that the chemical and detergent waste system piping lines

LD042HCD-2 and LD027HCD-3 shown on this drawing have spatial interaction termination

points where the fluid-filled piping lines leave the auxiliary building and enter the radwaste

tunnel, which has no safety-related equipment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 2,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Therefore, the staff's concern described in RAI 2.3.3.21-1,

part 2 is resolved.

The staff reviewed the gaseous radwaste system as described in LRA Section 2.3.3.21 and

USAR Sections 9.3.4 and 11.3 using the evaluation methodology described in SER Section 2.3

and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff reviewed the demineralized water makeup storage transfer system as described in

LRA Section 2.3.3.21 and USAR Section 9.2.3 using the evaluation methodology described in

SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the demineralized water makeup storage and transfer system as described

in LRA Section 2.3.3.21 E, identified an area in which additional information was necessary to

complete the review of the applicant's scoping and screening results. The applicant responded

to the staff's RAI as discussed below.

In RAI 2.3.3.21-1, part 3, dated April 3, 2007, the staff noted that a license renewal drawing for

the demineralized water makeup storage and transfer system shows system portions

highlighted in red and ending with no further explanation. The staff requested that the applicant

provides a description of the portions of the demineralized water makeup storage and transfer

system that are within the scope of license renewal for meeting the requirements of

10 CFR 54.4(a)(2) due to spatial interaction.

In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawing LR-WCGS-AN-M-12AN01, demineralized water storage and transfer system

components are within the scope of license renewal for meeting the requirements of

10 CFR 54.4(a)(2) due to spatial interaction and that fluid-filled demineralized water storage

and transfer system components have spatial interaction with safety-related components in the

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auxiliary building. The applicant further explained that demineralized water storage and transfer

system piping line AN042HCD-3 shown on this drawing has spatial interaction termination

points where the fluid-filled piping line leaves the auxiliary building and enter the radwaste pipe

tunnel and where the fluid-filled piping line leaves the auxiliary building and enters the turbine

building, which has no safety-related equipment.

The applicant also stated that demineralized water storage and transfer system piping line

AN050HCD-4 has a spatial interaction termination point where the fluid-filled piping line leaves

the auxiliary building and enters the communications corridor, which has no safety-related

equipment.

The applicant also stated that stated that demineralized water storage and transfer system

piping line AN028HCD-2 has a spatial interaction termination point where the fluid-filled piping

line leaves the auxiliary building and enters the radwaste tunnel, which has no safety-related

equipment.

The applicant lastly stated that demineralized water storage and transfer system piping lines

AN004HCD-1, AN01 5HCD-2 and AN01 9HCD-1 have spatial interaction termination points

where the fluid-filled piping lines leave the turbine building enter the auxiliary building and then

re-enter the turbine building, which has no safety-related equipment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 3,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Therefore, the staff's concern described in RAI 2.3.3.21-1,

part 3, is resolved.

The staff reviewed the domestic water system as described in LRA Section 2.3.3.21 and USAR

Section 9.2.4 using the evaluation methodology described in SER Section 2.3 and the guidance

in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the domestic water system as described in LRA Section 2.3.3.21 F,

identified an area in which additional information was necessary to complete the review of the

applicant's scoping and screening results. The applicant responded to the staff's RAI as

discussed below.

In RAI 2.3.3.21-1, part 4, dated April 3, 2007, the staff noted that a license renewal drawing for

the domestic water system shows system portions highlighted in red and ending with no further

explanation. The staff requested that the applicant provides a description of the portions of the

domestic water system that are within the scope of license renewal for meeting the

requirements of 10 CFR 54.4(a)(2) due to spatial interaction.

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In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawings LR-WCGS-KD-M-12KD01 and LR-WCGS-KD-M-12KD02, domestic water system

components are within the scope of license renewal for meeting the requirements of

10 CFR 54.4(a)(2) due to spatial interaction and that fluid-filled domestic water system

components have spatial interaction with safety-related components in the auxiliary building, the

control building and the fuel building.

The applicant further explained that domestic water system boundary drawings

LR-WCGS-KD-M12KDO1 and LR-WCGS-KD-M-12KD02 have been revised to clarify domestic

water component spatial interaction ends points and has provided revised drawings.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 4,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Therefore, the staff's concern described in RAI 2.3.3.21-1,

part 4, is resolved.

The staff reviewed the plant heating system as described in LRA Section 2.3.3.21 and USAR

Sections 9.4.9 and 9.5.9 using the evaluation methodology described in SER Section 2.3 and

the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the plant heating system as described in LRA Section 2.3.3.21 G, identified

an area in which additional information was necessary to complete the review of the applicant's

scoping and screening results. The applicant responded to the staff's RAI as discussed below.

In RAI 2.3.3.21-1, part 5, dated April 3, 2007, the staff noted that a license renewal drawing for

the plant heating system, shows system portions highlighted in red and ending with no further

explanation. The staff requested that the applicant provides a description of the portions of the

plant heating system that are within the scope of license renewal for meeting the requirements

of 10 CFR 54.4(a)(2) due to spatial interaction.

In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawing LR-WCGS-GA-M-12GA02, plant heating system components are within the scope of

license renewal for meeting the requirements of 10 CFR 54.4(a)(2) due to spatial interaction

and that fluid-filled plant heating system components have spatial interaction with safety-related

components in the auxiliary building, the control building, and the fuel building.

The applicant further explained that plant heating system piping lines GA095HBD-3 and

GA096HBD-3 as shown on this drawing have spatial interaction termination points where

fluid-filled piping leaves the auxiliary building and enters the radwaste tunnel, which has no

safety-related equipment.

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The applicant also explained that plant heating system piping lines GA064HBD-1 1⁄22 and

GA065HBD-1 1/2 have spatial interaction termination points where the fluid-filled piping

transitions from auxiliary building, BLA1 33 to 136, which contains no safety-related equipment.

In its response, the applicant provided additional isometric drawings referenced in

LR-WCGS-GA-M-1 2GA02 for these piping lines, which depict penetration points.

Lastly, the applicant stated that plant heating system piping lines GA003HBD-6 and

GA090HBD-6 have spatial interaction termination points where the fluid-filled piping transitions

from the auxiliary building to the communications corridor, which contains no safety-related

equipment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 5,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Additionally, the applicant provided drawings that identify

piping penetrations for areas in the auxiliary building that contains no safety-related

components. Therefore, the staff's concern described in RAI 2.3.3.21-1, part 5, is resolved.

The staff reviewed the boron recycle system as described in LRA Section 2.3.3.21 and USAR

Section 9.3.6 using the evaluation methodology described in SER Section 2.3 and the guidance

in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions pursuant tol 0 CFR 54.4(a). The staff then reviewed those components that

the applicant identified as within the scope of license renewal to verify that the applicant has not

omitted any passive and long-lived components subject to an AMR in accordance with the

requirements of 10 CFR 54.21 (a)(1).

The staff reviewed the central chilled water system as described in LRA Section 2.3.3.21 and

USAR Section 9.4.10 using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the central chilled water system as described in LRA Section 2.3.3.21,

identified an area in which additional information was necessary to complete the review of the

applicant's scoping and screening results. The applicant responded to the staff's RAI as

discussed below.

In RAI 2.3.3.21-1, part 6, dated April 3, 2007, the staff noted that a license renewal drawing for

the central chilled water system shows system portions highlighted in red and ending with no

further explanation. The staff requested that the applicant provides a description of the portions

of the central chilled water system that are within the scope of license renewal for meeting the

requirements of 10 CFR 54.4(a)(2) due to spatial interaction.

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In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawing LR-WCGS-GB-M-12GBO1, central chilled water system components are within the

scope of license renewal for meeting the requirements of 10 CFR 54.4(a)(2) due to spatial

interaction and that fluid-filled central chilled water system components have spatial interaction

with safety-related components in the auxiliary building.

The applicant further explained that the central chilled water system piping lines GB061 HBD-3

and GB072HBD-3 shown on this drawing have spatial interaction termination points where the

fluid-filled piping transitions from the auxiliary building to the radwaste tunnel, which contains no

safety-related equipment.

The applicant also explained that the central chilled water system piping lines GB037HBD-1

and GB038HBD-1 have spatial interaction termination points where the fluid-filled piping

transitions from auxiliary BLA 133 to 136, which contains no safety-related equipment. In its

response, the applicant provided additional isometric drawings referenced in

LR-WCGS-GA-M-12GBO1 for these piping lines, which depict penetration points.

The applicant also explained that the central chilled water system piping line GB065HBD-8 has

a spatial interaction termination point where the fluid-filled piping transitions from the auxiliary

building to the communications corridor, which has no safety-related equipment.

The applicant also explained the central chilled water system piping line GBO08HBD-8 has a

spatial interaction termination point where the fluid-filled piping transitions from the auxiliary

building to the communications corridor, which has no safety-related equipment. Also, the

central chilled water system piping lines GBO16HBD-1 1/2 and GBO15HBD-1 1/2 have spatial

interaction termination points where fluid-filled piping transitions from the control building to the

communications corridor, which contains no safety-related equipment.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 6,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Additionally, the applicant provided drawings that identify

piping penetrations for areas in the auxiliary building that contains no safety-related

components. Therefore, the staff's concern described in RAI 2.3.3.21-1, part 6, is resolved.

The staff reviewed the yard drainage system as described in LRA Section 2.3.3.21 the site

storm drain system as described in USAR Section 2.4.2 using the evaluation methodology

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff reviewed the secondary liquid waste system as described in LRA Section 2.3.3.21 and

USAR Section 10.4 using the evaluation methodology described in SER Section 2.3 and the

guidance in SRP-LR Section 2.3.

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During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of the secondary liquid waste system as described in LRA Section 2.3.3.21,

identified an area in which additional information was necessary to complete the review of the

applicant's scoping and screening results. The applicant responded to the staff's RAI as

discussed below.

In RAI 2.3.3.21-1, part 7, dated April 3, 2007, the staff noted that license renewal drawings for

the secondary liquid waste system shows system portions highlighted in red and ending with no

further explanation. The staff requested that the applicant provides a description of the portions

of the secondary liquid waste system that are within the scope of license renewal for meeting

the requirements of 10 CFR 54.4(a)(2) due to spatial interaction.

In its response dated May 2, 2007, the applicant stated that, as shown on license renewal

drawings LR-WCGS-HF-M-12HF01, LR-WCGS-HF-M-12HF02 and LR-WCGS-HF-M-12HF03,

secondary liquid waste system components are within the scope of license renewal for meeting

the requirements of 10 CFR 54.4(a)(2) due to spatial interaction and that fluid-filled secondary

liquid waste system components have spatial interaction with safety-related components in the

auxiliary building.

The applicant further stated that the secondary liquid waste system piping lines HF275HCD-2

shown on drawing LR-WCGS-HF-M-12HF01 and HF165HCD-3 shown on drawing

LR-WCGS-HF-M-12HF03 have spatial interaction termination points where the fluid-filled piping

transitions from the communications corridor, which has no safety-related equipment to the

auxiliary building. The applicant further explained that these piping lines also have spatial

interaction termination points where the fluid-filled piping transitions from the auxiliary building

to the radwaste tunnel, which has no safety-related equipment.

The applicant also stated that the secondary liquid waste system piping line HF1 07-HBD-3

shown on LR-WCGS-HF-M-12HF02 has a spatial interaction termination point where the

fluid-filled piping transitions from the auxiliary building to the radwaste tunnel, which has no

safety-related components. The applicant further explained that this piping line also has a

spatial interaction termination point where the fluid-filled piping transitions from the auxiliary

building to the turbine building, which contains no safety-related piping.

Based on its review, the staff finds the applicant's response to RAI 2.3.3.21-1, part 7,

acceptable because it adequately explains the reasons for terminating the scoping boundaries

at the various points in question. Therefore, the staff's concern described in RAI 2.3.3.21-1,

part 7, is resolved.

2.3.3.21.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

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omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the miscellaneous auxiliary systems in-scope only for criterion 10 CFR 54.4(a)(2)

components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4 Steam and Power Conversion Systems

In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversion

systems that are subject to an AMR for license renewal.

The applicant described the supporting SCs of the steam and power conversion systems in the

following LRA sections:

* 2.3.4.1 main turbine system

" 2.3.4.2 main steam system

• 2.3.4.3 feedwater system

• 2.3.4.4 condensate system

* 2.3.4.5 steam generator blowdown system

" 2.3.4.6 auxiliary feedwater system

The staff's review findings regarding LRA Sections 2.3.4.1 - 2.3.4.6 are presented in SER

Sections 2.3.4.1 - 2.3.4.6, respectively.

2.3.4.1 Main Turbine System

2.3.4.1.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the main turbine system, which converts steam thermal energy

from the main steam system to mechanical energy to drive the main generator. The system

consists of a high-pressure turbine, three low-pressure turbines, four main steam stop valves,

four control valves, four moisture separator reheaters, six combined intermediate valves,

strainers, turbine shaft turning gear, piping, valves, and instrumentation for monitoring and

turbine trip purposes.

The main turbine system performs functions that support fire protection and ATWS.

LRA Table 2.3.4-1 identifies main turbine system component types within the scope of license

renewal and subject to an AMR:

• closure bolting

* piping

* valve

The intended function of the main turbine system component types within the scope of license

renewal is to provide a pressure boundary.

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2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and USAR Sections 10.2 and 7.2 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

*intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.4.1.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

main turbine system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.2 Main Steam System

2.3.4.2.1 Summary of Technical Information in the Application

LRA Section 2.3.4.2 describes the main steam system, which removes heat from the RCS for

controlled cooldown during normal, accident, and post-accident conditions. Portions of the main

steam system provide containment isolation and overpressure protection for the secondary side

of the steam generators and the main steam piping. The auxiliary turbines subsystem of the

main steam system also provides steam as a motive force to support the operation of the

turbine-driven feedwater pump and auxiliary feedwater pumps. The auxiliary steam subsystem

is designed to provide the steam required for plant heating and for operation of the waste

evaporator. In the event of fire in some fire areas, nonsafety-related isolation valves that

interface with main steam lines are relied on to prevent uncontrolled RCS cooldown from steam

flow. The main steam system includes the auxiliary steam subsystem and the auxiliary turbines

subsystem. The main steam system consists of the piping systems that convey steam from the

steam generators to the turbine-generator system, the branches that supply steam to the main

feedwater pump turbines, auxiliary feedwater pump turbine, reheaters, and main turbine gland

seals. Each main steam line has one power-operated atmospheric relief valve, five

spring-loaded safety valves, one main steam isolation valve (MSIV) and its bypass, a cross-tie

header downstream of the MSIVs, and vent and drain valves. The steam piping system from

the MSIVs to the main turbine is evaluated with the main turbine system. The steam to the main

turbine gland seals is evaluated in turbine/generator auxiliaries.

The main steam system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SSCs in the main steam system could

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prevent the satisfactory accomplishment of a safety-related function. In addition, the main

steam system performs functions that support fire protection, SBO, and EQ.

LRA Table 2.3.4-2 identifies main steam system component types within the scope of license

renewal and subject to an AMR:

* closure bolting

* insulation

" orifice

* piping

* strainer

* trap

* tubing

* turbine

* valve

" flex hoses

" pump

* sight glass

* silencer

* tank

The intended functions of the main steam system component types within the scope of license

renewal include:

* flow restriction

* filtration

* heat loss control

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

direct flow

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and USAR Sections 10.3, 10.4.4, 7.3.8, 7.4, and 9.5.9

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR

Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

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the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.2 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.4.2-1 dated April 3, 2007, the staff stated that a license renewal drawing shows four

atmospheric relief valves silencers excluded from the scope of license renewal. The staff noted

that the silencers are attached to piping which are within the scope of license renewal in

accordance with 10 CFR 54.4(a)(2). The staff requested that the applicant explain why the

silencers are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The

staff also requested that the applicant describe the physical configuration of the silencers such

that if they fail they will not prevent the atmospheric relief valves from performing their intended

function.

In its response dated May 2, 2007, the applicant stated that the nonsafety-related atmospheric

relief valve exhaust pipes are within the scope of license renewal as required by

10 CFR 54.4(a)(2) based on the possibility of spatial interaction with safety-related components

in the area. The applicant further explained that the exhaust pipes are of seismic category Il/I

and that the silencers connected to the end of the exhaust pipes are located on the roof area

and do not have spatial interaction effects on any safety-related components. Additionally the

applicant explained that the silencers do not provide any support for the structural integrity of

any safety-related component and that based on the details of the location and structural

supports of the exhaust silencers on the roof area, the failure of the silencers will not prevent

the atmospheric relief valves from performing their intended function.

During a telephone conference dated June 8, 2007, the staff explained that the response did

not adequately address the potential effects of a degraded atmospheric relief valve exhaust

silencer on the intended function of the atmospheric relief valves. The staff finds that the

applicant's response is not consistent with the requirements of 10 CFR 54.4(a)(2) because the

atmospheric relief valve silencers are nonsafety-related components whose failure could

prevent the satisfactory accomplishment of safety functions. The atmospheric relief valves have

an intended function meeting 10 CFR 54.4(a)(1)(ii) in order to maintain a safe shutdown

condition. The staff believes that if the relief valve's exhaust paths were impeded by degraded

silencers the valve's intended function would be affected and; therefore, the silencers should

also be within the scope of license renewal.

In its response dated July 11, 2007, the applicant stated that it agreed with the staff's position.

Further, the applicant stated that the atmospheric relief valves exhaust silencers (in addition to

exhaust pipes) will be included within the scope of license renewal. By letter dated

August 31, 2007, the applicant amended LRA Table 2.3.4-2 to reflect the addition of the

silencers as a component type with an intended function of direct flow. The applicant also

amended LRA Table 3.4.2-2 to reflect the addition of the silencers as a component type with an

internal environment of wetted gas (internal) and an external environment of atmosphere and

weather.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-1 acceptable

because the applicant included the atmospheric relief valves exhaust silencers within the scope

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of license renewal and subject to an AMR. Therefore, the staff's concern described in

RAI 2.3.4.2-1 is resolved.

In RAI 2.3.4.2-2 dated April 3, 2007, the staff stated that a license renewal drawing shows

steam traps excluded from the scope of license renewal. The staff noted that the steam traps

are attached to 2-inch lines. The staff requested that the applicant explain why these four steam

traps are not within the scope of license renewal in accordance with 10 CFR 54.4(a)(3).

In its response dated May 2, 2007, the applicant stated that the steam traps are attached to

1-inch lines through 2-inch by 1-inch reducers installed upstream of the steam traps. The

applicant explained that one specific event, which causes the main steam lines in the turbine

building required to support a post-fire safe-shutdown, is a fire in the main steam tunnel that

causes two main steam lines to fail to isolate. The applicant explained that the valves in the

turbine building would be closed to isolate the main steam and prevent a rapid depressurization

of the secondary side, resulting cooldown of the primary side, and potential return to criticality

and that the failure of a 1-inch line, and even several 1 -inch lines, was considered and

determined to be insignificant. Additionally, the applicant explained that throttling one or both

atmospheric relief valves closed to control depressurization could easily compensate for the

loss of steam due to this event.

The applicant explained that the 1-inch lines associated with the subject steam traps are not

components required for post-fire safe-shutdown; therefore, are not included within the scope of

license renewal pursuant to 1OCFR54.4(a)(3). The steam traps only allow the condensation to

pass to the drain lines during normal operation or post-fire shutdown, and steam flow through

the traps is isolated as designed.

During a telephone conference dated June 8, 2007, the staff explained that the response did

not adequately address the function of the steam traps as a pressure boundary with respect to

10 CFR 54.4(a)(3) in the main steam system. Further, the staff asked that the applicant clarify

whether there is an analysis or calculation that serves as the basis for the exclusion of these

steam traps from the scope of license renewal.

In its response dated July 11, 2007, the applicant stated that the current WCGS licensing basis

for post-fire safe-shutdown includes calculation XX-E-01 3 "Post-Fire Safe Shutdown Analysis."

The applicant explained that this calculation evaluates the failures of components in the turbine

building on lines of 1-inch or less and concludes that these failures would not adversely affect

the main steam system's intended function. Further, the applicant identified that the steam traps

discussed in this RAI are located on lines of 1-inch or less and; therefore, their failure would not

adversely affect the main steam system and its intended functions.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-2 acceptable

because the applicant has adequately identified the calculation as the basis for evaluating the

failures of components of 1-inch or less and their exclusion from the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.4.2-2 is resolved.

In RAI 2.3.4.2-3 dated April 3, 2007, the staff stated that a license renewal drawing has a note

stating "to be evaluated in LRID AE, Feedwater System" which points to reference continuation

flags to other drawings. The staff requested that the applicant explain why the note references

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LRID AE, when these two drawings have been associated and evaluated within the main steam

system for license renewal.

In its response dated May 2, 2007, the applicant stated that the note in question is incorrect.

The applicant stated that when the scoping package for the main steam system for license

renewal (LRID AB) was revised to include the auxiliary turbine system, the note on license

renewal drawing LR-WCGS-AB-M-12AB03 was not removed.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-3 acceptable

because it adequately explained that the note leading to the incorrect system designator was an

error on the license renewal drawing and that, it was found to have no impact on the LRA.

Therefore, the staff's concern described in RAI 2.3.4.2-3 is resolved.

In RAI 2.3.4.2-4 dated April 3, 2007, the staff stated that a license renewal drawing has a note

stating "This Section is evaluated in LRID AL" which points to a reference continuation flag to

another drawing. The staff noted that for license renewal, the other drawing is associated with

the auxiliary feedwater system. The staff requested that the applicant explain why the note

references LRID AL, auxiliary feedwater system, when the referenced drawing has been

associated and evaluated within the main steam system for license renewal.

In its response dated May 2, 2007, the applicant stated that the note is incorrect. The applicant

stated that when the scoping package for the main steam system for license renewal (LRID AB)

was revised to include the auxiliary turbine system, the note on license renewal drawing

LR-WCGS-AB-M-12FBO1 was not removed.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-4 acceptable

because it adequately explained that the note leading to the incorrect system designator was an

error on the license renewal drawing and that, it was found to have no impact on the LRA.

Therefore, the staff's concern described in RAI 2.3.4.2-4 is resolved.

In RAI 2.3.4.2-5 dated April 3, 2007, the staff stated that license renewal drawings for the main

steam system have lines highlighted in green indicating that they are within the scope of license

renewal. However, the staff noted that multiple lines that are sized 1-inch and under, that

branch off the highlighted lines with no valve or other interfacing components, are not

highlighted. The staff requested that the applicant justify the exclusion of the size 1 -inch and

under lines from the scope of license renewal. In addition, the staff requested that the applicant

explain whether the impact of multiple line failures were considered on the system intended

functions.

In its response dated May 2, 200ý, the applicant stated that the 1-inch lines (vents and drains)

shown on LR-WCGS-AB-M-12AB03 are not required to support a post-fire safe-shutdown. The

applicant stated that post-fire safe-shutdown would have been the only reason these

components would be included within the scope of license renewal.

The one event which causes the main steam lines in the turbine building to be required to

support a post-fire safe-shutdown is a fire in the main steam tunnel that causes two main steam

lines to fail to isolate. Valves in the turbine building would be closed to isolate the main steam

and prevent a rapid depressurization of the secondary side, resulting cooldown of the primary

side, and potential return to criticality. The applicant explained that failure of a 1-inch line, and

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even several 1-inch lines, was considered and determined to be insignificant and by throttling

one or both atmospheric relief valves closed to control depressurization, compensation for this

the loss of steam due to this event could be easily accomplished.

The applicant described that the atmospheric relief valves at WCGS as 8-inch Masoneilan air

operated valves capable of throttling with a seat diameter of 5.061 inches. Further, the applicant

described the valve's port diameter as being slightly smaller, but still greater than 5 inches.

Therefore, the applicant concluded that each atmospheric relief valve has at least 19.6 square

inches of flow area and that analysis has shown that it takes a minimum of two functional

atmospheric relief valves to meet thel 0 CFR Part 50, Appendix R, criteria of being in cold

shutdown within 72 hours.

Additionally, the applicant stated that a 1-inch pipe has a flow area of less than 0.79 square

inches and that although multiple pipe failures were considered, all of the 1-inch pipes failing

simultaneously were considered incredible. Further explanation included that there are 31

1-inch vents and drains and seven 1/2-inch pipes in the main steam system excluded from the

scope of post-fire safe-shutdown and several instrument tubes of unknown sizes, that are

assumed to be 1/4-inch tubes. The applicant's analysis described that if all 38 pipes ruptured

cleanly at the same time, the resulting flow area would be less'than 26 square inches, or about

equal to 2/3 the flow area of two atmospheric relief valves and that throttling closed on the two

functional atmospheric relief valves will assure a controlled cooldown rate.

During a telephone conference dated June 8, 2007, the staff explained that the response did

not adequately identify whether there is an analysis or calculation that serves as the basis for

the exclusion of these 1-inch or less steam lines from the scope of license renewal.

In its response dated July 11, 2007, the applicant stated that the current WCGS licensing basis

for post-fire safe-shutdown includes calculation XX-E-01 3 "Post-Fire Safe Shutdown Analysis."

The applicant explained that this calculation evaluates the failures of components in the turbine

building on lines of 1-inch or less and concludes these failures would not adversely affect the

main steam system's intended function.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.2-5 acceptable

because the applicant has adequately identified the calculation as the basis for evaluating the

failures of components of 1-inch or less and their exclusion from the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.4.2-5 is resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and the RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the main steam system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.3.4.3 Feedwater System

2.3.4.3.1 Summary of Technical Information in the Application

LRA Section 2.3.4.3 describes the feedwater system, which provides flow paths for the auxiliary

feedwater to the steam generators and isolates feedwater flow to the steam generators during a

main steam or feedwater line break event or a containment overpressure event. The portions

inside the containment also serve as the containment barrier against fission product release to

the environment. The feedwater system receives condensate from the condensate system and

delivers feedwater at required pressure and temperature to the four steam generators. The

system consists of two interconnected trains with turbine-driven feedwater pumps for normal

power operation, a motor-driven feedwater pump for startup operation, three stages of

high-pressure feedwater heaters in two parallel trains, and four lines connecting to the four

steam generators. Each line has a feedwater control valve, feedwater isolation valve, and an

auxiliary feedwater connection. The feedwater system also includes components that monitor

the steam generator level for power operations and safe plant shutdown.

The feedwater system has safety-related components relied upon to remain functional during

and following DBEs. The failure of nonsafety-related SSCs in the feedwater system could

prevent the satisfactory accomplishment of a safety-related function. In addition, the feedwater

system performs functions that support fire protection, ATWS, SBO, and EQ.

LRA Table 2.3.4-3 identifies feedwater system component types within the scope of license

renewal and subject to an AMR:

* closure bolting

• flow element

* heat exchanger tube side

* heat exchanger shell side

* insulation

* orifice

* piping

" thermowell

* tubing

• valve

The intended functions of the feedwater system component types within the scope of license

renewal include:

" heat loss control

* pressure boundary

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

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2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3 and USAR Sections 6.2.4 and 10.4.7 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.4.3.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

feedwater system components that are within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.4 Condensate System

2.3.4.4.1 Summary of Technical Information in the Application

LRA Section 2.3.4.4 describes the condensate system, which delivers deaerated water from the

main condenser hotwells to the suction of the main feedwater pumps. Together with the

feedwater system, the condensate system delivers feedwater to the steam generators at

required pressure and temperature. The condensate storage and transfer system stores water

in the CST for makeup and surge capacity to compensate for changes in plant system

inventories. The condensate pumps take suction from the condenser hotwell and discharge

through, or bypass, the condensate demineralizers if desired. The condensate demineralizers

are evaluated in the condensate demineralizer system. At the condensate pump discharge the

condensate system interfaces with the condensate and feedwater chemical addition system for

oxygen and pH control, which is evaluated with the feedwater system. Downstream of the

condensate demineralizers are the low-pressure feedwater heaters, which join together at a

common header for the suction of the main feedwater pumps. The CST serves as a reservoir to

supply or receive condensate as required by the condenser hotwell level control system.

Portions of the condensate storage and transfer system and portions of the condensate system

also support fire protection and SBO requirements based on the criteria of 10 CFR 54.4(a)(3).

The failure of nonsafety-related SSCs in the condensate system could prevent the satisfactory

accomplishment of a safety-related function.

LRA Table 2.3.4-4 identifies condensate system component types within the scope of license

renewal and subject to an AMR:

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• closure bolting

* piping

• tank

• valve

* rupture disc

The intended functions of the condensate system component types within the scope of license

renewal include:

* pressure boundary

• maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

* maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.4 and USAR Sections 10.4.7 and 9.2.6 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.3.4.4 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.3.4.4-1 dated April 3, 2007, the staff stated that a license renewal drawing shows

penetrations to the CST as excluded from the scope of license renewal. Additionally the staff

noted that the CST shell is within the scope of license renewal. The staff requested that the

applicant justify the exclusion of the tank penetrations from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the CST is a nonsafety-related

component that is required for an SBO in accordance with 10 CFR 54.4(a)(3) and is highlighted

as green on license renewal boundary drawing LR-WCGS-AD-M-1 2AP01. The applicant further

explained that the penetrations for LT-0004, TE-0005, LSL-0010, low pressure N2 (nitrogen),

and LSH-007 are also nonsafety-related but should be shown as green on this drawing to

protect the integrity of the CST during an SBO. The applicant stated that the piping and

components associated with these changes will be included within the scope of license renewal.

However, because the component groups required in this change currently exist in the

application, no changes are needed for LRA Tables 2.3.4-4 and 3.4.2-4.

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Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-1 acceptable

because it adequately explained that the CST components in question are within the scope of

license renewal. Therefore, the staff's concern described in RAI 2.3.4.4.-i is resolved.

In RAI 2.3.4.4-2 dated April 3, 2007, the staff stated that a license renewal drawing shows vents

and vacuum relief valves on the CST that are excluded from the scope of license renewal.

Additionally, the staff noted that the tank shell is within the scope of license renewal. The staff

requested that the applicant justify the exclusion of the vents from the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the CST is a nonsafety-related

component that is required to support an SBO in accordance with 10 CFR 54.4(a)(3) and is

highlighted in green on license renewal drawing LR-WCGS-AD-M-12AP01. The applicant

explained that the tank vent lines and vacuum relief valves are also nonsafety-related.

However, these components should be shown as green on this drawing to protect the integrity

of the CST during an SBO. The applicant agreed that the piping and components associated

with the tank vent lines and vacuum relief valves will be included within the scope of license

renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-2 acceptable

because it adequately explains that the CST components in question are within the scope of

license renewal. Therefore, the staff's concern described in RAI 2.3.4.4-2 is resolved.

In RAI 2.3.4.4-3 dated April 3, 2007, the staff stated that a license renewal drawing shows

external steam heating coils attached to the CST as excluded from the scope of license

renewal. Additionally the staff noted that USAR Section 9.2.6.5 states that the nominal

minimum temperature for the CST is 50 0 F. The staff requested that the applicant justify the

exclusion of either the steam heating coils and/or the tank insulation from LRA Tables 2.3.4-4

and 3.4.4-4 as component types within the scope of license renewal.

In its response dated May 2, 2007, the applicant stated that the CST is a nonsafety-related

component that is within the scope of license renewal to support SBO requirements based on

the criteria of 10 CFR 54.4(a)(3). The applicant further explained that the CST is highlighted as

green on license renewal boundary drawing LR-WCGS-AD-M-12AP01. Additionally, the

applicant explained that the CST auxiliary steam heating components and its insulation are also

nonsafety-related. The applicant also stated that although these components are mentioned in

the USAR, the USAR does not state the components are required to remain functional during

and following DBEs nor do they support SBO requirements. The applicant further identified that

the WCGS technical specifications require a minimum of 281,000 gallons of water in the CST

during normal operations and USAR Section 9.2.6.5 states that CST water be at least 500 F

during normal operations. The applicant explained that the initial condition of 500 F water

temperature is verified during normal plant operation.

The applicant concluded that the WCGS technical specifications required water volume is

sufficient to assure mitigation of a DBE without associated nonsafety-related components and

that the CST auxiliary steam heating and insulation have no intended functions and are not

within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.3.4.4-3 acceptable

because it adequately identified a basis for the exclusion of the CST auxiliary steam heating

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components and its insulation from the scope of license renewal by citing that the required

minimum of 281,000 gallons of inventory along with temperature monitoring by technical

specification surveillance would ensure that minimum temperature would be met. Therefore, the

staff's concern described in RAI 2.3.4.4-3 is resolved.

2.3.4.4.3 Conclusion

The staff reviewed the LRA, USAR, drawings, and RAI responses to determine whether the

applicant failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

components subject to an AMR. The staff finds no such omissions. On the basis of its review,

the staff concludes that there is reasonable assurance that the applicant has adequately

identified the condensate system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.5 Steam Generator Blowdown System

2.3.4.5.1 Summary of Technical Information in the Application

LRA Section 2.3.4.5 describes the steam generator blowdown system (SGBS), which isolates

the steam generator to maintain a heat sink for safe shutdown. The SGBS also provides

containment isolation for steam generator drain piping penetration P-78. The SGBS provides

continuous blowdown of water from the lower portion of each steam generator secondary side

to remove solids and chemical contaminates that accumulate in the steam generators during

normal operations. The blowdown from each steam generator flows under pressure to a

blowdown flash tank. The discharge from the flash tank flows to a series of heat exchangers

where the temperature is reduced prior to processing of the effluent.

The SGBS has safety-related components relied upon to remain functional during and following

DBEs. The failure of nonsafety-related SSCs in the SGBS could prevent the satisfactory

accomplishment of a safety-related function. In addition, the SGBS performs functions that

support fire protection, ATWS, SBO, and EQ.

LRA Table 2.3.4-5 identifies SGBS component types within the scope of license renewal and

subject to an AMR:

• closure bolting

* instrument bellows

" insulation

* piping

* pump

* strainer

* tank

" tubing

* valve

The intended functions of the SGBS component types within the scope of license renewal

include:

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0 heat loss control

* pressure boundary

* maintains mechanical and structural integrity to prevent spatial interactions that could

cause failure of safety-related SSCs

maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and USAR Section 10.4.8 using the evaluation

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.4.5.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

SGBS components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.3.4.6 Auxiliary Feedwater System

2.3.4.6.1 Summary of Technical Information in the Application

LRA Section 2.3.4.6 describes the auxiliary feedwater system, which is relied upon as the

source of feedwater supply to the steam generators during startup, cooldown, and emergency

conditions to maintain a secondary heat sink for DBE mitigation. The auxiliary feedwater system

takes feedwater from the CST through the auxiliary feedwater pumps that discharge to the

feedwater system piping and steam generators. Auxiliary feedwater automatically transfers from

the CST to the ESWS on low CST suction pressure to maintain a source of feedwater for decay

heat removal. The CST is in the condensate storage and transfer system and included in

condensate system evaluation in SER Section 2.3.4.4. Two motor-driven auxiliary feedwater

pumps and one turbine-driven pump are available to ensure required feedwater flow to the

steam generators. The steam turbine drive for the turbine-driven auxiliary feedwater pump is

evaluated with the main steam system in SER Section 2.3.4.2.

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The auxiliary feedwater system has safety-related components relied upon to remain functional

during and following DBEs. In addition, the auxiliary feedwater system performs functions that

support fire protection, ATWS, and SBO.

LRA Table 2.3.4-6 identifies auxiliary feedwater system component types within the scope of

license renewal and subject to an AMR:

* closure bolting

* filter

* heat exchanger shell side

* heat exchanger tube side

" orifice

* piping

" pump

* tubing

" turbine

" valve

" spacer ring

The intended functions of the auxiliary feedwater system component types within the scope of

license renewal include:

* flow restriction

* filtration

* heat transfer

* pressure boundary

• maintains mechanical and structural integrity to provide structural support to attached

safety-related piping and components

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and USAR Sections 10.4.9, 7.3.6, and 9.2.6 using the

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

2.3.4.6.3 Conclusion

The staff reviewed the LRA, USAR, and drawings to determine whether the applicant failed to

identify any SSCs within the scope of license renewal. The staff finds no such omissions. In

addition, the staff's review determined whether the applicant failed to identify any components

subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

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concludes that there is reasonable assurance that the applicant has adequately identified the

auxiliary feedwater system components that are within the scope of license renewal, as

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4 Scoping and Screening Results: Structures

This section documents the staff's review of the applicant's scoping and screening results for

structures. Specifically, this section discusses the following structures:

* reactor building

• control building

" diesel generator building

" turbine building

* auxiliary building

• radwaste building

* emergency fuel oil tank access vaults

* ESW electrical duct banks and manways

* communications corridor

• transmission towers

" ESW access vaults

" fuel building

• ESW pumphouse

* circulating water screenhouse

" ultimate heat sink

" ESW discharge structure

* main dam and auxiliary spillway

* ESW valve house

" RWST foundation and valve house

* CST foundation and valve house

* concrete support structures for station transformers

* supports (structure)

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must list passive,

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the

applicant properly implemented its methodology, the staff's review focused on the

implementation results. This focus allowed the staff to confirm that there were no omissions of

SCs that meet the scoping criteria and are subject to an AMR.

The staff's evaluation of the information in the LRA was the same for all structures. The

objective was to determine whether the applicant has identified, in accordance with

10 CFR 54.4, components and supporting structures for structures that appear to meet the

license renewal scoping criteria. Similarly, the staff evaluated the applicant's screening results

to verify that all passive, long-lived SCs were subject to an AMR in accordance with

10 CFR 54.21 (a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA Sections and drawings, focusing

on components that have not been identified as within the scope of license renewal. The staff

reviewed relevant licensing basis documents, including the USAR, for each structure to

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determine whether the applicant has omitted from the scope of license renewal components

with intended functions delineated pursuant to 10 CFR 54.4(a). The staff also reviewed the

licensing basis documents to determine whether the LRA specified all intended functions

delineated pursuant to 10 CFR 54.4(a). The staff requested additional information to resolve

any omissions or discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant's screening results. For

those SCs with intended functions, the staff sought to determine whether (1) the functions are

performed with moving parts or a change in configuration or properties or (2) the SCs are

subject to replacement after a qualified life or specified time period, as described in

10 CFR 54.21 (a)(1). For those meeting neither of these criteria, the staff sought to confirm that

these SCs were subject to an AMR, as required by 10 CFR 54.21 (a)(1). The staff requested

additional information to resolve any omissions or discrepancies identified.

2.4.1 Reactor Building

2.4.1.1 Summary of Technical Information in the Application

LRA Section 2.4.1 describes the reactor building, which limits the release of radioactive fission

products following an accident to limit the dose to control room operators and the public. The

reactor building physically supports itself, the RCS, ESFs, and other systems and equipment

within the structure. The exterior walls and dome shelter and protect the reactor vessel and

other safety-related SSCs from external events.

The reactor building is a seismic Category I structure housing the reactor, the RCS, the steam

generators, and portions of the auxiliary and ESFs systems. The major structural components

of the reactor building are the steel liner plate, penetrations, and reactor building internal

structures.

The reactor building has safety-related components relied upon to remain functional during and

following DBEs. In addition, the reactor building performs functions that support fire protection,

ATWS, and SBO.

LRA Table 2.4-1 identifies reactor building component types within the scope of license renewal

and subject to an AMR:

* caulking and sealant

* compressible joints and seals

* concrete elements

* electrical penetrations

* fire barrier coatings and wrappings

0 fire barrier doors

* fire barrier seals

* hatch

* hatches/plugs

* containment liner

" refueling liner

" penetrations

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" pipe whip restraints and jet shields

* stairs, platforms, and grates

* structural steel

The intended functions of the reactor building component types within the scope of license

renewal include:

* shelter or protection for safety-related components

* rated fire barrier to confine or retard a fire from spreading

* flood protection barrier

" shielding against high-energy line breaks

" missile barrier

* thermal expansion and/or seismic separation

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

" structural and/or functional support to safety-related components

• leak-tight barrier to protect public health and safety during DBEs

* pipe whip restraint

" shielding against radiation

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and USAR Sections 3.8.1, 3.8.2.1, 3.8.3.1, and 3.8.5.1.1

using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR

Section 2.4, "Scoping and Screening Results: Structures."

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.1.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the reactor building SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.2 Control Building

2.4.2.1 Summary of Technical Information in the Application

LRA Section 2.4.2 describes the control building, which physically supports and protects the

safety-related systems within it, and maintains a pressurized habitable environment for the

operators during all postulated events. The control building is a rectangular, seven-story,

structural steel and reinforced concrete structure housing the main control room, the computer,

Class 1 E switchgear, Class 1 E battery rooms, access control data, cable spreading rooms, and

portions of the main control room emergency ventilation systems. The control building shares a

common base slab and a wall with the auxiliary building and is founded on undisturbed soil.

The control building has safety-related components relied upon to remain functional during and

following DBEs. In addition, the control building performs functions that support fire protection,

ATWS, and SBO.

LRA Table 2.4-2 identifies control building component types within the scope of license renewal

and subject to an AMR:

* boot seals penetration

* caulking and sealant

* compressible joints and seals

* concrete block (masonry walls)

* concrete elements

" doors

* electrical penetrations

* fire barrier coatings and wraps

• fire barrier doors

* fire barrier seals

• instrument panels and racks

• mechanical penetrations

• roofing membrane

" stairs, platforms, and grates

* structural steel

The intended functions of the control building component types within the scope of license

renewal include:

• shelter or protection for safety-related components

" rated fire barrier to confine or retard a fire from spreading

* flood protection barrier

* missile barrier

* thermal expansion and/or seismic separation

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

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* structural and/or functional support for safety-related components

" leak-tight barrier to protect public health and safety during DBEs

2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and USAR Sections 3.8.4.1.3, 3.8.5, and 6.4.2 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.2.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the control building SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.3 Diesel Generator Building

2.4.3.1 Summary of Technical Information in the Application

LRA Section 2.4.3 describes the diesel generator building, which physically supports, shelters,

and protects the diesel generators and its systems and components relied upon for the

capability to shut down the reactor and maintain it in a safe shutdown condition. The diesel

generator building is a seismic Category I, single-story, rectangular, structural steel and

reinforced concrete structure housing the emergency diesel engines, fuel oil day tanks, exhaust

silencers, and exhaust stacks.

The diesel generator building has safety-related components relied upon to remain functional

during and following DBEs. In addition, the diesel generator building performs functions that

support fire protection.

LRA Table 2.4-3 identifies diesel generator building component types within the scope of

license renewal and subject to an AMR:

• caulking and sealant

• compressible joints and seals

* concrete elements

• doors

* electrical penetrations

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* fire barrier coatings and wraps

* fire barrier seal

* hatches and plugs

• instrument panels and racks

* mechanical penetrations

* roofing membrane

* stairs, platforms, and grates

* structural steel

The intended functions of the diesel generator building component types within the scope of

license renewal include:

" shelter or protection for safety-related components

" rated fire barrier to confine or retard a fire from spreading

* flood protection barrier

* missile barrier

* thermal expansion and/or seismic separation

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

structural and/or functional support to safety-related components

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and USAR Sections 3.8.4.1.4, 3.8.4.4.3, and 3.8.5.1.4

using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR

Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.3.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the diesel generator building

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to

an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.4 Turbine Building

2.4.4.1 Summary of Technical Information in the Application

LRA Section 2.4.4 describes the turbine building, which is designed to preclude gross collapse

that could affect external safety-related structures or components under loads imposed by a

design-basis tornado. Structural features protect safety-related components in other buildings

from flooding by water from the turbine building. The turbine building is a rectangular,

three-story, steel-framed structure enclosed with steel siding housing the turbine generator,

condensers, and associated equipment.

The failure of nonsafety-related SSCs in the turbine building could prevent the satisfactory

accomplishment of an safety-related function. The turbine building also performs functions that

support fire protection and ATWS.

LRA Table 2.4-4 identifies turbine building component types within the scope of license renewal

and subject to an AMR:

* compressible joints and seals

* concrete block (masonry walls)

• concrete elements

* fire barrier coatings and wraps

* fire barrier doors

" fire barrier seals

" instrument panels and racks

* metal siding

" penetration

* roofing membrane

* structural steel

The intended functions of the turbine building component types within the scope of license

renewal include:

" shelter or protection for safety-related components

" rated fire barrier to confine or retard a fire from spreading

" flood protection barrier

* missile barrier

* thermal expansion and/or seismic separation

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 and USAR Sections 3.3.2.3 and 10.2 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

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During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.4.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the turbine building SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.4.5 Auxiliary Building

2.4.5.1 Summary of Technical Information in the Application

LRA Section 2.4.5 describes the auxiliary building, which supports, shelters, and protects ESFs

and nuclear auxiliary systems equipment. In a safe shutdown, including the events of

earthquake or post-fire accident that renders the control building uninhabitable and incapable of

performing necessary functions, the auxiliary panel located in the auxiliary building ensures that

the plant is able to reach a safe shutdown and maintain a safe condition. The auxiliary building

is a multi-story structural steel and reinforced concrete seismic Category I structure housing the

safety injection system, residual heat removal system, chemical and volume control monitoring

system, auxiliary feedwater pumps, steam and feedwater isolation and relief valves, heat

exchangers, other pumps, tanks, filters, and demineralizers, and heating and ventilating

equipment.

The auxiliary building has safety-related components relied upon to remain functional during

and following DBEs. In addition, the auxiliary building performs functions that support fire

protection, ATWS, and SBO.

LRA Table 2.4-5 identifies auxiliary building component types within the scope of license

renewal and subject to an AMR:

• caulking and sealant

* compressible joints and seals

• concrete block (masonry walls)

• concrete elements

* doors

* fire barrier coatings and wraps

* fire barrier doors

* fire barrier seals

* hatches and plugs

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" penetration

* boot seal penetration

* electrical penetration

* mechanical penetration

• roofing membrane

" stairs, platforms, and grates

" structural steel

The intended functions of the auxiliary building component types within the scope of license

renewal include:

" shelter or protection for safety-related components

" rated fire barrier to confine or retard a fire from spreading

" flood protection barrier

" missile barrier

* thermal expansion and/or seismic separation

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support for safety-related components

* leak-tight barrier to protect public health and safety during DBEs

* shielding against radiation

2.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.5 and USAR Sections 3.8.4.1.1 and 3.8.5.1.2 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.5.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the auxiliary building SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.6 Radwaste Building

2.4.6.1 Summary of Technical Information in the Application

LRA Section 2.4.6 describes the radwaste building, which shelters and protects an automatic

sprinkler system over the dry waste compactor and an automatic fire detection system. It also

shelters and protects four switches required for post-fire safe-shutdown located in the radwaste

control room. The switches and their cables run through the building, through the tunnel, and

into the auxiliary building. The radwaste building is a rectangular, multi-story, structural steel

and reinforced concrete structure housing radioactive waste treatment facilities, tanks, filters,

and other miscellaneous equipment. The building extends below plant grade and is supported

on a reinforced concrete mat foundation constructed on compacted earth fill. The building has a

built-up roof supported by structural steel beams and girders. The roof and intermediate floor

framing are supported by structural steel columns and reinforced concrete-bearing walls. The

radwaste pipe tunnel is a below-grade, reinforced concrete, two-cell box structure connecting

the auxiliary and radwaste buildings and separated from both buildings by isolation joints. The

tunnel provides access and carries electrical cable trays and piping between the auxiliary

building and the radwaste building.

The radwaste building performs functions that support fire protection.

LRA Table 2.4-6 identifies radwaste building component types within the scope of license

renewal and subject to an AMR:

* caulking and sealant

* concrete block (masonry walls)

* concrete elements

* doors

* metal siding

* penetration

* roofing membrane

* structural steel

* tunnel

The intended functions of the radwaste building component types within the scope of license

renewal include:

" shelter or protection for safety-related components

* structural support for nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.6 and USAR Section 3.8.6 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

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SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.6.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the radwaste building SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.7 Emergency Fuel Oil Tank Access Vaults

2.4.7.1 Summary of Technical Information in the Application

LRA Section 2.4.7 describes the emergency fuel oil tank access vaults, which provide access to

the emergency fuel oil storage tanks. The emergency fuel oil tank access vaults support,

shelter, and protect components relied upon for the capability to shut down the reactor and

maintain it in a safe shutdown condition. Also required to prevent nonsafety-related SSCs from

hindering accomplishment of safety-related functions. The emergency fuel oil tank access

vaults are seismic Category I, rectangular reinforced concrete vaults. The foundation is located

4 feet and 6 inches above each emergency fuel oil storage tank. The emergency fuel oil tank

access vault floors are set on stabilized fill and have penetrations to allow for mechanical and

electrical interface with the buried emergency fuel oil tank. The top slab is at grade and has a

removable concrete cover. A manway provides access to each tank manhole, pump, discharge

piping, conduits, level transmitter, and sample line. Buried pipe and electrical duct banks

connect the emergency fuel oil storage tanks to the diesel generator building.

The emergency fuel oil tank access vaults have safety-related components relied upon to

remain functional during and following DBEs. The failure of nonsafety-related SSCs in the

emergency fuel oil tank access vault could prevent the satisfactory accomplishment of a

safety-related function.

LRA Table 2.4-7 identifies emergency fuel oil tank access vault component types within the

scope of license renewal and subject to an AMR:

* compressible joints and seals

* concrete elements

* duct banks and manholes

* hatches and plugs

* boot seal penetration

The intended functions of the emergency fuel oil tank access vaults component types within the

scope of license renewal include:

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* shelter or protection to safety-related components

* flood protection barrier

* structural and/or functional support to safety-related components

2.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.7 and USAR Sections 3.8.4.1.6 and 9.5.4.2.2 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.7.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the emergency fuel oil tank

access vaults SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.8 Essential Service Water Electrical Duct Banks and Manways

2.4.8.1 Summary of Technical Information in the Application

LRA Section 2.4.8 describes the ESW electrical duct banks and manways, which protect

electrical raceways required to operate the ESWS. The ESW removes heat from plant

components requiring cooling for safe reactor shutdown. The ESWS also supplies emergency

makeup to the fuel storage pool and CCWSs and is the backup water supply to the auxiliary

feedwater system. The seismic Category I ESW electrical duct banks, located a minimum of 4

feet below grade, consist of numerous polyvinyl chloride (PVC) conduits encased in a

reinforced concrete beam. These conduits house safety-related electrical cables. The ESW

electrical duct banks exit the control building and traverse south and east to the ESW valve

house and to the ESW pumphouse.

The ESW electrical duct banks and manways have safety-related components relied upon to

remain functional during and following DBEs.

LRA Table 2.4-8 identifies ESW electrical duct banks and manways component types within the

scope of license renewal and subject to an AMR:

* caulking and sealant

* compressible joints and seals

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" concrete elements

* duct banks and manholes

* hatches and plugs * structural steel

The intended functions of the ESW electrical duct banks and manways component types within

the scope of license renewal include:

* shelter or protection to safety-related components

* missile barrier

* structural and/or functional support to safety-related components

2.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.8 and USAR Sections 3.8.4.1.11 and 3.8.5.1.8 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.8.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the ESW electrical duct

banks and manways SCs within the scope of license renewal, as required by 10 CFR 54.4(a),

and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.9 Communications Corridor

2.4.9.1 Summary of Technical Information in the Application

LRA Section 2.4.9 describes the communications corridor, which is designed to preclude gross

collapse that could affect safety-related structures or components under loads imposed by a

design-basis tornado. Structural features protect safety-related components from flooding. The

communications corridor is a steel-framed structure enclosed with steel siding, attached to the

west side of the turbine building, separated from the north side of the control and auxiliary

buildings by a 3-inch isolation gap, and supported by a reinforced concrete basemat founded on

compacted soil. The communications corridor provides routing space for-mechanical and

electrical systems and access to adjacent buildings.

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The failure of nonsafety-related SSCs in the communications corridor could prevent the

satisfactory accomplishment of an safety-related function. The communications corridor also

performs functions that support fire protection.

LRA Table 2.4-9 identifies communications corridor component types within the scope of

license renewal and subject to an AMR:

* concrete block (masonry walls)

* concrete elements

* electrical penetrations

* fire barrier coatings and wraps

" fire barrier door

" fire barrier seal

" mechanical penetrations

* structural steel

The intended functions of the communications corridor component types within the scope of

license renewal include:

* shelter or protection to safety-related components

* rated fire barrier to confine or retard a fire from spreading

" spray shield, curbs, or mechanical components for directing flow

* structural support for nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.4.9 and USAR Sdctions 3.3.2.3 and 3B.4.3 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.9 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4-1 dated April 10, 2007, the staff requested that the applicant identify the structural

features which are used to protect safety-related components from flooding, and discuss

whether they should be within the scope of license renewal.

In its response dated May 9, 2007, the applicant explained that the potential floodwater paths

utilize curbs to preclude water from entering the safety-related areas. The curbs along the west

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side of the condenser pit and around the T-1 stairwell are provided to prevent water from

spilling over into the safety-related spaces. The applicant stated that LRA Table 2.4-9 includes

curbing, which is within the scope of license renewal.

Based on its review, the staff finds the applicant's response to RAI 2.4-1 acceptable because it

has identified the structural features which are used to protect safety-related components from

flooding, and stated that they were within the scope of license renewal. Therefore, the staff's

concern described in RAI 2.4-1 is resolved.

2.4.9.3 Conclusion

The staff reviewed the LRA, USAR, and the RAI response to determine whether the applicant

failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

communications corridor SCs within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.10 Transmission Towers

2.4.10.1 Summary of Technical Information in the Application

LRA Section 2.4.10 describes the transmission towers, which support and suspend overhead

transmission power lines connecting the station power block to the 345kV switchyard. The

transmission tower structures support two independent and structurally separated overhead

transmission power lines. The first transmission power line connects the main transformer to

the 345kV switchyard and consists of two deadend structures, a steel transmission tower, and a

wooden H-frame structure. The second transmission power line connects the 345kV switchyard

to the start-up transformer and consists of two deadend structures, a steel transmission tower,

and a wooden H-frame structure. Both lines run approximately 700 feet due north of the turbine

building and make a right-angle turn into the 345kV switchyard.

The transmission towers perform functions that support SBO recovery.

LRA Table 2.4-10 identifies transmission towers component types within the scope of license

renewal and subject to an AMR:

* concrete elements

" transmission tower

The intended function of the transmission towers component type within the scope of license

renewal is structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions.

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2.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.10 and USAR Section 8.2.1.2 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.10 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

In RAI 2.4-2 dated April 10, 2007, the staff noted that LRA Section 2.4.10 states that there is a

wooden H-frame structure within each of the two transmission power lines. However, the

wooden H-frame structures are not listed in LRA Table 2.4-10 as a structure within the scope of

license renewal. The staff requested that the applicant justify its exclusion from the scope of

license renewal.

In its response dated May 9, 2007, the applicant stated that the wooden H-frame structure is

included in LRA Table 2.4-10 within the component type transmission tower. The applicant also

stated that LRA Table 3.5.2-10 includes line items for transmission towers made of carbon steel

and treated wood.

Based on its review, the staff finds the applicant's response to RAI 2.4-2 acceptable because it

clarifies that the wooden H-frame structure is within the scope of license renewal. Therefore,

the staff's concern described in RAI 2.4-2 is resolved.

As a result of the onsite inspection performed by the staff during the weeks of September 10,

and October 22, 2007, the applicant added the disconnects 13-21 and 13-23 within the scope of

license renewal. By letter dated November 16, 2007, the applicant amended LRA

Section 2.4.10 to state that the disconnects are housed in an electrical enclosure with a

concrete foundation.

The staff finds this acceptable because it is consistent with the recommendations in the

SRP-LR. The staff finds that this component is included within the component type of

transmission tower and that it was inadvertently omitted from the scope of license renewal.

2.4.10.3 Conclusion

The staff reviewed the LRA, USAR, and the RAI response to determine whether the applicant

failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

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transmissions towers SCs within the scope of license renewal, as required by 10 CFR 54.4(a),

and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.11 Essential Service Water Access Vaults

2.4.11.1 Summary of Technical Information in the Application

LRA Section 2.4.11 describes the ESW access vaults, which provide access to portions of the

underground ESW piping while protecting them from tornado-generated missiles. The ESW

removes heat from plant components requiring cooling for safe reactor shutdown, supplies

emergency makeup to the fuel storage pool and CCWSs, and is the backup water supply to the

auxiliary feedwater system. The four ESW access vaults, which are independent from each

other, are located below grade and provide for personnel and equipment access from the top.

The ESW access vaults have safety-related components relied upon to remain functional

during and following DBEs.

LRA Table 2.4-11 identifies ESW access vaults component types within the scope of license

renewal and subject to an AMR:

* caulking and sealant

* compressible joints and seals

* concrete elements

* hatches and plugs

* structural steel

The intended functions of the ESW access vaults component types within the scope of. license

renewal include:

* shelter or protection to safety-related components

* flood protection barrier

" missile barrier

* structural and/or functional support to safety-related components

2.4.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.11 and USAR Sections 3.8.4.1.14 and 3.8.5.1.11 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

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2.4.11.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the ESW access vaults SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21(a)(1).

2.4.12 Fuel Building

2.4.12.1 Summary of Technical Information in the Application

LRA Section 2.4.12 describes the fuel building, which supports, shelters, and protects SSCs for

the handling and storage of spent fuel. The fuel building contains the spent fuel pool, transfer

canal, cask loading pool and cask pit, spent fuel pool bridge crane, cask handling crane, and

other miscellaneous equipment. The spent fuel pool receives spent fuel from the containment

through the fuel transfer tube. The spent fuel pool, including the transfer canal, cask loading

pool, and cask washdown pit, consist of reinforced concrete walls and floors lined with stainless

steel plates. The concrete dividing walls and the spent fuel pool gates permit de-watering of the

spent fuel pool without dewatering the entire pool.

The fuel building has safety-related components relied upon to remain functional during and

following DBEs. In addition, the fuel building performs functions that support fire protection.

LRA Table 2.4-12 identifies fuel building component types within the scope of license renewal

and subject to an AMR:

• caulking and sealant

• compressible joints and seals

• concrete elements

• doors

• electrical penetrations

* fire barrier coatings and wraps

• fire barrier doors

* fire barrier seals

* instrument panels racks

• mechanical penetrations

* roofing membrane

* spent fuel pool liner

• stairs and platforms and grates

• structural steel

The intended functions of the fuel building component types within the scope of license renewal

include:

* shelter or protection to safety-related components

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" rated fire barrier to confine or retard a fire from spreading

* missile barrier

* thermal expansion and/or seismic separation

• structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

* leak-tight barrier to protect public health and safety during DBEs

• shielding against radiation

2.4.12.2 Staff Evaluation

The staff reviewed LRA Section 2.4.12 and USAR Sections 3.8.4.1.2 and 3.8.5.1.3 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.12.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the fuel building SCs within

the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.4.13 Essential Service Water Pumphouse

2.4.13.1 Summary of Technical Information in the Application

LRA Section 2.4.13 describes the ESW pumphouse, which supports, shelters, and protects the

ESW system. The ESW system removes heat from plant components requiring cooling for safe

reactor shutdown, supplies emergency makeup to the fuel storage pool and CCWSs, and is the

backup water supply to the auxiliary feedwater system. The seismic Category I ESW

pumphouse is a tornado-resistant, rectangular, conventionally reinforced-concrete structure.

Separate redundant operating floors and separate forebays support the ESW pumps and piping

systems. The roof is constructed of a concrete slab with removable hatches. Tornado-resistant

concrete missile shields protect ventilation system entrances and exits at roof elevation and the

doors at grade. Structural steel commodities provide trash rack and stop log slots and

guideways for the traveling water screens and walls.

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The ESW pumphouse has safety-related components relied upon to remain functional during

and following DBEs. In addition, the ESW pumphouse performs functions that support fire

protection.

LRA Table 2.4-13 identifies ESW pumphouse component types within the scope of license

renewal and subject to an AMR:

* boot seal penetration

• caulking and sealant

* compressible joints and seals

* concrete elements

• doors

• electrical penetrations

* hatches and plugs

* mechanical penetrations

• stairs, platforms, and grates

" structural steel

The intended functions of the ESW pumphouse component types within the scope of license

renewal include:

* shelter or protection for safety-related components

• rated fire barrier to confine or retard a fire from spreading

* spray shield, curbs, or mechanical components for directing flow

* flood protection barrier

* missile barrier

* structural support for nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

2.4.13.2 Staff Evaluation

The staff reviewed LRA Section 2.4.13 and USAR Sections 3.8.4.1.8 and 3.8.5.1.6 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review; the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.4.13 identified an area in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAI as discussed below.

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In RAI 2.4-3 dated April 10, 2007, the staff requested that the applicant clarify if the component

type structural steel listed in LRA Table 2.4-13 include the trash rack and stop log slots,

guideways for the traveling water screens, and walls. If not, the staff requested that the

applicant provides a justification for their exclusion from the scope of license renewal.

In its response dated May 9, 2007, the applicant clarified that the trash rack and stop log slots,

guideways for the traveling water screens, and walls are within the scope of license renewal.

The applicant stated that LRA Table 2.4-13 includes the walls with the component type of

concrete elements, and the trash rack, stop log slots, and guideways for the traveling screens

and walls are within the component type of structural steel.

Based on its review, the staff finds the applicant's response to RAI 2.4-3 acceptable because it

identifies the components in question within the scope of license renewal. Therefore, the staff's

concern described in RAI 2.4-3 is resolved.

2.4.13.3 Conclusion

The staff reviewed the LRA, USAR, and the RAI response to determine whether the applicant

failed to identify any SSCs within the scope of license renewal. The staff finds no such

omissions. In addition, the staff's review determined whether the applicant failed to identify any

SCs subject to an AMR. The staff finds no such omissions. On the basis of its review, the staff

concludes that there is reasonable assurance that the applicant has adequately identified the

ESW pumphouse SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.14 Circulating Water Screenhouse

2.4.14.1 Summary of Technical Information in the Application

LRA Section 2.4.14 describes the circulating water screenhouse, which provides

nonsafety-related structural support, shelter and protection for the motor-driven fire pump,

diesel-driven fire pump, and jockey pump relied upon for the fire protection system. The duct

banks and manholes shelter and protect the electrical cable supplying power to these fire

protection components. The circulating water screenhouse, founded on compacted soil and

rock, is a metal siding structure housing traveling screens, pumps and strainers for the service

water system, the chlorinator room, circulating water pumps, and fire pumps. A fire wall

separates the diesel-driven fire pump, its diesel oil fuel tank, and its controllers from the rest of

the screenhouse. The electrical equipment room is also separated from the rest of the

screenhouse by a fire wall. A series of duct banks and manholes provides a path for the

electrical cable supplying power from the turbine building to the circulating water screenhouse.

The site utilizes a large cooling lake as its source of circulating water and as its cooling

mechanism. The circulating water screenhouse is on the east side of this lake.

The circulating water screenhouse performs functions that support fire protection.

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LRA Table 2.4-14 identifies circulating water screenhouse component types within the scope of

license renewal and subject to an AMR:

* compressible joints and seals

* concrete block (masonry walls)

* concrete elements

* doors

* duct banks and manholes

* electrical penetrations

* fire barrier coatings and wraps

* fire barrier doors

• fire barrier seals

* mechanical penetrations

* metal siding

* roofing membrane

• structural steel

The intended functions of the circulating water screenhouse component types within the scope

of license renewal include:

* shelter or protection to safety-related components

* rated fire barrier to confine or retard a fire from spreading

* spray shield, curbs, or mechanical components for directing flow

• structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.14.2 Staff Evaluation

The staff reviewed LRA Section 2.4.14 and USAR Sections 2.4.1.1 and 9.5.1.2.2.1 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.14.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the circulating water

screenhouse SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and

those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.15 Ultimate Heat Sink

2.4.15.1 Summary of Technical Information in the Application

LRA Section 2.4.15 describes the UHS, which provides a reliable source of cooling water to the

ESW system to dissipate the heat of DBEs safely and to achieve and maintain safe shutdown

following a DBE. The UHS supplies emergency makeup water via the ESWS to the fuel storage

pool and CCWSs, and is the backup water supply for the auxiliary feedwater system. The UHS

consists of a normally submerged seismic Category I cooling pond (and no others). The UHS is

formed by a 455 acre-feet volume with no sedimentation behind a seismic Category I earth-fill

dam of predominantly clay soils in one finger of the main cooling lake approximately 1,700 feet

in length and 18 feet in height above the Leavenworth Limestone foundation rock. The

downstream slope was designed for instantaneous drawdown of the cooling lake. The rock

slope protection for the UHS dam is designed for scour and embankment erosion potential

during hypothetical main dam and baffle dike breaks.

The UHS has safety-related components relied upon to remain functional during and following

DBEs.

LRA Table 2.4-15 shows dams and dikes as the UHS component types within the scope of

license renewal and subject to an AMR.

The intended function of the UHS component types within the scope of license renewal is as a

heat sink during SBOs or design-basis accidents.

2.4.15.2 Staff Evaluation

The staff reviewed LRA Section 2.4.15 and USAR Sections 2.5.6 and 9.2.5 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.15.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the UHS SCs within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

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2.4.16 Essential Service Water Discharge Structure

2.4.16.1 Summary of Technical Information in the Application

LRA Section 2.4.16 describes the ESW discharge structure, which supports the ESWS

discharge lines and provides the ESW discharge path into the UHS. The ESWS removes heat

from plant components requiring cooling for safe reactor shutdown, supplies emergency

makeup to the fuel storage pool and CCWSs, and is the backup water supply to the auxiliary

feedwater system. The ESW discharge structure is a seismic Category I structure consisting of

a 2-foot-thick reinforced concrete slab below grade in the UHS slope, ESW discharge structure

wing walls, and an ESW discharge structure head wall.

The ESW discharge structure has safety-related components relied upon to remain functional

during and following DBEs.

LRA Table 2.4-16 identifies ESW discharge structure component types within the scope of

license renewal and subject to an AMR:

* concrete elements

* mechanical penetrations

The intended functions of the ESW discharge structure component types within the scope of

license renewal include:

" shelter or protection to safety-related components

" spray shield, curbs, or mechanical components for directing flow

" structural and/or functional support to safety-related components

2.4.16.2 Staff Evaluation

The staff reviewed LRA Section 2.4.16 and USAR Sections 3.8.4.1.12, 3.8.4.4.8, and 3.8.5.1.9

using the evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR

Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.16.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the ESW discharge structure

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SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to

an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.17 Main Dam and Auxiliary Spillway

2.4.17.1 Summary of Technical Information in the Application

LRA Section 2.4.17 describes the main dam and auxiliary spillway required for the probable

maximum flood. They protect safety-related structures during flooding DBEs. For cooling water

required for the plant operation, a lake was created by constructing an earth dam (main dam)

across the Wolf creek about 3 miles south of the plant. A service spillway and an auxiliary

spillway, both lined with concrete, are on the east abutment of the main dam. The auxiliary

(emergency) spillway is approximately 1500 feet east of the service spillway. The service

spillway is required for all floods up to the 100-year flood. For floods greater than the 100-year

flood up to the probable maximum flood, both the service and auxiliary spillways are required.

The ability of the spillways to pass the probable maximum flood is the only function of the main

dam within the scope of license renewal.

The failure of nonsafety-related SSCs in the main dam and auxiliary spillway could prevent the

satisfactory accomplishment of an safety-related function.

LRA Table 2.4-17 identifies dams and dikes as the main dam and auxiliary spillway component

types within the scope of license renewal and subject to an AMR.

The intended function of the main dam and auxiliary spillway component types within the scope

of license renewal is as a flood protection barrier.

2.4.17.2 Staff Evaluation

The staff reviewed LRA Section 2.4.17 and USAR Sections 2.4.8.2.2 and 2.5.6 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.17.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the main dam and auxiliary

spillway SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.18 Essential Service Water Valve House

2.4.18.1 Summary of Technical Information in the Application

LRA Section 2.4.18 describes the ESW valve house, which provides access to portions of

underground ESW piping and valves and shelters and protects the ESW components. The

ESW removes heat from plant components requiring cooling for safe reactor shutdown,

provides emergency makeup to the fuel storage pool and CCWSs, and is the backup water

supply for the auxiliary feedwater system. The ESW valve house is a rectangular, reinforced

concrete structure housing redundant ESW supply and discharge piping and valves. The valve

house is located below grade, and provides for personnel and equipment access from the top.

The ESW valve house has safety-related components relied upon to remain functional during

and following DBEs.

LRA Table 2.4-18 identifies ESW valve house component types within the scope of license

renewal and subject to an AMR:

* caulking and sealant

* compressible joints and seals

* concrete elements

* hatches and plugs

* boot seal penetration

* mechanical penetrations

" structural steel

The intended functions of the ESW valve house component types within the scope of license

renewal include:

* shelter or protection to safety-related components

* flood protection barrier

" missile barrier

* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

2.4.18.2 Staff Evaluation

The staff reviewed LRA Section 2.4.18 and USAR Sections 3.8.4.1.10 and 3.8.5.1.7 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

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those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.18.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the ESW valve house SCs

within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an

AMR, as required by 10 CFR 54.21 (a)(1).

2.4.19 Refueling Water Storage Tank Foundation and Valve House

2.4.19.1 Summary of Technical Information in the Application

LRA Section 2.4.19 describes the RWST foundation and valve house, which shelters and

protects mechanical and electrical components. The duct banks shelter and protect the RWST

electrical components. The 419,000-gallon RWST is supported on a reinforced concrete slab

on backfilled and compacted grade. The RWST foundation scope includes the slab foundation,

the integral sump, and the RWST valve house and its duct banks. The RWST piping is routed

to the fuel building and radwaste tunnel.

The RWST foundation and valve house have safety-related components relied upon to remain

functional during and following DBEs. In addition, the RWST foundation and valve house

perform functions that support fire protection.

LRA Table 2.4-19 identifies the RWST foundation and valve house component types within the

scope of license renewal and subject to an AMR:

* boot seal penetration

* caulking and sealant

* concrete elements

* doors

* duct banks and manholes

" electrical penetrations

* hatches and plugs

* mechanical penetrations

* roofing membrane

" structural steel

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The intended functions of the RWST foundation and valve house component types within the

scope of license renewal include:

* shelter or protection to safety-related components

• flood protection barrier

* structural and/or functional support to safety-related components

2.4.19.2 Staff Evaluation

The staff reviewed LRA Section 2.4.19 and USAR Sections 3.8.4.1.5 and 3.8.5.1.5 using the

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.19.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the RWST foundation and

valve house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.20 Condensate Storage Tank Foundation and Valve House

2.4.20.1 Summary of Technical Information in the Application

LRA Section 2.4.20 describes the CST foundation and valve house, which support the

nonsafety-related CST. The CST pipe house and CST trench shelter and protect mechanical

and electrical components. The 450,000-gallon CST is supported on a reinforced concrete slab

on babkfilled and compacted grade. The CST foundation includes the CST slab foundation, the

integral sump, the CST pipe house, CST trench, ladders, grating, gates and handrails. The

piping is routed through the CST trench to the turbine and auxiliary buildings.

The CST foundation and valve house perform functions that support fire protection and SBO.

LRA Table 2.4-20 identifies CST foundation and valve house component types within the scope

of license renewal and subject to an AMR:

• compressible joints and seals

* concrete block (masonry walls)

* concrete elements

* doors

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" hatches and plugs

• mechanical penetrations

* roofing membrane

* structural steel

The intended functions of the CST foundation and valve house component types within the

scope of license renewal include:

* shelter or protection to safety-related components

" structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.20.2 Staff Evaluation

The staff reviewed LRA Section 2.4.20 and USAR Section 9.2.6 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.20.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the CST foundation and

valve house SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those

subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.4.21 Concrete Support Structures for Station Transformers

2.4.21.1 Summary of Technical Information in the Application

LRA Section 2.4.21 describes the concrete support structures for station transformers, which

provide structural support of the ESF, startup, main, unit auxiliary, and station service station

transformers and support equipment. The concrete support structures for station transformers

(ESF, startup, main, unit auxiliary, and station service) are reinforced concrete pads founded on

structural fill. The main and unit auxiliary transformers and support equipment are mounted on

one common pad and are separated by concrete barrier walls. The two ESF transformers and

support equipment are mounted on another common pad and are separated by a concrete

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barrier wall. The startup and station service transformers and support equipment are mounted

on separate pads. Buried concrete duct banks connect the ESF transformers to the turbine

building and to the switchyard. Manholes along these duct banks are for cable installation and

access.

The concrete support structures for station transformers perform functions that support fire

protection and SBO.

LRA Table 2.4-21 identifies concrete support structure for station transformer component types

within the scope of license renewal and subject to an AMR:

• caulking and sealant

• concrete elements

• duct banks and manholes

• electrical penetrations

* structural steel

The intended functions of the concrete support structures for station transformers component

types within the scope of license renewal include:

• shelter or protection to safety-related components

• structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

2.4.21.2 Staff Evaluation

The staff reviewed LRA Section 2.4.21 and USAR Section 8.1.2 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.21.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the concrete support

structures for station transformers SCs within the scope of license renewal, as required by

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

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2.4.22 Supports

2.4.22.1 Summary of Technical Information in the Application

LRA Section 2.4.22 describes the supports, which are within the scope of license renewal

because they support and protect components within the scope of license renewal. Supports

are integral parts of all systems and many of these supports are not uniquely identified with

component identification numbers. However, support characteristics such as design, materials

of construction, environments, and anticipated stressors are similar. Therefore, structural

supports for mechanical and electrical components are evaluated as commodities across

system boundaries. The commodity evaluation applies to structural supports for structures

within the scope of license renewal. The following structural supports for mechanical

components are addressed: supports for ASME Class 1 piping and components, supports for

ASME Classes 2 and 3 piping and components, and supports for HVAC ducts, tube track,

instrument tubing, instruments, and non-ASME piping and components. The following electrical

components and supports are addressed: cable trays and supports, conduit and supports, and

electrical panels and enclosures. The following RCS component supports are included with the

ASME Class 1 piping and component commodity group: reactor vessel supports, pressurizer

supports, steam generators, and RCP supports.

Supports have safety-related components relied upon to remain functional during and following

DBEs. The failure of nonsafety-related SSCs in the supports could prevent the satisfactory

accomplishment of a safety-related function. In addition, the supports perform functions that

support fire protection, PTS, and SBO.

LRA Table 2.4-22 identifies supports component types within the scope of license renewal and

subject to an AMR:

* cable trays and supports

* conduit and supports

* electrical panels and enclosures

" high strength bolting

" spring hangers

* ASME 1 supports

* ASME 2 supports

* HVAC duct supports

* instrument supports

" mechanical equipment Class 1 supports

" mechanical equipment Class 2 and 3 supports

* mechanical equipment non-ASME supports

* non-ASME supports

The intended functions of the supports component types within the scope of license renewal

include:

* shelter or protection to safety-related components

" thermal expansion and/or seismic separation

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* structural support to nonsafety-related components whose failure could prevent

satisfactory accomplishment of required safety functions

* structural and/or functional support to safety-related components

2.4.22.2 Staff Evaluation

The staff reviewed LRA Section 2.4.22 and USAR Section 5.4.14.2 using the evaluation

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and USAR to verify that the applicant has not omitted from the scope of license renewal any

SCs with intended functions delineated pursuant to 10 CFR 54.4(a). The staff then reviewed

those SCs that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived SCs subject to an AMR in accordance

with the requirements of 10 CFR 54.21 (a)(1).

2.4.22.3 Conclusion

The staff reviewed the LRA and USAR to determine whether the applicant failed to identify any

SSCs within the scope of license renewal. The staff finds no such omissions. In addition, the

staff's review determined whether the applicant failed to identify any SCs subject to an AMR.

The staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the supports SCs within the

scope of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as

required by 10 CFR 54.21 (a)(1).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Controls

Systems

This section documents the staff's review of the applicant's scopirng and screening results for

electrical and I&C systems. Specifically, this section discusses the electrical component types.

In accordance with the requirements of 10 CFR 54.21 (a)(1), the applicant must list passive,

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the

applicant properly implemented its methodology, the staff's review focused on the

implementation results. This focus allowed the staff to confirm that there were no omissions of

electrical and I&C system components that meet the scoping criteria and subject to an AMR.

The staff's evaluation of the information in the LRA was the same for all electrical and I&C

systems. The objective was to determine whether the applicant has identified, in accordance

with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant's

screening results to verify that all passive, long-lived components were subject to an AMR in

accordance with 10 CFR 54.21 (a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on

components that have not been identified as within the scope of license renewal. The staff

reviewed relevant licensing basis documents, including the USAR, for each electrical and I&C

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system to determine whether the applicant has omitted from the scope of license renewal

components with intended functions delineated pursuant to 10 CFR 54.4(a). The staff also

reviewed the licensing basis documents to determine whether the LRA specified all intended

functions delineated pursuant to 10 CFR 54.4(a). The staff requested additional information to

resolve any omissions or discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant's screening results. For

those SCs with intended functions, the staff sought to determine whether (1) the functions are

performed with moving parts or a change in configuration or properties or (2) the SCs are

subject to replacement after a qualified life or specified time period, as described in

10 CFR 54.21 (a)(1). For those meeting neither of these criteria, the staff sought to confirm that

these SCs were subject to an AMR, as required by 10 CFR 54.21 (a)(1). The staff requested

additional information to resolve any omissions or discrepancies identified.

2.5.1 Electrical Component Types

2.5.1.1 Summary of Technical Information in the Application

LRA Section 2.5 describes the electrical component types, which include:

" cable connections (metallic parts)

" connectors

* electrical penetrations

* high-voltage insulators

* insulated cables and connections

* switchyard bus and connections

* terminal blocks

* transmission conductors and connections

* electrical equipment subject to 10 CFR 50.49 EQ requirements

* fuse holders (not part of a larger assembly)

* grounding conductors

* metal enclosed bus

Cable connections (metallic parts), connectors, insulated cables and connections, the

switchyard bus and connections, and terminal blocks electrically connect specified sections of

an electrical circuit to deliver voltage, current, or signals. High-voltage insulators support and

insulate the high-voltage transmission conductors and switchyard bus. Primary containment

electrical penetrations perform the functions of primary containment boundary and electrical

continuity. Transmission conductors and connectors supply offsite power to various plant

systems. Electrical equipment subject to 10 CFR 50.49 EQ requirements is evaluated as a

time-limited aging analysis and managed under the EQ program. All fuse holders, including the

fuses installed for electrical penetration protection, are parts of larger assemblies and managed

as parts of the active components. The uninsulated grounding conductors bond metal

raceways, building structural steel, and plant equipment to earth ground through an installed

grounding grid. The uninsulated grounding conductors are nonsafety-related and protect

personnel and equipment. The grounding conductors do not prevent faults and are not required

for equipment operation. Therefore, failure of a grounding conductor cannot affect the

accomplishment of any safety functions. The enclosed electrical phase bus is not part of an

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active component like a switchgear, load center, or motor control center. The isolated phase

bus is not within the scope of license renewal.

The failure of nonsafety-related SSCs in the electrical component types could prevent the

satisfactory accomplishment of an safety-related function. The electrical component types also

perform functions that support SBO.

LRA Table 2.5-1 identifies electrical component types within the scope of license renewal and

subject to an AMR:

* cable connections (metallic part)

• connector

* electrical penetrations

* high-voltage insulator

* insulated cable and connections

* switchyard bus and connections

* terminal block

* transmission conductors and connections

The intended functions of the electrical component types within the scope of license renewal

include:

* electrical continuity

* electrical insulation

* nonsafety-related support

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5 using the evaluation methodology described in SER

Section 2.5 and the guidance in SRP-LR Section 2.5, "Scoping and Screening Results:

Electrical and Instrumentation and Controls Systems."

During its review, the staff evaluated the system functions described in the LRA and USAR to

verify that the applicant has not omitted from the scope of license renewal any components with

intended functions delineated pursuant to1O CFR 54.4(a). The staff then reviewed those

components that the applicant has identified as within the scope of license renewal to verify that

the applicant has not omitted any passive and long-lived components subject to an AMR in

accordance with the requirements of 10 CFR 54.21 (a)(1).

The staff's review of LRA Section 2.5 identified areas in which additional information was

necessary to complete the review of the applicant's scoping and screening results. The

applicant responded to the staff's RAIs as discussed below.

In RAI 2.5-1 dated April 11, 2007, the staff noted that LRA Section 2.5 does not explicitly

describe the offsite recovery paths (from the switchyard to the onsite distribution system) for an

SBO. General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power

from the transmission network to the onsite electric distribution system be supplied by two

physically independent circuits to minimize the likelihood of their simultaneous failure. In

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addition, the staff noted that the guidance provided by letter dated April 1, 2002, "Staff

Guidance on Scoping of Equipment Relied on to Meet the Requirements of the Station Blackout

Rule (10 CFR 50.63) for License Renewal (10 CFR 54.4(a)(3))" and later incorporated in SRPLR Section 2.5.2.1.1, states:

For purposes of the license renewal rule, the staff has determined that the plant

system portion of the offsite power system that is used to connect the plant to

the offsite power source should be included within the scope of the rule. This

path typically includes switchyard circuit breakers that connect to the offsite

system power transformers (startup transformers), the transformers themselves,

the intervening overhead or underground circuits between circuit breaker and

transformer and transformer and onsite electrical system, and the associated

control circuits and structures. Ensuring that the appropriate offsite power

system long-lived passive SCs that are part of this circuit path are subject to an

AMR will assure that the bases underlying the SBO requirements are maintained

over the period of extended license.

The staff clarified that both paths that are used to control the offsite circuits to the plant should

be age managed. According to LRA drawing LR-WCGS-ELEC-KD-7496, the high-voltage

switchyard circuit breakers, underground cables, and its associated components and structures

are not presently included within the scope of license renewal. The staff requested that the

applicant justify why these components are not within the scope of license renewal and explain

in detail which high-voltage breakers and other components in the switchyard will be connected

from the startup transformer XMR01 and ESF No. 1 transformer XNB01 up to the offsite power

system for the purpose of SBO recovery.

In its response dated May 9, 2007, the applicant stated that the 345kV switchyard system

equipment beyond disconnect 345-163 and the 13.8kV switchyard system equipment beyond

disconnects 13-21 and 13-23 are not within the scope of license renewal because they are part

of the transmission system grid and not part of the plant system portion.

During a telephone conference dated June 13, 2007, the staff informed the applicant that its

response was unacceptable. The staff believes that the switchyard is part of the plant system

and that the SBO recovery paths should be within the scope of license renewal in accordance

with staff guidance dated April 1, 2002.

In its response dated August 8, 2007, the applicant stated that the WCGS scoping of SBO

equipment for license renewal is consistent with the direction provided in the letter dated

April 1, 2002. The applicant stated that the SBO boundary starts at the disconnects 345-163,

13-21 and 13-23, which are the preferred offsite power source and alternate offsite power

connection points, respectively, and include disconnects, the offsite system power transformers

(e.g., startup transformer), overhead and buried cables, station transformers, buses, and

isolation breakers. Upstream of the disconnects are the 345 kV buses, switchyard components,

and the incoming lines, all parts of the transmission (i.e., grid) system, not the plant system.

The staff informed the applicant that the WCGS position is not consistent with the staff

guidance and; therefore, is unacceptable. As discussed during a public meeting between NRC

and NEI, held on December 12, 2007, the staff believes that the offsite power recovery path,

from two independent sources from the switchyard to the plant Class 1 E safety buses, includes

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(1) switchyard circuit breakers that connect to the offsite power system (i.e., grid), (2) power

transformers, (3) intervening overhead or underground circuits (i.e., cables, buses and

connections, transmission conductors and connections, insulators, disconnect switches, and

associated components), (4) circuits between the circuit breakers and power transformers, (5)

circuits between the power transformers and onsite electrical distribution system, and (6) the

associated control circuits and structures. The staff evaluated the paths identified in the SBO

coping duration calculation for recovering offsite power following an SBO event. The SSCs

within the scope of the license renewal should include a circuit breaker at transmission voltage

to ensure adequate protection of the safety buses (ensure recovery of offsite sources). The

staff believes that the circuit breaker(s) needs to be within the scope of license renewal

because of its ability to provide plant power, protect downstream circuits and provide plant

operator-controlled isolation and energization ability. A circuit breaker can provide fault

protection and prevent transients from affecting the onsite distribution system as offsite power

is being restored. Therefore, the staff understands that at WCGS, the SBO recovery path that

should be included within the scope of license renewal are circuits up to and including the

switchyard circuit breakers. This was identified as open item (01) 2.5-1.

By letter dated March 29, 2008, the applicant revised the SBO recovery paths to include

circuitbreakers as the scoping boundary. The primary path from the safety buses, as described

in LRA Section 2.1.2.3.5, is through startup transformer XMR01. The startup transformer is

connected to the West Bus via disconnect switch 345-163 and the scoping boundary is circuit

breaker 345-70, which connects the West Bus to the 345 kV Benton line. LRA Section 2.1.2.3.5

describes the second SBO recovery path, which is from the safety buses through ESF

transformer No. 1 to disconnect switch 345-167, which connects to the East bus. The

underground cable from disconnect switch 13-23 to circuit breaker 13-48 has been included

within the scope of license renewal. The scoping boundary is circuit breaker 345-120, which

connects the East Bus to the 345 kV La Cygne line. Thus, the change to the SBO recovery

paths to include the complete path from the safety buses to circuit breakers at transmission

voltage level resolves 01 2.5-1.

In RAI 2.5-2 dated April 11, 2007, the staff requested that the applicant clarify why elements

such as resistance temperature detectors, sensors, thermocouples and transducers are not

included in the list of components and/or commodity groups subject to an AMR if a pressure

boundary is applicable.

In its response dated May 9, 2007, the applicant stated that the pressure boundary associated

with resistance temperature detectors, sensors, thermocouples, and transducers are evaluated

in mechanical systems as thermowells, flow indicators, and flow elements.

Based on its review, the staff finds the applicant's response to RAI 2.5-2 acceptable because it

adequately included the components in question within the scope of license renewal. The

applicant provided a list of the mechanical systems with thermowells, flow indicators, and flow

elements within the scope of license renewal that are subject to an AMR. Therefore, the staff's

concern described in RAI 2.5-2 is resolved.

In RAI 2.5-3 dated April 11, 2007, the staff noted that there has been operating experience

regarding the failure of cable tie-wraps caused by the brittleness of the plastic material. The

cable tie-wraps are long-lived passive components. Its intended functions include to maintain

spacing for power cable ampacity, maintain stiffness in unsupported lengths of wire bundles to

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ensure minimum bending radius, and maintain cables within vertical raceways. The staff noted

that most recently, at the Point Beach Nuclear Plant, the regional inspectors identified an

unresolved item (as documented in RAI 2.5-3) after noticing that the current configuration of the

plant may not be consistent with plant design documents due to age related breakage of a large

number of plastic tie-wraps used to fasten wires and cables. At Point Beach, cable tie-wraps

are part of the cable design in order to maintain cable ampacity or are credited in the licensee's

Seismic Qualifications Utility Group documents to seismically qualify the cable tray system.

Although Point Beach is a different power plant, the staff requested that the applicant explain

how it manages the aging of cable tie-wraps and to justify why the cable tie-wraps are not

included within the scope of license renewal.

In its response dated May 9, 2007, the applicant stated that:

Cable tie wraps at the WCGS are not within the scope of license renewal and

therefore, aging management is not required. Cable tie wraps perform no license

renewal intended functions. The functions stated by the staff "maintain spacing

for power cable ampacity, maintain stiffness in unsupported lengths of wire

bundles to ensure minimum bending radius, and maintain cables within vertical

raceways, among others" are not intended functions at the WCGS as defined by

10 CFR 54.4. WCGS has no CLB requirements that cable tie wraps remain

functional during and following DBEs. Cable tie wraps provide no license renewal

intended functions and do not meet any criteria found in 10 CFR 54.4(a)(1),

(a)(2), or (a)(3).

During a telephone conference dated July 9, 2007, the staff stated that the applicant's response

required clarification. The staff noted that there is operating experience showing instances in

which degraded cable tie-wraps have failed and lodged in components preventing the

performance of their intended functions. The staff requested that the applicant clarifies if

WCGS considered the potential effect on safety-related equipment caused by the failure of

plastic cable tie-wraps due to age-related degradation.

In its response dated August 9, 2007, the applicant stated that WCGS considered the potential

effect on safety-related equipment caused by the failure of plastic cable tie-wraps due to

age-related degradation and concluded that the failure of tie wraps that could prevent

satisfactory accomplishment of the applicable functions of the SSCs identified pursuant to

10 CFR 54.4(a)(1) is not credible because:

* WCGS uses nylon tie wraps that are resistant to heat related aging. Nylon has a 60-year

service environment of 119 OF. Most areas at WCGS have a maximum operating

temperature of 104 OF with a few rooms with maximum operating temperature of 120 OF.

No areas will see temperatures continuously above 119 OF for 60 years.

WCGS uses "tefzel" tie wraps in radiation areas and within the containment. Tefzel has

a 60-year service environment of 228 OF and 3 x 107 rads. The maximum operating

temperature for the containment is 120 OF with a 60-year normal dose of 5.25 x

103 rads.

* Tie wraps are lightweight and nonconductive.

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* Sensitive components that could be impacted by a loose tie wrap are installed within

protective enclosures.

* WCGS has experienced no equipment failures due to tie wrap failures.

" WCGS employs good housekeeping and foreign material exclusion practices.

Based on its review, the staff finds the applicant's response to RAI 2.5-3 acceptable. The staff

finds that WCGS considered the potential effect on safety-related equipment caused by the

failure of plastic cable tie-wraps due to age-related degradation. The staff also finds that the tie

wrap material at WCGS is appropriate for the environment (e.g., Tefzel in radiation areas),

sensitive components are installed with protective enclosures, and that WCGS applies foreign

material exclusion practices which would preclude tie wraps from entering sensitive areas. In

addition, a review of operating experience did not demonstrate a failure affecting safety-related

SSCs at WCGS. Therefore, the staff's concern described in RAI 2.5-3 is resolved.

2.5.1.3 Conclusion

The staff reviewed the LRA, USAR, and RAI responses to determine whether the applicant

failed to identify any SSCs within the scope of license renewal. In addition, the staff's review

determined whether the applicant failed to identify any components subject to an AMR. The

staff finds no such omissions. On the basis of its review, the staff concludes that there is

reasonable assurance that the applicant has adequately identified the electrical components

within the scope of license renewal with the exception of the SBO recovery paths, as required

by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

2.6 Conclusion for Scopincg and Screening

The staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology for

Identifying Structures and Components Subject to Aging Management Review and

Implementation Results," and determines that the applicant's scoping and screening

methodology was consistent with 10 CFR 54.21 (a)(1) and the staff's positions on the treatment

of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs

subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(1).

On the basis of its review, the staff concludes that the applicant has adequately identified those

systems and components within the scope of license renewal, as required by 10 CFR 54.4(a),

and those subject to an AMR, as required by 10 CFR 54.21 (a)(1).

The staff concludes that there is reasonable assurance that the applicant will continue to

conduct the activities authorized by the renewed license in accordance with the CLB and any

changes to the CLB in order to comply with 10 CFR 54.21 (a)(1), in accordance with the Atomic

Energy Act of 1954, as amended, and NRC regulations.

2-187

SECTION 3

AGING MANAGEMENT REVIEW RESULTS

This section of the safety evaluation report (SER) evaluates aging management programs

(AMPs) and aging management reviews (AMRs) for Wolf Creek Generating Station (WCGS)

Unit 1, by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff).

In Appendix B of its license renewal application (LRA), Wolf Creek Nuclear Operating

Corporation (WCNOC or the applicant) described the 39 AMPs that it relies on to manage or

monitor the aging of passive, long-lived structures and components (SCs).

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in

LRA Section 2 as within the scope of license renewal and subject to an AMR.

3.0 Applicant's Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, Revision 1, "Generic Aging Lessons

Learned (GALL) Report," dated September 2005: The GALL Report contains the staff's generic

evaluation of the existing plant programs and documents the technical basis for determining

where existing programs are adequate without modification, and where existing programs

should be augmented for the period of extended operation. The evaluation results documented

in the GALL Report indicate that many of the existing programs are adequate to manage the

aging effects for particular license renewal SCs. The GALL Report also contains

recommendations on specific areas for which existing programs should be augmented for

license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its

programs correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or

monitor the aging of SCs subject to an AMR. If an applicant commits to implementing these

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced,

improving the efficiency and effectiveness of the license renewal review process. The GALL

Report also serves as a quick reference for applicants and staff reviewers to AMPs and

activities that the staff has determined will adequately manage or monitor aging during the

period of extended operation.

The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials,

(3) environments to which the SCs are exposed, (4) the aging effects of the materials and

environments, (5) the AMPs credited with managing or monitoring the aging effects, and (6)

recommendations for further applicant evaluations of aging management for certain component

types.

To determine whether use of the GALL Report would improve the efficiency of LRA review, the

staff conducted a demonstration of the GALL Report process in order to model the format and

content of safety evaluations based on it. The results of the demonstration project confirmed

that the GALL Report process will improve the efficiency and effectiveness of LRA review, while

maintaining the staff's focus on public health and safety. NUREG-1800, Revision-1, "Standard

3-1
Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

dated September 2005, was prepared based on both the GALL Report model and lessons

learned from the demonstration project.

The staff's review was in accordance with Title 10, Part 54, of the Code of Federal Regulations

(10 CFR Part 54), "Requirements for Renewal of Operating Licenses for Nuclear Power Plants,"

and the guidance of the SRP-LR and the GALL Report.

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs and

associated AMPs during the weeks of March 26, and May 7, 2007. The onsite audits and

reviews are designed for maximum efficiency of the staff's LRA review. The applicant can

respond to questions, the staff can readily evaluate the applicant's responses, the need for

formal correspondence between the staff and the applicant is reduced, and the result is an

improvement in review efficiency.

3.0.1 Format of the License Renewal Application

The applicant submitted an application that follows the standard LRA format agreed to by the

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. This revised LRA

format incorporates lessons learned from the staff's reviews of the previous five LRAs, which

used a format developed from information gained during a staff-NEI demonstration project

conducted to evaluate the use of the GALL Report in the LRA review process.

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents

AMR results information in the following two table types:

(1) Table is: Table 3.x.1 - where "3" indicates the LRA Section number, "x" indicates the

subsection number from the GALL Report, and "1" indicates that this table type is the

first in LRA Section 3.

(2) Table 2s: Table 3.x.2-y - where "3" indicates the LRA Section number, "x" indicates the

subsection number from the GALL Report, "2" indicates that this table type is the second

in LRA Section 3, and "y" indicates the system table number.

The content of the previous LRAs and of the WCGS application is essentially the same. The

intent of the revised format of the WCGS LRA was to modify the tables in LRA Section 3 to

provide additional information that would assist in the staff's review. In its Table is, the

applicant summarized the portions of the application that it considered to be consistent with the

GALL Report. In its Table 2s, the applicant identified the linkage between the scoping and

screening results in LRA Section 2 and the AMRs in LRA Section 3.

3.0.1.1 Overview of Table is

Each Table 1 compares in summary how the facility aligns with the corresponding tables in the

GALL Report. The tables are essentially the same as Tables 1 through 6 in the GALL Report,

except that the "Type" column has been replaced by an "Item Number" column and the "Item

Number in GALL" column has been replaced by a "Discussion" column. The "Item Number"

column is a means for the staff reviewer to cross-reference Table 2s with Table is. In the

3-2
"Discussion" column the applicant provided clarifying information. The following are examples of

information that might be contained within this column:

* further evaluation recommended - information or reference to where that information is

located

" The name of a plant-specific program

* exceptions to GALL Report assumptions

* discussion of how the line is consistent with the corresponding line item in the GALL

Report when the consistency may not be obvious

* discussion of how the item is different from the corresponding line item in the GALL

Report (e.g., when an exception is taken to a GALL AMP)

The format of each Table 1 allows the staff to align a specific row in the table with the

corresponding GALL Report table row so that the consistency can be checked easily.

3.0.1.2 Overview of Table 2s

Each Table 2 provides the detailed results of the AMRs for components identified in LRA

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures

within a specific system grouping (e.g., reactor coolant system, engineered safety features,

auxiliary systems, etc.). For example, the engineered safety features group has tables specific

to the containment spray system, containment isolation system, and emergency core cooling

system (ECCS). Each Table 2 consists of nine columns:

(1) Component Type - The first column lists LRA Section 2 component types subject to an

AMR in alphabetical order.

(2) Intended Function - The second column identifies the license renewal intended

functions, including abbreviations, where applicable, for the listed component types.

Definitions and abbreviations of intended functions are in LRA Table 2.0-1.

(3) Material - The third column lists the particular construction material(s) for the

component type.

(4) Environment - The fourth column lists the environments to which the component types

are exposed. Internal and external service environments are indicated with a list of these

environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3.

(5) Aging Effect Requiring Management - The fifth column lists aging effects requiring

management (AERMs). As part of the AMR process, the applicant determined any

AERMs for each combination of material and environment.

(6) Aging Management Programs - The sixth column lists the AMPs that the applicant uses

to manage the identified aging effects.

(7) NUREG-1 801 Volume 2 Item - The seventh column lists the GALL Report item(s)

identified in the LRA as similar to the AMR results. The applicant compares each

combination of component type, material, environment, AERM, and AMP in LRA

Table 2 with the GALL Report items. If there are no corresponding items in the GALL

3-3
Report, the applicant leaves the column blank in order to identify the AMR results in the

LRA tables corresponding to the items in the GALL Report tables.

(8) Table 1 Item - The eighth column lists the corresponding summary item number from

LRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with

the GALL Report the Table 1 line item summary number should be listed in LRA

Table 2. If there is no corresponding item in the GALL Report, column eight is left blank.

In this manner, the information from the two tables can be correlated.

(9) Notes - The ninth column lists the corresponding notes used to identify how the

information in each Table 2 aligns with the information in the GALL Report. The notes,

identified by letters, were developed by an NEI work group and will be used in future

LRAs. Any plant-specific notes identified by numbers provide additional information

about the consistency of the line item with the GALL Report.

3.0.2 Staff's Review Process

The staff conducted three types of evaluations of the AMRs and AMPs:

(1) For items that the applicant stated were consistent with the GALL Report the staff

conducted either an audit or a technical review to determine consistency.

(2) For items that the applicant stated were consistent with the GALL Report with

exceptions, enhancements, or both, the staff conducted either an audit or a technical

review of the item to determine consistency. In addition, the staff conducted either an

audit or a technical review of the applicant's technical justifications for the exceptions or

the adequacy of the enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific GALL

AMP elements; however, any deviation from or exception to the GALL AMP should be

described and justified. Therefore, the staff considers exceptions as being portions of

the GALL AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet

all the program elements defined in the GALL AMP. However, the applicant may make a

commitment to augment the existing program to satisfy the GALL AMP prior to the

period of extended operation. Therefore, the staff considers these augmentations or

additions to be enhancements. Enhancements include, but are not limited to, activities

needed to ensure consistency with the GALL Report recommendations. Enhancements

may expand, but not reduce, the scope of an AMP.

(3) For other items, the staff conducted a technical review to verify conformance with

10 CFR 54.21 (a)(3) requirements.

Staff audits and technical reviews of the applicant's AMPs and AMRs determine whether the

effects of aging on SCs can be adequately managed to maintain their intended function(s)

consistent with the plant's current licensing basis (CLB) for the period of extended operation, as

required by 10 CFR Part 54.

3-4
3.0.2.1 Review of AMPs

For AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conducted

either an audit or a technical review to verify the claim. For each AMP with one or more

deviations, the staff evaluated each deviation to determine whether the deviation was

acceptable and whether the modified AMP would adequately manage the aging effect(s) for

which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full

review to determine their adequacy. The staff evaluated the AMPs against the following 10

program elements defined in SRP-LR Appendix A.

(1) Scope of the Program - Scope of the program should include the specific SCs subject

to an AMR for license renewal.

(2) Preventive Actions - Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected - Parameters monitored or inspected should be

linked to the degradation of the particular structure or component intended function(s).

(4) Detection of Aging Effects - Detection of aging effects should occur before there is a

loss of structure or component intended function(s). This includes aspects such as

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample

size, data collection, and timing of new/one-time inspections to ensure timely detection

of aging effects.

(5) Monitoring and Trending - Monitoring and trending should provide predictability of the

extent of degradation, as well as timely corrective or mitigative actions.

(6) Acceptance Criteria - Acceptance criteria, against which the need for corrective action

will be evaluated, should ensure that the structure or component intended function(s)

are maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process - Confirmation process should ensure that preventive actions are

adequate and that appropriate corrective actions have been completed and are

effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and

approval process.

(10) Operating Experience - Operating experience of the AMP, including past corrective

actions resulting in program enhancements or additional programs, should provide

objective evidence to support the conclusion that the effects of aging will be adequately

managed so that the SC intended function(s) will be maintained during the period of

extended operation.

Details of the staff's audit evaluation of program elements (1) through (6) are documented in

SER Section 3.0.3.

3-5
The staff reviewed the applicant's quality assurance (QA) program and documented its

evaluations in SER Section 3.0.4. The staff's evaluation of the QA program included

assessment of the "corrective actions," "confirmation process," and "administrative controls"

program elements.

The staff reviewed the information on the "operating experience" program element and

documented its evaluation in SER Section 3.0.3.

3.0.2.2 Review of AMR Results

Each LRA Table 2 contains information concerning whether or not the AMRs identified by the

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed

the intended function, material, environment, AERM, and AMP combination for a particular

system component type. Item numbers in column seven of the LRA, "GALL Report Volume 2

Item," correlates to an AMR combination as identified in the GALL Report. The staff also

conducted onsite audits to verify these correlations. A blank in column seven indicates that the

applicant was unable to identify an appropriate correlation in the GALL Report. The staff also

conducted a technical review of combinations not consistent with the GALL Report. The next

column, "Table 1 Item," refers to a number indicating the correlating row in Table 1.

3.0.2.3 USAR Supplement

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed

the updated safety analysis report (USAR) supplement, which summarizes the applicant's

programs and activities for managing the effects of aging for the period of extended operation,

as required by 10 CFR 54.21 (d).

3.0.2.4 Documentation and Documents Reviewed

In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.

During the onsite audit, the staff also examined the applicant's justifications to verify that the

applicant's activities and programs will adequately manage the effects of aging on SCs. The

staff also conducted detailed discussions and interviews with the applicant's license renewal

project personnel and others with technical expertise relevant to aging management.

3.0.3 Aging Management Programs

SER Table 3.0.3-1, presents the AMPs credited by the applicant and described in LRA

Appendix B. The table also indicates the SSCs that credit the AMPs and the GALL AMP with

which the applicant claimed consistency and shows the section of this SER in which the staff's

evaluation of the program is documented.

3-6
Table 3.0.3-1 WCGS Aging Management Programs

ýWCGS AMP 'New or ~-GALL Report~ GALL LRA Systems or ~ Staff s

.(LRA Section) -Existingl Comparison Report, Structures'.. SER Section

__,_______ '_ AMP< ___,_____ AMPs ThaitCreditthe AMP

ASME Code Existing Consistent with XI.M1 reactor vessel, internals, 3.0.3.2.1

Section Xl Inservice exceptions and reactor coolant system -

Inspection, / engineered safety features

Subsections IWB, / auxiliary systems

IWC, and IWD

(B2.1.1) __

Water Chemistry Existing. Consistent with XI.M2 reactor vessel, internals, 3.0.3.2.2

(B2.1.2) exception and reactor coolant system

I engineered safety features

I auxiliary systems / steam

and power conversion

system ! containments,

structures, and component

supports _____

Reactor Head Existing Consistent with XI.M3 reactorvessel, internals, 3.0.3.2.3

Closure-Studs exceptions and reactor coolant system

(B2.1.3) -

Boric Acid Existing Consistent with XI.M1 0 reactor vessel, internals, 3.0.3.2.4

Corrosion enhancement and reactor coolant system

(B2.1.4) / engineered safety features

• containments, structures,

and component supports /

electrical and

instrumentation and

controls

Nickel-Alloy Existing Consistent with XI.M1 1A reactor vessel, internals, 3.0.3.2.5

Penetration Nozzles enhancement and reactor coolant system

Welded to the

Upper Reactor

Vessel Closure

Heads of

Pressurized Water

Reactors

(82.1.5) I'

Flow-Accelerated Existing Consistent with XI.M17 reactor vessel, internals, 3.0.3.2.6

Corrosion exception and reactor.coolant system

(B2.1.6) / engineered safety features

/ steamand power

conversion, system

Bolting Integrity Existing :.Consistent with XI.M18 reactor vessel, internals, 3.0.3.2.7

(82.1.7) exceptions and reactor coolant system

/ engineered safety features

I auxiliary systems I steam,

and power. conversion

system / containments,

structures, and component

supports..

3-7
.WCGS AMP,'z.: New or GALL Report GALL ILRA Systems or.. Staffs

(LRA Section) Existing Comparison Report. .tructures SER Section,

AMP - '- AMPs That Credit the AMP

Steam Generator Existing Consistent with XI.M19 reactor vessel, internals, .3.0.3.2.8

Tube Integrity exception and reactor coolant system

(•B2.1.8) , •

Open-Cycle Cooling Existing Consistent XI.M20 auxiliary systems 3.0.3.1.1

Water System

(92.1.9)

Closed-Cycle Existing Consistent with XI.M21 reactor• vessel, internals, 3.0.3.2.9

CoolingWater exception and . and reactor coolant system

System enhancement l engineered safety features

(B2.1.10) /auxiliary systems

Inspection of Existing Consistent With XI.M23 auxiliary systems. 3.0.3.2.10

Overhead Heavy enhancements

Load and Ught

Load (Related to

Refueling) Handling

Systems

(B2.1.11)

Fire Protection Existing Consistent with XI.M26 auxiliary systems / 3.0.3.2.11

(B2.1.12) exception and containments, structures,

enhancements and component supports

Fire Water System Existing Consistent with XI.M27 auxiliary systems 3.0.3.2.12

(B2.1.13) exceptions _

Fuel Oil.Chemistry Existing Consistent with XI.M30 auxiliary systems 3.0.3.2.13

(B2.1.14). exceptions and

enhancements

Reactor Vessel Existing Consistent XI.M31 reactor vessel, internals, 3.0.3.1.2

Surveillance . . and reactor coolant system

(B2.1.15)_ _"_ _ _ _ _ _

One-Time New Consistent XI.M32 reactor vessel, internals, .3.0.3.1.3

Inspection and reactor coolant system

(B2.1.16) I engineered safety features

J auxiliary systems / steam

and power conversion

system

Selective Leaching New .Consistent with XI.M33 engineered safety features / 3.0.3.2.14

of Materials exceptions auxiliary systems

(92.1.17). ..

BuriedPipingand New Consistent XI.M34 engineeredsafety features/ 3&0.3.1.4

Tanks Inspection auxiliary systems / steam

(B2.1.18) * and power conversion

system

One-Time Existing Consistent with XI.M35 reactor vessel, internals, 3.0.3.2.15

Inspection of ASME exception and reactor coolant system

Code Class 1 / engineered safety features

Small-Bore Piping / auxiliary systems

(B2.1.19)

3-8
WCGS.AMP New or GALL Report GALL LRA Systems or Staffs

(LRA Section) Existing Comparison iReport Structures SER Section

-AMP_ -AMPs -That Creditthe AMP

External Surfaces Existing Consistent XI.M36 reactor vessel, internals, 3.0.3.1.5

Monitoring Program and reactor coolant system

(B2.1.20) . engineered safety features

/ auxiliary systems .steam

and power conversion

system

Flux Thimble Tube Existing Consistent XI.M37 reactor Vessel, internals, 3.0.3.1.6

Inspection and reactor coolant system

(B2.1.21)

Inspection of New Consistent XIM38 engineered safety features / :3.0.3.1.7

Internal Surfaces in auxiliary systems / steam

Miscellaneous and power conversion

Piping and Ducting system

Components

(92.1.22) ___, _

Lubricating Oil Existing Consistent with XI.M39 reactor vessel, internals, 13:0.3.2.16

Analysis exception and reactor coolant system

(B2.1.23) /engineered safety features

I auxiliary systems i steam

and power conversion

_system

Electrical Cables New Consistent XI.E1 electrical~and 3.0.3.1.8

and Connections instrumentation and

Not Subject to controls

10 CFR 50.49

Environmental

Qualification

Requirements

(B2.1.24)

Electrical Cables Existing Consistent XI.E2 electrical and 3.0.3.1.9

and Connections instrumentation and

Not Subject to controls

10 CFR 50.49

Environmental

Qualification

Requirements Used

in Instrumentation

Circuits

(82.1.25)

Inaccessible New Consistent XI.E3 . electrical and 3.0.3.1.10

Medium Voltage instrumentation and

Cables Not :Subject controls

to 10 CFR 50.49

Environmental

Qualification

Requirements

(B2.1.26)

3-9
.WCGS AMP New or GALL Report" GALL' LRA Systems or Staffsý.:,

(LRA Section) Existing Comparison Report Structures SER Section

.. AMPs That Credit the AMP

ASME Code Existing Consistent with Xl.S1. containments, structures, 3.0.3.2.17

Section Xl, exceptions and component supports

Subsection IWE

(B2.1.27)

ASME Code . Existing Consistent with XLS2 containments, structures, 3.0.3.2.18

Section XI, enhancement and component supports

Subsection IWL

(B2.1.28) . _

ASME Code Existing Consistent with XI.S3 containments,structures, 3.0.3.2.19

Section XI, exception and component supports

Subsection iWF

(B2-.1.29) '

10 CFR 50, Existing Consistent Xl.S4 auxiliary systems/ 310.3.1.11

Appendix J containments, structures,

(62.1.30) and component, supports _ _

Masonry Wall Existing Consistent with XI.S5 containments, structures, 3.0.3.2.20

Program enhancement and component supports

(12.1.31) I . . _ 

Structures Existing Consistent with XI.S6 auxiliary systems / 3.0.3.2.21

Monitoring Program enhancements containments, structures,

(B2.1.32) -. and component supports

RG 1.127, . Existing Consistent with XI.S7 containments, structures, 3.0.3.2.22

Inspection of enhancements and component supports

Water-Control. .

Structures

Associated with

Nuclear Power

Plants,

(62.1.33)

Nickel Alloy Aging Existing Plant-specific N/A reactor vessel, internals, 3.0.3.3.1

Management and reactor coolant system

Program / engineered safety features

(B2.1.34)

Reactor Coolant New Plant-specific N/A reactor coolant system 3.0.3.3.2

System Supplement

(62.1.35) ____,

Electrical Cable Existing Consistent with XI.E6 electrical and 3.0.3.2.23

Connections'Not enhancement instrumentation and

Subject to controls

10 CFR 50.49

Environmental

Qualification

Requirements

(B2.1.36)

3-10
K

WCGS AMP New or GALL Report GALL LRA Systems or Staffs

(LRA Section) Existing Comparison Report Structures SER Section/

AMP AMPs That Credit the AMP,

Metal Fatigue of Existing Consistent with X.M1 reactor vessel, internals, 3.0.3.2.24

Reactor Coolant enhancements and reactor coolant system

Pressure Boundary

(B3.1) .

Environmental Existing Consistent X.E1 electrical and 3.0.3.2.25

Qualification (EQ) of instrumentation and

Electrical controls

Components

(B3.2) __

Concrete Existing Consistent with X.S1 containments, structures, 3.0.3.2.26

Containment enhancements and component supports

Tendon Prestress

(B3.3) ....

3.0.3.1 AMPs Consistent with the GALL Report

In LRA Appendix B, the applicant identified thefollowing AMPs as consistent with the GALL

Report:

* Open-Cycle Cooling Water System

* Reactor Vessel Surveillance

• One-Time Inspection

* Buried Piping and Tanks Inspection

• External Surfaces Monitoring Program

• •Flux Thimble Tube Inspection

S- Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

10 CFR 50, Appendix J

3-11
3.0.3.1.1 Open-Cycle Cooling Water System

Summary of Technical Information in the Application. LRA Section B2.1.9 describes the existing

Open-Cycle Cooling Water System Program as consistent with GALL AMP XI.M20,

"Open-Cycle Cooling Water System."

The Open-Cycle Cooling Water System Program manages loss of material and reduction of

heat transfer for components exposed to raw water. The program includes chemical treatment

and control of biofouling, heat exchanger performance testing, and periodic inspections. The

program provides the general requirements for implementation and maintenance of programs

and activities which mitigate aging of the open-cycle cooling water (OCCW) SSCs. The various

aspects of the program (control, monitoring, maintenance, and inspections) are implemented in

station procedures. Chemical treatment of OCCW systems inhibits corrosion, deposition, and

fouling. A dispersant/anti-scalant is fed to the OCCW systems to prevent precipitation of

scale-forming salts. A copper corrosion inhibitor inhibits the corrosion of copper and/or copper

alloy system components. A nonoxidizing biocide controls macro-invertebrate (i.e., Asiatic

Clam) infestation. Physical cleaning of the OCCW system components, including the intake

bays, is also a macro-invertebrate control measure. Microbiological fouling is controlled by

oxidizing and nonoxidizing biocide treatments. Periodic flushes on heat exchangers and piping

in stagnant or low-flow areas of raw water systems remove silt and debris. Periodic visual

examinations of OCCW system components detect conditions which initiate aging. Specific

conditions to be documented include macro-invertebrate and microbiological fouling, scaling

and deposition build-up, and the condition of component interior surfaces and coatings.

Mechanical and/or chemical cleaning methods based on visual inspections remove deposits

and fouling from heat exchangers and other components in OCCW systems. Physical cleaning

of system components, including intake bays, also controls macro-invertebrate infestation.

Physical cleaning may be coordinated with chemical control treatment for optimum results.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Open-Cycle Cooling Water System Program, as listed in the audit summary.

Additionally, the staff reviewed the license renewal program evaluation report in which the

applicant assessed whether the program elements are consistent with GALL AMP XI.M20.

The applicant's license renewal program evaluation report indicates that the Open-Cycle

Cooling Water System Program relies on adherence to the commitments to Generic Letter (GL)

89-13 to manage age-related degradation in its open-cycle cooling water systems during the

period of extended operation. The applicant's commitments made to the staff are principally

implemented through the WCGS lake water systems corrosion and fouling mitigation program,

the' heat exchanger program, WCNOC procedure QCP-20-518, "Visual Examination of Heat

Exchangers and Piping Components," and the lake water system structural integrity program.

These programs and procedures perform the following activities on OCCW systems:

* biocides and corrosion inhibitors treatment

* periodic flushing and/or chemical cleaning to remove fouling

* periodic visual and/or nondestructive examination (NDE) inspection

* heat transfer testing in heat exchangers

* monitoring and trending of treatment, cleaning, and inspection results

* performs corrective actions through the plant's corrective action program

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On the basis that the applicant adheres to the commitments to GL 89-13 as described above,

the staff finds the Open-Cycle Cooling Water System Program follows the recommendations in

the GALL Report.

Operatingq Experience. LRA Section B2.1.9 (appendix) states that WCGS has experienced

macro-fouling (clam shells) of heat exchangers, room coolers, traveling screen spray nozzles,

and such low-flow or stagnant piping portions as drain lines, dead legs, and standby trains.

Macro-foul control methods include chemical treatment, system and component flushes, and

inspection and cleaning. The result of the transition in biocide treatments from the original

gaseous chloride through solid halogen donor in the 1993 to 1998 time frame to the current

sodium bromide supplemented with nonoxidizing biocide (in anticipation of the appearance of

Zebra mussels) is minimal evidence of clams at this time. The applicant stated that Zebra

mussels have not been detected in the lake. Low-flow areas are flushed for biocide coverage

and removal of silt and sedimentation. In addition, problems with the Train B auxiliary feedwater

(AFW) pump room cooler were resolved by modification of the previous design of its 4-inch

supply line, which caused susceptibility to clogging of the room cooler during quarterly supply

header flushing. A plant modification moved the room cooler supply line from the bottom of the

header to the top, thus preventing clogging of the line.

The applicant stated that in 2004, an increasing trend in tube leaks for OCCW room coolers

with copper-nickel tubes led to an evaluation of the impact of the leaks and a review of

maintenance and inspection practices. The review determined that a revised and a more

conservative acceptance criteria could detect and remove degraded tubes from service prior to

development of through-wall leaks.

The applicant describes that a report prepared in 2003 provided significant operating history for

buried piping in many OCCW systems. The report refers to a 1996 observation that the overall

condition of the piping was good with no significant internal corrosion and no systematic loss of

wall thickness. WCGS piping systems have experienced corrosion, pitting, and sedimentation

build-up especially in low-flow areas and stagnant dead legs off the main flow stream.

Replacement of OCCW piping has been infrequent. Some small piping has been replaced

because of blockage due to corrosion product build-up. These aging effects are controlled by

flushing, chemical treatment, inspections, and cleaning. In 2005, two normally stagnant or

low-flow sections of essential service water system (ESWS) piping were found to have pitting

corrosion that required repair or replacement. These sections of piping include the ESWS "A"

train warming line and auxiliary feed pump suction piping. The pitting corrosion of the ESWS

"A" train warming line was caused by multiple factors. The pitted section of piping is located

upstream of a vent previously used as an injection point for a chlorine solution used as a

biocide. The applicant stated that the chlorine solution appeared to have been introduced to the

warming line when there was no water flow. Chlorine gas absorbed into water forms hypochloric

and hydrochloric acids, both corrosive to steel, with hydrochloric acid the stronger of the two.

Chlorine gas is also highly corrosive to steel. Bubbles of chlorine gas apparently rose to the top

of the pipe sections after injection, directly corroding the steel and forming acids along the top

of the pipe. The applicant stated that chlorine is no longer used as a biocide.

The LRA states that another factor for pitting corrosion and wastage along the top piping

quadrant is a water-air interface. Waterline attack is driven by the large difference in oxygen

concentrations at the air-metal and water-metal interfaces. A section of ESWS "A" train

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auxiliary feed pump suction piping with through-wall leaks was cut out and visually examined.

The applicant determined that the aging mechanism for the through-wall leak was pitting due to

under-deposit corrosion typical for carbon steel piping exposed to raw water where small

regions under tubercles develop into self-sustaining pits. The applicant stated that the aging did

not compromise the structural integrity of the piping. The repair and replacements gained

additional margin on the minimum wall thickness. Additional ultrasonic testing (UT) inspections

of stagnant and low-flow areas of OCCW system piping are planned for the next refuel cycle.

The applicant stated that stagnant and low-flow piping lines have such preventive maintenance

as flushing and chemical treatment to mitigate such aging. However, due to the recent

operating experience with pitting and under-deposit corrosion in these lines, study is on-going

to improve the pressure boundary reliability of the OCCW systems. An overall project plan for

OCCW piping remediation is under development.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Open-Cycle Cooling Water System Program. The staff also

interviewed selected onsite personnel with specialized knowledge of the program. The staff

reviewed selected instances previously documented by the applicant, that identified issues with

the OCCW system and instances where the applicant implemented corrective actions.

The staff also reviewed the operating experience provided in the LRA to confirm that the

plant-specific operating experience did not reveal any degradation not bounded by industry

experience. During review of the operating experience, the staff noted that the applicant, during

a visual examination, discovered degradation that appeared to result from de-alloying in the

emergency diesel generator (EDG) heat exchanger train "A" tubing that is made of copper alloy

(i.e., C44300). Subsequent eddy current testing revealed multiple degradation indications.

Metallurgical evaluation of the tubing did not show de-alloying. Most indications were identified

as erosion-corrosion; however, one indication was a stress corrosion crack. The staff noted that

stress corrosion cracking (SCC) of copper alloys is usually associated with ammonia or polluted

waters. As a result, the staff requested that the applicant provides the details of augmented

inspection, trending, and mitigation resulting from this incident.

In its response to the audit, the applicant stated that there was one axial crack in the EDG

intercooler heat exchanger and that it was caused by stress corrosion. The exact initiation

mechanism could not be established since the original inside diameter surface was lost due to

flow-assisted corrosion. Ongoing corrective actions include preventive maintenance with eddy

current test (ECT), analysis of the data, and corrective actions for any tubes that do not meet

acceptance criteria. The applicant also stated that the EDG heat exchangers are being replaced

with stainless steel tubing (i.e., AL6X) and that the intercooler heat exchangers were replaced

during the refueling outage in 2006. The lube oil coolers and jacket water coolers are scheduled

for replacement during the refueling outages in 2008 and 2011, respectively, or during a

planned maintenance outage at power.

The staff noted that AL6X stainless steel is superior than copper alloys and is highly resistant to

SCC, pitting, erosion corrosion, and crevice corrosion in raw water. The staff finds that the

replacement of heat exchangers and coolers with copper tubing with heat exchangers and

coolers with stainless steel tubing will provide improved resistance to erosion corrosion, pitting,

crevice corrosion, and SCC.

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During the audit, the staff noted that the problem identification reports indicated an increase in

leakage trend in the electrical pen room cooler, the residual heat removal (RHR) pump "A"

cooler, the centrifugal charging pump "A" room cooler, and the containment air "D" cooler. The

staff requested that the applicant explain what caused the leaks and what actions are being

taken to address the increased leak trend.

In its response, the applicant stated that about half of the room cooler leaks are the result of an

isolated through-wall pit in the tubing. The remaining half of the leaks resulted from through-wall

pitting combined with some flow erosion in the H-bend areas. The applicant clarified that tubes

with deep through-wall pitting were allowed to remain in service because past eddy current

testing acceptance criteria allowed it. The eddy current acceptance criteria was changed and

past eddy current test data were reviewed to select room coolers for replacement. The RHR

pump "A" cooler leak caused a lot of unavailability time and room coolers were declared a

maintenance rule issue.

The applicant stated that corrective actions consist of replacing all degraded coolers. From a

total of 16 room coolers, 11 have been replaced, three are scheduled for replacement by the

refueling outage in 2008, and the remaining two are scheduled for replacement by the end of

2008. New cooler bundles are made of AL6XN tube material. Ongoing actions include

preventive maintenance, ECTs, data analysis, and corrective actions for any tubes that do not

meet acceptance criteria.

The applicant clarified that the failure mechanism of pitting and erosion for the containment air

"D" cooler tubes and U-bends is assumed to be consistent with other copper nickel tube

bundles in the room coolers because they have the same materials and same water source.

The tube bundles are planned for replacement during the refueling outage in 2008. Future

corrective actions will be based on the apparent cause because, given the configuration of

these coolers, eddy current testing is not possible. Flow and pressure change and heat transfer

capability are periodically verified in accordance with the WCGS commitments to GL 89-13. Any

leakage is detected early by continuous monitoring of leak detection systems.

The staff noted that AL6XN stainless steel is superior to copper alloys and highly resistant to

SCC, pitting, erosion corrosion, and crevice corrosion in raw water. Since the applicant is

replacing room coolers with room coolers made of AL6XN stainless steel tubing, the staff finds

that the applicant has addressed the degradation found during the inspection.

Based on its review, the staff finds that the actions taken by the applicant in response to the

problem identification reports demonstrate the effectiveness of the plant's corrective action and

the Open-Cycle Cooling Water System Programs.

The staff confirmed that the "operating experience" program element satisfies requirements

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.9, the applicant provided the USAR supplement for the

Open-Cycle Cooling Water System Program. The staff reviewed this section and determines

that the information in the USAR supplement is an adequate summary description of the

program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its audit and review of the applicant's Open-Cycle Cooling Water

System Program, the staff finds all program elements consistent with the GALL Report. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.2 Reactor Vessel Surveillance

Summary of Technical Information in the Application. LRA Section B2.1.15 describes the

existing Reactor Vessel Surveillance Program as consistent with GALL AMP XI.M31, "Reactor

Vessel Surveillance."

The Reactor Vessel Surveillance Program is consistent with American Society for Testing and

Materials (ASTM) E 185. Actual reactor vessel coupons are used but an exemption in the

original license permits use of material other than beltline weld for the weld coupons. The

surveillance coupons are tested by an offsite vendor qualified to its procedures. The testing

program and reporting comply with requirements of 10 CFR 50 Appendix H, "Reactor Vessel

Material Surveillance Program Requirements." The schedule has been revised by removal of

the last two coupon sets to the spent fuel pool at exposures greater than those expected at the

beltline wall at 60 years. Therefore, this removal meets the ASTM E 185-82 criterion that

capsules may be removed when its neutron fluence is between one and two times the limiting

fluence calculated for the vessel at the end of expected life. Vessel fluence is now determined

by ex-vessel dosimetry. This schedule change has been approved as required by 10 CFR 50

Appendix H.

Staff Evaluation. During its review, the staff evaluated the applicant's claim of consistency with

GALL AMP XI.M31.

The staff noted that the applicant has removed and analyzed four reactor vessel surveillance

capsules. The most recent capsule withdrawn, Capsule X, was determined to have a neutron

fluence of 3.49 x1019 n/cm2 (i.e., E greater than 1 MeV, 54 effective full power years (EFPY)).

All capsules were removed and tested to meet the test procedures and reporting requirements

of ASTM E-185-82. The two remaining capsules have been placed in the spent fuel pool and

are maintained for possible future reinsertion. Also, the calculations of reactor vessel

embrittlement have been projected in accordance with Regulatory Guide (RG) 1.99, Revision 2,

"Radiation Embrittlement of Reactor Vessel Materials." The current applicable

pressure-temperature (P-T) limits report is valid up to 20 EFPY and is not based on the

evaluation of the most recently withdrawn Capsule X. The staff finds that the applicant will

revise this report before reaching 20 EFPY and will project appropriate P-T limits to the end of

the 60-year period as part of its CLB and required by the NRC regulations.

Section 50.61 of 10 CFR and 10 CFR Part 50, Appendix G, establish the requirements and

criteria for generating the P-T limits for commercial light-water reactors in the United States.

The P-T limit curves that apply for the current operating conditions are included in the facility's

P-T limits report. The applicant's current P-T limits report is valid up to 20 EFPY. The data from

the analysis of surveillance Capsule X are not included in the current P-T limits report.

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By letter dated April 8, 2003, the applicant submitted its reactor pressure vessel (RPV)

surveillance capsule report for Capsule X. By letter dated December 13, 2003, the staff

concluded that there will not be any significant impact on P-T operating limits due to the

Capsule X results. The applicant committed to revise the P-T limits report before reaching 20

EFPY and will at that time project appropriate P-T limits to the end of the 60-year licensed

operating period. The P-T limit curves will be updated as required by 10 CFR Part 50,

Appendix G, or by operational needs. The staff finds that this assures that the operational limits

remain valid through the period of extended operation.

The staff reviewed the Reactor Vessel Surveillance Program for which the applicant claims the

program to be consistent with GALL AMP XI.M31, and finds that it follows the recommendations

provided in the GALL Report.

Operating Experience. LRA Section B2.1.15 states that the last tested capsule specimens were

exposed to fluences equivalent to approximately 54 effective full-power years and

demonstrated generous margins to the upper-shelf energy (USE) criterion, to pressurized

thermal shock (PTS) temperature screening criteria, to low end-of-life adjusted reference

temperatures, and to P-T limits in the limiting materials.

As part of the staff review of the operating experience, the staff noted that Capsule X was the

fourth reactor pressure surveillance capsule withdrawn from WCGS on April 12, 2002. The

neutron peak fluence was determined to be 3.49 x 10'9 n/cm2 (E greater than 1 MeV),

equivalent to 60 years or 54 EFPY. The two remaining capsules have been transferred to the

spent fuel pool.

The staff finds that this meets the ASTM E 185-82 criterion which states that capsules may be

removed when the capsule neutron fluence is between one and two times the limiting fluence

calculated for the vessel at the end of life. The staff's finds that the USE and PTS values in the

limiting materials are acceptable.

Based on its review (observation of plant evolution), the staff confirmed that the "operating

experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR

Section A.1.2.3.10; therefore, the staff finds this program element acceptable.

USAR Supplement. In LRA Section A1.15, the applicant provided the USAR supplement for the

Reactor Vessel Surveillance Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review of the applicant's Reactor Vessel Surveillance Program,

the staff finds all program elements consistent with the GALL Report. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

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3.0.3.1.3 One-Time Inspection

Summary of Technical Information in the Application. LRA Section B2.1.16 describes the

One-Time Inspection Program as consistent with GALL AMP XI.M32, "One-Time Inspection."

This program conducts one-time inspections of plant system piping and components to verify

the effectiveness of the Water Chemistry, Fuel Oil Chemistry, and Lubricating Oil Analysis

Programs. The aging effects to be evaluated by the One-Time Inspection Program are loss of

material, cracking, and reduction of heat transfer. The One-Time Inspection Program specifies

corrective actions and increased sampling of components if inspections find aging effects that

lead to loss of component intended function. The inspections required by this program will be

implemented and completed within ten years prior to the period of extended operation. In this

time period the One-Time Inspection Program will assure manifestation of potential aging

effects based on at least 30 years of WCGS operation. Major elements of the One-Time

Inspection Program include identification of component populations subject to one-time

inspection based on common materials and environments; determination of sample size by the

method described in Electric Power Research Institute (EPRI) Report TR-107514 based on the

population size of the material-environment groups; selection of components within such groups

for inspection based on specified criteria like service period, operating conditions, and design

margins; conducting American Society of Mechanical Engineers (ASME) Code Section Xl NDE

inspections of the selected components within the sample; and evaluating inspection results

and initiating corrective action for unacceptable results to maintain component intended

function.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the One-Time Inspection Program, as listed in the audit summary, including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M32.

As a result of the onsite inspection performed by the staff during the weeks of September 10,

and October 22, 2007, the applicant deleted the reference to EPRI TR-1 07514 from the

program description. By letter dated November 16, 2007, the applicant amended LRA

Section B2.1.16. As documented in the inspection report dated December 05, 2007, the staff

noted that the sample size used by the applicant will be based on a 90 percent confidence that

90 percent of the material and environment population is not experiencing significant aging

effects. The staff noted that the applicant made reference to EPRI TR-1 07514 because it

discusses this sampling plan; however, the staff confirmed that the applicant will not apply the

assumptions and analyses described by EPRI. Therefore, the staff finds acceptable the deletion

of this reference since the AMP continues to be consistent with the recommendations of the

GALL Report.

The staff finds that the applicant's One-Time Inspection Program provides reasonable

assurance that the aging effects of loss of materials, cracking, and reduction of heat transfer

will be adequately managed. The staff finds the applicant's One-Time Inspection Program

acceptable because, when implemented, it will conform to the recommendations of the GALL

Report.

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Operating Experience. LRA Section B2.1.16 states that there is no programmatic operating

experience for the new One-Time Inspection Program.

In LRA Section B2.1.16, the applicant explained that the One-Time Inspection Program is a

new program to be implemented before the current operating license expires. The NDE

inspection methods that will be used, such as visual (or remote visual), surface or volumetric, or

other established techniques, are consistent with industry practice.

During the audit, the staff interviewed the applicant's technical personnel to confirm that

plant-specific operating experience did not reveal degradation not bounded by industry

experience. On this basis, the staff finds that performing a one-time inspection is an acceptable

method for confirming that existing programs adequately manage potential aging effects.

The staff recognizes that the applicant's corrective action program, which records internal and

external plant operating experience, ensures continued review of operating experience. The

implementation of the corrective action program also ensures that appropriate changes to the

plant's program will be made, if deemed necessary. On the basis of its review of industry

operating experience and discussions with the applicant's technical personnel, the staff

concludes that the applicant's One-Time Inspection Program will adequately manage the aging

effects identified in the LRA for which this AMP is credited.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.16, the applicant provided the USAR supplement for the

One-Time Inspection Program. The applicant committed (Commitment No. 7) to implement the

One-Time Inspection Program described in LRA Section B2.1.16 within ten years prior to the

period of extended operation. By letter dated November 16, 2007, the applicant deleted the

reference to EPRI TR-1 07514 from the program description. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's One-Time Inspection

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.4 Buried Piping and Tanks Inspection

Summary of Technical Information in the Application. LRA Section B2.1.18 describes the new

Buried Piping and Tanks Inspection Program as consistent with GALL AMP XI.M34, "Buried

Piping and Tanks Inspection."

The Buried Piping and Tanks Inspection Program manages loss of material of buried

components in the emergency service water (ESW), emergency diesel engine fuel oil storage

and transfer, AFW, high-pressure coolant injection (HPCI (borated refueling water storage)),

3-19
and the fire protection systems. Opportunistic visual inspections monitor the conditions of

protective coatings and wrappings on carbon steel, gray cast iron, or ductile iron components,

and assess the conditions of stainless steel components with no protective coatings or wraps.

Evidence of damaged wrapping or defective coating is an indicator of possible corrosion

damage to the external surface of the components.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Buried Piping and Tanks Inspection Program, as listed in the audit summary,

including the license renewal program evaluation report in which the applicant assessed

whether the program elements are consistent with GALL AMP XI.M34.

During the audit, the staff requested that the applicant clarify which materials are included in the

Buried Piping and Tanks Inspection Program. Also, the staff requested that the applicant clarify

which materials are not coated. If there are coated materials, the staff requested that the

applicant describe these coatings.

In its response, the applicant stated that the materials included in the Buried Piping and Tanks

Inspection Program include steel, stainless steel, ductile iron, and gray cast iron. The applicant

clarified that coatings are not used on stainless steel materials. However, the steel, ductile iron

and gray cast iron piping is coated with coal tar enamel, and steel tanks are coated with coal tar

epoxy.

The staff finds that not using coatings in stainless steel piping is acceptable because this type

of piping is not usually coated when it is used in soil. Stainless steel piping that is in contact with

soil is not susceptible to aging effects. The staff finds that the use of coal tar enamel on piping

and the use of coal tar epoxy on tanks is acceptable because both of these coating systems are

commonly used for steel, ductile iron, and gray cast iron components that are in contact with

soil.

During the audit, the staff requested that the applicant identify if WCGS has buried tanks. In its

response, the applicant stated that the emergency fuel oil storage tanks are the only tanks

monitored by the Buried Piping and Tanks Inspection Program. The applicant clarified that

these storage tanks are made of carbon steel. The staff finds this acceptable because it is

consistent with accepted industry practices which are endorsed by NRC.

The staff reviewed the Buried Piping and Tanks Inspection Program for which the applicant

claims consistency with GALL AMP XI.M34 and finds that it follows the recommendations

provided in the GALL Report.

Operating Experience. LRA Section B2.1.18 states that the Buried Piping and Tanks Inspection

Program is a new program. However, there is operating experience with buried piping at

WCGS. The applicant stated that in 1987, corrosion was discovered on multiple runs of buried

piping within the scope of license renewal in the fire protection and AFW systems. The

corrosion discovered in the fire protection system piping was on carbon steel piping directly

connected to ductile iron piping. The study postulated that the AFW system corrosion was due

to current straying (not protected) from the fuel oil system or galvanic due to the carbon steel

piping acting as a sacrificial anode. The LRA states that since the completion of the 1987 study,

there have been four occurrences of leakage due to corrosion of the external surface of buried

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components. Three occurred in buried portions of the service water system not within the scope

of license renewal. An additional leak was discovered in the fire protection system in 1997.

Subsequent excavation discovered loss of material due to pitting corrosion caused by a break

in the protective coating.

During its review of the plant operating experience, the staff noted that in 1987, the engineering

study for galvanic corrosion on underground piping at WCGS discovered corrosion on multiple

runs of buried piping in the fire protection system that are within the scope of license renewal.

The corrosion was characterized as galvanic corrosion. The fire protection system had four

recorded discoveries of pitting corrosion, with two of these resulting in leakage. These

sections of piping were replaced and recoated. Pitting was also found on carbon steel piping

that was directly connected to ductile iron piping.

As a part of the staff review of operating experience, the staff noted that the study also

discovered corrosion in the AFW system. It postulated that the corrosion in the AFW system

was either due to stray current from the fuel oil system or galvanic corrosion due to the carbon

steel piping becoming a sacrificial anode. This piping was repaired or replaced.

In addition, there were four occurrences of leakage due to corrosion of the external surface of

buried components at WCGS. Three of these leaks occurred in buried portions of the

non-ESWS, which are not within the scope of license renewal. An additional leak was

discovered 1997 in the fire protection system outside the DG building. Subsequent excavation

in 1998 discovered loss of material due to pitting corrosion caused by a break in the protective

coating.

The staff finds that the borated refueling water and the AFW systems have only short runs of

pipe between the pipe tunnels and the buildings. The 1987 engineering study provides the only

known documentation of corrosion related failure in the AFW system. In this case, pitting

corrosion was discovered on excavated carbon steel piping. This section of piping was then

replaced from the condensate storage tank (CST) to the power block. There are no

documented external corrosion related failures of the borated refueling water system.

The staff finds that the emergency fuel oil system has only short runs of pipe between the

below grade fuel oil storage tank and the DG building. There are no documented external

corrosion related failures of the emergency fuel oil system piping. Also, the ESWS has multiple

long runs of carbon steel piping. There are no documented external aging failures of the buried

ESWS piping.

The staff finds that the corrective action program, which captures internal and external plant

operating experience issues, will ensure that operating experience is reviewed and incorporated

to provide objective evidence to support the conclusion that the aging effects are adequately

managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section Al .18, the applicant provided the USAR supplement for the

Buried Piping and Tanks Inspection Program. The applicant committed (Commitment No. 9) to

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implement the Buried Piping and Tanks Inspection Program described in LRA Section B2.1.18

prior to the period of extended operation. The staff reviewed this section and determines that

the information in the USAR supplement is an adequate summary description of the program,

as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Buried Piping and Tanks

Inspection Program, the staff finds all program elements consistent with the GALL Report. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.5 External Surfaces Monitoring Program

Summary of Technical Information in the Application. LRA Section B2.1.20 describes the

existing External Surfaces Monitoring Program as consistent with GALL AMP XI.M36, "External

Surfaces Monitoring."

The External Surfaces Monitoring Program manages loss of material from external surfaces of

steel components and hardening and loss of strength of elastomers in ventilation and

mechanical systems. The program consists of periodic visual inspections during system

engineer walkdowns to detect aging effects for aging management of loss of material, leakage,

elastomer hardening and loss of strength. The scope of the program includes those systems

and components requiring external surface monitoring. Walkdowns for systems inside

containment are at least at every refueling outage or as necessary based on system safety

significance, accessibility, production significance, trending of inspection results, and operating

experience. Components inaccessible during both plant operations and refueling outages are

evaluated for whether they have been or will be inspected at frequencies to ensure that aging

effects are managed to maintain intended functions during the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the External Surfaces Monitoring Program, as listed in the audit summary, including

the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M36.

The staff reviewed the External Surfaces Monitoring Program for which the applicant claims

consistency with GALL AMP XI.M36 and finds that it follows the recommendations provided in

the GALL Report.

Operating Experience. LRA Section B2.1.20 states that external surfaces inspections via

system inspections and walkdowns have been in effect at WCGS in support of 10 CFR 50.65

and have proven effective in maintaining the material condition of plant systems. The applicant

stated that elements that comprise these inspections are consistent with industry practice.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's External Surfaces Monitoring Program. The staff also interviewed

selected onsite personnel who have specialized knowledge of the program. The staff reviewed

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selected instances previously documented by the applicant that identified issues with external

surfaces and where the applicant had implemented corrective action.

During the audit, the staff reviewed a sampling of the applicant's completed walkdown forms to

assess how the data collected during the system walkdowns were documented, evaluated and

added to the corrective action program. The staff finds that the corrective action program, which

captures internal and external plant operating experience issues, will ensure that operating

experience is reviewed and incorporated to provide objective evidence to support the

conclusion that the aging effects are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.20, the applicant provided the USAR supplement for the

External Surfaces Monitoring Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's External Surfaces Monitoring

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.6 Flux Thimble Tube Inspection

Summary of Technical Information in the Application. LRA Section B2.1.21 describes the

existing Flux Thimble Tube Inspection Program as consistent with GALL AMP XI.M37, "Flux

Thimble Tube Inspection."

The Flux Thimble Tube Inspection Program performs wall thickness eddy current testing of all

flux thimble tubes forming parts of the reactor coolant system (RCS) pressure boundary, which

includes the length of the tube inside the reactor out to the seal fittings outside the reactor

vessel. Eddy current testing is performed on the portion of the tubes inside the reactor vessel.

The program implements the recommendations of NRC Bulletin 88-09, "Thimble Tube Thinning

in Westinghouse Reactors." All flux thimble tubes are inspected during each refueling outage.

Wall thickness measurements are trended and wear rates are calculated. If the predicted wear

for a given flux thimble tube is projected to exceed the established acceptance criterion prior to

the next refueling outage, corrective actions are taken to reposition, cap, or replace the tube.

Program documentation maintains details of the core location, wear location, and the number of

times a tube has been repositioned or replaced.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Flux Thimble Tube Inspection Program, as listed in the audit summary, including

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the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M37.

The GALL Report "scope of the program" program element refers to the applicant's responses

to NRC Bulletin 88-09 and any amendments to those responses. The "acceptance criteria"

program element states that acceptance criteria different from those previously documented in

NRC acceptance letters for the responses to NRC Bulletin 88-09 should be justified.

During the audit, the staff reviewed the applicant's original response to NRC Bulletin 88-09 and

its implementation procedure for the Flux Thimble Tube Inspection Program. The staff noted

that the applicant's original response to NRC Bulletin 88-09 states that any flux thimble with a

wall thickness loss of 60 percent or more would be removed from service. However, the

applicant's implementation procedure states that any flux thimble with greater than 80 percent

through-wall or projected to be greater than 80 percent before the next outage shall be

removed from service by capping or an equivalent action.

For clarification purpose, the staff requested that the applicant (1) explain if WCGS had

submitted any amendments to its original response to NRC Bulletin 88-09, (2) discuss the

technical bases for the change from 60 percent to 80 percent through-wall wear as the criterion

for removing a flux thimble tube from service, and (3) address whether the 80 percent

acceptance criterion includes allowances for uncertainties as described in the GALL Report.

In its response, the applicant stated that NRC Bulletin 88-09 does not require that subsequent

changes to the Flux Thimble Tube Inspection Program be submitted for NRC review, and no

amendments to its original response to NRC Bulletin 88-09 have been submitted. The applicant

also stated:

WCAP [Westinghouse Commercial Atomic Power] -12866, 'Bottom Mounted

Instrumentation Flux Thimble Wear,' was used to justify the change from 60

percent to 80 percent through-wall wear criterion at Wolf Creek for removing flux

thimble tubes from service. Appendix A of WCAP-1 2866 provides the results of

pressure testing and a finite element analysis and determined the maximum

allowable wall loss. Based on the Westinghouse test results [in WCAP-1 2866], it

was conservatively determined that a flux thimble can remain in service with up

to 80 percent through-wall loss. The 80 percent through-wall loss acceptance

criterion will maintain the structural and functional integrity of the flux thimble

tubes, and the flux thimble tubes can remain in service up to 80 percent wall

loss. It is noted that Wolf Creek procedures also address corrective actions at 60

percent indicated wall loss to prevent further through-wall loss by wear.

The staff reviewed the applicant's response and the detailed test data and evaluations provided

in Westinghouse Commercial Atomic Power (WCAP)-12866. In WCAP-12886, Westinghouse

compiled plant-specific wear rate data from Westinghouse-designed thimble tubes on behalf of

participating members in the Westinghouse Owner's Group. Westinghouse used its generic

compilation of thimble tube wear data to derive a generic wear rate equation for

Westinghouse-designed thimble tubes.

The staff reviewed the WCGS implementing procedure for projecting flux thimble tube wear and

finds that the implementing procedure requires that plant-specific eddy current test data be

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used for projecting wear. The following projecting wear methods are used: (1) linear

extrapolation from zero wear, (2) linear extrapolation from the most recent eddy current test

data, and (3) extrapolation using plant-specific data with the extrapolation method

recommended in the WCAP's. The staff finds that the most limiting wear projected by these

three methods is used to determine when corrective actions are necessary.

Based on its review, the staff concludes that the applicant's methodology for projecting flux

thimble tube wear is adequate because it is based on plant-specific data and a conservative

methodology for projecting wear. The staff also finds that the 80 percent through-wall loss

acceptance criterion is adequate because it includes appropriate conservatism to ensure that

structural and functional integrity of the flux thimble tubes will be maintained.

On this basis, the staff concludes that the applicant has an adequate technical justification for

the change in the acceptance criterion from what was documented in the applicant's response

to NRC Bulletin 88-09, and that the applicant's use of an 80 percent through-wall loss criterion

for removing a thimble tube from service by capping or equivalent is acceptable.

The GALL Report "monitoring and trending" program element states that examination

frequency will be based upon wear predictions that have been technically justified as providing

conservative estimates of flux thimble tube wear. It also states that the interval between

inspections will be established such that no flux thimble tube is predicted to incur wear that

exceeds the established acceptance criteria before the next inspection.

During the audit, the staff noted that the Flux Thimble Tube Inspection Program description in

the LRA states "all flux thimble tubes are inspected during each outage." However, the

applicant's implementing procedure includes a step that states "record the refueling at which

eddy current testing will next be required, this will be one refueling before the wear reaches 60

percent through-wall for the thimble with the greatest projected wear."

The staff requested that the applicant clarify whether the frequency for eddy current testing of

the flux thimble tubes is conditional (i.e., based on projected wear) or whether it is performed at

each outage, as stated in the LRA. The staff also requested that the applicant provides

technical justification that the methodology used for projecting flux thimble tube wear for future

operating cycles is conservative.

In its response, the applicant stated:

The Wolf Creek Flux Thimble Tube Inspection Program performs eddy current

testing that is conditional (i.e., based on predicted wear). The Flux Thimble Tube

Inspection Program calculates predicted wear based on WCGS' plant-specific

data and verifies that wear is acceptable for the next two subsequent refueling

outages. The refueling outage at which eddy current testing will be required is

determined and will be one refueling before the wear reaches 60 percent

through-wall for the thimble with the greatest projected wear. Wear trending of

thimble tubes is documented as well as projected wear at the next cycle. Any

thimble with wear in an active location greater than 60 percent through-wall or

projected to be greater than 60 percent through-wall before the next outage

should be repositioned. Any thimbles with greater than 80 percent through-wall

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or projected to be greater than 80 percent through-wall before the next outage

are capped, or equivalent, and considered for future replacement.

Based on the Westinghouse tests [as documented in WCAP-1 2866], eddy

current data over-estimates the depth of actual wear scars. Using eddy current

thimble wear data to predict wear will result in very conservative predictions of

wall loss. Although the WCAP states that it is not necessary to add additional

uncertainty margin to the eddy current wall loss indications, Wolf Creek uses an

uncertainty margin of 5 percent for conservatism. Conservatism of the

methodology for projecting wear for the following cycles is confirmed by WCAP

test data that exhibits an exponentially decreasing curve of flux thimble wall loss

versus operating time.

The applicant also stated that LRA Sections B2.1.21 and A1.21 will be amended to state

"During each outage, flux thimble tube wear is evaluated and inspections performed based on

evaluation results."

The staff reviewed the applicant's response and its methodology for projecting flux thimble tube

wear. The staff finds that the applicant's method for determining when to perform eddy current

testing of the flux thimble tubes is based on plant-specific wear projections, which is consistent

with the recommendations in the GALL Report.

Based on its review, the staff concludes that the applicant's methodology for determining when

to perform eddy current examinations is adequate to ensure that no flux thimble tube is

predicted to incur wear that exceeds the established acceptance criteria before the next

inspection. The staff determines that the applicant's conditional methodology for determining

flux tube thimble examination frequency is consistent with the recommendations in the GALL

Report.

By letter dated August 31, 2007, the applicant adequately amended LRA Sections A1.21 and

B2.1.21 to include this change. The staff finds this acceptable because the amended LRA

provides an accurate description of the Flux Thimble Tube Inspection Program as implemented

in the applicant's procedures.

The staff reviewed the Flux Thimble Tube Inspection Program for which the applicant claims

consistency with GALL AMP XI.M37 and finds that it follows the recommendations provided in

the GALL Report.

Operating Experience. LRA Section B2.1.21 states that WCGS has inspected flux thimble tubes

in accordance with NRC Bulletin 88-09, "Thimble Tube Wearing in Westinghouse Reactors."

Details of the core location, wear location, and the number of times a tube has been

repositioned, capped, or replaced are maintained. The applicant states that prior to 2002, no

thimble tubes were replaced. Since that time, 11 flux thimble tubes were replaced, ten due to

wear, with more wear-resistant chrome-plated tubes. There have been no through-wall failures

of flux thimble tubes causing a loss of reactor coolant pressure boundary (RCPB).

During the audit, the staff reviewed the operating experience provided in the LRA and

interviewed the applicant's technical personnel to confirm that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience. The staff

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requested that the applicant: (1) provide records of flux thimble tube inspections, (2) provide

additional discussion of site-specific operating experience with the Flux Thimble Tube

Inspection Program, and (3) explain why 10 of 11 flux thimble tubes were replaced with a more

wear-resistant design, but the eleventh replacement did not use a more wear-resistant design.

In its response, the applicant stated:

The first flux thimble tube inspection using eddy current testing with recorded

wear results was performed during refueling outage 4, spring 1990. Eddy current

testing has been performed on every flux thimble at every outage since such

testing was first begun. The 10 thimbles replaced due to thimble wall thinning

were ordered with [wear-resistant] chrome plating and available for replacement

during refueling outage 12. However, during cycle 12, after the new

chrome-plated thimbles had been ordered, another thimble developed an

obstruction which would not allow the incore detector to traverse the thimble. The

1 th thimble was replaced due to the obstruction, and not due to through-wall

wear. Since a chrome-plated thimble was not available and thimble wear was not

a concern for this thimble, an available thimble of original design and

manufacturing was used to replace the obstructed thimble. All 58 thimbles were

inspected using eddy current testing during refueling outage 15, fall 2006. All

thimbles met acceptance criteria for an additional cycle of operation, and no flux

thimble tubes were repositioned or replaced during refueling outage 15.

The staff reviewed the applicant's records from past flux thimble tube inspections and noted

that eddy current measurements of wall thickness for all flux thimble tubes were recorded at

each of the past 12 refueling outages. The staff also noted that the plant's records show when

flux thimble tubes have been replaced and whether, or how much, flux thimble tubes have been

repositioned.

The staff finds that the applicant's operating records provide detailed plant-specific data on flux

thimble wear patterns and wear rates. The staff determines that this plant-specific data has

been used to determine when flux thimble tubes require repositioning or replacement.

Therefore, the staff finds the applicant's response acceptable.

The staff confirmed that the "operating experience" program element satisfies requirements

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.21, the applicant provided the USAR supplement for the

Flux Thimble Tube Inspection Program. By letter dated August 31, 2007, the applicant

amended LRA Section A1.21 to state:

The Flux Thimble Tube Inspection Program performs wall thickness eddy current

testing of all flux thimble tubes that form part of the reactor coolant system

pressure boundary. The pressure boundary includes the length of the tube inside

the reactor out to the seal fittings outside the reactor vessel. Eddy current testing

is performed on the portion of the tubes inside the reactor vessel. The program

implements the recommendations of NRC Bulletin 88-09, "Thimble Tube

Thinning in Westinghouse Reactors."

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During each outage, flux thimble tube wear is evaluated and inspections

performed based on evaluation results. Wall thickness measurements are

trended and wear rates are calculated. If the predicted wear (as a measure of

percent through-wall) for a given flux thimble tube is projected to exceed the

established acceptance criteria prior to the next outage, corrective actions are

taken to reposition, cap, or replace the tube.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Flux Thimble Tube Inspection

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.7 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Summary of Technical Information in the Application. LRA Section B2.1.22 describes the new

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as

consistent with GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components."

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

manages cracking, loss of material, hardening, and loss of strength. Visual inspections of the

internal surfaces of piping, piping components, ducting, and other components not covered by

other AMPs are included in this program. The Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components Program uses the work control process to conduct and

document inspections. The program's visual inspections during periodic, predictive and

corrective maintenance, and surveillance testing detects aging effects that could cause a loss

of component-intended function. A review will determine the number of inspection opportunities

in the work control process for all systems within the scope of license renewal. In most of the

systems, the number of work opportunities are expected to be sufficient to detect aging and

provide reasonable assurance that intended functions are maintained. For systems or

components where inspections of opportunity are insufficient, an inspection prior to the period

of extended operation will provide reasonable assurance that intended functions are

maintained.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program, as listed in the audit summary, including the license renewal program evaluation

report in which the applicant assessed whether the program elements are consistent with GALL

AMP XI.M38.

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During the audit, the staff noted that LRA Section B2.1.22 states that the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program manages cracking, loss of

material, and hardening or loss of strength. The staff requested that the applicant clarify what

inspection techniques will be utilized to detect degradations such as hardening and loss of

strength.

In its response, the applicant clarified that piping and piping components will be inspected for

loss of material and that the inspection related to the loss of strength or hardening is only

applicable to elastomers in the heating, ventilation, and air conditioning (HVAC) systems. The

applicant also stated that physical manipulation during visual inspection of elastomers could be

used to verify the absence of hardening or loss of strength. The applicant stated that its new

AMP will provide procedural guidance and training required for personnel performing visual

inspections.

The staff finds the applicant's response acceptable because it clarified that the planned

inspection procedures will include required details to ensure that personnel performing visual

inspections have been adequately trained to determine whether a loss of strength has been

developed.

The GALL Report "acceptance criteria" program element recommends that indications of

various corrosion mechanisms or fouling that would impact component-intended function are

reported and evaluated.

During the audit, the staff requested that the applicant explain why the absence of monitoring of

fouling was not an exception to this GALL Report program element.

In its response, the applicant stated that monitoring of fouling was not included because it was

not identified as an aging effect for any component monitored by this AMP. Furthermore, by

letter dated August 31, 2007, the applicant amended LRA Section B2.1.22 to state:

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program manages cracking, fouling, loss of material, and

hardening - loss of strength. Fouling has not been identified as an aging effect in

any component currently in-scope for this aging management program.

The staff finds the applicant's response of justification acceptable. In addition, the staff finds

that the LRA amendment adequately clarifies that fouling is not an aging effect for the

components monitored by the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program.

During the audit, the staff reviewed those portions of the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program for which the applicant claims

consistency with GALL AMP XI.M38 and finds that they are consistent with the GALL AMP. The

staff finds the applicant's Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program acceptable because it conforms to the recommended GALL

AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components," as described below.

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The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program for which the applicant claims consistency with GALL AMP XI.M38 and

finds that it follows the recommendations provided in the GALL Report.

Operating Experience. LRA Section B2.1.22 states that the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program is a new program. Therefore, no

programmatic operating experience has been gained. The applicant stated that the program will

be reviewed to account for industry and station operating experience.

During the audit, the staff discussed the details of this program with the applicant's technical

personnel who informed the staff that the new Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components Program (a new program) will be implemented via existing

predictive maintenance, preventive maintenance, surveillance testing, and periodic testing work

order tasks. Such tasks have been in place since the plant began operation.

Based on the sampling review and discussions with the applicant, the staff finds that these

activities have proven effective at maintaining the material condition of systems, structures, and

components, and in detecting unsatisfactory conditions.

Based on its review supported by the staff's onsite audit, the staff confirmed that the "operating

experience" program element satisfies the criterion defined in the GALL Report and in SRP-LR

Section A.1.2.3.10. Therefore, the staff finds this program element acceptable.

USAR Supplement. In LRA Section A1.22, the applicant provided the USAR supplement for the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program. The

applicant committed (Commitment No. 11) to implement the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program prior to the period of extended

operation. By letter dated August 31, 2007, the applicant amended LRA Section A1.22 to state:

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program manages cracking, fouling, loss of material, and

hardening - loss of strength.

The staff reviewed this section and determines that the information in the amended USAR

supplement is an adequate summary description of the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components, the staff finds all program

elements consistent with the GALL Report. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.1.8 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B2.1.24 describes the new

Electrical Cables and Connections Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program, as consistent with GALL AMP XI.E1, "Electrical Cables and

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."

The Electrical Cables and Connections Not Subject to 10 CFR 50.49, Environmental

Qualification Requirements Program, manages the aging effects of embrittlement, melting,

cracking, swelling, surface contamination, or discoloration to ensure that electrical cables and

connections within the scope of license renewal not subject to the environmental qualification

(EQ) requirements of 10 CFR 50.49 can perform its intended functions. Non-EQ cables and

connections within the scope of license renewal in accessible areas with adverse environments

are inspected. Results of these inspections are representative, with reasonable assurance, of

conditions of cables and connections in inaccessible areas with adverse environments. At least

once every ten years non-EQ cables and connections within the scope of license renewal in

accessible areas are visually inspected for embrittlement, melting, cracking, swelling, surface

contamination, or discoloration. The acceptance criterion for visual inspection of accessible

non-EQ cable jacket and connection insulating material is the absence of anomalous

indications of degradation. Corrective actions for conditions adverse to quality are in

accordance with the corrective action program as part of the QA program. The corrective action

process provides reasonable assurance that conditions adverse to quality are either promptly

corrected or evaluated as acceptable.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Electrical Cables and Connections Not Subject to 10 CFR 50.49, Environmental

Qualification Requirements Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.E1.

The staff reviewed the Electrical Cables and Connections Not Subject to 10 CFR 50.49,

Environmental Qualification Requirements Program, for which the applicant claims consistency

with GALL AMP XI.E1 and finds it consistent with the recommendations in the GALL Report.

Operating Experience. LRA Section B2.1.24 states that the Electrical Cables and Connections

Not Subject to 10 CFR 50.49, Environmental Qualification Requirements Program, is a new

program and as such, no programmatic operating experience is available. A review of the plant

operating history determined that, in 2001, a steam leak had allowed water to drip onto a cable

tray. The steam leak was repaired and the cables were inspected. The applicant stated that no

cable degradation was observed.

The staff also reviewed the applicant's evaluation of industry operating experiences identified in

the staff's generic communications (i.e., NRC Information Notices (INs) 86-49, 92-81, and

98-21). The staff finds that the plant-specific operating experience did not reveal degradations

that are not bounded by industry experience.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.24, the applicant provided the USAR supplement for the

Electrical Cables and Connections Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program. The applicant committed (Commitment No. 12) to implement the

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environment Qualification

Requirements Program prior to the period of extended operation. The staff reviewed this

section and determines that the information in the USAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and

Connections Not Subject to 10 CFR 50.49, Environmental Qualification Requirements Program,

the staff finds all program elements consistent with the GALL Report. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.1.9 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits

Summary of Technical Information in the Application. LRA Section B2.1.25 describes the

existing Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits Program as consistent with GALL

AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits."

The scope of this program includes the cables and connections in sensitive instrumentation

circuits with sensitive, high-voltage low-level signals, within the ex-core neutron monitoring

system, including the source, intermediate, and power range monitors. This program provides

reasonable assurance that the intended functions of cables and connections in instrumentation

circuits with sensitive, low-level signals, not subject to the EQ requirements of 10 CFR 50.49

and exposed to adverse environments of heat, radiation, or moisture are maintained

consistently with the CLB through the period of extended operation. In most areas, the actual

ambient environments (e.g., temperature, radiation, or moisture) are less severe than the plant

design environment. Calibration surveillance tests manage the aging of the cable insulation and

connections so instrumentation circuits perform intended functions. For an instrumentation

channel found out of calibration during routine surveillance testing, troubleshooting on the loop,

including the instrumentation cable and connections, is performed. A review of calibration

results will be completed before the period of extended operation and every 10 years thereafter.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits Program, as listed in the audit

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summary, including the license renewal program evaluation report in which the applicant

assessed whether the program elements are consistent with GALL AMP XI.E2.

The GALL Report "scope of the program" program element includes electrical cables and

connections (i.e., cable system) used in circuits with sensitive, high-voltage, low level signals

such as radiation monitoring, and nuclear instrumentation. However, the scope of Electrical

Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program only includes the ex-core neutron

monitoring system.

During the audit, the staff requested that the applicant explain why the high range radiation

monitoring cable systems are not included within the scope of this program. In its response, the

applicant stated that the cable systems associated with the high-range radiation monitor that

are within the scope of license renewal are subject to 10 CFR 50.49 environmental

requirements and, therefore, are not included in this AMP.

The staff confirmed that high range radiation monitoring cables, J-361A, are included in the EQ

master list. The staff finds the applicant's response acceptable because high range radiation

monitors are subject to EQ requirements pursuant to 10 CFR 50.49. Therefore, the cable

systems associated with the high range radiation systems do not require an AMR.

During the audit, the staff also requested that the applicant identify other sensitive,

high-voltage, low level signal circuits, in addition to the ex-core neutron monitoring system at

WCGS. The staff requested that the applicant explain why these circuits are not within the

scope of the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits Program.

In its response, the applicant stated that the following is a list of the equipment that uses coaxial

cable that could have sensitive, high-voltage, low level signal circuits in addition to the ex-core

neutron monitoring systems at WCGS:

* high range area radiation monitors

* containment atmosphere humidity detectors

* unit vent radiation monitors

* solid radwaste system radwaste effluent radiation monitors

* post-accident sample system sampling panels

* loose parts monitoring

* solid radwaste spent resin primary storage tank inlet element and control station

* balance of plant computer

* public address system (intercom)

* plant security system equipment

* generator hydrogen and carbon dioxide system

* miscellaneous control panels (rad camera)

* in-core neutron monitoring system

* condensate demineralizer system acid day tank level

The applicant also stated that these systems do not provide license renewal intended functions

and do not meet any criteria found in 10 CFR 54.4(a)(1), (a)(2), or (a)(3), except for high-range

area-radiation monitors.

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The staff finds the applicant's response acceptable because it clarified that these systems are

not within the scope of license renewal and are not within the scope of this program.

The GALL Report states that review of calibration results or surveillance programs finding can

provide an indication of aging effects based on the instrumentation circuit performance

acceptance criteria related. By reviewing the results obtained during normal calibration or

surveillance, an applicant may detect severe aging degradation prior to the loss of the cable

and connection intended function. In cases where a calibration or surveillance program does

not include the cabling system (i.e., disconnected cables), the applicant should perform a cable

system test.

The staff requested that the applicant clarify if the ex-core neutron monitoring cables are

disconnected during the calibration surveillance procedure. In its response, the applicant stated

that the ex-core neutron monitoring system cables are not disconnected during the calibration

procedure.

The staff finds the applicant's response acceptable because it explained that the cables in

question are connected during the performance of the calibration procedure. The staff finds that

this is consistent with the GALL Report, which explains that testing of cable systems is not

required if these cable systems are not disconnected during calibration surveillance.

The staff reviewed the Electrical Cables and Connections Not Subject to 10 CFR 50.49

Environmental Qualification Requirements Used in Instrumentation Circuits Program for which

the applicant claims consistency with GALL AMP XI.E2 and finds it consistent with the

recommendations of the GALL Report.

Operatin, Experience. LRA Section B2.1.25 describes a case where a change in temperature

across a high-range radiation monitor cable in containment caused substantial change in the

monitor reading. The applicant stated that changes in instrument calibration can be caused by

degradation of the circuit cable and are possible indications of electrical cable degradation.

Most site-specific and industry-wide operating experience with neutron flux instrumentation

circuits relates to cable and connector issues inside of containment near the reactor vessel.

During the audit, the staff noted that in the plant program evaluation report the applicant stated

that a review of plant operating experience indicates that there has been no failure of the

source, intermediate, and power range instrumentation cables. The applicant also stated that

there have been a few problems with loose connectors due to improper connector installation

and dirty connectors. Because of circuit problems, testing was performed on the source,

intermediate, and power range circuits in 1998, 1999 and 2005. The tests performed in 2005

determined that the condition of the cables for the source and intermediate range circuits

remained constant, showing no degradation for the past seven years. However, the cables for

the power range circuits indicated an increase in the capacitance between the outer shield and

ground near the detector assembly. The applicant evaluated this condition through its corrective

action program and found it acceptable.

The staff reviewed samples of problem identification reports and operating experience

evaluations and noted that plant-specific operating experience revealed no degradation not

bounded by industry experience.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.25, the applicant provided the USAR supplement for the

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits Program. The applicant committed

(Commitment No. 13) to complete a review of the calibration surveillance test results before the

period of extended operation and every ten years thereafter. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Electrical Cables and

Connections Not Subject to 10 CFR 50.49, Environmental Qualification Requirements Used in

Instrumentation Circuits Program, the staff finds all program elements consistent with the GALL

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s), as evaluated above, will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.1.10 Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B2.1.26 describes the new

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program, as consistent with GALL AMP XI.E3, "Inaccessible Medium-Voltage

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."

The Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49, Environmental

Qualification Requirements Program, manages the aging effects of inaccessible

medium-voltage cables within the scope of license renewal exposed to adverse environments

caused by significant moisture and voltage to ensure that they can perform their intended

functions. All cable manholes, with non-EQ inaccessible medium-voltage cables that are within

the scope of license renewal will be inspected for water collection to be removed as required.

This inspection and water removal will be based on actual plant experience with the inspection

frequency at least once every two years. All non-EQ inaccessible medium-voltage cables that

are within the scope of license renewal will be tested for indications of adverse conductor

insulation conditions. There will be a polarization index test as described in EPRI

TR-1 03834-Pl -2 or other state-of-the-art testing at least once every ten years. The acceptance

criteria for each test will be defined for the specific type of test and specific cable tested.

Periodic inspections of cable manholes for water accumulation will minimize cable exposure to

water. Corrective actions for conditions adverse to quality are in accordance with the corrective

action program as part of the QA program. The corrective action process provides reasonable

assurance that conditions adverse to quality are either promptly corrected or evaluated as

acceptable.

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Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49,

Environmental Qualification Requirements Program, as listed in the audit summary, including

the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.E3.

The GALL Report defines medium voltage as voltage from 2 kV to 35 kV. The Inaccessible

Medium-Voltage Cables Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program, states that the non-EQ inaccessible medium-voltage cables that are

within the scope of license renewal, and that are exposed to significant moisture simultaneously

with significant voltage, are 5 kV and 15 kV.

During the audit, the staff requested that the applicant identify any inaccessible medium voltage

cables from 2 kV to 35 kV. In its response, the applicant stated that the only medium-voltage

cables that are from 2 kV to 35 kV are the 5 kV and 15 kV cables. The scope of this program

includes all of the inaccessible voltage cables that are within the scope of the license renewal at

WCGS.

The staff finds the applicant's response acceptable because it clarified that none of the

inaccessible medium-voltage cables within the scope of this program are greater than 15 kV.

The staff guidance in SRP-LR Section 2.5.2.1.1, states that station blackout (SBO) restoration

of offsite power paths should be included within the scope of license renewal. The staff noted

that the scope of the applicant's Inaccessible Medium Voltage Cables Not Subject to

10 CFR 50.49, Environmental Qualification Requirements Program, only includes inaccessible

medium-voltage cables from disconnect switch 13-23 to the engineered safety features (ESF)

transformer. The staff noted that it did not include the underground cables from transformer 7 to

disconnect switch 13-23. This inaccessible medium-voltage cable provides connection for the

SBO restoration of offsite power path. If this underground cable is not managed, significant

aging effects due to moisture can affect its intended function for SBO restoration.

During the audit, the staff requested that the applicant explain how it manages this underground

cable to satisfy the criteria in the SRP-LR (and in accordance with the rules) to ensure that SBO

restoration of offsite power paths are maintained during the period of extended operation.

In its response, the applicant stated that WCGS includes two paths of SBO restoration power

within the scope of license renewal. The connections to the switchyard are through disconnects,

not circuit breakers. One path is from disconnect switches 13-21 or 13-23 via underground

cable to the station ESF transformer. The applicant stated that this configuration conforms to

the requirement of 10 CFR 50, Appendix A, General Design Criterion (GDC) 17, that states

"The onsite electrical distribution system shall be supplied by two physically independent circuits

designed and located so as to minimize the extent practical the likelihood of their simultaneous

failure under operating and postulated accident and environmental conditions."

The applicant also stated that the entire plant system portion of the SBO restoration power

system is within the scope of license renewal. The applicant stated that this conforms with the

staff position in the SRP-LR which states, "Consistent with the requirements specified in

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10 CFR 54.4(a)(3) and 10 CFR 50.63(a)(1), the plant system portion of the offsite power

system should be included within the scope of license renewal."

The applicant stated that the 345 kV switchyard system equipment beyond disconnect 345-163

and the 13.8 kV switchyard system equipment beyond disconnect switches 13-21 and 13-23,

including the 13.8 kV switchgear, circuit breaker 13-48; transformers 4, 5, and 7, and the

underground cable are part of the offsite transmission system (i.e., grid), and are not part of the

plant system portion of the offsite power and; therefore, are not within the scope of license

renewal. The applicant also stated that Westar Energy is the owner of the switchyard and is

responsible for switchyard equipment design, operation, and maintenance.

The staff found that additional information was necessary to determine if the scoping of these

electrical components was performed adequately. As described in SER Section 2.5, in request

for information (RAI) 2.5-1 dated April 11, 2007, the staff requested that the applicant further

justify why the high-voltage switchyard circuit breakers, 13.8 kV medium-voltage underground

cables, and its associated components and structures are not within the scope of license

renewal. The applicant responded to the staff's RAIs by letters dated May 9 and

August 8, 2007. For the reasons below, the staff finds the applicant's responses unacceptable.

General Design Criteria 17, described in 10 CFR 50, Appendix A, requires that the onsite

electrical distribution system be supplied by two physically-independent circuits designed and

located to minimize the likelihood of their simultaneous failure under operating and postulated

accident and environmental conditions. The staff's position in the SRP-LR is that

physically-independent power paths are maintained for SBO restoration for offsite power during

extended periods of operation. The staff clearly defined the plant's system boundary as the

offsite power system. The offsite power system consists of transmission system (i.e., grid)

components that provide a source of power and components that connect that power source to

the plant's onsite electrical distribution system. For the purposes of the license renewal rule, the

staff determines that the relevant portion of the offsite power system that connect to the onsite

electrical distribution systems should be included within the scope of license renewal. This path

includes the switchyard circuit breakers that connect the offsite system power transformers (i.e.,

startup transformers), the transformers themselves, the relevant intervening overhead or

underground circuits between the circuit breaker and the transformer and the transformer and

onsite electrical distribution system, and its associated control circuits and structures. Ensuring

that the appropriate offsite power system, long-lived passive structures and components, that

are part of this circuit path are subjected to an AMR guarantees that the bases underlying the

SBO requirements are maintained over the period of the extended license. This is consistent

with the NRC expectations in including the SBO regulated event as described under

10 CFR 54.4(a)(3) of the license renewal rule. Managing only a portion of the independent

power path (i.e., the equipment beyond disconnect switches 13-21 and 13-23) does not satisfy

the staff's guidance in the SRP-LR. Further, the fact that Westar Energy is the owner of the

switchyard does not preclude the applicant from managing the complete circuit paths. The staff

believes that the subject components should be included within the scope of license renewal

and managed by this AMP. Therefore, this has been identified as open item (01) 3.0.3.1.10-1.

In a letter dated March 29, 2008, ET 08-0022, the applicant stated that in response to 01 2.5-1,

the applicant has included the inaccessible medium voltage switchyard cable from disconnect

13-23 up to breaker 13-48 within the scope of license renewal. Per 10 CFR 54.4(a)(3), the AMP

related to inaccessible medium voltage cable not subject to 10 CFR 50.49, EQ requirements

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applies to this cable. In a March 29, 2008 letter, ET 08-0021, to resolve 01 3.0.3.1.10-1, the

applicant submitted Amendment 6 to the LRA to provide changes to the license renewal scope.

As a part of this submittal, the underground cables from circuit breaker 13-48 to disconnect

switch 13-23 will be included in the scope of inaccessible medium-voltage cable not subject to

10 CFR 50.49 EQ requirements AMP. This will ensure that long-lived passive structure and

components that are parts of SBO offsite power restoration paths are maintained consistent

with CLB during the period of extended operation. The staff finds the applicant's response to

01 3.0.3.1.10-1 acceptable. 01 3.0.3.1.10-1 is closed.

The staff reviewed the Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49

Environmental Requirements Program requirements for which the applicant claims consistency

with GALL AMP X1 .E3. The staff finds it is consistent with the GALL report recommendations.

ODerating Experience. LRA Section B2.1.26 states that the non-EQ inaccessible medium

voltage cables within the scope of license renewal exposed to significant moisture and voltage

are 5kV and 15kV Kerite cables with high-temperature Kerite insulation. According to Sandia

report SAND96-0344, Section 4.1.2.5, industry operating experience shows that water treeing is

much less prevalent with this insulation type than in cable with cross-linked polyethylene

insulation. The applicant stated that a review of the plant operating history determined that

water has accumulated in cable manholes. In 2004, the cable manholes for these in-scope

medium-voltage cables exposed to significant moisture and voltage were inspected for

degradation of the cable support members due to water. All cable support members were found

satisfactory. In addition, the applicant stated that there has been no failure of inaccessible

medium-voltage cables.

The staff reviewed operating experience in the program evaluation report and noted that in the

applicant identified a substantial amount of water in manhole 119. This manhole contains

13.8 kV cable that goes to the circulation water pumps. This manhole also contains other

medium-voltage cables that are within the scope of license renewal. It appeared that no

corrective action was taken because the applicant performed an evaluation and concluded that

the cable was qualified to be submerged. The staff noted that if these cables were allowed to

be wet for a period of time, there is a possibility of cable degradation that can affect their safety

functions during the period of extended operation.

During the audit, the staff requested that the applicant describe corrective actions taken to

address water problems in manholes. The staff also requested that the applicant clarify if the

manhole inspection procedures will be implemented during the period of extended operation.

In its response, the applicant stated that the evaluation of this issue was based on the criteria

available at that time. Since 1998, additional guidance and information has become available.

Based on this information, the applicant initiated a preventive maintenance program to

periodically inspect applicable manholes containing medium-voltage cables. This inspection

includes removal of water (if required), visual inspection for corrosion and degradation of the

cable tray support, and visual inspection for cable jacket degradation. The applicant also stated

that preventive maintenance will be implemented before the period of extended operation.

During the regional onsite inspection performed during the week of September 22, 2007

(documented in inspection report IR 05000482/2007007), the inspectors found water in the

emergency service water cable manholes. The staff noted that these cables are within the

scope of license renewal. The staff finds that this incident demonstrates that the corrective

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actions previously described by the applicant have not been properly implemented or were not

adequate. In light of this operating experience, the staff is concerned that cables that were

submerged for a period of time may not perform their intended functions during the period of

extended operation. The inspection and water removal frequency of at least once every two

years, as proposed in the applicant's Inaccessible Medium-Voltage Not Subject to

10 CFR 50.49, Environment Qualification Requirements Program, may not be adequate to

detect water accumulation in the manholes.

During the inspection, as documented in the inspection report dated December 5, 2007, the

staff discussed the details of this program with the applicant's technical personnel. The staff

expressed concerns that the draft program procedure failed to ensure that inaccessible cables

that are within the scope of license renewal would be kept dry during the period of extended

operation. As a result, the applicant revised the draft procedure to include operating history

when determining the frequency of cable vault pumping and clarified its requirement that the

cables were to remain dry before entering the period of extended operation. In addition, the

applicant revised the procedure to ensure that if any cable is found submerged: (1) a work

request will be initiated, (2) the manhole will be pumped dry, and (3) the inspection frequency

will be increased.

The staff noted that the applicant claims that the subject emergency service water cables are

qualified for being submerged. However, the staff disagrees with the applicant's position. The

staff noted that this is currently being evaluated as a current operating license issue under the

requirements of 10 CFR Part 50. However, the staff determined there is reasonable assurance

that if the AMP is implemented as described, the aging effects of these inaccessible cables will

be adequately managed during the period of extended operation. The staff finds that the

applicant will evaluate its plant-specific operating experience to determine if the inspection

frequency for these manholes should be increased to ensure that the cables are maintained

dry. The staff finds that the AMP implementing procedure has been revised to ensure that if

water is found during the increased inspection frequency, additional actions must be considered

to keep the cables from becoming submerged.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.26, the applicant provided the USAR supplement for the

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program. The applicant committed (Commitment No. 14) to implement the

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49, Environmental Qualification

Requirement Program, prior to the period of extended operation. The staff reviewed this

section and determines that the information in the USAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Inaccessible Medium Voltage

Cables Not Subject to 10 CFR 50.49, Environmental Qualification Requirements Program, the

staff finds all program elements as documented in the LRA consistent with the GALL Report.

The staff concludes that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

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reviewed the USAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.1.11 10 CFR 50, Appendix J

Summary of Technical Information in the Application. LRA Section B2.1.30 describes the

existing 10 CFR 50, Appendix J Program as consistent with GALL AMP XI.S4, "10 CFR 50,

Appendix J."

The 10 CFR Part 50, Appendix J Program monitors leakage rates through the containment

pressure boundary, including the penetrations and access openings, to detect degradation of

containment pressure boundary. Seals, gaskets, and bolted connections are also monitored

under the program. Containment leak rate tests assure that leakage through the primary

containment and systems and components penetrating primary containment do not exceed

allowable leakage limits in the technical specifications. Corrective actions are taken if leakage

rates exceed established administrative limits for individual penetrations or the overall

containment pressure boundary. Type A tests measure the containment overall integrated

leakage rate. Program procedures require a general visual inspection of the accessible interior

and exterior surfaces of the primary containment and components prior to each integrated leak

rate test pressurization. In addition, there were visual examinations of containment, as

described by RG 1.163, during two other refueling outages between 10-year interval Type A

tests. Type B local leak rate tests on containment pressure boundary access penetrations are

performed at frequencies that comply with the requirements of 10 CFR Part 50 Appendix J,

Option B. The Type B test is intended to detect or measure leakage across pressure-retaining

or leakage-limiting boundaries other than valves. Type C local leak rate tests on containment

isolation valves are performed at frequencies that comply with the requirements of

10 CFR Part 50, Appendix J, Option B.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff interviewed the applicant's technical staff and reviewed documents

related to the 10 CFR 50, Appendix J Program, as listed in the audit summary, including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with the corresponding elements of GALL AMP XI.S4.

The staff reviewed the 10 CFR 50, Appendix J Program, for which the applicant claims

consistency with GALL AMP XI.S4 and finds that it follows the recommendations of the GALL

Report.

Operating Experience. LRA Section B2.1.30 states that the most recent Type A test was

performed in October 2000. The 95-percent confidence limit was 0.59 percent/24 hours (La).

Type A tests in the third (1988) and fifth (1991) refueling outages showed leakages of 0.56 La

and 0.35 La, respectively. The integrated leakage rate test acceptance criterion is 1.0 La

(as-found). There are Types B and C tests at various intervals for the many different

penetrations. The applicant stated that the results of the Type B and C tests are combined and

the total combined leakage is updated after each test. The Types B and C combined leakage

rate acceptance criterion is 0.6 La (250,000 sccm). The combined Type B and C maximum path

leakage rate used during refueling periods was 49,710 sccm as of November 2005. The

combined Type B and C minimum path leakage rate used when the plant is in Modes 1

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through 4 was 21,641 sccm as of November 2005. The applicant stated that the Types B and C

test failures noted in the past have been due to debris, corrosion products, and general

degradation of valve seating surfaces. Most of these failures were corrected by replacement of

the seat, valve flushing, or valve seat lapping.

The LRA states that one gasket degradation has been noted. The gasket, which was installed

in 1989, exhibited an increasing leakage trend since 1993 and was replaced in 1997. In

addition, there was a failure of the T-ring seal on the purge supply damper. The T-Ring seal,

which was installed in 1985, failed in 1997. Subsequently, the T-ring seal was replaced. The

applicant stated that in both of these cases, the 10 CFR 50, Appendix J Program detected the

condition and initiated corrective actions.

During the audit, the staff reviewed the applicant's documentation for the gasket degradation

incident described above. The gasket addressed in this incident was the equipment hatch

gasket, which was made of ethylene propylene diene monomer rubber. The replacement

gasket was made of the same material as that of the original gasket. The staff reviewed the

leakage rates recorded by the applicant from the tests performed after the gasket was replaced

in 1997. For the eight leakage tests performed between November 1997 and November 2006,

the leakage rates measured for the replaced hatch gasket ranged between 0 to 170 sccm, with

an error margin of 4 to 20 sccm, respectively, against the leakage acceptance criteria of

4200 sccm. In addition, the staff also interviewed the applicant's technical personnel on the

10 CFR 50, Appendix J Program, details such as the "as found" leakage rates versus the

administrative leakage limits, test intervals for type A, B and C tests, adjustment of the type A

test interval when the leak rate testing yielded unacceptable results, and the corrective action

process to address the test results that are not acceptable.

During the audit, the staff reviewed a sampling of the implementing procedures and problem

identification reports related to the applicant's. 10 CFR 50, Appendix J Program. The staff also

interviewed selected onsite personnel who have specialized knowledge of the program. The

staff reviewed instances previously documented by the applicant that identified issues with the

10 CFR 50, Appendix J Program, test results and where the applicant had implemented

corrective actions.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.30, the applicant provided the USAR supplement for the

10 CFR 50, Appendix J Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's 10 CFR 50, Appendix J

Program, the staff finds all program elements consistent with the GALL Report. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

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3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with

the GALL Report, with exceptions or enhancements:

* ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

" Water Chemistry

* Reactor Head Closure Studs

* Boric Acid Corrosion

" Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of

Pressurized Water Reactors

* Flow-Accelerated Corrosion

* Bolting Integrity

* Steam Generator Tube Integrity

* Closed-Cycle Cooling Water System

* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems

* Fire Protection

* Fire Water System

* Fuel Oil Chemistry

" Selective Leaching of Materials

* One-Time Inspection of ASME Code Class 1 Small-Bore Piping

• Lubricating Oil Analysis

" ASME Section XI, Subsection IWE

" ASME Section XI, Subsection IWL

* ASME Section Xl, Subsection IWF

" Masonry Wall Program

" Structures Monitoring Program

* RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

* Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements

• Metal Fatigue of Reactor Coolant Pressure Boundary

* Environmental Qualification (EQ) of Electrical Components

• Concrete Containment Tendon Prestress

3-42
For AMPs that the applicant claimed are consistent with the GALL Report, with exception and/or

enhancement, the staff performed an audit and review to confirm that those attributes or

features of the program for which the applicant claimed consistency were indeed consistent.

The staff also reviewed the exception and/or enhancement to the GALL Report to determine

whether they were acceptable and adequate. The results of the staff's audits and reviews are

documented in the following sections.

3.0.3.2.1 ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

Summary of Technical Information in the Application. LRA Section B2.1.1 describes the existing

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program as

consistent, with exceptions, with GALL AMP XI.M1, "ASME Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD."

ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD Program

inspections are performed to manage cracking, surface and subsurface discontinuities, loss of

fracture toughness, loss of material, and physical damage in Class 1, 2, and.3 piping and

components within the scope of license renewal. The program includes periodic visual, surface,

and volumetric examinations and leakage tests of Class 1, 2, and 3 pressure-retaining

components, including welds, pump casings, valve bodies, integral attachments, and

pressure-retaining bolting. WCGS inspections meet ASME Code Section XI requirements. The

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is in

accordance with 10 CFR 50.55a and the ASME Code Section XI, 1998 Edition through 2000

addenda. WCGS weld examinations for Class 1 and 2 piping are in accordance with

risk-informed inservice inspection (RI-ISI) selection and examination requirements. RI-ISI

includes an evaluation for degradation mechanisms like flow accelerated corrosion, water

hammer, thermal fatigue, high-cycle fatigue, corrosion, and SCC and is based on the

methodology described in EPRI TR-1 12657, "Revised Risk-Informed Inservice Inspection

Evaluation Procedure." In compliance with 10 CFR 50.55a(g)(4)(ii), the ASME Code Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD Program is updated each successive

120-month inspection interval to comply with the requirements of the latest edition of the ASME

Code 12 months before the start of the inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

Program, as listed in the audit summary, including the license renewal program evaluation

report in which the applicant assessed whether the program elements are consistent with GALL

AMP XI.M1.

The staff noted that the LRA lists six exceptions to the GALL Report. The six exceptions are the

following:

(1) WCGS ASME Section XI, Inservice Inspection Program, uses ASME Code 1998

Edition through the 2000 addenda. NUREG -1801, Section XI.M1, "ASME

Section XI Inservice Inspection, Subsections IWB, IWC and IWD" is based on

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ASME Code, 2001 edition through 2002 and 2003 addenda. The use of the 1998

version of the ASME Code through 2000 addenda is consistent with provisions in

10 CFR 50.55a that allow use of the code in effect 12 months prior to the start of

the inspection interval.

(2) WCGS uses the RI -ISI Program for ASME Code Section XI Tables IWB-2500-1

and IWC-2500 -1, Examination Categories B-F, B-J, C-F-1 and C-F -2 for

Class 1 and 2 piping welds.

(3) WCGS ASME Section XI, Inservice Inspection Program, uses Code Case N-623

for examination and inspection requirements for deferral of inspection of shell to

flange and head to flange welds in the reactor vessel.

(4) WCGS ASME Section XI, Inservice Inspection Program, uses Code Case

N-648-1, with the condition specified in RG 1.147 for examination and inspection

requirements for Examination Category B-D, Full Penetration Welded Nozzles in

Vessels, for reactor vessel nozzles.

(5) WCGS ASME Section XI, Inservice Inspection Program, uses 10 CFR 50.55a,.

Section (b)(2)(xxi), for examination and inspection requirements for Examination

Category B-D, Full Penetration Welded Nozzles in Vessels, for steam generator

and pressurizer nozzles.

(6) WCGS ASME Section Xl, Inservice Inspection Program, uses Code Case N-700

for examination and inspection requirements for Examination Categories B-K,

C-C, and D-A (Welded Attachments for Vessels, Piping, Pumps, and Valves).

In its review of exception (5), the staff noted that 10 CFR 50.55a, Section (b)(2)(xxi), imposes

examination and inspection requirements from the ASME Code, Section XI, 1998 Edition, and

are more stringent than, the corresponding requirements from later ASME Code, Section XI,

editions and addenda.

During the audit, the staff requested that the applicant clarify why item (5) was listed as an

exception to the GALL Report.

In its response, the applicant stated that the LRA will be amended to delete exception (5) from

the list of exceptions.

Because exception (5) describes requirements of the applicant's program that are imposed by

10 CFR 50.55a and the requirements include, and are more stringent than, the corresponding

requirements imposed by the ASME Code, Section XI, edition and addenda referenced in the

GALL Report, the staff finds that item (5) is not an exception to GALL AMP XI.M1. On this

basis, the staff finds that it is acceptable for the applicant to delete exception (5) from the list of

exceptions to the GALL Report.

Because current approval to use RI-ISI or ASME Code, Section XI, code cases does not

provide justification or a basis for their use during the period of extended operation, the staff

requested that the applicant clarify why the LRA identifies items (2), (3), (4), and (6) as

exceptions to the GALL Report.

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In its response, the applicant stated that the LRA will be amended to delete exceptions to GALL

AMP XI.M1 that are related to RI-ISI or ASME Code, Section XI, code cases. The applicant

stated that the LRA will be revised to delete exceptions (2), (3), (4), and (6). The applicant

stated that the LRA amendment will also affect the summary description of the AMP in

LRA Section A1.1, and the program description in LRA Section B2.1.1.

The staff noted that the applicant's current 10-year ISI interval ends on September 2, 2015,

approximately ten years before the start of the period of extended operation. Because currently

approved alternatives to ASME Code, Section XI, requirements expire at the end each 10-year

ISI interval, the applicant's use of RI-ISI or ASME Code, Section XI, code cases will not

continue into the period of extended operation without required approval pursuant to

10 CFR 50.55a. Because currently approved alternatives to ASME Code, Section XI,

requirements do not continue into the applicant's period of extended operation, the staff finds

that it is acceptable to delete exceptions (2), (3), (4), and (6) from the list of exceptions to GALL

AMP XI.M1.

By letter dated August 31, 2007, the applicant amended the LRA to delete the following

sentences from the "program description" in LRA Section B2.1.1:

WCGS weld examinations for Class 1 and Class 2 piping are performed in

accordance with Risk-Informed Inservice Inspection (RI-ISI) selection and

examination requirements. RI-ISI includes an evaluation for degradation

mechanisms such as flow accelerated corrosion, water hammer, thermal fatigue,

high cycle fatigue, corrosion and stress corrosion cracking and is based on the

methodology described in EPRI TR-1 12657, "Revised Risk-Informed Inservice

Inspection Evaluation Procedure."

By letter dated August 31, 2007, the applicant also deleted five of six exceptions listed in the

LRA and revised the remaining exception to read as stated in the following paragraph.

Exception. In the LRA, as amended by letter dated August 31, 2007, the applicant credited an

exception to the GALL Report program elements "scope of the program," "parameters

monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance

criteria," and "corrective actions." Specifically, the exception states:

NUREG-1801, Section XI.M1, "ASME Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD" specifies the use of ASME Section XI, 2001

edition through 2002 and 2003 addenda. WCGS third interval ISI Program uses

ASME Code, 1998 Edition through the 2000 addenda. The use of the 1998

version of the ASME Code through 2000 addenda is consistent with provisions in

10 CFR 50.55a to use the Code in effect 12 months prior to the start of the

inspection interval. WCGS will use the ASME Code Edition consistent with the

provisions of 10 CFR 50.55a during the period of extended operation.

The staff noted that the affected program elements are those where GALL AMP XI.M1 includes

a reference to specific ASME Code, Section XI, requirements. The staff finds that this is an

exception to the GALL Report's recommendations because the applicant's ASME Code

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program is based on ASME

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Code, Section Xl, editions and addenda that are different from the ASME Code, Section Xl,

edition and addenda referenced in the GALL Report.

The staff noted that the applicant's use of ASME Code, Section XI, 1998 Edition through 2000

Addenda for the third 10-year inspection interval has been approved pursuant to

10 CFR 50.55a, and that the third 10-year inspection interval does not continue into the period

of extended operation. The staff also noted that the ASME Code Section XI editions and

addenda used by the applicant during the period of extended operation will be pursuant to the

requirements of 10 CFR 50.55a that are applicable for future 10-year inspection intervals.

During the period of extended operation the applicant will use ASME Code Section XI editions

and addenda that are then currently endorsed by the staff pursuant to 10 CFR 50.55a as a

basis for its ASME Code Section XI Inservice Inspection, Subsection IWB, IWC, and IWD

Program. The staff-endorsed ASME Code Section XI editions and addenda, provide

requirements for ISI that are comparable to those referenced in the GALL Report; therefore, the

staff finds that the applicant's use of ASME Code Section Xl editions and addenda which differ

from those referenced in the GALL Report is acceptable. On this basis, the staff finds that the

applicant's exception to GALL AMP XI.M1 is acceptable.

The staff reviewed those portions of the ASME Code Section Xl Inservice Inspection,

Subsections IWB, IWC, and IWD Program for which the applicant claims consistency with

GALL AMP XI.M1 and finds that they are consistent with the GALL AMP. The staff finds the

applicant's ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD

Program acceptable because it conforms to the recommended AMP with the exception

described.

Operating Experience. LRA Section B2.1.1 states that plant-specific operating experience for

the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

reveals no implementation issues. This program is updated to account for industry operating

experience. In addition, the ASME Code Section Xl is revised every three years and addenda

issued in the interim for code updates to reflect industry operating experience. The applicant

stated that the requirement to update the ASME Code Section XI Inservice Inspection Program

with references to more recent editions of ASME Code Section XI at the end of each inspection

interval makes the program reflect enhancements by operating experience incorporated into

ASME Code Section XI.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that the plant-specific operating experience did not

reveal any degradation that is not bounded by industry experience.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's ASME Code Section XI, Subsection IWB, IWC, and IWD Program.

The staff also interviewed selected onsite personnel who have specialized knowledge of the

program. The staff reviewed instances previously documented by the applicant that identified

issues with the ISI program. The staff noted that the applicant had implemented appropriate

and timely corrective actions, relative to the ISI program.

The staff requested that the applicant discuss any current challenges related to inspections and

examinations required by ASME Code Section XI. The staff found no instances where the

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plant's equipment arrangement or configuration prevented the applicant from examining

components specified in the ASME Code Section Xl (accessibility of physical configuration).

Where deviations from the inspection requirements were taken (e.g., the inspection area or

technique was not entirely consistent with the requirements of ASME Code Section Xl),

acceptable alternatives to the specified examination were approved pursuant to 10 CFR 50.55a.

The staff found no omissions in the applicant's current program that have resulted in failure to

maintain the intended functions of components that are within the scope of the program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.1, the applicant provided the USAR supplement for the

ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD. In its letter

dated August 31, 2007, the applicant amended LRA Section A1.1 to state:

ASME Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD

inspections are performed to manage aging in Class 1, 2, and 3 piping and

components within the scope of license renewal. The program includes periodic

visual, surface, volumetric examinations and leakage tests of Class 1, 2 and 3

pressure-retaining components, including welds, pump casings, valve bodies,

integral attachments, and pressure-retaining bolting. WCGS inspections meet

ASME Section XI requirements and can manage aging such as cracking, surface

and subsurface discontinuities, loss of material, loss of fracture toughness, and

physical damage. The WCGS ISI Program is in accordance with 10 CFR 50.55a

and ASME Section Xl, 1998 edition through 2000 addenda.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's ASME Code Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD, the staff determines that those program

elements for which the applicant claimed consistency with the GALL Report are consistent. In

addition, the staff reviewed the exception and its justifications and determines that the AMP,

with the exception, is adequate to manage the aging effects for which it is credited. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.2 Water Chemistry

Summary of Technical Information in the Application. LRA Section B2.1.2 describes the existing

Water Chemistry Program as consistent, with exception, with GALL AMP XI.M2, 'Water

Chemistry."

The Water Chemistry Program maintains the chemical environment in the reactor coolant

system and related auxiliary systems containing treated borated water and the chemical

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environment in the steam generator secondary side and the secondary cycle systems to limit

aging effects of corrosion mechanisms and SCC. The methods for managing both the primary

and secondary chemical environments rely on (1) limiting the concentration of chemical species

known to cause corrosion and (2) adding chemical species known to inhibit degradation by their

influence on pH and dissolved oxygen levels. Water chemistry control is most effective in areas

of high flow and thorough mixing where the monitoring samples represent actual conditions. For

low-flow areas and stagnant portions of the systems, sampling may not be as effective in

determining local environmental conditions, and a one-time inspection of a representative group

of components verifies the effectiveness of the Water Chemistry Program.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Water Chemistry Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.M2.

The GALL Report "scope of the program" program element states that water chemistry control

is performed in accordance with the guidelines in EPRI TR-105714, Revision 3, for primary

water chemistry in pressurized-water reactors (PWRs), EPRI TR-102134, Revision 3, for

secondary water chemistry in PWRs, or later revisions. The Water Chemistry Program "scope

of the program" program element states that the program accomplishes this task by monitoring

and controlling known detrimental contaminants like chlorides, fluorides, dissolved oxygen, and

sulfate concentrations for water chemistry based on the guidelines in EPRI TR-1 05714,

Revision 5, for primary water chemistry and TR-1 02134, Revision 6, for secondary water

chemistry.

The staff noted that when EPRI TR-1 02134 was revised, it was issued a new number. It is now

EPRI TR-1 08224, Revision 6. The Water Chemistry Program still references EPRI TR-1 02134,

Revision 6. The staff requested that the applicant clarify this discrepancy.

In its letter dated August 31, 2007, the applicant amended LRA Section B2.1.2 to specify that

the Water Chemistry Program is consistent with EPRI TR-1 08224, Revision 6. On this basis,

the staff finds the applicant's response acceptable.

The staff found this use different from the GALL Report recommendation and requested that

the applicant: (1) compare the monitored parameters for EPRI TR-1 05714, Revision 3 to

Revision 5 and EPRI TR-1 02134, Revision 3 to Revision 6, (2) explain why use of a later

version is acceptable by verifying that none of the controlled parameters are relaxed in the later

version, and (3) justify why this is not considered an exception to the GALL Report.

In its response, the applicant stated that the GALL Report "scope of the program" program

element states that "water chemistry control is in accordance with industry guidelines such as...

EPRI TR-1 05714 for primary water chemistry in PWRs, and EPRI TR-1 02134 for secondary

water chemistry in PWRs." The applicant stated that no EPRI revisions are specified in the

program element; therefore, no exception was taken with respect to EPRI revisions. The

applicant also provided a list of changes between the different revisions.

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The staff finds the applicant's response acceptable because the GALL Report states that later

revisions of the EPRI documents are acceptable. Therefore, the staff finds that an exception to

the GALL Report is not necessary. The staff reviewed the changes between the different

revisions of the EPRI document and finds the applicant's use of the later revisions acceptable

because the parameters of operation in EPRI TR-1 05714, Revision 5, or the formerly used

EPRI TR-1 02134, Revision 6 (now EPRI TR-1 08224, Revision 6), were generally the same or

more conservative than those of Revision 3.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

element "scope of the program." Specifically, the exception states:

When in wet layup conditions, WCGS is meeting the requirements for mixing of

the steam generator bulk solution. This ensures the chemistry of the bulk fluid is

uniform and that samples are representative of the bulk steam generator

secondary side water. The WCGS design incorporates pumps for periodic

recirculation of the steam generator fluid in wet layup conditions. Operating

experience has shown that a 33-hour recirculation period will provide adequate

bulk mixing. If sample results after 33 hours of recirculation indicate a failure to

meet the layup specifications, corrective action is taken to correct the layup

mixture. After any chemical additions necessary to adjust chemistry, the steam

generator is recirculated for another 33 hours prior to sampling. The intent of the

EPRI Secondary Water Chemistry Guidelines for mixing is met after 33 hours of

recirculation. Three samples per week are not necessary to demonstrate

adequate mixing.

The staff requested that the applicant confirm if there was an analysis that states that when in

wet layup conditions, a 33-hour recirculation of steam generators followed by weekly sampling

is better than, or equivalent to, obtaining three samples per week until values are stable.

In its response, the applicant stated that this exception was taken based on operating

experience. Prior to initial fill of the steam generators during plant construction, calculations

were performed to determine the required recirculation time to achieve mixing of the bulk

solution. This calculation was based on the steam generators volume, flow-rate of the mix

pumps, and recirculating three volumes of the bulk solution. The result indicated that a 33-hour

recirculation time would thoroughly mix the bulk solution. The use of the 33-hour mix time

became standard practice. Once in wet layup with chemicals added, the steam generators are

mixed for 33 hours and then sampled to analyze for the desired chemical environment. Then,

recirculation and sampling are done weekly in accordance with AP 02-002, "Chemistry

Surveillance Program." Experience has shown that once the steam generators bulk solution

meets required specifications, it remains satisfactory. If the parameters set forth in AP 02-003

are not met, adjustments are made and the recirculation and sampling is repeated.

The staff noted from the license renewal program evaluation report that the WCGS design

incorporates pumps for recirculation of the steam generator fluid. Because the applicant had

performed calculations based on the steam generator volume, flow-rate of the mix pumps and

recirculating three volumes of the bulk solution, and based on the plant operating history of over

20 years, the staff finds this exception acceptable.

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The staff reviewed those portions of the Water Chemistry Program for which the applicant

claims consistency with GALL AMP XI.M2 and finds that they are consistent with the GALL

AMP. The staff finds the applicant's Water Chemistry Program acceptable because it conforms

to the recommended AMP, with the exception described.

Operating Experience. LRA Section B2.1.2 states that the primary and secondary water

chemistry control programs have been developed in accordance with the EPRI primary and

secondary water chemistry control guidelines and therefore benefit from the industry operating

experience available when the EPRI guidelines were issued. The applicant's Strategic Primary

Water Chemistry Plan incorporates nine specific topics of WCGS primary chemistry operating

history into the top-level document for the primary chemistry control strategy. The Strategic

Secondary Water Chemistry Plan incorporates WCGS secondary chemistry operating history of

iron transport reduction, condenser integrity, and dissolved oxygen control into the top-level

document setting the secondary chemistry control strategy.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Water Chemistry Program. The staff also interviewed selected onsite

personnel who have specialized knowledge of the program. The staff reviewed instances

previously documented by the applicant that identified issues with the Water Chemistry

Program and where the applicant had implemented corrective action. The staff noted that the

applicant's corrective actions were timely and appropriate.

The staff noted several problem identification reports where limits on contaminants, such as

chlorides, sulfates, and pH, had been exceeded. The staff also noted that the license renewal

program evaluation report states that there have been no major chemical excursions during the

plant's operating history. The staff requested that the applicant explain what "major" means.

In its response, the applicant stated that although the Water Chemistry Program is intended to

maintain water chemistry parameters within specifications, it is recognized that water chemistry

parameters may occasionally exceed the limits specified in the plant procedures. As the amount

of departure from specifications increases, action levels increase. Prompt graduated corrective

actions are specified at each action level to eliminate or mitigate degradation from the

out-of-specification condition. A "major" chemical excursion, as discussed in the license renewal

application, is an event where one or more chemical species exceeded an action level and did

not comply with the procedurally-specified corrective actions. None of the identified problem

identification reports address events that did not comply with the procedurally-specified

corrective actions.

Based on the definition of "major," the staff agrees with the applicant that there have been no

major chemical excursions during the plant's operating history. Because the appropriate

corrective actions, as specified for each action level, were taken and compliance was achieved,

the staff finds the applicant's response acceptable.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.2, the applicant provided the USAR supplement for the

Water Chemistry Program. The staff reviewed this section and determines that the information

3-50
in the USAR supplement is an adequate summary description of the program, as required by

10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Water Chemistry Program,

the staff determines that those program elements for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exception and their

justifications and determine that the AMP, with the exception, is adequate to manage the aging

effects for which it is credited. The staff concludes that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.3 Reactor Head Closure Studs

Summary of Technical Information in the Application. LRA Section B2.1.3 describes the existing

Reactor Head Closure Studs Program as consistent, with exceptions, with GALL AMP XI.M3,

"Reactor Head Closure Studs."

The Reactor Head Closure Studs program conducts ASME Code Section XI inspections of

reactor vessel flange stud hole threads, reactor head closure studs, nuts, and washers to

identify and manage cracking and loss of material. The program includes periodic visual,

surface, and volumetric examinations of reactor vessel flange stud hole threads, reactor head

closure studs, nuts, and washers and visually inspects the reactor vessel flange closure during

primary system leakage tests. The program implements the ASME Code Section Xl,

Subsection IWB, 1998 Edition through the 2000 Addenda and manages reactor vessel stud, nut

and washer cracking, loss of material, and reactor coolant leakage from the reactor vessel

flange. In compliance with 10 CFR 50.55a(g)(4)(ii), the ASME Code Section XI Inservice

Inspection Program is updated each successive 120-month inspection interval to comply with

the requirements of the latest ASME Code edition specified 12 months before the start of the

inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Reactor Head Closure Studs Program, as listed in the audit summary, including

the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M3.

The staff noted that the LRA lists the following three exceptions to the GALL Report:

(1) NUREG-1801, Section XI.M3 specifies the use of ASME Code Section XI,

Subsection IWB, 2001 edition with addenda 2002 and 2003. WCGS' third

interval ISI Program is using ASME Code Section XI 1998 Edition through 2000

addenda as modified by 10 CFR 50.55a, and approved code cases. Use of the

1998 Code through 2000 addenda is consistent with provisions in

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10 CFR 50.55a to use the ASME Code in effect 12 months prior to the start of

the inspection interval.

(2) NUREG-1801, Section XI.M3 specifies the use of ASME Code Section XI,

Subsection IWB, Table 2500-1 for reactor vessel flange stud holes, reactor head

closure studs, nuts, and washers. The WCGS ASME Code Section XI ISI

Program uses approved Code Case N-652 for examination and inspection

requirements for Examination Category B-G-1, Pressure Retaining Bolting

Greater than 2 inches in diameter, for WCGS reactor vessel flange stud holes,

reactor head closure studs, nuts, and washers.

(3) NUREG-1 801, Section XI.M3, specifies the use of NRC Regulatory Guide 1.65,

"Materials and Inspections for Reactor Vessel Closure Studs" for reactor head

closure studs and nuts. WCGS is committed to Regulatory Guide 1.65 with three

exceptions. These exceptions are discussed in USAR Appendix 3A as follows:

a. The use of modified SA-540, Grade B-24 stud material as specified in

Code Case 1605 has been found acceptable to the NRC for this

application within the limitations discussed in Regulatory Guide 1.85,

"Material Code Case Applicability."

b. The use of stud bolting material that does not exceed 170 ksi tensile

strength. The closure stud bolting material is procured to a minimum yield

strength of 130 ksi and a minimum tensile strength of 145 ksi. This

strength level is compatible with the fracture toughness requirements of

10 CFR 50, Appendix G (paragraph I.C), although higher strength level

bolting materials are permitted. Additional design considerations that

permit visual and/or nondestructive inspection and prevent exposure to

borated water also apply.

c. Inservice inspection of the reactor vessel closure studs is performed in

accordance with ASME Code Case N-652 and does not follow the

guidance of regulatory Guide 1.65. The NRC has approved the use of

Code Case N-652 in Regulatory Guide 1.147.

In its review of exception (2), the staff noted that ASME Code Section XI, Code Case N-652,

examination requirements have been incorporated into ASME Code Section XI, 2001 Edition

through 2002 and 2003 Addenda, which is the basis for GALL AMP XI.M3. Because the

examination requirements of Code Case N-652 are consistent with those referenced in

GALL AMP XI.M3, and because the use of specific code cases is approved pursuant to

10 CFR 50.55a, not as part of the license renewal process, the staff requested that the

applicant clarify why the use of Code Case N-652 was listed as an exception to the GALL

Report.

In its response, the applicant stated that the LRA will be amended to remove references to code

cases from LRA Section B2.1.3. The applicant stated that after this change the Reactor Head

Closure Studs Program will credit only two exceptions to the GALL Report.

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By letter dated October 11, 2007, the applicant amended LRA Section B2.1.3 to delete

exception (2), and modify exceptions (1) and (3).

The staff noted that examination requirements for reactor head closure studs provided in

Code Case N-652 are different from the requirements in ASME Code Section XI, 1998 Edition

through 2000 Addenda, which is the basis for the applicant's current 10-year IS[ interval.

However, those examination requirements have been incorporated into ASME Code Section Xl,

2001 Edition, with 2002 and 2003 Addenda, which is the basis for GALL AMP XI.M3. On the

basis that the applicant's examination requirements are consistent with the ASME

Code Section XI editions and addenda referenced in the GALL Report, the staff finds that it is

acceptable to delete the second exception originally listed in LRA Section B2.1.3.

Exception 1. In the LRA, as revised by the letter dated October 11, 2007, the applicant credited

an exception to the GALL Report program elements "scope of the program," "parameters

monitored or inspected," "detection of aging effects," "monitoring and trending," "acceptance

criteria," and "corrective actions." Specifically, the exception states:

NUREG 1801, Section XI.M3 specifies the use of ASME Section XI,

Subsection IWB, 2001 edition with addenda 2002 and 2003. WCGS third interval

ISI Program is using ASME Section XI 1998 Edition through 2000 addenda. Use

of the 1998 Code through 2000 addenda is consistent with provisions in

10 CFR 50.55a to use the ASME Code in effect 12 months prior to the start of

the inspection interval. WCGS will use the ASME Code Edition consistent with

the provisions of 10 CFR 50.55a during the period of extended operation.

The staff noted that the affected program elements are those where GALL AMP XI.M3 includes

a reference to specific ASME Code Section XI requirements. The staff finds that this is an

exception to the GALL Report's recommendations because the applicant's Reactor Head

Closure Studs Program is based on ASME Code Section Xl editions and addenda that are

different from the ASME Code Section Xl edition and addenda referenced in the GALL Report.

The staff noted that the applicant is in its third 10-year inspection interval and that use of ASME

Code Section XI, 1998 Edition through the 2000 Addenda, for the third 10-year inspection

interval is consistent with the requirements of 10 CFR 50.55a. The staff also noted that the third

10-year inspection interval ends on September 2, 2015, and does not continue into the period

of extended operation. The applicant uses ASME Code Section XI editions and addenda that

are currently endorsed by the staff pursuant to 10 CFR 50.55a as a basis for its Reactor Head

Closure Studs Program during the period of extended operation. The staff finds that the

endorsed code examination requirements are adequate to identify potential degradation in

reactor head closure studs, nuts, and washers. Therefore, the staff finds that use of ASME

Code Section XI editions and addenda different from those referenced in the GALL Report is

acceptable.

Exception 2. In the LRA, as revised by the letter dated October 11, 2007, the applicant credited

an exception to the GALL Report program elements "scope of the program" and "corrective

actions." Specifically, the exception states:

NUREG-1801 AMP XI.M3 specifies the use of NRC Regulatory Guide 1.65,

"Material and Inspections for Reactor Vessel Closure Studs" for reactor head

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closure studs and nuts. WCGS uses NRC Regulatory Guide 1.65, except: (a)

modified SA-540, Grade B-24 stud material is used; (b) stud bolting material was

procured with a minimum yield strength of 130 ksi and a minimum tensile

strength of 145 ksi; and (c) volumetric inspection of removed studs is performed

per ASME Code Section XI.

The staff noted that the affected program elements are those where GALL AMP XI.M3 includes

a reference to RG 1.65. The staff finds that this is an exception to the GALL Report's

recommendations because the applicant's program is not in conformance with all of the

material and inspection guidance in RG 1.65, as recommended in GALL AMP XI.M3.

The applicant provided the following discussion of this exception:

NUREG-1801, Section XI.M3, specifies the use of NRC Regulatory Guide 1.65,

"Material and Inspections for Reactor Vessel Closure Studs" for reactor head

closure studs and nuts. WCGS is committed to Regulatory Guide 1.65, with

three exceptions. These are discussed in USAR Appendix 3A as follows:

a. Modified SA-540, Grade B-24 stud material is used. The use of this

material is within the limitations discussed in Regulatory Guide 1.85,

Materials Code Case Acceptability.

b. Stud bolting material that does not exceed 170 ksi tensile strength is

used. The closure stud bolting material is procured to a minimum yield

strength of 130 ksi and a minimum tensile strength of 145 ksi. This

strength level is compatible with the fracture toughness requirements of

10 CFR 50, Appendix G (paragraph I.C), although higher strength level

bolting materials are permitted. Additional design considerations that

permit visual and/or nondestructive inspection and prevent exposure to

borated water also apply.

c. Inservice inspection of the reactor vessel closure studs is performed with

the ASME Code Section Xl 1998 Edition through 2000 addenda for the

third 10-year inspection interval. Volumetric inspection of removed studs

is performed.

The staff reviewed USAR, Appendix 3A, "Conformance to NRC Regulatory Guides," and noted

the following discussion about the reactor head closure studs' conformance to RG 1.65:

Westinghouse follows the recommendations of this regulatory guide, with the

following exceptions:

a. The use of modified SA-540, Grade B-24, as specified in the ASME

Code (Code Case 1065), is permitted by Westinghouse, but is not listed

in this regulatory guide.

b. A maximum ultimate tensile strength of 170 ksi is not specified by

Westinghouse, as recommended by this regulatory guide.

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Exception "a." above is not considered an issue since Code Case 1605 has been

found acceptable to the NRC for application in the construction of components

for water-cooled nuclear power plants within the limitations discussed in

Regulatory Guide 1.85. The use of Code Case 1605 for reactor vessel closure

stud material is not precluded by this regulatory guide.

On the basis that the use of modified SA-540, Grade B-24, for reactor head closure studs is

included in the applicant's CLB and the use of this material has been accepted by the staff, as

documented in RG 1.85, the staff finds that this deviation from the recommendations of

RG 1.65 is an acceptable exception to the GALL Report.

During the audit, the staff requested that the applicant provides additional information to

substantiate that the maximum tensile strength of the reactor closure studs and nuts is less

than 170 ksi.

In its response, the applicant provided copies of certified material test reports for the WCGS

reactor head closure studs, nuts, and washers. The staff reviewed the certified material test

reports and confirmed that the WCGS reactor head closure studs, nuts, and washers have a

maximum tensile strength less than 170 ksi. Because all WCGS reactor head bolting material

has a maximum tensile strength less than 170 ksi, the limit specified in RG 1.65, the staff finds

that use of a specification that did not identify a maximum tensile strength for reactor head

closure bolting material is an acceptable deviation from the recommendations of RG 1.65 and is

an acceptable exception to the GALL Report.

The applicant stated that volumetric inspection (i.e., ultrasonic examination) is performed on

reactor head closure studs when they are removed. The applicant identified this as a deviation

from RG 1.65 and an exception to the GALL Report because, in addition to volumetric

examinations, RG 1.65 recommends performing visual and surface examinations of removed

studs while holding them under tension in a tensioning fixture.

The staff reviewed the recommendations of RG 1.65 and the requirements for examination of

reactor vessel closure studs in ASME Code Section XI, 2001 Edition with 2002 and 2003

Addenda, referenced in the GALL Report. The staff noted that in the ASME Code Section XI,

2002 Addenda, Table IWB-2500-1,"Examination Category B-G-1, Pressure Retaining Bolting

Greater than 2 inches in diameter," a change was made to the requirements for examination of

reactor vessel closure studs. Earlier ASME Code editions and addenda had specified

volumetric examination for in-place closure studs and had specified volumetric and surface

examinations for closure studs when they are removed. However, the ASME Code, Section XI,

2002 Addenda, eliminated separate requirements for in-place and removed studs and

implemented a single requirement for volumetric examination that applies for these two cases.

The staff determines that the applicant's examination methodology is consistent with the

requirements of the ASME Code Section XI edition and addenda that are referenced in the

GALL Report and is adequate to identify potential degradation in the reactor head closure bolts.

On this basis, the staff finds that the applicant's use of only volumetric examination for the

reactor head closure studs is an acceptable deviation from the recommendations of RG 1.65

and is an acceptable exception to the GALL Report.

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The staff reviewed those portions of the Reactor Head Closure Studs Program for which the

applicant claims consistency with GALL AMP XI.M3 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Reactor Head Closure Studs Program acceptable

because it conforms to the recommended AMP, with the exceptions described.

Operating Experience. LRA Section B2.1.3 states that as part of the ASME Code Section XI

Inservice Inspection Program this program is updated to account for industry operating

experience. ASME Code Section XI is revised every three years with addenda issued in the

interim to update the code to reflect operating experience. The requirement to update the

ASME Code Section XI Inservice Inspection Program to most recent editions of ASME

Code Section Xl at the end of each inspection interval makes the program reflect

enhancements from incorporated operating experience. The applicant stated that a review of

plant-specific operating experience revealed minor surface discontinuities on reactor vessel

stud nuts and washers, and flange stud hole thread damage detected during reactor head

closure stud inspections. No cases of cracking have been detected in WCGS reactor vessel

studs, nuts, flange stud holes, or washers.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that the plant-specific operating experience did not

reveal any degradation that is not bounded by industry experience.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Reactor Head Closure Studs Program. The staff also interviewed

selected onsite personnel who have specialized knowledge of the program. The staff did not

identify any instances where the applicant's operating experience is outside the envelope of

industry experience or where omissions in the applicant's current program resulted in failure to

maintain intended functions of components that are within the scope of the program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.3, the applicant provided the USAR supplement for the

Reactor Head Closure Studs Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Reactor Head Closure Studs

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exceptions

and their justifications and determines that the AMP, with the exceptions, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

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3.0.3.2.4 Boric Acid Corrosion

Summary of Technical Information in the Application. LRA Section B2.1.4 describes the existing

Boric Acid Corrosion Program as consistent, with enhancement, with GALL AMP XI.M10, "Boric

Acid Corrosion."

The Boric Acid Corrosion Program manages loss of material due to borated water leakage. The

program monitors mechanical, electrical, and structural components within the scope of license

renewal susceptible to boric acid corrosion from systems containing reactor coolant or treated

borated water. The program relies in part on implementation of recommendations of

GL 88-05, "Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary Components in

PWR Plants." Additionally, the program includes examinations during ISI pressure tests in

accordance with ASME Code Section XI requirements. The program addresses recent

operating experience noted in Regulatory Issue Summary 2003-013, "NRC Review of

Responses to Bulletin 2002-01, 'Reactor Pressure Vessel Head Degradation and Reactor

Coolant Pressure Boundary Integrity,"' which includes NRC Bulletins 2002-01, 2002-02, and

NRC Order EA-03-009. The Boric Acid Corrosion Program detects leakage, examines for

evidence of leakage, evaluates it, and initiates corrective actions. The program maintains a

tracking and trending program for boric acid leakage from plant components and a

component-based visual history of boric acid leakage and/or seepage.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancement to determine whether

the AMP, with the enhancement, remains adequate to manage the aging effects for which it is

credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Boric Acid Corrosion Program (documented in the audit summary), including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M10. The staff questioned the applicant

about the inspections of the vessel head for evidence of boric acid.

In its response, the applicant stated that any evidence that boron leakage from above the

vessel may have penetrated the mirror insulation shall require a head bare metal inspection for

the potentially affected areas to the vessel head, and require cleanup of the head and mirror

insulation. The applicant also stated that, in accordance with NRC Order EA-03-009, additional

commitments to perform inspections in the RPV closure head have been implemented. These

commitments include performing bare metal visual examination of the head surface every third

refueling outage or five years, whichever occurs first. The applicant stated that additional

information on this subject is included in the Nickel-Alloy Penetration Nozzles Welded to the

Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program.

This response is acceptable in providing assurance that the aging management program is

adequate relative to boric acid corrosion. This is because the applicant's actions conform with

NRC bulletins and orders. In addition the staff's evaluation of Nickel-Alloy Penetration Nozzles

Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program is

documented in SER Section 3.0.3.2.5.

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Enhancement. In the LRA, the applicant credits an enhancement to the GALL Report program

element "scope of the program." Specifically, the enhancement states:

Procedures will be enhanced to state that susceptible components adjacent to

potential leakage sources will include electrical components and connectors.

The staff finds that the Boric Acid Corrosion Program states that "The program covers any

structures or components on which boric acid corrosion may occur (e.g., steel and aluminum)

and electrical components on which borated reactor water may leak." The staff determines that

this enhancement is acceptable because the inclusion of electrical components and connectors

makes the program consistent with the GALL Report.

The staff reviewed those portions of the Boric Acid Corrosion Program for which the applicant

claims consistency with GALL AMP XI.M10 and finds that they are consistent with the GALL

AMP. The staff finds the applicant's Boric Acid Corrosion Program acceptable because it

conforms to the recommended AMP, with the enhancement described.

Operatincq Experience. LRA Section B2.1.4 states that industry operating experience indicates

that boric acid leakage can cause significant corrosion damage to susceptible plant

components. In response to recent NRC generic communications, the RCS pressure boundary

integrity walkdowns have been revised to perform periodic visual inspection of the RPV

safe-end nozzles, sides, and bottom head, and documentation of any indication of leakage. The

applicant stated that a review of plant operating experience revealed instances of boric acid

crystals on either the leaking components or the surrounding equipment. Both active leakage

and crystal buildup have occurred from packing, bolted connections, or pump seal sources, but

it did not cause any loss of intended function due to boric acid corrosion. The applicant stated

that leakage effects on nearby components were limited. The Boric Acid Corrosion Program

initiates corrective actions upon detection of boric acid crystals or active leakage.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Boric Acid Corrosion Program. The staff also interviewed selected

onsite personnel who have specialized knowledge of the program. The staff reviewed selected

instances previously documented by the applicant that identified issues with boric acid corrosion

and where the applicant had implemented corrective action.

After Refueling Outage 14, a borated water leak was discovered at the high pressure seals at

an incore instrument seal table in containment. Pictures were taken on December 2005 and

January 2006 at 100 percent power to identify any changes in this leakage. After this outage,

the applicant implemented lessons-learned and knowledge transfer actions to ensure seals are

installed properly to minimize the probability of leakage at this and similar locations.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.4, the applicant provided the USAR supplement for the

Boric Acid Corrosion Program. The applicant committed (Commitment No. 1) that, prior to the

period of extended operation, procedures will be enhanced to include electrical components

and connectors as susceptible components adjacent to potential leakage sources. The staff

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reviewed this section and determines that the information in the USAR supplement is an

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Boric Acid Corrosion

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancement

and confirms that its implementation prior to the period of extended operation would make the

existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.5 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads

of Pressurized Water Reactors

Summary of Technical Information in the Application. LRA Section B2.1.5 describes the existing

Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of

Pressurized Water Reactors Program as consistent, with enhancement, with GALL

AMP XI.M1 1A, "Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure

Heads of Pressurized Water Reactors."

The Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of

Pressurized Water Reactors Program manages cracking due to primary water stress corrosion

cracking (PWSCC) and loss of material due to boric acid wastage in nickel-alloy vessel head

penetration nozzles for the reactor vessel closure head, upper vessel head penetration nozzles,

and welds. This program was developed in response to NRC Order EA-03-009. Cracking is

detected through a combination of bare metal visual (external surface of head) and nonvisual

(underside of head) examination techniques. Procedures are developed for reactor vessel head

bare metal inspections and calculations of plant susceptibility ranking. Examinations are

performed by Level II or III VT-2 certified personnel. Completed testing to date verifies a

susceptibility ranking of "Low" per NRC Order EA-03-009, as amended. Plants in the "Low"

category require bare metal visual inspections every third refueling outage or every five years

(whichever comes first) and ultrasonic, eddy current, or dye penetrant testing every fourth

refueling outage or every seven years (whichever comes first). NDEs (ultrasonic, eddy current,

or dye penetrant) of the RPV head penetration nozzles and welds will occur initially during the

2006 refueling outage in accordance with this order.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure

Heads of Pressurized Water Reactors Program, as listed in the audit summary, including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M1 1A.

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The staff noted that the applicant's implementing procedure for the RPV head bare metal

inspection requires an inspection be performed every third refueling outage or every five years,

whichever comes first, and that both direct and remote visual techniques may be used. The

applicant's procedure for the RPV head NDE examination requires that the examination use

ultrasonic, eddy current, or dye penetrant testing and that it be performed every fourth refueling

outage or every seven years, whichever comes first. The inspection or examination techniques

and frequencies required by the applicant's procedures are consistent with those specified in

NRC Order EA-03-009, as amended, as referenced in the GALL Report. The staff noted that

the frequencies are applicable for inspection or examination of plants that are in the "low"

susceptibility category for PWSCC-related reactor head degradation. It also noted that the

applicant's implementing procedures include requirements to determine the susceptibility

category for the reactor head using the methodology specified in NRC Order EA-03-009, as

amended, and that the reactor head is currently in the "low" susceptibility category.

The applicant identified one enhancement to procedures in the existing Nickel-Alloy Penetration

Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors

Program.

Enhancement. In the LRA, the applicant credited an enhancement to the GALL Report program

element "corrective actions." Specifically, the enhancement states:

Procedures will be enhanced to indicate that detection of leakage or evidence of

cracking in the vessel head penetration nozzles or associated welds will cause

an immediate reclassification to the "High" susceptibility ranking, commencing

from the same outage in which the leakage or cracking is detected.

The applicant's existing program currently incorporates the requirements for reclassification of

susceptibility ranking indirectly, by referencing NRC Order EA-03-009. The enhancement

improves the applicant's implementing procedures and provides additional assurance that the

requirement will be implemented correctly.

On the basis that a reclassification to the "high" susceptibility category results in more frequent

performance of RPV head bare metal inspections and NDE examinations, which is consistent

with NRC Order EA-03-009, as amended, and the GALL Report, the staff finds that the

applicant's proposed enhancement is acceptable.

The staff reviewed those portions of the Nickel-Alloy Penetration Nozzles Welded to the Upper

Reactor Vessel Closure Heads of Pressurized Water Reactors Program for which the applicant

claims consistency with GALL AMP XI.M1 1A and finds that they are consistent with the GALL

AMP. The staff finds the applicant's Nickel-Alloy Penetration Nozzles Welded to the Upper

Reactor Vessel Closure Heads of Pressurized Water Reactors Program acceptable because it

conforms to the recommended AMP, with the enhancement described.

Operating Experience. LRA Section B2.1.5 states that during a scheduled modification of the

control rod drive mechanism (CRDM) cooling shroud, boron residue was detected on the upper

surface of the insulation in the vicinity of three CRDMs. The insulation in the affected area was

removed and when the vessel head penetrations were examined in October 2003, no evidence

of boric acid leakage was detected. The annulus area of the potentially affected penetrations

was verified to be free of boric acid. Small accumulations of loose debris were found on the

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upper side of some penetrations. Loose boric acid crystals on the head surface and transparent

boron film on both the penetration sleeves and the head surface were observed. The amount

and configuration of the debris and film were compared to as-left conditions from a RPV head

bare metal inspection performed in Refueling Outage 12 and were found comparable. The

debris was removed and the boron film cleaned. There were no material deficiencies detected

on the RPV head or penetration pressure boundaries. There were also no indications of actual

or potential leakage through the CRDM penetrations. The boron residue on the head insulation

that initiated the examination in accordance with NRC Order EA-03-009, as amended,

originated from head vent valve leakage during Operation Cycle 12. Transient event walkdowns

in August and October 2004 noted a dry white residue on CRDM penetration P-52 at the lower

canopy seal weld. The boron was in the area previously identified with boron accumulation from

head vent valve leakage in Refueling Outage 13. The applicant stated that the area was

cleaned and a penetrant test found no indication of accumulation.

During the audit, the staff reviewed the operating experience provided in the LRA and

interviewed the applicant's technical personnel to confirm that the plant-specific operating

experience did not reveal any degradation not bounded by industry experience.

The staff noted that the applicant had recently performed a bare metal visual examination of the

top of the reactor vessel closure head and a non-visual NDE of the nickel-alloy penetration

nozzles of the reactor vessel closure head. The staff reviewed the implementing procedures

related to these examinations and requested that the applicant provides a summary of

examination results.

In its response, the applicant stated that a bare metal visual examination of the top of the

reactor vessel closure head meeting the requirements of the revised NRC Order EA-03-009,

Section IV.C.(5)(a), as amended, was performed during a refueling outage in October 2006. No

evidence of leakage of boron or corrosive products was found. The applicant stated that it also

performed a non-visual NDE (i.e., ultrasonic examination) of the nickel-alloy penetration nozzles

of the reactor vessel closure head meeting the requirements of the revised NRC Order

EA-03-009, Section IV.C.(5)(b). The ultrasonic examination found no indication of cracking in

any of the vessel head penetration nozzles.

Based on the applicant's conformance with the requirements of NRC Order EA-03-009, as

amended, and as referenced in the GALL Report (relative to aging management), the staff finds

the applicant's response acceptable.

The staff reviewed implementing procedures and interviewed selected applicant personnel who

have specialized knowledge of the program. The staff did not identify any instances where the

applicant's program omitted requirements of NRC Order EA-03-009, as amended, or

recommendations of the GALL Report. On this basis, the staff finds that the applicant's

implementation of the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel

Closure Heads of Pressurized Water Reactors Program is acceptable.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this

program element acceptable.

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USAR Supplement. In LRA Section A1.5, the applicant provided the USAR supplement for the

Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of

Pressurized Water Reactors Program. The applicant committed (Commitment No. 2) that, prior

to the period of extended operation, procedures will be enhanced to ensure that the detection of

leakage or evidence of cracking in the vessel head penetration nozzles or associated welds will

cause an immediate reclassification to the "high" susceptibility ranking, commencing from the

same outage in which the leakage or cracking is detected. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Nickel-Alloy Penetration

Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancement

and confirms that its implementation prior to the period of extended operation would make the

existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.6 Flow-Accelerated Corrosion

Summary of Technical Information in the Application. LRA Section B2.1.6 describes the existing

Flow-Accelerated Corrosion Program as consistent, with exception, with GALL AMP XI.M1 7,

"Flow-Accelerated Corrosion."

The Flow-Accelerated Corrosion Program manages aging effects of wall thinning due to

flow-accelerated corrosion on the internal surfaces of carbon or low-alloy steel piping, elbows,

reducers, expanders, and valve bodies containing high-energy fluids (both single phase and two

phases). The program implements the EPRI guidelines in Nuclear Safety Analysis Center

(NSAC)-202L, Revision 3 for an effective flow-accelerated corrosion program to detect,

measure, monitor, predict, and mitigate wall thinning. To aid in planning inspections and

choosing inspection locations, the applicant utilizes the EPRI computer program CHECWORKS

developed solely for flow-accelerated corrosion management. The objectives of the

Flow-Accelerated Corrosion Program are achieved by (a) identifying system components

susceptible to flow-accelerated corrosion, (b) determining by a predictive code like

CHECWORKS critical locations for inspection and evaluation, (c) providing guidance for

followup inspections, (d) repairing or replacing components as determined by program

guidance, and (e) continually evaluating and incorporating the latest technologies and industry

and plant-specific operating experience.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Flow-Accelerated Corrosion Program, as listed in the audit summary, including

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the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M17.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

elements "scope of the program" and "detection of aging effects." Specifically, the exception

states:

The WCGS FAC program is in accordance with NSAC-202L-R3,

'Recommendations for an Effective Flow-Accelerated Corrosion Program.' The

WCGS FAC program, which adheres to the NSAC-202L-R3 guidance, is

consistent with NSAC-202L-R2, for defining the scope of the program and the

detection of wall thinning due to Flow-Accelerated Corrosion.

The staff interviewed the applicant's technical personnel and reviewed the scope of

NSAC-202L, Revision 3. The staff found that a later revision of NSAC-202L was issued by

EPRI to include recommendations updated with the experience feedback received from the

members of CHECWORKS Users Group, and to incorporate the recent developments in

detection, modeling, and mitigation technology. In the report summary included in NSAC-202L,

EPRI stated that the revised recommendations were intended to refine and enhance those

provided in the earlier revisions of NSAC-202L, without contradiction, to ensure the continuity of

the existing plant flow-accelerated corrosion programs. In addition, the staff reviewed a

sampling of the applicant's implementation procedures supporting the objectives of the

Flow-Accelerated Corrosion Program.

Based on its review, the staff finds that the exception to the program described above improves

the program and; therefore, is acceptable.

The staff reviewed those portions of the Flow-Accelerated Corrosion Program for which the

applicant claims consistency with GALL AMP XI.M17 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Flow-Accelerated Corrosion Program acceptable

because it conforms to the recommended AMP, with the exception described.

Operatinq Experience. LRA Section B2.1.6 states that work orders dated back to 1995 show no

reported flow-accelerated corrosion-related leak or rupture. Most of the work orders were for

wall thinning found during Flow-Accelerated Corrosion Program inspections. The minimum

acceptable thickness has not been violated. Problems detected during program activities had

no significant impact on the safe operation of the plant, and adequate corrective actions were

taken to prevent recurrence. The applicant stated that industry and plant-specific operating

experience and periodic self-assessments are incorporated into the Flow-Accelerated Corrosion

Program as necessary.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Flow-Accelerated Corrosion Program and interviewed selected onsite

personnel who have specialized knowledge of the program. The staff reviewed instances

previously documented by the applicant that identified issues with the flow-accelerated

corrosion and where the applicant had implemented corrective action.

The staff also reviewed a sampling of the work orders and problem identification reports

pertinent to the applicant's Flow-Accelerated Corrosion Program. These work orders represent

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the plant-specific operating experience in detecting and managing the aging effects that result

from flow-accelerated corrosion in piping and piping components.

The staff requested that the applicant describe if there have been improvements and/or

modifications to the Flow-Accelerated Corrosion Program since it was first implemented.

The staff also requested that the applicant explain what actions are taken to ensure that the

predicted wear rates performed by the CHECWORKS model are consistent with the actual

wear rate

In its response, the applicant stated that WCGS has increased participation in the EPRI

CHECWORKS Users Group to better review and respond to issues within the industry. The

applicant further stated that in March 2006, WCGS had upgraded its EPRI CHECWORKS

program to the later version (i.e., SFA version 2.1) and the model was verified and updated

again at this upgrade. Several examples of plant documents were provided by the applicant's

technical personnel during the audit that demonstrated the use of the plant and industry

experience to carry out flow-accelerated corrosion inspections that led to the detection of wall

thinning degradations and subsequent replacement of the piping components.

Based on its review, the staff finds that the applicant's program has been effective in identifying,

monitoring, and correcting the effects of flow-accelerated corrosion and can be expected to

ensure that piping wall thickness will be maintained above the minimum required by design.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.6, the applicant provided the USAR supplement for the

Flow-Accelerated Corrosion Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Flow-Accelerated Corrosion

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception

and its justifications and determines that the AMP, with the exception, is adequate to manage

the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.7 Bolting Integrity

Summary of Technical Information in the Application. LRA Section 82.1.7 describes the existing

Bolting Integrity Program as consistent, with exceptions, with GALL AMP XI.M1 8, "Bolting

Integrity."

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The Bolting Integrity Program manages the aging effects of cracking, loss of material, and loss

of preload for pressure-retaining bolting and ASME component support bolting. The program

includes preload control, selection of bolting material, use of lubricants and sealants consistent

with EPRI bolting practices, and periodic inspections for indications of aging effects. The

program also includes ISI requirements in accordance with ASME Code Section Xl,

Subsections IWB, IWC, IWD, and IWF for ASME Class bolting. WCGS bolting practices are in

accordance with plant procedures including requirements for proper disassembly, inspection,

and assembly of connections with threaded fasteners. The following AMPs supplement the

Bolting Integrity Program with management of loss of preload, cracking, and loss of material:

(1) the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

provides the requirements for ISI of ASME Classes 1, 2, and 3 safety-related pressure retaining

bolting, (2) the ASME Code Section Xl, Subsection IWF Program provides the requirements for

ISI of safety-related component support bolting, and (3) the External Surfaces Monitoring

Program provides the requirements for the inspection of pressure boundary closure bolting

within the scope of license renewal.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exceptions to determine whether the

AMP, with the exceptions, remains adequate to manage the aging effects for which it is

credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Bolting Integrity Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.M1 8.

The staff requested that the applicant clarify if they use a bolting expert in accordance with

EPRI recommendations. In its response, the applicant stated that while EPRI identifies a bolting

coordinator as an individual who has technical ability and authority to focus on both

programmatic issues and day-to-day resolution of problems, the mechanical design engineering

group provides the functions of the bolting coordinator which is consistent with the EPRI

guidance.

The staff finds the applicant's response acceptable because it explained that the mechanical

design engineering group performs the functions recommended in the EPRI guidance.

The staff requested that the applicant explain if the WCGS fasteners are being inspected in

place. If not, the staff requested that the applicant clarify if WCGS requested relief from the

ASME Code, Section XI, requirements.

In its response, the applicant stated that the statement in the operating experience implying that

this is an ASME Code Section Xl inspection is incorrect. The inspection was required in

response to NRC Bulletin 82-02, which states that ASME Code, Section XI, acceptance criteria

should be utilized. The Bulletin also states that fasteners which were seized or interference fit

could be inspected in place. This indicates that either excessive force would be required to

remove the fastener (i.e., seized) or the fastener was designed to be difficult to remove or back

out (i.e., interference fit). In either case, this allowance is technically justified when considering

that a borated water path into the fastener threads would have to begin at an exposed surface.

Also, the applicant stated that boric acid corrosion needs oxygen, which also is not present in

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sufficient quantities internal to a seized fastener. Both the borated water path and oxygen

supply would be present at the exposed surface of the fastener. Therefore, the Bulletin was

correct in allowing such fasteners to be inspected in place. The applicant stated that based on

these arguments, seized or interference fit fasteners are inspected in place, and no ASME

Code relief is required.

The staff finds the applicant's response acceptable because the seized or interference fit

fasteners are inspected in place and the inspections are not ASME Code requirements;

therefore, relief from ASME Code requirements are not needed.

The staff requested that the applicant describe the maintenance procedures used to check bolt

torque and the uniformity of gasket compression. The staff also requested that the applicant

provides the frequency for the maintenance activity.

In its response, the applicant stated that, in accordance with plant procedures on bolting

installations, proper bolting practice to provide leak tight pressure retaining joints includes: (1)

pre-assembly inspection and cleaning requirements, (2) use of specific bolting torquing

patterns, (3) increased application of torque through multiple passes, and (4) verification of

uniformity of the gasket compression. Post-bolting inspections include verifying contact

between the fastener and flange and proper flange alignment. The applicant stated that

guidance for proper preload is provided with desired torque values to ensure adequate gasket

stress for leak tightness.

These activities are performed when there are opportunities of removal and installation of the

subject components for maintenance or scheduled inspections.

The staff finds the applicant's response acceptable because it clarifies that WCGS has qualified

procedures for torquing bolts and for assuring uniformity of gasket compression.

Exception 1. In the LRA, the applicant credited an exception to the GALL Report program

element "scope of the program." Specifically, the exception stated:

NUREG-1 801, Section XI.M1 8 specifies the use of ASME Section XI 1995

edition with the 1996 addenda. WCGS uses the ASME Section XI, 1998 Edition

through 2000 addenda for the current third interval ISI Program. Use of the 1998

Code through 2000 addenda does not change the requirements regarding

inspections, evaluations and corrective actions for safety-related bolting to

ensure the integrity of the intended functions.

The staff finds that this exception is acceptable because the use of this ASME Code edition and

addenda for the current interval has been approved by the staff and the requirements in the

different editions have not changed.

Exception 2. In the LRA, the applicant credited an exception to the GALL Report program

elements "scope of the program," and "preventive actions." Specifically, the exception stated:

The procedures for ensuring bolting integrity identify preload requirements and

general practices for in-scope bolting but do not directly reference EPRI

NP-5769 or NUREG-1 339 as applicable source documents for these

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recommendations. However, these procedures do reference and incorporate the

good bolting practices identified in EPRI NP-5067 and EPRI TR-104213. EPRI

NP-5769 and NUREG-1339 are very closely related with EPRI NP-5067 and

EPRI TR-104213 and they cross-reference one another. EPRI NP-5769,

Section 8, Good Bolting Practices, refers to EPRI NP-5067 for the identification

of bolting practices associated with disassembly and assembly of bolted joints,

and the methods for minimizing bolted joint problems such as leaks, vibration

loosening, fatigue, and stress corrosion cracking. Implementation of the

recommendations in EPRI NP-5067 and EPRI TR-104213 is considered to be

consistent with the recommendations in EPRI NP-5769 and NUREG-1 339 to

meet the NUREG-1801 recommendations.

The staff finds this exception acceptable because the EPRI recommendations followed by the

applicant are consistent with the recommendations provided in the GALL Report.

Exception 3. In the LRA, the applicant credited an exception to the GALL Report program

element "parameters monitored or inspected." Specifically, the exception stated:

Loss of preload is not a parameter of inspection for the WCGS Bolting Integrity

Program. EPRI NP-5769, Volume 2, Section 10, indicates that job inspection

torque is non-conservative since, for a given fastener tension, more torque is

required to restart the installed bolts. The techniques for measuring the amount

of bolt tension in an assembled joint are both difficult and unreliable. EPRI

NP-5769, Volume 2, Section 10, suggests that inspection of preload is usually

unnecessary if the installation method has been carefully followed. Torque

values provided in the procedures are based on criteria of stretch to cover the

expected relaxation of the fasteners over the life of the joint. Gasket stress is

also considered for pressure boundary closure bolting.

During the audit, the staff requested that the applicant describe the maintenance procedures

used to check bolt torque and the uniformity of gasket compression. In its response, the

applicant stated that, in accordance with plant procedures on bolting installations, proper bolting

practice to provide leak tight pressure retaining joints includes: (1) pre-assembly inspection and

cleaning requirements, (2) use of specific bolting torque patterns, (3) increased application of

torque through multiple passes, and (4) verification of uniformity of the gasket compression.

Post-bolting inspections include verifying contact between the fastener and flange and proper

flange alignment. Guidance for proper preload is provided with desired torque values to ensure

adequate gasket stress for leak tightness.

The staff finds the applicant's response acceptable because WCGS is following EPRI

guidelines that have been developed by the industry. These EPRI guidelines are consistent with

the Bolting Integrity Program as described in the GALL Report.

Exception 4. In the LRA, the applicant credited an exception to the GALL Report program

element "monitoring and trending." Specifically, the exception stated:

NUREG-1 801, Section XI.M18, specifies that if bolting connections for pressure

retaining components (not covered by ASME Section XI) are reported to be

leaking, then they may be inspected daily. If the leak rate does not increase, the

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inspection frequency may be decreased to biweekly or weekly. WCGS

procedures require the inspection frequency be adjusted as necessary based on

the trending of inspection results to ensure there is not a loss of intended

function between inspection intervals. For pressure retaining components

reported to be leaking, the site corrective action process is initiated.

Consideration is also given to adequate frequency of subsequent inspections to

ensure the inspection interval is adequate to detect further aging degradation so

that a loss of intended function is avoided.

The staff finds that this exception is acceptable because it is more restrictive than the

recommendations provided in the GALL Report.

The staff reviewed those portions of the Bolting Integrity Program for which the applicant claims

consistency with GALL AMP XI.M18, and finds that they are consistent with the GALL AMP.

The staff finds that the applicant's Bolting Integrity Program is acceptable because it conforms

to the recommended AMP, with the exceptions described.

Operatinq Experience. LRA Section B2.1.7 states that a review of plant-specific operating

experience found issues with corrosion, missing or loose bolts, inadequate thread engagement,

and improper bolt applications. There is no reported cracking of the bolts due to SCC. The

applicant stated that all concerns were corrected, no significant safety event occurred, and

additional actions like procedural enhancements were implemented as needed to prevent

recurrence.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Bolting Integrity Program for programmatic issues relevant to license

renewal review. The staff also interviewed selected onsite personnel who have specialized

knowledge of the program. The staff reviewed selected instances previously documented by the

applicant that identified issues with bolting and where the applicant had implemented corrective

action.

During the audit, the staff noted that a valve (in one operating experience example) was found

to have external corrosion (relative to programmatic issues associated with corrective action

program). Some of the corrosion had affected the threads on the bolts. A work order was

written to replace two of the bolts. The staff finds that the corrective actions taken by the

applicant are acceptable because the bolts were adequately replaced.

While reviewing the problem identification reports, the staff noted that the studs on a leaking

bonnet flange were found to be overtorqued at 355 ft-lb. A plan of action was developed to

replace the studs, one at a time, and the cover during a refueling outage, if needed. The staff's

concern is that this problem was not identified in a corrective work package. The purpose of this

report was only to identify the issue. The operability of the valve was not a concern because the

valve and the nonsafety-related service loop in the component cooling water system (CCWS)

can be isolated. In addition, the studs may have been yielded, but were not taken to the

ultimate tensile strength of the studs.

The staff believes that the studs will keep the bonnet cover in place based on the past service

of the component and the fact that the studs are currently torqued to a lower value according to

plant procedures.

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The staff also noted that work instructions were issued for correcting an oil leak at the gaskets

between a lube oil pump casing, rotor, and end cover housing. While disassembly the pump

end cover housing, it was noted that four bolts which tighten the pump housing gaskets were

loose. The bolts in question were less than snug tight. WCGS determined that this was the

cause of the leakage.

The staff believes that in all likelihood, tightening the four bolts could have stopped the leakage.

The work of developing work package instructions, scheduling, and implementing of this activity

might well have been precluded had the cause for the oil leak been more closely examined.

In the Boric Acid Corrosion Program, the applicant stated that WCGS is treating fasteners that

are difficult to remove for engaged thread inspection as "seized" to prevent backing out. This

practice is based on guidance provided in NRC IE Bulletin 82-02, which states "Fasteners

"seized" or designed with interference fit may be inspected in place." As a result, the engaged

threads of certain stuck fasteners designed as removable, but are difficult to remove, are not

being inspected as required by ASME Code, Section XI.

The staff finds that the corrective action program, which captures internal and external plant

operating experience issues, will ensure that operating experience is reviewed and incorporated

to provide objective evidence to support the conclusion that the aging effects are adequately

managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.7, the applicant provided the USAR supplement for the

Bolting Integrity. The staff reviewed this section and determines that the information in the

USAR supplement is an adequate summary description of the program, as required by

10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Bolting Integrity, the staff

determines that those program elements for which the applicant claimed consistency with the

GALL Report are consistent. In addition, the staff reviewed the exceptions and their

justifications and determines that the AMP, with the exceptions, is adequate to manage the

aging effects for which it is credited. The staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.8 Steam Generator Tube Integrity

Summary of Technical Information in the Application. LRA Section B2.1.8 describes the existing

Steam Generator Tube Integrity Program as consistent, with exceptions, with GALL

AMP XI.M1 9, "Steam Generator Tube Integrity."

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The scope of the Steam Generator Tube Integrity Program includes the preventive measures,

condition monitoring inspections, degradation assessments, and repair and leakage monitoring

activities necessary to manage cracking, loss of material, denting, and wall thinning. The aging

management measures include NDE examination, visual inspection, sludge removal, tube

plugging, in-situ pressure testing, and chemical environmental maintenance by removal of

impurities and addition of chemicals to control pH and oxygen. NDE inspection scope and

frequency and primary to secondary leak rate monitoring are consistent with the requirements

of WCGS Technical Specifications. Structural integrity limits consistent with RG 1.121,

Revision 0, "Bases for Plugging Degraded PWR Steam Generator Tubes," are applied.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report. The staff reviewed the exceptions to determine whether the

AMP, with the exceptions, remains adequate to manage the aging effects for which it is

credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Steam Generator Tube Integrity Program, as listed in the audit summary,

including the license renewal program evaluation report in which the applicant assessed

whether the program elements are consistent with GALL AMP XI.M1 9.

During the audit and review, the staff requested that the applicant clarify how many tubes are

plugged in each steam generator, and if WCGS has plans to replace these steam generators.

In its response, the applicant stated that less than 1 percent are plugged in steam generators A,

B, and C, and about 2 percent in steam generator D. The applicant stated that the current

economic model for steam generators does not recommend replacement. The model is

updated as the conditions change. The applicant clarified that the steam generator tubes are

made from Alloy 600 thermally treated, which are much more resistant to degradation

compared to Alloy 600 mill annealed tubes.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

element "scope of the program." Specifically, the exception states:

When in wet layup conditions, WCGS is meeting the requirements for mixing of

the steam generator bulk solution and ensuring adequate sample line flush times

are employed. This ensures the chemistry of the bulk fluid is uniform and that

samples are representative of the bulk steam generator secondary side water.

The WCGS design incorporates pumps for periodic recirculation of the steam

generator fluid. Operating experience has shown that a 33-hour recirculation

period will provide adequate bulk mixing. If sample results after 33 hours of

recirculation indicate a failure to meet the layup specifications, corrective action

is taken to correct the layup mixture.

The staff requested that the applicant confirm if there was an analysis that states that a 33-hour

recirculation of steam generators followed by weekly sampling is better than or equivalent to

obtaining three samples per week until values are stable when in wet layup conditions.

In its response, the applicant stated that this exception was taken based on operating

experience and history. Prior to initial fill of the steam generators during plant construction,

calculations were performed to determine the required recirculation time to achieve mixing of

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the bulk solution. This calculation was based on the steam generator volume, flow-rate of the

mix pumps, and recirculating three volumes of the bulk solution. The result was that a 33-hour

recirculation time would thoroughly mix the bulk solution. The use of the 33-hour mix time

became a standard practice. Once in wet layup with chemicals added, the steam generators

are mixed for 33 hours and then sampled to analyze the desired chemical environment. Then,

recirculation and sampling are done on a weekly basis, in accordance with plant procedures.

The applicant stated that experience has shown that once the steam generators bulk solution

meets the required specifications, it remains satisfactory. If the parameters set forth in the plant

procedures are not met, adjustments are taken and the recirculation and sampling is repeated.

The staff noted from the license renewal program evaluation report that the WCGS design

incorporates pumps for recirculation of the steam generator fluid. The staff also finds that the

applicant performed calculations based on the steam generator volume, flow-rate of the mix

pumps, and recirculating three volumes of the bulk solution. On the basis that the applicant

provided an analytical basis for the 33-hour mix time, the staff finds this exception acceptable.

The staff reviewed LRA Section B2.1.8 and identified areas in which additional information was

necessary to complete the review of the applicant's aging management program. The applicant

responded to the staff's RAIs as discussed below.

The staff noted that the GALL Report states, in part, that the degradation management

program in NEI 97-06, "Steam Generator Tube Integrity," is adequate to manage the effects of

aging of the steam generator tubes. NEI 97-06 references guideline documents developed by

EPRI for managing areas important to steam generator tube integrity, including tube

inspections. The LRA discusses several exceptions taken to these EPRI guidelines.

In RAI B2.1.8-1 dated September 27, 2007, the staff noted that the LRA states that the rotating

pancake probe is used to inspect from 3 inches above to 3 inches below the top of the

tubesheet and that the bobbin probe is used to inspect the entire engagement length of the

hydraulically expanded tubesheet region. However, the bobbin probe is not qualified for

inspection in this area. The application also states that there was a one-cycle license

amendment request to use an alternate tube repair criteria which, in part, eliminated the need

to inspect near the tube ends on the hot-leg side of the steam generator.

The staff noted that the EPRI guidelines indicate that the full length of the steam generator

tubes requires an inspection with an inspection technique qualified for each region of the tube.

The staff requested that the applicant clarify this exception to the GALL Report and the EPRI

guidelines. The staff requested that the applicant clarify whether the exception being taken to

the EPRI guidelines is that the entire tube is not inspected or whether WCGS is not inspecting

the portions of the tube that require inspection with techniques capable of detecting flaws that

may occur in that region. The staff noted that the tube requires inspection with the objective of

detecting flaws of any type, and that may satisfy the applicable tube repair criteria, as described

in the WCGS technical specification 5.5.9.d. If cracking of the tube could occur at various

locations within the tubesheet, these areas should be inspected with techniques capable of

finding these flaws (and consistent with the sampling and tube integrity requirements of the

technical specifications).

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In its response, dated October 17, 2007, the applicant stated that this issue is no longer

considered as an exception to the GALL Report. NEI 97-06 and the associated EPRI guidelines

are established to perform degradation assessments and condition monitoring and operational

assessments to ensure steam generator tube integrity. The applicant stated that since the LRA

was submitted, WCGS implemented its operating license amendment 164 to revise various

technical specifications associated with steam generator tube integrity to adopt TSTF-449,

Revision 4, "Steam Generator Tube Integrity." Currently, WCGS is in compliance its technical

specification 5.5.9.d.

The staff finds the applicant's response to RAI B2.1.8-1 acceptable because it explained that

this is no longer an exception to the GALL Report. Further, it clarified that WCGS is in

compliance with its technical specification 5.5.9.d. Therefore, the staff's concern described in

RAI B2.1.8-1 is resolved.

In RAI B2.1.8-2 dated September 27, 2007, the staff noted that the LRA states that the bobbin

probe is used to detect PWSCC at tube dents in support plates and SCC in free span regions.

However, the bobbin probe is not qualified for detection of these degradation mechanisms

when the voltage of the dent exceeds certain threshold values. Further, the staff noted that the

EPRI guidelines indicate that the full length of the steam generator tubes requires an inspection

with an inspection technique qualified for each region of the tube.

The staff requested that the applicant clarify the nature of this exception to the GALL Report

and EPRI guidelines since the WCGS technical specifications require, in part, to (a) perform an

assessment of the type and location of flaws to which the tubes may be susceptible and, based

on this assessment, to determine which inspection methods need to be employed and at what

locations, and (b) inspect the tubes with the objective of detecting flaws that may satisfy the

applicable tube repair criteria.

The staff noted that in light of these requirements, if WCGS concludes that PWSCC could

occur at tube dents in support plates or outer diameter SCC could occur in free span regions,

these regions should be inspected with techniques capable of finding these forms of

degradation.

In its response, dated October 17, 2007, the applicant stated that this issue is no longer

considered to be an exception to the GALL Report. NEI 97-06 and the associated EPRI

guidelines are established to perform degradation assessments and condition monitoring and

operational assessments to ensure steam generator tube integrity. The applicant stated that

since the LRA was submitted, WCGS implemented its operating license amendment 164 to

revise various technical specifications associated with steam generator tube integrity to adopt

TSTF-449, Revision 4. Currently, WCGS is in compliance its technical specification 5.5.9.d.

The staff finds the applicant's response to RAI B2.1.8-2 acceptable because it explained that

this is no longer an exception to the GALL Report. Further, it clarified that WCGS is in

compliance with its technical specification 5.5.9.d. Therefore, the staff's concern described in

RAI B2.1.8-2 is resolved.

In RAI B2.1.8-3 dated September 27, 2007, the staff noted that the LRA indicates that the EPRI

guidelines require that if active damage mechanisms are identified then all steam generators

shall be examined at the end of each fuel cycle. The application also states that although

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WCGS currently has one active damage mechanism (i.e., wear at anti-vibration bars), only two

steam generators are inspected at each refueling outage on an alternating basis so that each

steam generator is examined every other refueling outage.

The staff requested that the applicant confirm that WCGS has verified the acceptability of this

approach at each outage by confirming that tube integrity will be maintained for the period of

time between the planned inspections of the steam generators, consistent with the WCGS

technical specification requirements.

In its response, dated October 17, 2007, the applicant stated that this issue is no longer

considered to be an exception to the GALL Report. NEI 97-06 and the associated EPRI

guidelines are established to perform degradation assessments and condition monitoring and

operational assessments to ensure steam generator tube integrity. The applicant stated that in

accordance with these requirements, the condition monitoring evaluation is performed to

compare the observed tube eddy current indication parameters against structural and leakage

integrity limits that are included in the pre-outage degradation assessment. An operational

assessment is also performed to project the inspection results and trends tothe next

inspections, and to provide reasonable assurance that the structural and leakage requirements

will continue to be met during the planned operating interval. These evaluations are conducted

as required during each inspection.

The staff finds the applicant's response to RAI B2.1.8-3 acceptable because it explained that

this is no longer an exception to the GALL Report. Further, it explained that a condition

monitoring evaluation and an operational assessment are performed to provide reasonable

assurance that the leakage requirements are met. Therefore, the staff's concern described in

RAI B2.1.8-3 is resolved.

By letter dated October 17, 2007, the applicant amended LRA Section B2.1.8 to delete three of

the four exceptions to the GALL Report originally credited in the application. The staff finds that

this is acceptable. The staff finds that WCGS is in compliance with its technical specifications

and is not taking exceptions to the recommended EPRI guidelines; therefore, these three items

should not be considered as exceptions to the GALL Report. Further, as previously discussed,

the only exception credited by the applicant (i.e., steam generators mixing solution), has been

found acceptable by the staff.

The staff reviewed those portions of the Steam Generator Tube Integrity Program for which the

applicant claims consistency with GALL AMP XI.M19 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Steam Generator Tube Integrity Program acceptable

because it conforms to the recommended AMP, with the exception described.

Operating Experience. LRA Section B2.1.8 states that the Steam Generator Tube Integrity

Program has been developed to be consistent (with the minor exceptions noted) with

NEI 97-06, "Steam Generator Program Guidelines," and to benefit from industry operating

experience available when the initiative was issued as well as from the EPRI guidelines it

endorses. The applicant stated that procedures require a steam generator degradation

assessment update every operating cycle to incorporate the latest industry and plant-specific

operating experience with steam generator degradation mechanisms.

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GL 95-05 addresses issues related to alternate repair criteria. The applicant stated that a

one-time license amendment request for alternate repair criteria (B*) was approved for

Refueling Outage 14 and the subsequent operating cycle. Tube sleeves are not approved for

use at WCGS, and therefore, are not used.

The applicant evaluates industry and plant-specific operating experience to identify active,

relevant, and potential tube damage mechanisms as addressed in NRC IN 97-88.

WCGS is a four-loop Westinghouse plant with four identical Model F steam generators. After

Refueling Outage 14 in the spring of 2005, 181 tubes had been plugged, which consists of less

than 1 percent of the total number of tubes. The applicant determined that the plugging was

caused by manufacturing issues, anti-vibration bar wear, loose part wear, tube support wear

(most likely due to a trapped loose part), flow distribution baffle wear (due to pressure pulse

cleaning), and preventive measures (manufacturing anomalies discovered in the field). As of

the end of Refueling Outage 14, no corrosion degradation was detected in any steam generator

tubes. The applicant stated that wear due to anti-vibration bars and loose parts is the only

active effect observed in the steam generators.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Steam Generator Tube Integrity Program. The staff also interviewed

selected onsite personnel who have specialized knowledge of the program. The staff reviewed

selected instances previously documented by the applicant that identified issues with steam

generator tube integrity and where the applicant had implemented corrective action.

The NRC IN 2005-09 addresses recent operating experience with degradation in steam

generator tubes and tube-to-tube sheet welds. In the United States, only a few cracks, or

crack-like defects, have been detected in steam generator tubes fabricated from thermally

treated Alloy 600. Prior to 2004, most, if not all, of these indications occurred at two plants and

were attributed to non-optimal tube processing.

The staff determines that the findings at Catawba Nuclear Station, Unit 2, are noteworthy

(relevant and applicable to WCGS which is also a PWR) because they indicate that degradation

can occur at various locations within the tubesheet region of thermally treated Alloy 600 tubes.

Crack-like indications were first found in manufacturing anomalies (e.g., bulges or tubesheets

anomalies) rather than at tube locations with short-bend radii like the expansion transition on

the hot-leg side and the u-bend region. Inspections at Catawba, Unit 2, focused on these areas

due to high operating temperatures and residual stress in these regions. The staff believes that

recent operating experience at Catawba, Unit 2, shows the importance of monitoring all tube

locations, such as bulges, dents, and dings, with techniques capable of finding potential forms

of degradation that may be occurring at these locations, as described in GL 2004-001,

"Requirements for Steam Generator Tube Inspections." The Catawba, Unit 2, experience also

highlights the need to inspect all regions with high residual stress. Such inspections will provide

added assurance that any degradation at these locations will be promptly detected.

The staff also noted that thermally treated Alloy 600 or Alloy 690 tubing steam generator leaks

at H. B. Robinson, Palo Verde, and Shearon Harris nuclear power plants also show the need

for thorough inspections and robust ISI programs regardless of tube material or steam

generator history.

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Given the industry operating history with steam generator tube leaks, the staff was concerned

because it seemed that the Steam Generator Inspection Program was using techniques that

are not consistent with the staff position, EPRI guidance, and the recommendations in the

GALL Report. However, in its letter dated October 17, 2007, the applicant clarified that WCGS

is following the recommendations in the EPRI guidance and is no longer taking exceptions to

the GALL Report.

In its letter, the applicant amended LRA Section B2.1.8 and clarified that an operating license

amendment allowed WCGS to use alternate repair criteria (B*) during Refueling Outages 14

and 15 and the subsequent operating cycles following these outages. The applicant also

clarified that after Refueling Outage 15, 204 tubes have been plugged, which consists of less

than 1 percent of the total number of tubes. It also clarified that no corrosion degradation has

been detected in any steam generator tubes.

The staff finds that the steam generator tube inspection findings at WCGS are consistent with

the inspection findings at other similarly designed and operated steam generators. In addition,

its Steam Generator Inspection Program is similar to that employed at other PWRs. The staff

determines that these programs have been effective at incorporating operating experience into

their steam generator programs.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.8, the applicant provided the USAR supplement for the

Steam Generator Tube Integrity.

In RAI B2.1.8-4 dated September 27, 2007, the staff noted that the description provided in the

LRA and the USAR supplement states that structural integrity limits consistent with RG 1.121,

"Bases for Plugging Degraded PWR Steam Generator Tubes," are applied as part of the Steam

Generator Tube Integrity Program. The staff requested that the applicant confirm that the AMP

also includes the structural integrity limits contained within the WCGS technical specifications.

The applicant, in its response dated October 17, 2007, stated that since the LRA was

submitted, WCGS implemented its operating license amendment 164 to revise various

technical specifications associated with steam generator tube integrity to adopt TSTF-449,

Revision 4. Currently, WCGS is in compliance its plant technical specifications.

The applicant amended LRA Sections B2.1.8 and A1.8 and in addition, clarified that NDE

inspection scope and frequency, and primary to secondary leak rate monitoring are conducted

consistent with the requirements of the plant's technical specifications. The applicant also

clarified that the structural integrity limits are consistent with RG 1.121, Revision 0 and that

plant's steam generator management practices are consistent with NEI 97-06, without

exceptions.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its audit and review of the applicant's Steam Generator Tube

Integrity, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception

and its justifications and determines that the AMP, with the exceptions, is adequate to manage

the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP

and concludes that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.9 Closed-Cycle Cooling Water System

Summary of Technical Information in the Application. LRA Section B2.1.10 describes the exiting

Closed-Cycle Cooling Water System Program as consistent, with exception and enhancement,

with GALL AMP XI.M21, "Closed-Cycle Cooling Water System."

The Closed-Cycle Cooling Water System Program manages loss of material, cracking, and

reduction of heat transfer for components in closed-cycle cooling water systems. The program

includes maintenance of system corrosion inhibitor concentrations within specified

EPRI TR-1 07396 limits to minimize aging and periodic testing and inspections to evaluate

system and component performance. Inspection methods include visual, UT, and eddy current

testing. For the CCWS, through the addition of corrosion inhibitors and biocides, the program

maintains water chemistry within the parameters specified in plant procedures to minimize

corrosion and microbiological growth. Diagnostic chemistry parameters are monitored to

maintain the water within specified parameters and indicate abnormal conditions. Performance

of selected heat exchangers is monitored by surveillance testing of the thermal or hydraulic

function. The system pumps are also tested for performance. NDEs verify maintenance of the

pressure boundary intended function of system components. The program requires system

pressure tests to find leaks so corrective actions can be taken. For the emergency diesel

engine cooling water subsystem, plant heating system, and central chilled water system, the

program relies on mitigative measures to minimize corrosion and microbiological growth with

corrosion inhibitors and biocides. Chemistry parameters also are monitored for abnormal

conditions to preclude cracking in stainless steel in the plant heating system. Emergency Diesel

generator (DG) engine performance parameters are monitored through periodic surveillance

tests. The plant heating and central chilled water systems are within the scope of license

renewal for spatial interaction concerns only; therefore, the periodic sampling and maintenance

of system chemistry in accordance with specified limits is adequate assurance that component

intended functions are maintained.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception and enhancement to determine whether the

AMP, with the exception and enhancement, remained adequate to manage the aging effects for

which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Closed-Cycle Cooling Water Program, as listed in the audit summary, including

the license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M21.

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Exception 1. In the LRA, the applicant credited an exception to the GALL Report program

element "parameters monitored or inspected." Specifically, the exception stated:

NUREG-1 801, Section XI.M21 states this program should monitor heat

exchanger parameters including flow, inlet and outlet temperatures, and

differential pressure. The letdown heat exchangers, residual heat removal heat

exchangers, safety injection pump coolers, and the PASS sample coolers, are

not periodically tested for flow, inlet and outlet temperatures, and differential

pressure. The CCW heat exchangers are periodically tested to measure heat

transfer capability. Shell-side (closed-cycle cooling water) flow and temperature

measurements are used to calculate heat exchanger performance in terms of a

fouling factor. Tube side (raw water) flow and differential pressure are also

measured and used as an indicator of tube fouling. The CCW heat exchangers

are periodically NDE-tested (ECT) to detect aging of the tube pressure

boundary. The performance monitoring and NDE of the CCW heat exchangers

will provide a leading indicator foraging of the other CCW supplied heat

exchangers. An enhancement to the WCGS closed-cycle cooling water system

program to specify inspection of the internal surfaces of the CCW pump return

line check valves during operational readiness inspection activities will also

provide additional indicators of the effective aging management of loss of

material and fouling in the CCW system. A review of WCGS plant-specific

operating experience indicates there has been no evidence of significant fouling

or loss of material observed in the closed cooling water systems. In lieu of

performance testing of all CCW supplied heat exchangers, the CCW heat

exchanger performance monitoring, system internal inspections activities, and

CCW chemistry program are used to manage aging effects in the CCW system.

The staff noted that in lieu of monitoring heat exchanger parameters such as flow, inlet and

outlet temperatures and differential pressures, the applicant periodically tests the component

cooling water heat exchangers to measure heat transfer capability. The heat exchangers are

also periodically tested with NDE to detect aging of the tube pressure boundary. The applicant

has proposed an enhancement to inspect internal surfaces of check valves in the CCWS pump

return lines during ISI activities.

The staff determines that the performance monitoring of the heat exchangers, the NDE

inspection of heat exchanger tubes, and the inspection of internal surfaces of check valves will

provide a leading indicator that aging resulting in a loss of material and fouling of heat

exchangers is adequately managed in the closed cycle cooling water system. The staff also

reviewed the operating experience and determines that there has been no evidence of

significant fouling or loss of materials in the CCWS. On the basis of its review, the staff finds

the exception acceptable.

The GALL AMP XI.M21 program description states that the program includes preventive

measures to minimize corrosion, and testing and inspection to monitor the effects of corrosion

on the intended function of the component.

During the audit, the staff reviewed the license renewal program evaluation report for the

Closed-Cycle Cooling Water System Program and found that in elements "parameters

monitored or inspected" and "detection of aging effects," the applicant stated that for the plant

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heating steam and central chilled water systems, inspection is not performed; only periodic

sampling and maintenance of water chemistry within specified limits is adequate to manage

aging. The staff requested that the applicant justify why this is not considered an exception to

the GALL Report.

In its response, the applicant stated that it agreed with the staff and that this is an exception to

the GALL Report. By letter dated August 31, 2007, the applicant amended LRA Section B2.1.10

to include exception as discussed below.

Exception 2. In the LRA amendment, the applicant credited an exception to the GALL Report

program elements "parameters monitored or inspected," "detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically, the exception stated:

WCGS will not perform inspection or testing of plant heating and central chilled

water systems. Plant heating and central chilled water systems are in the scope

of license renewal due to 1OCFR50.54(a)(2) due to spatial interactions only.

Therefore, the only intended function applicable to these systems is pressure

boundary. Crud buildup would not directly affect the intended function of these

components. The periodic sampling and maintenance of system chemistry within

specified limits is adequate to manage aging before the loss of intended

function.

During the audit, the staff verified that the applicant maintains the system corrosion inhibitor

concentrations within the limits specified by EPRI TR-107396, "Closed-Cooling Water

Chemistry Guidelines," to minimize aging. The staff reviewed the operating experience for

systems and components that have an internal environment of closed cycle cooling water and

have had inspections performed, and found that there has been no evidence of significant loss

of materials in the system. Since plant heating and central chilled water systems are within the

scope of license renewal pursuant to 10 CFR 50.54(a)(2) for spatial interactions, and the only

intended function applicable to these systems is pressure boundary, the staff finds that the

periodic sampling and maintenance of system chemistry within specified limits is adequate to

manage aging before the loss of intended function. On the basis of its review, the staff finds the

exception acceptable.

Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program element "monitoring and trending." Specifically, the enhancement stated:

A new periodic preventive maintenance activity will be developed to specify

performing inspections of the internal surfaces of the valve bodies and

accessible piping while the valves are disassembled for operational readiness

inspections to detect loss of material and fouling.

During the audit, the staff noted that although the "monitoring and trending" program element is

enhanced to include performing inspections, the "acceptance criteria" program element was not

enhanced to provide an acceptance criteria for these inspections. The staff requested that the

applicant explain where the acceptance criteria for these new inspections will be provided.

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In its response, the applicant stated that the acceptance criteria will be specified within the

preventive maintenance activities. By letter dated August 31, 2007, the applicant amended the

enhancement in LRA Section B2. 1.10 to state:

A new periodic preventive maintenance activity will be developed to specify

performing inspections of the internal surfaces of the valve bodies and

accessible piping while the valves are disassembled for operational readiness

inspections to detect loss of material and fouling. The acceptance criteria will be

specified in this preventive maintenance activity.

The staff finds that this enhancement specifies performing periodic inspections of check valve

internals as part of a new preventive maintenance activity and provides acceptance criteria for

these inspections. The staff finds this enhancement acceptable because it provides further

verification of the effectiveness of the closed cycle cooling water chemistry and will make the

Closed-Cycle Cooling Water System Program consistent with the program description in the

GALL Report, which includes inspection to monitor the effects of corrosion.

During the audit, the staff found that one of the implementing procedures used for visual

inspection did not clearly state how the use of this procedure will manage cracking. The staff

requested that the applicant clarify how cracking will be managed.

In its response, the applicant stated that the procedure will be revised to clearly define the term

cracking and to provide further guidance. By letter dated August 31, 2007, the applicant

amended LRA Section B2.1.10 to add the following enhancement:

Enhancement 2. In the LRA amendment, the applicant credited an enhancement to the GALL

Report program element "detection of aging effects." Specifically, the enhancement stated:

Visual inspection procedures used for identification of stress corrosion cracking

(SCC) will be enhanced to define cracking, provide additional guidance for

detection of cracking and identify specific acceptance criteria relating to

"as-found" cracking.

The staff finds this enhancement acceptable because it provides information on how cracking is

defined and identified, and provides specific acceptance criteria for "as-found" cracking.

The staff reviewed those portions of the Closed-Cycle Cooling Water Program for which the

applicant claims consistency with GALL AMP XI.M21 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Closed-Cycle Cooling Water Program acceptable

because it conforms to the recommended AMP, with exceptions and enhancements described.

Operating Experience. LRA Section B2.1.10 states that the applicant has identified biological

activity and deposit build-up in the closed cycle cooling water systems. The LRA also states that

through-wall leakage was observed at welds in the closed cycle cooling water return line, and

rejectable linear indications were found in letdown heat exchanger discharge piping and in the

reactor coolant pump (RCP) closed cycle cooling water discharge piping. The cause was

identified as SCC. Based on the results of the UT examinations, repair plans were developed to

replace all welds with rejectable indications. Piping was replaced, as necessary, to facilitate

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fieldwork and to limit radiation exposure. Welds inside the heat exchanger room were not

inspected because of the dose rates. However, all these welds and piping were replaced.

The applicant contracted with various outside agencies to perform hardware failure analysis

and inspections. The staff also contracted an outside agency to perform further analysis. The

final reports from both organizations were provided to the staff and WCGS for their review. The

investigations performed by the applicant's contractor revealed no significant SCC in the

circumferential direction. However, small amounts (degree and instances) of SCC in the

longitudinal direction were found. The deterioration was limited to a few very small areas and

was characterized as intergranular attack. No cracking was observed in the analyses performed

by the staff's contractor.

The LRA states that, based on conclusions and recommendations of the various reports and

analyses of cracking in the closed cycle cooling water system piping, plant's corrective actions

included (1) adjustment of pH and molybdate to the higher levels in EPRI guidelines, (2)

monitoring of biological activities and adding biocides, (3) replacement and stress relief of

susceptible welds, and (4) revision of plant-specific UT inspection procedures to incorporate

EPRI recommendations. The staff concluded that, based on the applicant's information and the

work performed by the staff's contractor, WCGS has taken sufficient corrective action and no

additional action was needed.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Closed-Cycle Cooling Water System Program. The staff also

interviewed selected onsite personnel who have specialized knowledge of the program. The

staff reviewed instances previously documented by the applicant that identified issues with the

water chemistry and where the applicant had implemented corrective action.

The staff noted that outside agencies had performed an assessment of the applicant's

Closed-Cycle Cooling Water Program and the applicant has taken appropriate corrective

actions to modify the program to meet acceptable standards. The staff also verified that the

applicant has implemented appropriate and timely corrective actions for resolving age-related

degradation issues. The applicant is following the EPRI guidelines, which provide the limits on

contaminants and recommends an inspection program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section Al.10, the applicant provided the USAR supplement for the

Closed-Cycle Cooling Water System Program. The applicant committed (Commitment No. 3) to

develop a new periodic preventive maintenance activity to include inspections of internal

surfaces of valve bodies and accessible piping to detect loss of material and fouling. By letter

dated May 25, 2007, the applicant modified this commitment to specify that acceptance criteria

will be added to this preventive maintenance activity. By letter dated May 25, 2007, the

applicant committed (Commitment No. 32) to enhance the visual inspection procedures used

for SCC identification to define cracking, provide additional guidance for detection of cracking,

and identify specific acceptance criteria relating to "as-found" cracking. The staff reviewed this

section and determines that the information in the USAR supplement is an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its audit and review of the applicant's Closed-Cycle Cooling Water

System Program, the staff determines that those program elements for which the applicant

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the

exceptions and their justifications and determines that the AMP, with the exceptions, is

adequate to manage the aging effects for which it is credited. Also, the staff reviewed the

enhancements and confirms that their implementation prior to the period of extended operation

would make the existing AMP consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.10 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems

Summary of Technical Information in the Application. LRA Section B2.1.11 describes the

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program as consistent, with enhancements, with GALL AMP XI.M23, "Inspection of

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems."

The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program manages the loss of material and the effects of rail wear for all cranes, trolley

structural components, and applicable rails within the scope of license renewal. The program

periodically inspects components visually. Crane inspections verify structural integrity of the

crane components required to maintain the crane intended function. Visual inspections assess

such conditions as loss of material of structural members, misalignment, flaking, side wear of

rails, loose tie down bolts, and excessive wear or deformation of monorails.

Staff Evaluation. During its audit and review, the staff reviewed the applicant's claim of

consistency with the GALL Report. The staff reviewed the enhancements to determine whether

the AMP, with the enhancements, remains adequate to manage the aging effects for which it is

credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program, as listed in the audit summary, including the license renewal

program evaluation report in which the applicant assessed whether the program elements are

consistent with GALL AMP XI.M23.

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Enhancements. In the LRA, the applicant credited enhancements to the GALL Report program

elements "detection of aging effects" and "acceptance criteria." Specifically, the enhancements

stated that:

* Procedures will be enhanced to specifically inspect for loss of material

due to corrosion or rail wear.

* Procedures will be enhanced to identify industry standards or WCGS

Specifications that are applicable to the component.

The staff finds these enhancements acceptable because they will make the Overhead Heavy

Load and Light Load (Related to Refueling) Handling Systems Program consistent with

GALL AMP XI.M23, program elements 4 and 6, which state that crane rails are visually

inspected and that evaluation is performed according to applicable industry standards.

The staff reviewed those portions of the Overhead Heavy Load and Light Load (Related to

Refueling) Handling Systems Program for which the applicant claims consistency with GALL

AMP XI.M23 and finds that they are consistent with the GALL AMP. The staff finds the

applicant's Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

Program acceptable because it conforms to the recommended AMP, with the enhancements

described.

Operating Experience. LRA Section B2.1.11 states that corrosion has been detected on the

reactor vessel internals (RVI) lifting device. The corrosion from the lifting device flaked off and

fell into the reactor vessel during the upper and lower internals were removed and reinstalled.

The applicant stated that the lifting device was repainted and that its intended function was

never compromised. Additionally, the applicant stated that because cranes, hoists, and fuel

handling equipment have not been operated outside their design limits nor beyond their design

lifetime, no fatigue-related structural failures have occurred.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems Program. The staff also interviewed selected onsite personnel who have specialized

knowledge of the program. The staff reviewed selected instances previously documented by the

applicant that identified issues with the overhead heavy load and light load handling systems

and where the applicant had implemented corrective action.

The staff reviewed the operating experience provided in the LRA to confirm that the

plant-specific operating experience did not reveal degradation that is not bounded by industry

experience. The staff reviewed documents listed in the audit summary that describe the

deterioration RVI lifting device and the corrective action taken to ensure no further degradation

has taken place. The staff noted that the lifting device was painted and no additional corrosion

has developed, and that future inspections in accordance with the Overhead Heavy Load and

Light Load (Related to Refueling) Handling Systems Program will correct any corrosion

incidence during the period of extended operation.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

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USAR Supplement. In LRA Section A1.11, the applicant provided the USAR supplement for the

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

Program. The applicant committed (Commitment No. 4) to enhance and implement the

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems

Program prior to the period of extended operation. The applicant stated that procedures will be

enhanced to (1) identify industry standards or WCGS specifications that are applicable to the

component, and (2) specifically inspect for loss of material due to corrosion or rail wear. The

staff reviewed this section and determines that the information in the USAR supplement is an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff

determines that those program elements for which the applicant claimed consistency with the

GALL Report are consistent. Also, the staff reviewed the enhancements and confirms that its

implementation prior to the period of extended operation would make the existing AMP

consistent with the GALL AMP to which it was compared. The staff concludes that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this

AMP and concludes that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.11 Fire Protection

Summary of Technical Information in the Application. LRA Section B2.1.12 describes the

existing Fire Protection Program as consistent with GALL AMP XI.M26, "Fire Protection," with

exception and enhancements.

The Fire Protection Program manages loss of material for fire-rated doors, fire dampers, the

diesel-driven fire pump, and the Halon fire suppression system; cracking, spalling, and loss of

material for fire barrier walls, ceilings, and floors; and hardness and shrinkage due to

weathering of fire barrier penetration seals by periodic visual inspections of fire barrier

penetration seals, fire dampers, fire barrier walls, ceilings, and floors, and periodic visual

inspections and functional tests of fire-rated doors. Periodic testing of the diesel-driven fire

pump ensures no loss of function due to aging of diesel fuel supply lines. The program visually

inspects, at least once every 18 months, the fire barrier walls, ceilings, and floors, including

coating and wraps (structural steel fireproofing, raceway fire wrap, and hatch covers), for any

signs of aging like cracking, spalling, and loss of material. Approximately 10 percent of each

type (electrical and mechanical as practical) of penetration seal is inspected visually and there

are drop tests performed on approximately 10 percent of accessible horizontal and vertical fire

dampers at least every 18 months. Fire dampers inaccessible for drop testing are inspected

visually to assess integrity and availability. The fire damper inspection and drop test procedure

also visually inspects fire dampers with transfer grilles, with no or limited ductwork, on both

sides of safety-related fire barriers. The program visually inspects, at least annually, fire-rated

doors for the integrity of door surfaces and for clearances to detect aging. The diesel-driven fire

pump is under observation during performance tests for any aging of the fuel supply line. Visual

inspections and function tests of the Halon fire suppression system are every 18 months.

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Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception and enhancements to determine whether the

AMP, with the exception and enhancements, remains adequate to manage the aging effects for

which it is credited.

The staff interviewed the applicant's technical staff and reviewed documents related to the Fire

Protection Program, as listed in the audit summary, including the license renewal program

evaluation report in which the applicant assessed whether the program elements are consistent

with GALL AMP XI.M26.

In LRA Section B2.1.12, the applicant stated that 10 percent of each type of electrical and

mechanical penetration seal is visually inspected at least once every 18 months. The staff

requested that the applicant clarify whether the 10 percent population of penetration seals

includes all types of seals (e.g., cables trays, conduits, pipes, ducts, and seismic gaps).

In its response, the applicant stated that the fire barrier penetration seals inspection procedure

visually inspects approximately 10 percent of electrical and mechanical penetration seals and

that the fire barrier inspection procedure performs a visual inspection of the exposed surface of

each fire-rated assembly (i.e., fire barriers separating redundant post-fire safe-shutdown

systems) for the presence of breaches and gross deterioration. The fire-rated assembly

inspections include items like seismic gap seals, cable tray fire stops, and steel pipe caps.

The staff reviewed each of these procedures and confirmed that inspections are performed on

10 percent of all fire barrier penetration seals and fire barriers at least once every 18 months.

On the basis of its review, the staff finds the applicant's response acceptable because it is

consistent with the recommendations in the GALL Report.

The GALL Report "detection of aging effects" program element recommends a visual inspection

of the Halon system to detect any sign of degradation such as corrosion, mechanical damage,

or damage to dampers. The "acceptance criteria" program element recommends that signs of

corrosion and mechanical damage should not be acceptable. The applicant's license renewal

program evaluation report for the Fire Protection Program states that a functional deluge test is

performed on the Halon system to identify any mechanical damage and referenced WCGS

surveillance procedures.

The staff's review of these procedures noted that the procedures did not address visual

inspection nor provide acceptance criteria for corrosion or mechanical damage. The staff

requested that the applicant clarify how it meets this GALL Report recommendation and if not,

to justify why an exception to the GALL Report is not taken.

In its response, the applicant stated that the Halon system has the internal environments of

plant indoor air and dry gas. The Halon system galvanized carbon steel and copper alloy

materials have an internal environment of plant indoor air. The following are the Halon system

materials, such that, the system has an internal environment of dry gas: bronze, carbon steel,

galvanized carbon steel, cast iron, elastomer, copper alloy, and stainless steel. These material

and environment combinations do not require aging management. The applicant further stated

that carbon steel and cast iron materials in the Halon system are exposed to an external

environment of plant indoor air and will be visually inspected with the External Surfaces

Monitoring Program.

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The staff evaluated the material and environment combination and reviewed the GALL Report

for the same material and environment combination. The staff finds that these material and

environment combinations do not have aging effects and do not require aging management. On

the basis of its review, the staff finds the applicant's response acceptable. The staff concludes

that visual inspections are not needed.

The GALL Report "acceptance criteria" program element recommends that no corrosion should

be acceptable in the fuel oil supply line for the diesel-driven fire pump. In the LRA

Section B.2.1.12, the applicant stated that performance testing in the diesel-driven fire pump is

used to detect degradation and corrosion in the fuel supply lines. The staff requested that the

applicant explain how the performance test will detect corrosion.

In its response, the applicant stated that the diesel-driven fire pump fuel oil supply line has an

internal environment of fuel oil and is made of carbon steel. The applicant clarified that the

GALL Report references item VII.G-21 for this component's configuration. This item

recommends the use of fire protection and fuel oil chemistry programs. The GALL Report fuel

oil chemistry program credits a one-time inspection to verify its effectiveness. The applicant

stated that the LRA will be amended to take this into consideration.

In its letter dated August 31, 2007, the applicant amended the LRA Section B2.1.12 to state:

The Fire Protection Program manages loss of material for fire rated doors, fire

dampers, diesel-driven fire pump, and the halon fire suppression system,

cracking, spalling, and loss of material for fire barrier walls, ceilings, and floors,

and hardness and shrinkage due to weathering of fire barrier penetration seals;

and hardness-loss of strength for halon fire suppression system flexible hoses.

Periodic visual inspections of fire barrier penetration seals, fire dampers, fire

barrier walls, ceilings and floors, and periodic visual inspections and functional

tests of fire-rated doors are performed. The internal surface of the diesel-driven

fire pump fuel oil supply line is managed by the Fuel Oil Chemistry Program

([LRA Section] B1.14), which utilizes the One-Time Inspection Program ([LRA

Section] B13.16) to verify the effectiveness of the Fuel Oil Chemistry Program

using a representative sample of components in systems that contain fuel oil,

ensuring that there is no loss of function due to aging of the fuel oil supply line.

The Fire Protection Program performs a visual inspection, at least once per year,

on firerated doors to verify the integrity of door surfaces and for clearances to

detect aging of the fire doors. The internal surface of the diesel-driven fire pump

fuel oil supply line is managed by the Fuel Oil Chemistry program ([LRA section]

B1.14), which utilizes the One-Time Inspection program ([LRA section] B1.16) to

verify the effectiveness of the Fuel Oil Chemistry program using a representative

sample of components in systems that contain fuel oil, ensuring that there is no

loss of function due to aging of the fuel oil supply line. A visual inspection and

function test of the halon fire suppression system is performed every 18 months.

On the basis that the applicant has amended the application to include the programs that are

credited for performing inspection of the diesel-driven fire pump fuel oil supply line, the staff

finds the applicant's response acceptable.

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Exception. In the LRA, the applicant credited an exception to the GALL Report program

elements "parameters monitored or inspected" and "detection of aging effects." Specifically, the

exception stated:

WCGS performs visual inspections and function tests of the Halon system every

18 months, not every 6 months as suggested by NUREG-1 801, Section XI.M26.

The 18 month inspection frequency is specified in the WCGS fire protection

program, which is referenced in the USAR, and was part of the original licensing

basis until the fire protection requirements were removed from the Technical

Specifications and placed in plant procedures.

The 18-month Halon fire suppression functional test frequency is part of the plant's CLB and

the review of WCGS operating experience indicated that this frequency is reasonable to

manage the aging effects. The 18-month frequency is considered sufficient to ensure system

availability and operability based on plant operating history showing that there has been no

aging-related event that has adversely affected system operation. Because these aging effects

occur over a considerable period of time, the staff concludes that the 18-month inspection

interval will be sufficient to detect aging in the Halon fire suppression system. The staff

reviewed the USAR supplement and confirmed it references these frequencies.

In addition, the staff noted that the applicant currently performs Halon fire suppression system

valve position checks and operational tests every 92 days and Halon fire suppression system

storage tank level and pressure checks every month. Maintenance procedures at WCGS also

include visual inspections of component external surfaces for signs of corrosion and mechanical

damage. The applicant's review of station operating experience identified no aging-related

degradation adversely affecting the operation of the Halon fire suppression system.

On the basis of the plant's operating history and that this inspection frequency is part of the

applicant's CLB, the staff finds the exception acceptable.

Enhancement 1. In the LRA Section B2.1.12, the applicant credited an enhancement to the

GALL Report program elements "scope of the program," "parameters monitored or inspected,"

"detection of aging effects," "monitoring and trending," and "acceptance criteria." Specifically,

the enhancement stated:

Fire damper inspection and drop test procedures will be enhanced to inspect

damper housing for signs of corrosion.

Fire barrier and fire door inspection procedures will be enhanced to specify fire

barriers and doors described in USAR Appendix 9.5A, "WCGS Fire Protection

Comparison to APCSB 9.5-1 Appendix A," and WCGS Fire Hazards Analysis.

Training for technicians performing the fire door and fire damper visual

inspections will be enhanced to include fire protection inspection requirements

and training documentation.

On the basis that the enhancements, when implemented, will make the Fire Protection Program

consistent with the GALL Report, the staff finds the enhancements acceptable.

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During the audit, the applicant added the Halon system flexible hoses within the scope of the

Fire Protection Program. The applicant stated that the Fire Protection Program will be

enhanced to include visual inspection of these hoses.

By letter dated August 31, 2007, the applicant amended LRA Section B2.1.12 to add the

following enhancement to the Fire Protection Program.

Enhancement 2. In the LRA Section B2.1.12 amendment, the applicant credited an

enhancement to the GALL Report program elements "parameters monitored or inspected" and

"detection of aging effects." Specifically, the enhancement stated:

Prior to the period of extended operation, halon fire suppression system

inspection procedures will be enhanced to include visual inspections of halon

tank flexible hoses for hardening-loss of strength. Visual inspections would not

be required for flexible hoses that have scheduled periodic replacement

intervals.

The staff noted that Halon tank weight and pressure check surveillance tests are performed

every 18 months. These tests provide opportunities for visual inspection of the Halon tank

flexible hoses. The staff determines that the enhancement, when implemented, will make the

Fire Protection Program consistent with the GALL Report; therefore, the staff finds the

enhancement acceptable.

The staff reviewed those portions of the Fire Protection Program for which the applicant claims

consistency with GALL AMP XI.M26 and finds that they are consistent with the GALL AMP. The

staff finds the applicant's Fire Protection Program acceptable because it conforms to the

recommended AMP, with the exception and enhancements described.

Operating Experience. LRA Section B2.1.12 states that fire barrier penetration seals have been

found with degradation during inspections that determined that it had existed since original

construction. The applicant determined that the procedure version for the inspection provided

no detailed location of seismic gap. The procedure was revised and seismic gap seals were

inspected using the revised procedure. The LRA states that the fire barrier inspection found

wear of door hinges and handles, and several penetration seals required field action to maintain

a fire barrier configuration. Appropriate corrective actions have been implemented.

The applicant's Fire Protection Program self-assessment examined penetration seals for

installation compliance with approved installation details and bounding test parameters. The

self-assessment found and evaluated unbounded penetration seal conditions acceptance

and/or functionality. The applicant stated that all penetrations found with unbounded seal

conditions have been repaired or evaluated in accordance with Generic Letter 86-10

"Implementation of Fire Protection Requirements," and that no further action is required.

During the audit, the staff reviewed implementing procedures and problem identification reports,

as listed in the audit summary, related to the applicant's Fire Protection Program. The staff also

interviewed selected onsite personnel who have specialized knowledge of the program. The

staff reviewed instances previously documented by the applicant that identified issues with the

Fire Protection Program and where the applicant had implemented corrective action. The staff

noted that the applicant's corrective actions were timely and appropriate.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.12, the applicant provided the USAR supplement for the

Fire Protection Program. By letter dated August 31, 2007, the applicant amended the first

paragraph of LRA Section Al.12 to state:

The Fire Protection Program manages loss of material for fire rated doors, fire

dampers, diesel-driven fire pump, and the Halon fire suppression system,

cracking, spalling, and loss of material for fire barrier walls, ceilings, and floors,

and hardness and shrinkage due to weathering of fire barrier penetration seals;

and hardness-loss of strength of for halon fire suppression system flexible hoses

Periodic visual inspections of fire barrier penetration seals, fire dampers, fire

barrier walls, ceilings and floors, and periodic visual inspections and functional

tests of fire-rated doors are performed. The internal surface of the diesel-driven

fire pump fuel oil supply line is managed by the Fuel Oil Chemistry program

([LRA Section] Al.14), which utilizes the One-Time Inspection program (AI.16) to

verify the effectiveness of the Fuel Oil Chemistry Program using a representative

sample of components in systems that contain fuel oil, ensuring that there is no

loss of function due to aging of diesel fuel oil supply line.

The letter also added a paragraph that states:

Prior to the period of extended operation, Halon fire suppression system

inspection procedures will be enhanced to include visual inspections of halon

tank flexible hoses for hardening-loss of strength. Visual inspections would not

be required for flexible hoses that have scheduled periodic replacement

intervals.

In addition, the applicant committed (Commitment No. 5) to enhance its fire damper inspection

and drop test procedures to specify that damper housings should be inspected for signs of

corrosion and to specify the fire barriers and doors described in USAR, Appendix 9.5A, and the

WCGS fire hazards analysis. The applicant also committed to enhance training for the

technicians performing the fire door and fire damper visual inspections to include inspection

requirements and training documentation. In its letter dated October 11, 2007, the applicant

revised Commitment No. 5 to state that the Halon fire suppression system inspection

procedures will be enhanced to include visual inspection of Halon tank flexible hoses (that do

not have scheduled periodic replacement intervals) for hardening or loss of strength.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Fire Protection Program, the

staff determines that those program elements for which the applicant claimed consistency with

the GALL Report are consistent. In addition, the staff reviewed the exception and its

justifications and determines that the AMP, with the exception, is adequate to manage the

aging effects for which it is credited. Also, the staff reviewed the enhancements and confirms

that their implementation prior to the period of extended operation would make the existing

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AMP consistent with the GALL AMP to which it was compared. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.12 Fire Water System

Summary of Technical Information in the Application. LRA Section B2.1.13 describes the

existing Fire Water System Program as consistent, with exceptions, with GALL AMP XI.M27,

"Fire Water System."

The Fire Water System Program manages loss of material for water-based fire protection

systems. Periodic hydrant inspections, fire main flushing, sprinkler inspections, and flow tests

are in accordance with applicable National Fire Protection Association (NFPA) codes and

standards. Nuclear Electric Insurance Limited performance-based guidance is for fire protection

system inspection, testing, and maintenance intervals. The fire water system discharge

pressure is monitored continuously to detect loss of system pressure immediately and initiate

corrective actions. The Fire Water System Program conducts an air or water flow test through

each open head spray or sprinkler head for unobstructed nozzles. The program tests a

representative sample of fire protection sprinkler heads and replaces those in service 50 years

with the guidance of NFPA Code 25, 2002 Edition, and tests at 10-year intervals thereafter

during the period of extended operation to promptly detect signs of aging.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Fire Water System Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.M27.

The applicant's license renewal program evaluation report references the Internal Surfaces in

Miscellaneous Piping and Ducting Components Program to perform visual inspection of fire

water system piping and components. The staff requested that the applicant describe how the

Internal Surfaces in Miscellaneous Piping and Ducting Components Program evaluates wall

thickness, as recommended by the GALL Report.

In its response, the applicant stated that visual inspections performed by the Inspection of

Internal Surfaces in Miscellaneous Piping and Ducting Components Program would detect wall

thinning by identifying corrosion, surface or finish discontinuities, or a lack of symmetry of the

component dimensions. If degradation is unacceptable, deficiencies would be resolved with the

plant's corrective action program. The corrective action program may then specify mechanical

or NDE methods to be used in quantifying the degradation consistent with QCP 20-518, "Visual

Examination of Heat Exchangers and Piping Components" or other approved plant procedures.

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The staff reviewed instances previously documented by the applicant that identified issues with

the Fire Water System Program and where the applicant had implemented corrective action.

The staff noted that the applicant's corrective actions were timely and appropriate.

On the basis that the visual inspections are performed, unacceptable degradation is identified in

the corrective action program, and further action is taken to quantify the degradation by

mechanical or NDE methods, the staff finds the response acceptable.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

element "detection of aging effects." Specifically, the exception stated:

NUREG-1 801 specifies annual hydrant hose hydrostatic tests. WCGS performs

a hydrostatic test of its power block fire hoses every three years. WCGS may

replace an existing fire hose with a new fire hose every five years in lieu of

performing a hydrostatic test.

NUREG-1801 specifies annual gasket inspections. WCGS performs gasket inspections

at least once every 18 months. Since aging effects are typically manifested over several

years, differences in inspection and testing frequencies are insignificant.

During the audit, the staff requested that the applicant justify and provide a basis for this 3-year

frequency. The staff also requested that the applicant clarify if hydrostatic test frequency of

hoses once every three years is documented in the Fire Protection Program and in

commitments to 10 CFR 50.48 using the Branch Technical Position (BTP), Auxiliary and Power

Conversion Systems Branch (APCSB) 9.5 1, "Guidelines for Fire Protection for Nuclear Power

Plants," dated May 1, 1976, and BTP APCSB 9.5 1, Appendix A, dated August 23, 1976.

In its response, the applicant stated that USAR Table 9.5E-1, Section Ill.E, "WCGS Fire

Protection Comparison to 10 CFR 50 Appendix R," states that interior standpipe hose is tested

every three years or the fire hose is replaced every five years. The applicant clarified that

hydrostatic testing of fire hoses is not discussed in BTP APCSB 9.5-1 or in its Appendix A. The

basis for testing or replacement of interior fire hose is obtained from NFPA, "Inspection, Care,

and Use of Fire Hose Couplings and Testing of Fire Hose," dated 1962. Specifically, NFPA

Section 4.3.2 requires that hydrotesting be performed five years after the manufacture date and

every three years thereafter. WCGS addresses this requirement by replacing the hose every

five years because it is more economical than the manpower cost associated with performing

the hydrotesting.

The staff finds that the 3-year hydrostatic test frequency is part of the plant's CLB. The staff's

review of plant operating experience indicated that this frequency is reasonable to manage the

aging effects. Based on plant operating history which shows that there has been no

aging-related event that adversely affected system operation, the staff finds that the 3-year

frequency is sufficient to ensure system availability and operability. Because these aging effects

occur over a considerable period of time, the staff concludes that the 3-year inspection interval

will be sufficient to detect aging in the fire hydrant hoses. The staff reviewed the information

provided in the USAR and finds that it established the plant's CLB. On the basis of its review,

the staff finds the exception to hydrotest the fire hydrant hose every three years or replace them

every five years acceptable.

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Also, the staff reviewed the exception to inspect the gaskets every 18 months in lieu of

annually, and determines that, since aging effects are manifested over several years, an

additional six months in inspection frequency is insignificant. On this basis, the staff finds the

exception acceptable.

The staff reviewed those portions of the Fire Water System Program for which the applicant

claims consistency with GALL AMP XI.M27 and finds that they are consistent with the GALL

AMP. The staff finds the applicant's Fire Water System Program acceptable because it

conforms to the recommended AMP, with the exception described.

Operating Experience. LRA Section B2.1.13 states that fire hydrants have been found with

valves that could not be opened, with excessive leakage, and with foreign material that was

flushed out after work requests initiated repair or replacement activities. In 1987, corrosion was

found on carbon steel piping directly connected to ductile iron piping. Since then, an additional

leak was discovered in the fire protection system outside the DG building. Subsequent

excavation discovered loss of material due to pitting corrosion. The applicant determined that

the fire protection system corrosion was from a break in the protective coating. Three localized

areas of through-wall corrosion have been detected on the fire protection piping for the unit

auxiliary transformer. The applicant evaluated this condition, determined that the system still

could perform its intended function, but replaced this portion of the pipe. The fire protection

sprinkler headers surrounding transformers were found corroded at the unions and threaded

connections. The applicant stated that repair or replacement was initiated and the threaded

surfaces of the sprinkler heads were cleaned and painted before the loss of intended function.

The LRA states that Asiatic clams were discovered in the fire protection system in 1996. The

system was flushed to force them out of the system. As a corrective action a chemical injection

system was installed near the jockey pump for biocide treatment of the fire protection water.

Since the installation of this chemical injection system there have been no indications of clams

in the fire protection system. The applicant completed its first C-factor test in 2004. The system

pressure differentials met the acceptance criteria.

During the audit the staff reviewed implementing procedures and problem identification reports

related to the applicant's Fire Water System Program. The staff also interviewed selected

onsite personnel who have specialized knowledge of the program. The staff reviewed instances

previously documented by the applicant that identified issues with the Fire Protection Program

and where the applicant had implemented corrective action. The staff noted that the applicant's

corrective actions were timely and appropriate.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section Al.13, the applicant provided the USAR supplement for the

Fire Water System Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Fire Water System Program,

the staff determines that those program elements for which the applicant claimed consistency

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with the GALL Report are consistent. In addition, the staff reviewed the exception and its

justifications and determines that the AMP, with the exception, is adequate to manage the

aging effects for which it is credited. The staff concludes that the applicant has demonstrated

that the effects of aging will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.13 Fuel Oil Chemistry

Summary of Technical Information in the Application. LRA Section B2.1.14 describes the

existing Fuel Oil Chemistry Program as consistent, with exceptions and enhancements, with

GALL AMP XI.M30, "Fuel Oil Chemistry."

The Fuel Oil Chemistry Program manages loss of material on internal component surfaces in

the emergency diesel fuel oil storage and transfer system and diesel fire pump fuel oil system.

The program includes (a) surveillance and monitoring procedures for fuel oil quality

maintenance by control of contaminants in accordance with applicable ASTM Standards, (b)

periodic drainage of water from fuel oil tanks, (c) visual inspection of internal surfaces during

periodic draining and cleaning, (d) ultrasonic measurement of emergency fuel oil storage tank

wall thickness if indications of reduced cross-sectional thickness are found during the visual

inspection, (e) inspection of new fuel oil before its introduction into the storage tanks, and (f)

one-time inspections by the One-Time Inspection Program of a representative sample of

components in systems that contain fuel oil.

Fuel oil quality is maintained by monitoring and controlling fuel oil contaminants in accordance

with applicable ASTM standards by periodic sampling and chemical analysis of the fuel oil

inventory and sampling, testing, and analysis of new fuel oil prior to delivery at the plant. If a

sample appears to be unsatisfactory, delivery is discontinued or not allowed. All samples are

taken in accordance with ASTM D4057 and shipped to a laboratory approved under the

applicant's QA program for analysis. Accumulated water is removed monthly from the

emergency fuel oil storage and emergency fuel oil day tanks and quarterly from the diesel fire

pump fuel tank. The internal surfaces of the emergency fuel oil storage tanks are drained,

cleaned, and visually inspected periodically for potential aging. The emergency fuel oil day

tanks are also drained, cleaned, and visually inspected at the same time as the emergency fuel

oil storage tanks. The diesel fire pump fuel tank does not have interior accessibility for cleaning.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exceptions and enhancements to determine whether the

AMP, with the exceptions and enhancements, remains adequate to manage the aging effects

for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Fuel Oil Chemistry Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.M30.

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During the audit, the staff identified a difference between the Fuel Oil Chemistry Program and

the GALL Report "preventive actions" program element. The Fuel Oil Chemistry Program does

not provide for the periodic cleaning and inspection of the diesel fire pump fuel tank, whereas

the GALL Report specifies these actions. Specifically, the Fuel Oil Chemistry Program states:

The diesel fire pump fuel tank does not have interior accessibility for cleaning.

Due to the fuel oil day tanks and diesel fire pump fuel tanks periodic sampling

and testing for water and sediment, and having no history in the last ten years of

having more than trace amounts of water found during sampling, no ultrasonic

thickness measurements will be performed on these tanks.

The staff noted that since water and particulate contamination and corrosion has been detected

in WCGS fuel oil tanks, there is the potential that microbiologically influenced corrosion (MIC),

pitting, and general corrosion might be present in the diesel fire pump fuel tank. Degradation

could be progressing through the tank wall undetected since cleaning and visual inspection

have not been performed for the diesel fire pump fuel tank. The staff noted that an alternative

method will not be employed to detect wall thinning, and that biocides and/or corrosion

inhibitors have not been used to mitigate corrosion. The applicant indicated that operating

experience for the other fuel oil tanks justifies not having to implement preventive actions.

The staff requested that the applicant provides additional information to justify not having to

implement preventive actions, such as cleaning and visually inspecting the diesel fire pump fuel

tank on a periodic basis, if alternate inspection methods such as UT are not employed. The

staff also requested that the applicant explain why this is not an exception to the GALL Report.

In its response, the applicant stated that the diesel fuel oil tanks internal material and

environment are similar to the emergency fuel oil day tanks. Periodic sampling and testing for

water and sediment, performed during the past 10 years, has demonstrated that neither tank

showed water and sediment levels exceeding the normal chemistry of 0.05 percent. This

demonstrates that both tanks have the same material and internal environment.

The applicant stated that periodic sampling, cleaning, and visual inspection of the emergency

fuel oil day tanks will act as a representative sample and will ensure that significant aging is not

occurring in other fuel oil day tanks. The emergency fuel oil tanks inspection results will be of

value in assessing the condition of the diesel fire pump fuel oil tanks since these tanks have

similar internal materials and environments. Any adverse condition found in the inspected

emergency fuel oil day tanks will be assumed to be occurring in the fuel oil day tanks and diesel

fire pump fuel tanks, and preventive actions will be taken in accordance with the plant's

corrective action program. In its response, the applicant committed (Commitment No. 6) to

perform a one-time UT or pulsed eddy current thickness examination on the external surface of

the diesel fire pump fuel oil tank.

Exception 1. In the LRA, the applicant credited an exception to the GALL Report program

element "preventive actions." Specifically, the exception stated that:

WCGS does not add fuel oil stabilizers, corrosion inhibitors, or biocides; it relies

on the periodic sampling and analysis for particulates and corrosion products.

Any accumulated water is removed monthly from the emergency fuel oil storage

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and emergency fuel oil day tanks and quarterly from the diesel fire pump fuel

tank.

The applicant stated that degradation of the diesel fuel oil tanks cannot occur without exposure

of the tank internal surfaces to contaminants in the fuel oil, such as water and microbiological

organisms. Compliance with diesel fuel oil standards and periodic multi-level sampling provide

assurance that fuel oil contaminants are below the acceptable levels. Internal surfaces of tanks

(except the diesel fire pump fuel tank) are drained, cleaned, and visually inspected to detect

potential degradation. Water and biological activity or particulate contamination concentrations

are monitored and trended at least quarterly.

The applicant stated that based on industry operating experience, quarterly sampling and

analysis of fuel oil provide for timely detection of conditions conducive to corrosion before the

loss of the tank's intended function. If indications of degradation are found in the future,

additions of corrosion inhibitors and biocides will be considered as part of the corrective action

process, similar to the case when corrosion was found in the emergency fuel oil storage tanks.

On the basis of its review, the staff finds that this exception to the GALL Report is acceptable

because sampling for particulate and water contamination and periodic tank dewatering will

provide an environment that is not conducive to corrosion.

Exception 2. In the LRA, the applicant credited an exception to the GALL Report program

elements "parameters monitored or inspected" and "acceptance criteria." Specifically, the

exception stated that:

WCGS uses only ASTM Standard D1 796-83, not D1 796 and D2709. Wolf

Creek's Tech Spec is committed to using only D1 796-83. The testing conducted

using ASTM D1796 gives quantitative results, whereas D2709 testing gives only

pass-fail results; therefore, the D1796 method gives more descriptive information

about the fuel oil condition than the D2709 method.

The staff reviewed ASTM D 2709 and D 1796 to determine if both standards are necessary to

assure fuel oil quality. The staff noted that both standard test methods use a centrifuge method

to determine water and sediment contents using a 100 ml sample. The staff determines that

using only ASTM D 1796 is adequate to quantitatively determine water and sediment contents

in fuel oil. Additionally, the staff noted that the applicant adheres to the plant's technical

specifications, as recommended in the GALL Report. On this basis, the staff finds that this

exception to the GALL Report is acceptable.

Exception 3. In the LRA, the applicant credited an exception to the GALL Report program

element "acceptance criteria." Specifically, the exception stated that:

WCGS uses the guidance of D 2276, Method A, for determination of

particulates, as opposed to the combination of D 2276 and D 6217. ASTM

D6217 states that it is the first ASTM standard test method for assessing the

mass quantity of particulates in middle distillate fuels. Test Method D5452 and its

predecessor, Test Method D2276, were developed for aviation fuels and used 1

gallon or 5 Liters of fuel sample. Using greater than or equal to 1 gallon of

middle distillate fuel often requires significant time to complete the filtration. The

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D6217 test method uses about a quarter of the volume in the D2276 aviation fuel

method. There is no indication that ASTM D6217 is either technically superior to

D2276, as far as managing the effects of aging (it merely allows for faster

filtration), or that the combination of the two standards adds any value beyond

using just D2276 itself.

The staff reviewed ASTM D 2276 and D 6217. The staff noted that using ASTM D 2276,

Method A, alone is adequate to quantitatively determine particulate content in fuel oil.

Additionally, the staff noted that the applicant adheres to the plant's technical specifications as

recommended in the GALL Report.

During the audit, the staff reviewed ASTM D 2276-00 and could not find the acceptance criteria

in this standard test method. The staff requested that the applicant clarify what is the source for

its acceptance criteria.

In its response, the applicant indicated that there are acceptance criteria in the plant's chemistry

specification manual. After review of this manual, the staff finds the acceptance criteria and the

basis for the criteria are in accordance with the plant's technical specifications requirements as

recommended by the GALL Report. On this basis, the staff finds that this exception to the GALL

Report is acceptable.

By letter dated August 31, 2007, the applicant amended LRA Section B2.1.14 to include the

following exception.

Exception 4. In the LRA amendment, the applicant credited an exception to the GALL Report

program element "detection of aging effects." Specifically, the exception stated that:

The diesel fire pump fuel oil tank does not have interior accessibility for cleaning.

Periodic sampling and testing for water and sediment has demonstrated that

neither the emergency fuel oil day tanks or the diesel fire pump fuel oil tank have

any history, within the last ten years, of water or sediment exceeding the normal

chemistry level. Periodic sampling, cleaning, and visual inspection of the

emergency fuel oil day tanks will act as a representative sample and ensure that

significant aging is not occurring in the diesel fire pump fuel oil tanks. A one-time

ultrasonic (UT) or pulsed eddy current (PEC) thickness examination on the

external surface of the diesel fire pump fuel oil tank will be performed to detect

corrosion related wall-thinning.

The staff determines that there is an equivalency between the emergency fuel oil day tanks and

the diesel fire pump oil tanks based on materials of construction, periodic sampling for water

and particulate contamination, sediment levels, and operating experience. This equivalency

ensures wall thinning in the diesel fire pump fuel tank will be managed during the period of

extended operation because any degradation found in the emergency fuel oil day tanks will

trigger preventive actions through the plant's corrective action program.

The staff also noted that a one-time inspection of the diesel fire pump fuel tank bottom

performed before entering the period of extended operation, will confirm that there is no

age-related degradation. On this basis, the staff finds this exception to the GALL Report

acceptable.

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Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program elements "preventive actions" and "detection of aging effects." Specifically, the

enhancement stated:

Procedures will be enhanced to provide for supplemental ultrasonic thickness

measurements if there are indications of reduced cross-sectional thickness

found during the visual inspection of the emergency fuel oil storage tanks. The

emergency fuel oil day tanks will be added to the 10-year drain, clean, and

internal inspection program.

The applicant stated that the emergency fuel oil day tanks will be added to the 10-year drain,

clean, and internal inspection program. Cleaning and visual inspection of the emergency fuel oil

day tanks will (1) provide assurance that these tank are not subject to loss of material and

indicators of corrosion for the diesel fire pump fuel tank, and (2) implement the

recommendations of the GALL Report providing additional assurance that the effects of aging

for the emergency fuel oil day tanks will be adequately managed.

The staff noted that corrosion may occur at locations where contaminants accumulate, such as

a tank bottom, and ultrasonic thickness measurements in areas where corrosion is visually

detected ensure that significant wall thinning is not occurring. The applicant stated that it will

perform supplemental ultrasonic thickness measurements in areas where corrosion is

discovered to characterize the extent of wall thinning. The wall thinning trend will be used by the

applicant in the engineering disposition of any detected corrosion.

On this basis, the staff finds this enhancement acceptable since, when implemented, the Fuel

Oil Chemistry Program will be consistent with the GALL Report and will provide additional

assurance that the effects of aging for the emergency fuel oil day tanks will be adequately

managed.

By letter dated August 31, 2007, the amended LRA Section B2.1.14 to add the following

enhancement.

Enhancement 2. In the LRA amendment, the applicant credited an enhancement to the GALL

Report program elements "detection of aging effects." Specifically, the enhancement stated:

A one-time ultrasonic (UT) or pulsed eddy current (PEC) thickness examination

on the external surface of the diesel fire pump fuel oil tank will be performed to

detect corrosion related wall-thinning. The examination will be performed once

between 10 and 2 years prior to the period of extended operation.

The staff finds this enhancement acceptable since, when the enhancement is implemented, the

Fuel Oil Chemistry Program will be consistent with the GALL Report and will provide additional

assurance that the effects of aging for the diesel fire pump fuel oil tank will be adequately

managed.

The staff reviewed those portions of the Fuel Oil Chemistry Program for which the applicant

claims consistency with GALL AMP XI.M30 and finds that they are consistent with the GALL

AMP. The staff finds the applicant's Fuel Oil Chemistry Program acceptable because it

conforms to the recommended AMP, with the exceptions and enhancements described.

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Operating Experience. LRA Section B2.1.14 states that plant-specific operating experience

indicates that both emergency fuel oil storage tanks have experienced high particulate counts.

The fuel oil tanks are checked regularly for the presence of water and sediment and the

emergency fuel oil storage tanks for particulates; any instances are corrected promptly. Neither

the fuel oil day tanks nor the diesel fire pump fuel tanks have any history of water and sediment

levels exceeding the normal chemistry level.

The LRA states that the internals of the emergency fuel oil storage tanks were visually

inspected in 2002. This inspection revealed deterioration of the interior coating of one of the

emergency fuel oil storage tanks and rust on the interior walls. An engineering evaluation

determined that the failure of the interior coating should not cause failure of the diesel system to

perform its intended functions and that the rust found during this inspection was acceptable as

it was and not at a stage that cause component failure. The applicant stated that future

inspections will document any deteriorated conditions in corrective actions. After the discovery

of the condition of the emergency fuel oil storage tank interior coating, biocide was added to

that tank and all of the diesel fuel oil in the emergency fuel oil storage tanks was replaced with

new fuel oil. Since that discovery, one of the emergency fuel oil day tanks has been visually

inspected with no coating degradation found. The other fuel oil day tank was scheduled to be

visually inspected by the end of 2006.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to confirm that the plant-specific operating experience did not reveal

degradation that is not bounded by industry experience. The staff reviewed documents listed in

the audit summary that describe the deterioration of the interior coating with associated

corrosion of the steel tank wall and the corrective action taken to ensure no further degradation

has taken place. Since the Fuel Oil Chemistry Program operating experience shows that

corrosion has been discovered in the emergency fuel oil storage tank, the staff requested that

the applicant provides the frequency at which UT is performed when degradation is discovered

in the diesel fuel tanks.

In its response, the applicant stated that UT inspections are only required if indications of

reduced cross sectional thickness is found. The frequency at which UT is performed on the

emergency fuel oil tanks has not been determined because a degradation requiring UT has not

been found. A visual inspection in 2002 revealed that the interior coating of one of the

emergency fuel oil storage tanks was deteriorated and some rust had developed in the interior

walls of the tank. The applicant stated that an engineering evaluation determined that the failure

of the interior coating of the emergency fuel oil storage tank should not result in degradation or

failure of the diesel system to perform its intended functions. The applicant also determined that

the rust identified during this inspection was an acceptable condition because it is not at a stage

that could result in a failure to perform its intended function. The applicant stated that any

degraded conditions in future inspections will be documented in a non-conformance work order.

The applicant stated that upon the discovery of the condition of the emergency fuel oil storage

tank interior coating, a biocide was added to that tank and all of the diesel fuel in the

emergency fuel oil storage tanks was subsequently replaced with new fuel. Since the discovery

of the condition of the emergency fuel oil storage tank interior coating, one of the emergency

fuel oil day tanks has been visually inspected, and no coating degradation was found. In 2006,

both day tanks were inspected and no debris or degradation of the coatings was found.

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The staff reviewed the applicant's response and finds this response acceptable because

additional corrosion in fuel oil tanks has not been discovered, corrective action has been taken

through biocide additions and oil replacement, and future visual inspections of the emergency

fuel storage tanks will identify any progression of corrosion that will initiate UT inspection of the

degraded area.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10. Therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.14, the applicant provided the USAR supplement for the

Fuel Oil Chemistry Program. The applicant committed (Commitment No. 6) to enhance and

implement the Fuel Oil Chemistry Program and to provide supplemental ultrasonic thickness

measurements if there are indications of reduced cross-sectional thickness found during the

visual inspection of the emergency fuel oil storage tanks. By letter dated May 25, 2007, the

applicant revised this commitment to (1) include the emergency fuel oil day tanks to the 10-year

drain and internal inspection program, and (2) include a one-time UT or pulsed eddy current

thickness examination on the external surface of the engine-driven fire pump fuel oil tank to

detect corrosion related wall thinning. By letter dated August 31, 2007, the applicant amended

LRA Section Al.14 to incorporate the changes made to Commitment No. 6. The staff reviewed

this section and determines that the information in the USAR supplement is an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Fuel Oil Chemistry Program,

the staff determines that those program elements for which the applicant claimed consistency

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and its

justifications and determines that the AMP, with the exceptions, is adequate to manage the

aging effects for which it is credited. Also, the staff reviewed the enhancements and confirms

that its implementation prior to the period of extended operation would make the existing

AMP consistent with the GALL AMP to which it was compared. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.14 Selective Leaching of Materials

Summary of Technical Information in the Application. LRA Section B2.1.17 describes the new

Selective Leaching of Materials Program as consistent, with an exception, with GALL

AMP XI.M33, "Selective Leaching of Materials."

The Selective Leaching of Materials Program manages loss of material due to selective

leaching for brass (greater than 15 percent zinc) and gray cast iron components within the

scope of license renewal exposed to raw water or closed-cycle cooling water. Components

susceptible to selective leaching are in the fire protection system, the auxiliary building HVAC

system, the containment purge HVAC system, the control building HVAC system, the fuel

building HVAC system, the miscellaneous buildings HVAC system, the standby diesel engine

system, and the oily waste system. There are no bronze alloy components susceptible to

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selective leaching. The program includes a one-time inspection of a selected sample of

component internal surfaces. Visual and mechanical methods determine whether loss of

material due to selective leaching occurs. If these inspections detect dezincification or

graphitization, indications of selective leaching, a followup evaluation will be performed. This

evaluation may require confirmation of selective leaching with a metallurgical evaluation (which

may include a microstructure examination). The sample size for the system, material, and

environment combination may be expanded based upon the results of the evaluation and

confirmatory testing. Initial visual evaluations required by this program will be completed prior to

the period of extended operation. If indications of selective leaching are confirmed, there will be

followup evaluations.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception (and associated technical basis), remains adequate to manage the aging effects.

The staff interviewed the applicant's technical staff and reviewed documents related to the

Selective Leaching of Materials Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.M33.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

elements "preventive actions," "parameters monitored or inspected," and "detection of aging

effects." Specifically, the exception stated:

A qualitative determination of selective leaching will be used in lieu of Brinell

hardness testing for components within the scope of the Selective Leaching of

Materials aging management program. The exception involves the use of

examinations, other than Brinell hardness testing identified in NUREG-1 801, to

identify the presence of selective leaching of material. The exception is justified,

because: (1) hardness testing may not be feasible for most components due to

form and configuration (i.e., heat exchanger tubes), and (2) other mechanical

means (i.e., scraping, or chipping, provide an equally valid means of

identification).

During the audit, the applicant stated that selective leaching in gray cast iron occurs when the

iron is dissolved, leaving a weakened structure with no geometrical changes in the component.

Similarly, selective leaching in copper alloys occurs when zinc is dissolved. Since visual

inspection alone will not detect selective leaching, some mechanical means is necessary to

detect the weakened structure of the material. The GALL Report recommends hardness testing

to detect a weakened structure, although other mechanical means may be as effective as the

hardness testing. The applicant stated that scraping or chipping the material provides an

equally valid means of detecting selective leaching. However, the LRA did not provide detailed

mechanical test methods. The staff requested that the applicant provides additional justification

that supports that these alternative mechanical methods are reliable for detecting selective

leaching.

In its response, the applicant stated that chipping and scraping of the mechanical methods will

detect a corroded component structure. If these methods detect dezincification or

graphitization, then a follow up examination or evaluation will be performed. The examination or

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evaluation may require confirmation of selective leaching with a metallurgical evaluation, which

may include a microstructure examination.

The staff agrees that chipping and scraping will remove material of a weakened microstructure

due to selective leaching, thus providing an indication of selective leaching during visual

examination.

On the basis that mechanical probing of gray cast iron and high zinc copper alloy components

along with metallurgical examination of weakened materials will be effective in detecting

selective leaching, the staff finds that this exception to GALL Report is acceptable.

The staff reviewed those portions of the Selective Leaching of Materials Program for which the

applicant claims consistency with GALL AMP XI.M33 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Selective Leaching of Materials Program acceptable

because it conforms to the recommended AMP, with the exception described.

Operating Experience. LRA Section B2.1.17 states that the new Selective Leaching of Materials

Program does not have plant-specific operational history. During ECTs of the EDG heat

exchanger tubing in 2001, several tubes were found with defect indications originating on the

tubing inside diameter. To support the root cause investigation of these indications, selected

tubes were removed from the EDG heat exchangers and destructively examined. The

laboratory examinations revealed no evidence of selective leaching (e.g., dezincification) in any

of the tube sections.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Selective Leaching of Materials Program. The staff also interviewed

the applicant's personnel who have knowledge of the program. The staff reviewed selected

instances previously documented by the applicant that identified issues with selective leaching

of materials and where the applicant had implemented corrective action.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to confirm that the plant-specific operating experience did not reveal

degradations that are not bounded by industry experience. The staff reviewed documents listed

in the audit summary that describe operating experience with de-alloying of heat exchanger

tubing. The applicant credits a one-time inspection in the Selective Leaching of Materials

Program. The Selective Leaching of Materials Program provides for an expanded inspection

scope and inspection schedule if de-alloying is found. As a result of this operating experience,

the staff requested that the applicant provides the plan and schedule for these additional

inspections for selective leaching.

In its response, the applicant stated that the indications in the copper-nickel tubes described in

the problem identification reports were suspected to be the result of de-alloying, but that

assumption was never verified. Subsequent eddy current testing revealed multiple degradation

indications. Metallurgical evaluation of the tubing showed no de-alloying. Most indications were

identified as erosion-corrosion.

The staff finds that the actions in response to the problem identification reports demonstrate the

effectiveness of the Selective Leaching of Materials Program.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.17, the applicant provided the USAR supplement for the

Selective Leaching of Materials Program. The applicant committed (Commitment No. 8) to

implement the Selective Leaching of Materials Program prior to the period of extended

operation. During the audit, the staff requested that the applicant clarify the meaning of the term

"visual, mechanical methods." By letter dated August 31, 2007, the applicant amended LRA

Section Al .17 to state "visual and mechanical methods." The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Selective Leaching of

Materials Program, the staff determines that those program elements for which the applicant

claimed consistency with the GALL Report are consistent. In addition, the staff reviewed the

exception and its justification and determines that the AMP, with the exception, is adequate to

manage the aging effects for which it is credited. The staff concludes that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this

AMP and concludes that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.15 One-Time Inspection of ASME Code Class 1 Small-Bore Piping

Summary of Technical Information in the Application. LRA Section B2.1.19 describes the

existing One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program as consistent,

with exception, with GALL AMP XI.M35, "One-Time Inspection of ASME Code Class 1

Small-Bore Piping."

The One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program manages

cracking of stainless steel ASME Code Class 1 piping of 4 inches or less. This program is a

part of the Risk-Informed Inservice Inspection Program. For ASME Code Class 1 small-bore

piping, the Risk-Informed Inservice Inspection Program requires volumetric examinations (by

UT) to detect cracking on weld locations selected based on the guidelines of EPRI TR-1 12657.

Ultrasonic examinations are in accordance with ASME Code Section Xl with acceptance criteria

from paragraphs IWB-3131 and IWB-2430. The fourth interval of the ASME Code Section XI

Inservice Inspection Program will report results for the one-time inspection of ASME

Code Class 1 small-bore piping. In compliance with 10 CFR 50.55a(g)(4)(ii), the ASME Code

Section XI Inservice Inspection Program is updated each successive 120-month inspection

interval to comply with the latest edition of the ASME Code specified 12 months before the start

of the inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, remains adequate to manage the aging effects for which it is credited.

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During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program, as

listed in the audit summary, including the license renewal program evaluation report in which

the applicant assessed whether the program elements are consistent with GALL AMP XI.M35.

During the audit, the staff requested that the applicant clarify if there are any socket welds

identified as high safety significant locations as part of the Risk-Informed Inservice Inspection

Program. The EPRI topical report on RI-ISI specifies that high safety significant locations be

volumetrically examined. The staff requested that the applicant explain what volumetric

examination method will be used to examine the socket welds if they are classified as high

safety significant.

In its response, the applicant stated that there are no socket welds identified as high safety

significant locations as part of the Risk-Informed Inservice Inspection Program.

The applicant stated that for ASME Code, Class 1, small-bore piping, the Risk-Informed

Inservice Inspection Program requires volumetric examinations (i.e., UT) on selected weld

locations to detect cracking. Weld locations are selected based on the guidelines provided in

EPRI TR-1 12657. UT examinations are conducted in accordance with the ASME Code,

Section XI, with acceptance criteria from Paragraphs IWB-3131 and IWB-2430. The fourth

interval of the ISI program at WCGS will provide the results for the one-time inspection of

ASME Code, Class 1, small-bore piping.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

element "acceptance criteria." Specifically, the exception stated:

The WCGS ISI Program uses ASME Section XI, 1998 Edition through 2000

Addenda, as modified by 10 CFR 50.55a, and approved code cases.

NUREG-1801, Section XI.M35, specifies the use of ASME Section XI, 2001

edition with 2002 and 2003 addenda. There are no differences in the two code

versions for Paragraphs IWB-3131 and IWB-2430.

Because current approval to use ASME Code, Section XI, code cases does not provide

justification or a basis for their use during the period of extended operation, the staff requested

that the applicant clarify why the LRA identifies approved code cases in this exception.

By letter dated August 31, 2007, the applicant amended the exception in LRA Section B2.1.19

to state:

The WCGS ISI Program uses ASME Section XI 1998 Edition through 2000

addenda. NUREG-1801, Section XI.M35 specifies the use of ASME Section XI,

2001 edition with 2002 and 2003 addenda. There are no differences in the two

code versions for Paragraphs IWB-3131 and IWB-2430.

WCGS will use the ASME Code Edition consistent with the provisions of

10 CFR 50.55a during the 10-year period prior to the period of extended

operation (4th interval) and during the period of extended operation.

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The staff finds that this exception is acceptable because there are no differences in the two

code versions for Paragraphs IWB-3131 and IWB-2430.

The staff reviewed those portions of the One-Time Inspection of ASME Code Class 1 Small

Bore Piping Program for which the applicant claims consistency with GALL AMP XI.M35 and

finds that they are consistent with the GALL AMP. The staff finds the applicant's One-Time

Inspection of ASME Code Class 1 Small Bore Piping Program acceptable because it conforms

to the recommended AMP, with the exception described.

Operating Experience. LRA Section B2.1.19 states that there has been no cracking of stainless

steel ASME Code Class 1 piping with nominal pipe size (NPS) of less than or equal to 4 inches,

or in piping with NPS of greater than or equal to 1 inch.

During the audit, the staff reviewed implementing procedures and problem identification reports

that are related to the applicant's One-Time Inspection of ASME Code Class 1 Small-Bore

Piping Program. The staff also interviewed selected onsite personnel who have specialized

knowledge of the program. The staff did not identify any instances where the applicant's

operating experience is outside the envelope of industry experience or where omissions in the

applicant's current program resulted in failure to maintain intended functions of components

that are within the scope of the program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section Al.19, the applicant provided the USAR supplement for the

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program. The applicant

committed (Commitment No. 10) that the fourth interval of the ISI program at WCGS will

provide the results for the one-time inspection of ASME Code, Class 1, small-bore piping. The

staff reviewed this section and determines that the information in the USAR supplement is an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's One-Time Inspection of

ASME Code Class 1 Small-Bore Piping Program, the staff determines that those program

elements for which the applicant claimed consistency with the GALL Report are consistent. In

addition, the staff reviewed the exception and its justifications and determines that the AMP,

with the exception, is adequate to manage the aging effects for which it is credited. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.16 Lubricating Oil Analysis

Summary of Technical Information in the Application. LRA Section B2.1.23 describes the

existing Lubricating Oil Analysis Program as consistent, with an exception, with GALL

AMP XI.M39, "Lubricating Oil Analysis."

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The Lubricating Oil Analysis Program manages loss of material and reduction of heat transfer

for components within the scope of license renewal. The program maintains lubricating oil

contaminants within acceptable limits to preserve an environment not conducive to aging

effects and includes acceptance criteria based on original equipment manufacturer or industry

guidelines for oil chemical and physical properties, wear metals, contaminants, additives, and

water. Increased impurities and degradation of oil properties indicate aging of materials

exposed to lubricating oil. Additionally, ferrography on oil samples trends wear particle

concentrations for the RCPs upper and lower bearing oil and other components. Monitoring and

trending of lubricating oil analysis results detects component aging prior to loss of intended

function. Corrective actions, when alert action levels or limits are reached, include increased

sampling frequency, additional oil filtration, oil change-out, visual inspections, and corrective

maintenance.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Lubricating Oil Analysis Program, as listed in the audit summary, including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.M39.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

element "parameters monitored or inspected." Specifically, the exception stated that:

WCGS does not specify flash point testing as part of the Lubricating Oil Analysis

Program as indicated in NUREG-1 801, Section XI.M39. The WCGS lubricating

oil analysis program instead specifies a fire point analysis to determine fuel

contamination. The fire point analysis is a test method for determining the lowest

temperature a test specimen can sustain combustion for 5 seconds following the

introduction of an ignition source. Flash point and fire point are determined using

the same standard ASTM test method (ASTM D92) and are equally effective

measures for determining the suitability of lubricating oils for continued use with

regards to fuel contamination.

The staff reviewed ASTM D92 to compare the details of flash point and fire point analyses. The

flash point is the lowest temperature at which application of a test flame causes the vapors to

ignite; whereas, the fire point is the temperature when burning is sustained for a minimum of

5 seconds. Both parameters are indicators of flammability of lubricating oil and can be used as

indicators of dilution of lubricating oil with, for example, fuel oil. The applicant indicated that

lubricating oil that is not routinely changed is monitored for any change in fire point. Any trend

of fire point will be analyzed by the Predictive Maintenance Group. If adverse trends are

identified, corrective action will be initiated, including increased sampling frequencies, oil

change, and/or visual inspection.

The staff noted that the license renewal program evaluation report states that the plant's

Predictive Maintenance Group reviews lubricating oil analysis results and determines the

acceptability for continued service using engineering judgment. The staff requested that the

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applicant provides documentation that shows the analyses trending performed by the Predictive

Maintenance Group.

In its response, the applicant provided examples of lubricating oil analysis results. Oil analysis

results are reviewed by the Predictive Maintenance Group to determine if there are unusual

trends, or if alert levels have been reached or exceeded.

The staff reviewed the oil analysis result examples provided by the applicant and finds that

these reports provide the data to identify any adverse trends in lubrication oil quality.

On the basis that flammability of lubricating oil can be determined using the fire point of the oil

instead of the flash point, the staff finds that this exception to the GALL Report is acceptable.

The staff reviewed those portions of the Lubricating Oil Analysis Program for which the

applicant claims consistency with GALL AMP XI.M39 and finds that they are consistent with the

GALL AMP. The staff finds the applicant's Lubricating Oil Analysis Program acceptable

because it conforms to the recommended AMP, with the exception described.

Operatina Experience. LRA Section B2.1.23 states that there have been no instances of

component failure attributed to lubricating oil contamination or degradation. Analysis results

indicate no water pooling in lubricating oil.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Lubricating Oil Analysis Program. The staff also interviewed the

applicant's onsite personnel. The staff reviewed selected instances previously documented by

the applicant that identified issues with lubricating oil quality and where the applicant had

implemented corrective action.

The staff reviewed problem identification reports and work orders listed in the audit summary

and found no indication of wear or water pooling. The lack of wear, water pooling, and

equipment failures resulting from poor lubricating oil quality provide an indication of the

effectiveness of the Lubricating Oil Analysis Program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Suoplement. In LRA Section A1.23, the applicant provided the USAR supplement for the

Lubricating Oil Analysis Program. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant's Lubricating Oil Analysis

Program, the staff determines that those program elements for which the applicant claimed its

justification, and determines that the AMP, with the exception, is adequate to manage the aging

effects for which it is credited. The staff concludes that the applicant has demonstrated that the

effects of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

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that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.2.17 ASME Code Section Xl, Subsection IWE

Summary of Technical Information in the Application. LRA Section B2.1.27 describes the

existing ASME Code Section XI, Subsection IWE Program as consistent, with exceptions, with

GALL AMP XI.S1, "ASME Section XI, Subsection IWE."

The ASME Code Section XI, Subsection IWE Program manages aging of the steel liner of the

concrete containment building, including the containment liner plate, piping and electrical

penetrations, access hatches, moisture barrier, and the fuel transfer tube. Inspections are in

accordance with ASME Code Section XI, Subsection IWE, 1998 Edition with no addenda to

manage any containment liner aging effects that could cause loss of intended function.

Acceptance criteria for components subject to ASME Code Section XI, Subsection IWE exam

requirements are specified in Article IWE-3000. In compliance with 10 CFR 50.55a(g)(4)(ii), the

ASME Code Section XI Inservice Inspection Program is updated during each successive

120-month inspection interval to comply with the latest code edition and addenda specified 12

months before the start of the inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exceptions to determine whether the AMP, with the

exceptions, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the ASME Code Section XI, Subsection IWE Program, as listed in the audit summary,

including the license renewal program evaluation report in which the applicant assessed

whether the program elements are consistent with GALL AMP XI.S1.

Exception 1. In the LRA, the applicant credited an exception to the GALL Report program

element "scope of the program." Specifically, the exception states:

Pressure retaining containment seals and gaskets are not addressed by the

1998 edition of ASME Code Section XI, Subsection IWE. These components are

evaluated per 10 CFR Part 50, Appendix J.

During the audit, the staff reviewed the applicant's ASME Code Section XI, Subsection IWE

Program and finds that the IWE containment ISI program at WCGS is in accordance with

ASME Code, Section XI, 1998 Edition with no Addenda. The staff finds that the pressure

retaining containment seals and gaskets are not addressed by the ASME Code, Section XI,

1998 Edition, Subsection IWE. However, the applicant's 10 CFR Part 50, Appendix J Program

provides for local leak rate testing of elastomer material, and containment seals and gaskets.

The staff noted that the GALL Report "parameters monitored or inspected" program element

states that the examination method for all pressure retaining components, which includes

containment seals and gaskets, is the 10 CFR Part 50, Appendix J, leak rate testing. On this

basis, the staff finds the exception acceptable because 10 CFR Part 50, Appendix J testing is

referenced in the GALL Report as an acceptable AMP for managing the aging effects of

containment seals and gaskets.

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Exception 2. In the LRA, the applicant credited an exception to the GALL Report program

element "parameters monitored or inspected." Specifically, the exception states:

Table IWE-2500-1 does not specify seven categories for examination in the 1998

or later editions of ASME Code Section XI, Subsection IWE. The ASME

Code Section XI, Subsection IWE Program is in accordance with the 1998

Edition of ASME Code Section XI (with no addenda), Subsection IWE,

supplemented with the applicable requirements of 10 CFR 50.55a(b)(2)(ix). The

WCGS IWE CISI program, which adheres to these code requirements, is

consistent with the 2001 edition of ASME Code Section XI, Subsection IWE,

including the 2002 and 2003 Addenda, for the parameters monitored by this

program.

During the audit, the staff reviewed the applicant's ASME Code, Section XI, Subsection IWE

Program. WCGS uses the ASME Code, Section XI, 1998 Edition with no Addenda for the

interval from 1998 to 2008. The IWE containment ISI program, which adheres to these code

requirements, is consistent-with the ASME Code, Section XI, 2001 Edition, Subsection IWE,

including the 2002 and 2003 Addenda.

The staff noted that the applicant's use of the ASME Code, Section XI, 1998 Edition with no

Addenda for the third 10-year inspection interval has been approved pursuant to

10 CFR 50.55a, and that the third 10-year inspection interval does not continue into the period

of extended operation.

The staff finds that, during the period of extended operation, the applicant will use ASME Code,

Section Xl, editions and addenda that will be endorsed by the staff in accordance to the

requirements of 10 CFR 50.55a, as a basis for its ASME Code Section XI, Subsection IWE

Program. Also, the staff finds that these endorsed editions and addenda provide requirements

for the containment ISI that are equivalent to those referenced in the GALL Report. On this

basis, the staff finds that the applicant's use of ASME Code, Section Xl, editions and addenda

different from those referenced in the GALL Report is acceptable. The staff finds that the

applicant's exception to the GALL Report is acceptable.

Exception 3. In the LRA, the applicant credited an exception to the GALL Report program

element "monitoring and trending." Specifically, the exception states:

WCGS manages containment liner aging in accordance with procedures which

require when flaws or areas of degradation are accepted by engineering

evaluation, the area containing the flaw or degradation shall be reexamined in

accordance with IWE-2420(b) and (c). This ASME Code requirement specifies

that flaws or areas of degradation no longer require augmented examination if

they remain essentially unchanged for the next inspection period. This is not

consistent with NUREG 1801, Section XI.S1, Element 5, which requires that they

remain essentially unchanged for three consecutive inspection periods.

The staff reviewed the ASME Code, Section XI, Subsection IWE Program and finds that the

ASME Code, Table 1, IWE 2430 was deleted from the ASME Code, Section Xl, 1998 Edition.

The staff also finds that it is also absent from the ASME Code, Section XI, 2001 Edition, with

2002 and 2003 Addenda. The changes to Table IWE 2500-1 eliminate several examination

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categories. The categories that remain require 100 percent examination; therefore, no items are

available for additional examinations.

On the basis that the changes made to ASME Code, Section Xl, Table IWE 2500-1, now

require 100 percent examination of all remaining categories, and that the reexamination is

performed in accordance with ASME Code, Section Xl, IWE-2420 (b) and (c), the staff finds this

exception acceptable. The staff finds that performing additional examinations is not necessary.

The staff reviewed those portions of the ASME Code Section XI, Subsection IWE Program for

which the applicant claims consistency with GALL AMP XI.S1 and finds that they are consistent

with the GALL AMP. The staff finds the applicant's ASME Code Section XI, Subsection IWE

Program acceptable because it conforms to the recommended AMP, with the exceptions

described.

Operating Experience. LRA Section B2.1.27 states that an inspection of the containment liner

plate during the 1996 refueling outage included both internal containment liner and external

containment concrete surfaces which indicated no corrosion, pitting, or other degraded liner

plate conditions. This result is documented in the applicant's response to NRC IN 97-10, "Liner

Plate Corrosion in Concrete Containments." With the exception of pitting on the in-core

instrument tunnel sump, all degradation in the containment liner discovered during normal

inspections have been minor. The applicant stated that in 2002, as part of the ASME Code

Section Xl Inservice Inspection Program, a general visual examination of the in-core instrument

tunnel sump noted areas of apparent liner plate degradation indicated by rust and degraded

coatings. The coatings were removed, a detailed visual examination was performed, and an

engineering evaluation was required to approve continued operation of this section of the liner

plate in this condition. In addition, inspections performed in 2003 noted two additional

recordable indications. After a detailed visual inspection, one area was prepped and recoated

and the disposition of the second was used as-is.

During the audit, the staff asked the applicant to clarify if there have been any containment liner

plate inspections performed since 1996.

In its response, the applicant provided the owner's activity report documenting the containment

liner plate inspections. The report provides the following information regarding the containment

ISI program findings:

* First Interval, First Period 2002 findings:

(1) There were no components containing flaws or relevant conditions that required

an evaluation to determine acceptability for continued service.

(2) There were no Class MC components that required repairs, replacements, or

corrective measures for continued service.

* First Interval, Second Period 2006 findings:

(1) A general visual exam found localized pitting in the liner floor of the incore tunnel

sump.

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(2) A detailed visual exam was performed to determine the magnitude and extent of

degradation to the incore tunnel sump liner. Pitting was the only degradation

found. It was believed that the pitting resulted from nearby welding that damaged

the coating. An evaluation performed by design engineering determined that the

remaining wall thickness is sufficient and that recoating the pitted area with a

qualified coating will stop further degradation. The pitted areas have been

recoated with a qualified coating. The incore tunnel sump liner was found to be

acceptable for continued service, and the areas containing the pitting were

identified for reexamination during the next inspection period.

(3) The WCGS Corrective Action Program addressed programmatic concerns.

Applicable procedures were reviewed and revised as necessary to ensure

compliance with IWE requirements and to establish acceptance criteria for pitting

of the containment liner plate.

First Interval, Third Period 2007 findings:

(1) There were no containment liner plate components containing flaws or relevant

conditions that required an evaluation to determine acceptability for continued

service.

(2) There were no repairs, replacements, or corrective measures performed on any

Class MC or CC items during the period of this report that were required due to

an item containing a flaw or relevant condition that exceeded acceptance criteria.

The staff also requested that the applicant provides a description of the degradation found in

the in-core instrument tunnel sump in 2002 and 2003.

In its response, the applicant stated a detailed visual exam was performed to determine the

magnitude and extent of degradation to the in-core tunnel sump liner. Pitting was the only

degradation found. It is believed that the pitting resulted from nearby welding that damaged the

coating. An evaluation performed by design engineering determined that the remaining wall

thickness is sufficient and that recoating the pitted area with a qualified coating will stop further

degradation. The pitted areas have been recoated with a qualified coating. The in-core tunnel

sump liner was found to be acceptable for continued service, and the areas containing the

pitting were identified for reexamination during the next inspection period.

The staff finds that the applicant response is acceptable because it did not reveal degradations

that are not bounded by industry experience. In addition, the staff finds that the corrective

action program, which captures internal and external plant operating experience issues, will

ensure that operating experience is reviewed and incorporated in the future to provide objective

evidence to support the conclusion that the effects of aging are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.27, the applicant provided the USAR supplement for the

ASME Code Section XI, Subsection IWE Program. The staff reviewed this section and

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determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's ASME Code Section XI,

Subsection IWE Program, the staff determines that those program elements for which the

applicant claimed consistency with the GALL Report are consistent. In addition, the staff

reviewed the exceptions and their justifications and determines that the AMP, with the

exceptions, is adequate to manage the aging effects for which it is credited. The staff concludes

that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB for the period of

extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR

supplement for this AMP and concludes that it provides an adequate summary description of

the program, as required by 10 CFR 54.21 (d).

3.0.3.2.18 ASME Code Section XI, Subsection IWL

Summary of Technical Information in the Application. LRA Section B2.1.28 describes the

existing ASME Code Section Xl, Subsection IWL Program as consistent, with enhancement,

with GALL AMP XI.S2, "ASME Section Xl, Subsection IWL."

The ASME Code Section XI, Subsection IWL containment ISI program manages aging of the

concrete containment structure (including the tendon gallery ceiling), the concrete dome, and

the post-tensioning system. For the 1998 through 2008 inspection interval, the applicant

inspects concrete in accordance with the 1998 Edition of ASME Code Section XI (with no

addenda), Subsection IWL, supplemented with applicable 10 CFR 50.55a(b)(2)(xiii)

requirements. Additional commitments define the visual examinations parts of the program and

the qualification requirements for inspectors. Acceptance criteria for components subject to

ASME Code Section XI, IWL examination requirements are specified in Article IWL-3000. In

compliance with 10 CFR 50.55a(g)(4)(ii), the ISI Program is updated during each successive

120-month inspection interval to comply with the latest code edition and addenda specified 12

months before the start of the inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the ASME Code Section Xl, Subsection IWL Program, as listed in the audit summary,

including the license renewal program evaluation report in which the applicant assessed

whether the program elements are consistent with GALL AMP XI.S2.

Enhancement. In the LRA, the applicant credited an enhancement to the GALL Report program

element "detection of aging effects." Specifically, the enhancement states:

The 2003 edition of ASME Code Section XI, Subsection IWL, Article IWL-2000,

includes two provisions regarding inspection of repair/replacement activities that

are not required by the 1998 edition. IWL-2410(d) specifies additional

inspections for concrete surface areas affected by a repair/replacement activity,

and IWL-2521.2 specifies additional inspections for tendons affected by a

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repair/replacement activity. In accordance with 10 CFR 50.55a, WCGS will

revise their ASME Code Section XI, Subsection IWL Containment Inservice

Inspection Program prior to the next inspection interval to incorporate the ASME

code edition and addenda incorporated into 10 CFR 50.55a at that time.

During the audit, the staff noted that the plant's IWL components are inspected in accordance

with IWL-2000, as discussed in WCRE-1 1, "Containment Inservice Inspection Program Plan."

The structural integrity (tendon) and the concrete exams were performed on

December 18, 1984, and May 23, 2000, respectively. The plant is beyond ten years of

commercial operation; therefore, the frequency of concrete exams is now five years, plus or

minus one year.

The staff noted that as described in C-158(Q), "Technical Specification for Containment Tendon

Surveillance," tendons for surveillance are selected in a random manner and are representative

of the various types of tendons and conditions of exposure existing in the containment. There

are 86 inverted u-shaped tendons and 1 65 hoop tendons (i.e., 135 in the cylinder and 30 in the

dome). The ASME Code, Section XI, 1998 Edition, Table IWL-2521-1, specifies that

inspections in the tenth year, and every fifth year thereafter, include two percent of each type of

tendon. ASME Code, Paragraph IWL-2521 (c), specifies that the population from which the

random sample is drawn shall consist of all tendons of a particular type not examined during

earlier inspections. At WCGS, surveillance conducted every five years consist of three inverted

u-shaped and three hoop tendons. One inverted u-shaped tendon (i.e., V65) and one hoop

tendon (i.e., 45BA) are kept unchanged for each surveillance. The prestressing force in all

inspection sample tendons is determined by the liftoff method. One tendon from each group of

tendons is completely de-tensioned to allow for the removal of one tendon wire, which is

inspected and subjected to laboratory testing.

The ASME Code, Section XI, 2001 Edition, Subsection IWL-2000, includes two provisions that

are not required by the 1998 Edition. ASME Code, IWL-2410(d), specifies additional inspections

for concrete surface areas affected by a repair or replacement activity, and IWL-2521.2

specifies additional inspections for tendons affected by a repair or replacement activity. In

accordance with 10 CFR 50.55a, WCGS will revise their containment ISI program prior to the

next inspection interval to incorporate the ASME Code, edition and addenda, endorsed by

10 CFR 50.55a.

The staff requested that the applicant clarify why the enhancement references the ASME Code,

Section XI, 2003 Edition, which does not exist.

In its letter dated August 31, 2007, the applicant amended LRA Section B2.1.28 and

Commitment No. 15 to state ASME Code, Section XI, 2001 Edition with 2002 and 2003

Addenda.

The staff reviewed the applicant's ASME Code Section XI, Subsection IWL procedures, and

their aging effects requiring management under the "detection of aging effects" program

element of the ASME Code Section XI, Subsection IWL Program. The staff finds this

information acceptable since the corrective action program will consider expanding the scope, if

significant degradation is observed.

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The staff finds this enhancement acceptable because, when implemented, the applicant's

ASME Code Section XI, Subsection IWL will be consistent with the GALL Report and will

provide additional assurance that the effects of aging will be adequately managed.

The staff reviewed those portions of the ASME Code Section Xl, Subsection IWL Program for

which the applicant claims consistency with GALL AMP XI.S2 and finds that they are consistent

with the GALL AMP. The staff finds the applicant's ASME Code Section XI, Subsection IWL

Program acceptable because it conforms to the recommended AMP, with the enhancement

described.

Operating Experience. LRA Section B2.1.28 states that the results of the twentieth year (2005)

surveillance report of the post-tensioning system, including inspection of the unbonded

post-tensioning system (Examination Category L-B), and the visual examination of the

containment concrete surfaces (Examination Category L-A), showed no abnormal degradation.

The results of the 2000 physical inservice tendon inspection of the containment building

post-tensioning system, including both the concrete surfaces (Examination Category L-A) and

the unbonded post-tensioning system (Examination Category L-B), concluded that the

containment structure has experienced no abnormal degradation of the post-tensioning system.

The applicant stated that plant-specific operating experience shows no unacceptable

degradation of the concrete containment building or the post-tensioning system.

During the audit, the staff requested that the applicant explain the result of the 20-year tendon

surveillance, which found some excessive grease void volumes.

In its response, the applicant stated that in the twentieth year surveillance of the post-tensioning

system, four tendons were found to accept greater than 10 percent of the tendon duct volume

of grease when refilled after testing, with the highest being 17.4 percent. These conditions were

evaluated by design engineering and found not to be significant conditions. The apparent cause

of these excess voids was determined to be an elevated initial filling temperature along with a

short soak time, resulting in increased shrinkage. Examination of the tendons found no

deterioration. The engineers also consulted a study conducted at Callaway Nuclear Station,

addressing a similar condition with their unbonded tendons. The essential criterion for the

operability of the sheathing filler material is to prevent corrosion of both the tendon wires and

the anchorage components. The material used at Callaway and at WCGS accomplishes this by

a characteristic which gives the filler material: (1) an affinity to adhere to steel surfaces, (2) its

ability to emulsify any moisture in the system; therefore, nullifying its rusting ability, and (3) its

resistance to moisture, mild acids, and alkalis. In addition, each tendon wire is individually

pre-coated prior to installation for added protection.

The staff reviewed the applicant's response and finds it acceptable because the material used

at WCGS emulsifies any moisture in the system nullifying its rusting ability and is resistant to

moisture, mild acids, and alkalis (i.e. the material nullifies rusting and is resistant to harsh

conditions).

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to confirm that the operating experience did not reveal degradations

that are not bounded by industry experience. In addition, the staff finds that the corrective

action program, which captures internal and external plant operating experience issues, will

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ensure that operating experience is reviewed and incorporated in the future to provide objective

evidence to support the conclusion that the effects of aging are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.28, the applicant provided the USAR supplement for the

ASME Code Section XI, Subsection IWL Program. The applicant committed (Commitment

No. 15) to enhance procedures to include two new provisions regarding inspection of repair and

replacement activities. In addition, by letter dated May 25, 2007, the applicant revised

Commitment No. 15 to correct the ASME Code reference to read, "ASME Code, Section XI,

2001 Edition with 2002 and 2003 addenda." The staff reviewed this section and determines that

the information in the USAR supplement is an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's ASME Code Section XI,

Subsection IWL Program, the staff determines that those program elements for which the

applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the

enhancement and confirms that their implementation prior to the period of extended operation

would make the existing AMP consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.19 ASME Code Section XI, Subsection IWF

Summary of Technical Information in the Application. LRA Section B2.1.29 describes the

existing ASME Code Section XI, Subsection IWF Program as consistent, with exception, with

GALL AMP XI.S3, "ASME Section XI, Subsection IWF."

The ASME Code Section XI, Subsection IWF Program manages aging for Classes 1, 2, and 3

component supports. There are no Class MC supports at WCGS. For the September 3, 2005

through September 3, 2015 inspection interval, Classes 1, 2, and 3 component support ISIs are

in accordance with the ASME Code Section XI, Subsection IWF 1998 Edition through 2000

Addenda. Inspection scope for supports is based on class and total population as defined in

Table IWF-2500-1. Detection of deficiencies during regularly scheduled inspections requires

reexamination of the support during the next inspection period. Component supports

immediately adjacent to supports requiring corrective action are also examined. The primary

inspection method is visual examination. In compliance with 10 CFR 50.55a(g)(4)(ii), the ASME

Code Section XI Inservice Inspection Program is updated during each successive 120-month

inspection interval to comply with the requirements of the latest code edition and addenda

specified 12 months before the start of the inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the exception to determine whether the AMP, with the

exception, remains adequate to manage the aging effects for which it is credited.

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During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the ASME Code Section XI, Subsection IWF Program, as listed in the audit summary,

including the license renewal program evaluation report in which the applicant assessed

whether the program elements are consistent with GALL AMP XI.S3.

Exception. In the LRA, the applicant credited an exception to the GALL Report program

elements "scope of the program" and "parameters monitored or inspected." Specifically, the

exception states:

WCGS uses the 1998 Edition through the 2000 addenda of the ASME Section XI

code instead of the 2001 Edition with 2002 and 2003 addenda which is

referenced in NUREG-1801, Section XI.S3.

The staff noted that the affected program elements are those where the GALL Report includes

a reference to specific ASME Code, Section XI, Subsection IWF, requirements. The staff finds

that this is an exception to the GALL Report's recommendations because the applicant's ASME

Code Section Xl, Subsection IWF Program is based on ASME Code, Section Xl, editions and

addenda that are different from the ASME Code Section XI edition and addenda referenced in

the GALL Report.

The staff noted that the applicant is in its third 10-year inspection interval and that the use of

ASME Code Section XI, 1998 Edition through the 2000 Addenda for the third 10-year inspection

interval is consistent with provisions in 10 CFR 50.55a. The staff also noted that the third

10-year inspection interval ends on September 2, 2015, and does not continue into the period

of extended operation.

The staff finds that, during the period of extended operation, the applicant will use ASME

Code Section XI editions and addenda that will be endorsed by the staff, in accordance with

10 CFR 50.55a, as a basis for its ASME Code Section XI, Subsection IWF Program. The staff

also finds that the endorsed ASME Code Section XI editions and addenda provide examination

requirements adequate to identify potential degradation in supports for ASME piping and

components. On this basis, the staff finds that the use of ASME Code Section XI editions and

addenda are different from those referenced in the GALL Report. This exception to the GALL

Report is acceptable.

The staff reviewed those portions of the ASME Code Section XI, Subsection IWF Program for

which the applicant claims consistency with GALL AMP XI.S3 and finds that they are consistent

with the GALL AMP. The staff finds the applicant's ASME Code Section XI, Subsection IWF

Program acceptable because it conforms to the recommended AMP, with the exception

described.

Operating Experience. LRA Section B2.1.29 states that a review of the owner activity reports for

interval 2 indicated that there were 282 required examinations for ASME Code Classes 1, 2,

and 3 component supports. All required examinations were completed. The applicant replaced

one ASME Class 1 support sway strut for the chemical and volume control system (CVCS)

letdown piping. The sway strut had a bent paddle that appeared to have been damaged during

refueling operations, not by normal service or aging. The applicant stated that the ASME Code

Section XI, Subsection IWF Program is updated to incorporate industry operating experience.

ASME Code Section Xl is also revised every three years and addenda issued in the interim to

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allow code updates to reflect operating experience. The applicant stated that the requirement to

update the ASME Code Section XI, Subsection IWF Program to refer to more recent editions of

the ASME Code Section XI at the end of each inspection interval makes the program reflect

enhancements of incorporated operating experience.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical personnel to confirm that the plant-specific operating experience did not

reveal any degradation not bounded by industry experience. During the audit, the staff reviewed

implementing procedures and problem identification reports related to the applicant's ASME

Code Section XI, Subsection IWF Program. The staff also interviewed selected onsite

personnel who have specialized knowledge of the program. The staff found no omissions in the

applicant's current program that resulted in failure to maintain the intended functions of

components that are within the scope of the program.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.29, the applicant provided the USAR supplement for the

ASME Code Section Xl, Subsection IWF Program. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's ASME Code Section Xl,

Subsection IWF Program, the staff determines that those program elements for which the

applicant claimed consistency with the GALL Report are consistent: In addition, the staff

reviewed the exception and its justification and determines that the AMP, with the exception, is

adequate to manage the aging effects for which it is credited. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.20 Masonry Wall Program

Summary of Technical Information in the Application. LRA Section B2.1.31 describes the

existing Masonry Wall Program as consistent, with enhancement, with GALL AMP XI.S5,

"Masonry Wall Program."

The Masonry Wall Program is part of the Structures Monitoring Program that implements

structures monitoring requirements pursuant to 10 CFR 50.65. The program manages aging of

masonry walls and their structural steel restraint systems within the scope of license renewal

guided by NRC IE Bulletin 80-11, "Masonry Wall Design," and NRC IN 87-67, "Lessons

Learned from Regional Inspections of Licensee Actions in Response to NRC IE Bulletin 80-11."

The Masonry Wall Program states inspection guidelines, lists causes of aging of masonry walls

to be monitored during structural monitoring inspections, and establishes examination criteria,

evaluation requirements, and acceptance criteria.

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Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which-it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Masonry Wall Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.S5.

Enhancement. In the LRA, the applicant credited an enhancement to the GALL Report program

element "scope of the program." Specifically, the enhancement states:

Procedures will be enhanced to identify unreinforced masonry in the radwaste

building within the scope of license renewal that requires aging management.

The staff reviewed the plant procedures and the aging effects requiring management under the

scope of the Masonry Wall Program. The staff finds this information acceptable since the

corrective action program will consider expanding the scope if significant degradation is

observed.

The staff finds this enhancement acceptable because, when the enhancement is implemented,

the Masonry Wall Program will be consistent with the GALL Report and provides additional

assurance that the effects of aging will be adequately managed.

The staff reviewed those portions of the Masonry Wall Program for which the applicant claims

consistency with GALL AMP XI.S5 and finds that they are consistent with the GALL AMP. The

staff finds the applicant's Masonry Wall Program acceptable because it conforms to the

recommended AMP, with the enhancement described.

Operating Experience. LRA Section B2.1.31 states that the baseline evaluation of the

Maintenance Rule observations was completed in 1998. Aging effects were observed on

masonry walls in the auxiliary building, communication corridor, control building, and turbine

building. Cracking was the most frequently observed aging effect on masonry walls. Other

types of deterioration that could lead to increased aging effects on masonry walls were missing

bolt support angles, pop-outs due to installation of steel components, and the presence of

water.

The LRA states that based upon the baseline evaluation of Maintenance Rule observations

completed in 1998, subsequent inspections of structures with masonry walls within the scope of

license renewal with aging effects took place between 2002 and 2003. The control building had

cracks repaired with grout, but the joint was moving enough to re-crack the repair. The wall is

located in an area not subject to weather or threatened by water exposure. The applicant stated

that the wall will continue to be monitored until a history demonstrates its stability. The masonry

will retain an "acceptable with degradation" status. The turbine building was observed to have

several masonry walls categorized as "acceptable with degradation." The applicant stated that

in most cases during the five-year re-inspection, conditions stabilized from the baseline

observation attained a downgraded category. The latest inspection revealed that the length and

size of one crack continue to increase. Engineering (applicant) evaluated this wall and

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determined that it will still perform intended functions. The applicant stated that it will continue to

monitor this condition.

During the audit, the staff requested that the applicant: (1) provide details on the operating

experience relating to the degradation found in 2002 and 2003, (2) explain how this compares

to the 1998 established baseline, including the acceptance criteria for cracking, deterioration,

missing anchor bolts, anchor bolts pop-outs, and the presence of water, (3) clarify if a scope

expansion was required because of unacceptable conditions identified, and (4) identify any

additional inspections scheduled for the next inspection period.

In its response, the applicant stated:

(1) Inspections that took place between 2002 and 2003 are summarized as

follows:

A masonry wall in the control building had cracks visible on both

sides. The cracks were repaired with grout, but the joint was

moving enough to re-crack the repair. The wall is located in an

area not subject to weather or a threat to water exposure. Design

engineering (applicant) evaluated this condition and determined

that there had been no change in the described conditions since

the previous inspection, and the described condition is not

indicative of any structural concern. This item was re-categorized

as "Acceptable With Minor Degradation," and will be re-inspected

during the next scheduled inspection.

" Several masonry walls in the turbine building were observed to

have minor cracks categorized as "Acceptable With Degradation."

In most cases during the 5-year re-inspection, the conditions had

stabilized from the baseline observation resulting in a downgraded

category. In the north wall of the southeast turbine building truck

bay, a previous attempt had been made to repair the crack and

was not accessible from the opposite side due to a building

column. No leakage is involved that could lead to corrosion. The

latest inspection reveals that the length and size of crack

continues to increase. Design engineering has evaluated this wall

and determined that it will still perform its intended functions.

During the Advisory Committee of Reactor Safeguards (ACRS) sub-committee meeting on

March 5, 2008, the ACRS made an inquiry about the intended function and the acceptability of

the masonry wall in the turbine building (truck bay) that has a crack in the inaccessible area. In

its responses to the ACRS's inquiry, the applicant clarified via a conference call on

March 12, 2008, that the wall in question is located on the north wall of the southeast turbine

building truck bay, and is not within the scope of license renewal. The wall is a fire barrier for

commercial (property) protection, not for fire protection of safety-related equipment. In the letter

dated March 29, 2008, the applicant removed reference to this wall from the LRA. The staff

confirmed that the wall in question is not within the scope of license renewal by reviewing the

applicant's drawing and verifying that the wall listing is for insurance purpose only (there are no

(a)(1) components associated with safety function in the turbine building). The turbine building

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(a)(2) intended function is to prevent adverse interaction with the external safety-related SSC's

(when subjected to design basis wind loads) and the internal masonry wall in question is not

credited in performance of this function. Therefore, the staff found the applicant's response

acceptable.

(2) Based on the 1998 baseline inspections, several masonry walls in the

Control Building and Turbine Building had aging effects classified as

"Acceptable With Degradation."

A support angle attached to a masonry wall was found to be

missing an anchor bolt. The angle supports the building's metal

siding and is not a seismic support for the wall. This situation was

evaluated by design engineering, who determined that no further

action was required due to the redundancy of the design. Several

pop outs around anchor bolts or through-bolts were identified. All

of these were determined to have occurred during construction,

not as a result of aging. Design engineering evaluated all of the

cases and determined that the damage did not prevent any of the

components from performing their intended functions. None were

found to have increased degradation during subsequent

inspections.

* No operating experience pertaining to the presence of water in masonry

walls was found.

(3) No scope expansion was required. All items that remain classified as

"Acceptable with Degradation" will be inspected again during the next

inspection period. No cases of "major degradation" were found.

(4) There were no additional inspections scheduled for the next inspection

period. All items that remain classified as "Acceptable with Degradation"

will be inspected again during the next inspection period.

The staff finds that the applicant response is acceptable because it did not reveal degradations

that are not bounded by industry experience. In addition, the staff finds that the corrective

action program, which captures internal and external plant operating experience issues, will

ensure that operating experience is reviewed and incorporated to provide objective evidence to

support the conclusion that the effects of aging are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.31, the applicant provided the USAR supplement for the

Masonry Wall Program. The applicant committed (Commitment No. 16) to enhance procedures

to identify the unreinforced masonry in the radwaste building requiring aging management

within the scope of license renewal. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its audit and review of the applicant's Masonry Wall Program, the

staff determines that those program elements for which the applicant claimed consistency with

the GALL Report are consistent. Also, the staff reviewed the enhancement and confirms that

their implementation prior to the period of extended operation would make the existing

AMP consistent with the GALL AMP to which it was compared. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.21 Structures Monitoring Program

Summary of Technical Information in the Application. LRA Section B2.1.32 describes the

existing Structures Monitoring Program as consistent, with enhancement, with GALL

AMP XI.S6, "Structures Monitoring Program."

The Structures Monitoring Program manages cracking, loss of material, and change in material

properties by monitoring the condition of structures and structural supports within the scope of

license renewal. The program provides inspection guidelines and walkdown checklists for

concrete elements, structural steel, masonry walls, treated wood, structural features (e.g.,

caulking, sealants, roofs, etc.), structural supports, and miscellaneous components like doors.

The program includes all masonry walls within the scope of license renewal and inspects

supports for equipment, piping, conduit, cable tray, HVAC, and instrument components.

Although coatings may be applied to the external surfaces of structural members, no credit was

taken for these coatings in the determination of aging effects for the underlying materials. The

Structures Monitoring Program evaluates the condition of the coatings as an indication of the

condition of the underlying materials.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Structures Monitoring Program, as listed in the audit summary, including the

license renewal program evaluation report in which the applicant assessed whether the

program elements are consistent with GALL AMP XI.S6.

Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program element "parameters monitored or inspected." Specifically, the enhancement states:

Procedures will be enhanced to add inspection parameters for treated wood.

The staff reviewed the aging effects requiring management under the parameters monitored or

inspected of the Structures Monitoring Program. The staff finds that the offsite power supply

poles for the SBO are treated wood. Visual inspections are performed at 5-year intervals. Visual

inspections of buried plant structures are performed when opportunistic excavation occurs.

However, more frequent inspections may be performed based on past inspection results,

industry experience, or exposure to a significant event (e.g., tornado, earthquake, fire, or

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chemical spill). The staff finds this enhancement acceptable because, when the enhancement

is implemented, the Structures Monitoring Program will be consistent with the GALL Report and

provides additional assurance that the effects of aging will be adequately managed.

During the audit, the staff also requested that the applicant address the aging management of

inaccessible concrete areas and clarify the aggressiveness or non-aggressiveness of

groundwater.

In its response, the applicant provided its most recent groundwater monitoring results. By letter

dated August 31, 2007, the applicant amended LRA Section B2.1.32 to add the following

enhancement.

Enhancement 2. In the LRA amendment, the applicant credited an enhancement to the GALL

Report program element "parameters monitored or inspected." Specifically, the enhancement

states:

The Structures Monitoring Program will be enhanced to monitor groundwater for

pH, sulfates, and chlorides. Two samples of groundwater will be tested every five

years.

The staff finds this enhancement acceptable because monitoring of groundwater would verify

that aging effects due to an aggressive environment will not occur.

During the audit, the staff requested that the applicant explain why the LRA does not make

reference to documents or codes to be used as guidance for conducting a concrete condition

survey and to evaluate the existing safety-related concrete structures.

In its response, the applicant stated that the inspection methods, inspection frequency, and

inspector qualifications are in accordance with plant procedures, which reference American

Concrete Institute (ACI) 349.3R-96, American Society of Civil Engineers 11-90, and

ACI 201.1 R-92.

The staff finds the response acceptable because the appropriate references are provided.

Further, by letter dated August 31, 2007, the applicant adequately amended LRA

Section B2.1.32 to incorporate these references.

As a result of the onsite inspection performed by the staff during the weeks of September 10,

and October 22, 2007, the applicant added an enhancement to this program. By letter dated

November 16, 2007, the applicant amended LRA Section B2.1.32 to add the following:

Enhancement 3. In the LRA amendment, the applicant credited an enhancement to the GALL

Report program element "scope of the program." Specifically, the enhancement states:

Procedures will be enhanced to add disconnect enclosure and foundation in the

switchyard.

The staff finds, as described in SER Section 2.4.10, that the applicant added disconnects 13-21

and 13-23 within the scope of license renewal. The staff finds this enhancement acceptable

because it ensures that the subject component will be adequately monitored with this AMP.

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On this basis, the staff finds these enhancements acceptable because, when enhancements

are implemented, the Structures Monitoring Program will be consistent with the GALL Report

and provides additional assurance that the effects of aging will be adequately managed.

Operating Experience. LRA Section B2.1.32 states that the baseline walkdown inspection for

the Structures Monitoring Program occurred in 1998. The results of this inspection were

categorized primarily as "acceptable with minor degradation." All items found to have more

severe aging effects were categorized as "acceptable with degradation," reexamined, and

evaluated for further action. No items required a categorization of "major degradation." The

applicant stated that during the five-year reinspection in 2002-2003, four items had increased

degradation. Two previously categorized as "acceptable with degradation" are not within the

scope of license renewal and two previously categorized as "acceptable with minor

degradation" had increased degradation and were reclassified as "acceptable with

degradation." One item was corrosion on an essential service water hanger in the

communications corridor, the other corrosion on a steel column in the turbine building.

Corrective action has been initiated. Five new items categorized as "acceptable with

degradation" were reported during the 2002-2003 inspection. The applicant stated that none of

these items required immediate action to maintain their intended functions and all will be

monitored for future changes.

During the audit, the staff requested that the applicant clarify if a scope expansion was required

because of unacceptable conditions identified during the 2002-2003 inspection. In its response,

the applicant stated that all concrete structures and the components that are within the scope of

license renewal and covered by the Structures Monitoring Program are inspected and

compared to the acceptance criteria in accordance with ACI 201.1 R and ACI 349.3R. Specific

limits for each type of degradation are provided in applicable plant procedures. During the

5-year inspection in 2002-2003, only four items were identified as having increased aging

effects. Two of those items previously categorized as "acceptable with degradation" are not

within the scope of license renewal. Two items that were previously categorized as "acceptable

with minor degradation" were noted to have increased aging effects and reclassified as

"acceptable with degradation." One was corrosion on an essential service water hanger in the

communications corridor, and the other was corrosion on a steel column in the turbine building.

The applicant stated that five new items categorized as "acceptable with degradation" were

reported during the 2002-2003 inspection. Four of the items have been corrected including: (1)

platforms and ladders in the auxiliary building require painting, (2) grating in the auxiliary

building has missing clips, (3) grating in the DG building has a loose clip, and (4) structural steel

in the turbine building has corrosion. The fifth item, cracked flashing on a roof hatch in the

auxiliary building, will be monitored for future changes in aging effects. No scope expansion

was required. All items that remain classified as "acceptable with degradation" will be inspected

during the next inspection period. No cases of "major degradation" were found.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to confirm that the operating experience did not reveal degradations

that are not bounded by industry experience. In addition, the staff finds that the corrective

action program, which captures internal and external plant operating experience issues, will

ensure that operating experience is reviewed and incorporated in the future to provide objective

evidence to support the conclusion that the effects of aging are adequately managed.

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The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.32, the applicant provided the USAR supplement for the

Structures Monitoring Program. The applicant committed (Commitment No. 17) to enhance

procedures to add inspection parameters for treated wood. By letter dated May 25, 2007, the

applicant revised Commitment No. 17 to include monitoring of groundwater for pH, sulfates,

and chlorides. Two samples of groundwater will be tested every five years. By letter dated

November 16, 2007, the applicant amended LRA Section A1.32 to enhance the procedures to

add inspection parameters for the disconnect enclosures and foundations in the switchyard.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Structures Monitoring

Program, the staff determines that those program elements for which the applicant claimed

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements

and confirms that their implementation prior to the period of extended operation would make the

existing AMP consistent with the GALL AMP to which it was compared. The staff concludes that

the applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.22 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants

Summary of Technical Information in the Application. LRA Section B2.1.33 describes the

existing RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants Program as consistent, with enhancements, with GALL AMP XI.S7, "RG 1.127,

Inspection of Water-Control Structures Associated with Nuclear Power Plants."

Regulatory Guide 1.127 Inspection of Water Control Structures Associated with Nuclear Power

Plants Program manages aging due to extreme environmental conditions and the effects of

natural phenomena that may affect water-control structures. The applicant is committed to

RG 1.127, Revision 1. The program implements the requirements of 10 CFR 50.65, the

Maintenance Rule program that incorporates the guidance of RG 1.160, Revision 2, "Monitoring

the Effectiveness of Maintenance at Nuclear Power Plants," and Nuclear Management and

Resources Council (NUMARC) 93-01, Revision 2. This program includes:

* Periodic visual inspections of in-scope concrete structures using techniques from such

industry standards and codes as ACI 201.1 R.

* Periodic monitoring of the hydraulic and structural condition of the ultimate heat sink

(UHS) as prescribed in USAR Section 2.5.6.8.4, as well as its structures, main dam

service spillway, and auxiliary spillway.

* Periodic dredging of the UHS reservoir (every fifteen years) and channel (every five

years) connecting the reservoir to the ESW pumphouse.

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Survey of the UHS dam for vertical movement every five years and a complete profile

when warranted by unusual events.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancements to determine whether the AMP, with the

enhancements, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants Program, as listed in the audit summary, including the license renewal program

evaluation report in which the applicant assessed whether the program elements are consistent

with GALL AMP XI.S7.

During the audit, the staff requested that the applicant explain the baseline, past, and present

survey reading (i.e., vertical movements) of the UHS dam. The staff also requested that the

applicant clarify the acceptance criteria and provide any operating experience related to this

dam.

In its response, the applicant stated that the UHS dam is a normally submerged seismic

Category I earthen structure whose side slopes and crest are protected with riprap. The crest of

the dam was surveyed before being covered with riprap. The baseline survey of the settlement

monuments was completed after construction and before filling of the cooling lake and the

submergence of the UHS dam within the cooling lake. The settlement monuments are

anchored within the dam embankment and project above the riprap. Current dam elevations are

determined by subtracting the as-built top of monument elevation and as-built top of dam

elevation from the current monument elevation. The UHS dam elevation is required to be at or

above elevation 1,070 feet mean sea level. The minimum as-built elevation for the crest of the

dam was 1,070.30 feet mean sea level. The most recent elevation was found to be 1,070.24

feet. An elevation survey of the settlement monuments on the UHS dam demonstrated that the

top surface of the dam is at or above the required 1,070-foot elevation. The variances between

the new elevations and the adjusted previous years elevations revealed no abnormal changes,

trends or unsafe movements of the dam structure.

Since all of the as-found elevations were above the baseline of 1,070 feet, the staff finds the

applicant response acceptable.

Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program element "scope of the program." Specifically, the enhancement states:

Procedures will be enhanced so that the main dam service spillway and the

auxiliary spillway will be inspected in accordance with the same specification that

governs the other water control structures that are in-scope for license renewal.

During the audit, the staff reviewed the aging effects requiring management under the scope of

this AMP. The staff finds that WCGS is committed to RG 1.127, Revision 1, and has a program

in place that is consistent with the elements of this RG, as recommended in the GALL Report.

The program implements the requirements of 10 CFR 50.65 which incorporates the guidance of

RG 1.160, Revision 2, and NUMARC 93-01, Revision 2.

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The staff also finds that the plant's inspection frequency is at least once every five years based

on the acceptable inspection results from previous inspections. This is consistent with

RG 1.127, position C4. Concrete surface descriptions conform to ACI 201.1 R, "Guide for

Making a Condition Survey of Concrete in Service," and are consistent with the descriptions in

ACI 349.3R-96, "Evaluation of Existing Nuclear Safety-Related Concrete Structures."

The staff finds this enhancement acceptable because, when enhancements are implemented,

the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

Program will be consistent with the GALL Report and will provide assurance that the effects of

aging are adequately managed.

Enhancement 2. In the LRA, the applicant credited an enhancement to the GALL Report

program element "parameters monitored or inspected." Specifically, the enhancement states:

Procedures will be enhanced to clarify the scope of inspections for the main dam

service and auxiliary spillways, and to add cavitation to the list of concrete aging

effects for surfaces other than spillway.

During an audit, the staff noted that the concrete structures above water are inspected by the

plant's department of engineering. Structures below water are inspected by divers, whom

provide the results, evidence, and records for evaluation. Photographic records are obtained of

any unusual conditions. These inspections include a visual examination of concrete surfaces for

evidence of cracking, spalling, cavitation, and erosion movements, seepage, or separation.

Drains are examined for signs of blockage and clogging to ensure that they are performing

satisfactorily. Foundations are monitored for evidence of damage, distress, or possible

undermining. The auxiliary spillway and the main dam service spillway are examined for any

conditions that impose operational constraints on the functioning of the spillways. This includes

any conditions that may contribute to blockage, stability of slopes and cantilever walls, and

condition of outlet channels.

The staff finds the applicant's inspection program is acceptable since the corrective action

program will consider expanding the scope if significant degradation is observed.

On this basis, the staff finds this enhancement acceptable because, when implemented, the

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

Program, will be consistent with the GALL Report and will provide additional assurance that the

effects of aging will be adequately managed.

Enhancement 3. In the LRA, the applicant credited an enhancement to the GALL Report

program element "detection of aging effects." Specifically, the enhancement states:.

Procedures will be enhanced to add the 5-year frequency for inspecting the main

dam service spillway.

During an audit, the staff noted that the main dam service spillway is monitored once every five

years. Special examinations are performed if any unusual conditions arise. WCGS procedures

establish requirements for surveillance and require that special surveillances be performed

immediately after the occurrence of unusual events, including but not restricted to, 5-foot lake

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level fluctuations, earthquakes, tornadoes, or intense local rainfalls that occur during operation

period.

The staff finds that the applicant inspection program is acceptable since the corrective action

program will consider expanding the scope if significant degradation is observed.

The staff finds this enhancement acceptable because, when implemented, the RG 1.127,

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program will be

consistent with the GALL Report, and will provide additional assurance that the effects of aging

are adequately managed.

The staff reviewed those portions of the RG 1.127, Inspection of Water-Control Structures

Associated with Nuclear Power Plants Program for which the applicant claims consistency with

GALL AMP XI.S7 and finds that they are consistent with the GALL AMP. The staff finds the

applicant's RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants Program acceptable because it conforms to the recommended AMP, with the

enhancements described.

Operating Experience. LRA Section B2.1.33 states that the latest inspection report for the UHS

and its safety-related structures in 2002 concluded that there were no signs of unacceptable

conditions or deterioration of the safety-related water control structures. An elevation survey of

the settlement monuments on the UHS dam revealed no abnormal changes, trends, or unsafe

movements of the dam structure. The estimated sedimentation volume is within the acceptable

volume. The sediment in the channel is minimal due to the recent dredging. The inspection of

the main dam service and auxiliary spillways in 2004 found the concrete surfaces at the service

spillway and discharge chute in generally good condition. The applicant stated that previous

repairs are performing satisfactorily. No trees or deep-rooted vegetation was observed adjacent

to the chute. The concrete surfaces at the auxiliary spillway are also generally in good

condition. The approach area leading to the spillway and discharge channel was clear of

obstructions.

During the audit, the staff requested that the applicant explain why and when the repairs were

made to the main dam, service, and auxiliary spillways.

In its response, the applicant stated that the upstream main dam surface was repaired in 2001

near the water line with additional riprap due to the degradation and exposure of the sand and

gravel riprap base. The 2004 surveillance report noted that riprap slope protection was in good

condition and the repair work completed in 2001 adequately corrected deficiencies noted in the

1999 inspection. The main dam is not within the scope of license renewal because is not relied

upon to perform a safe shutdown and is under the jurisdiction of the Kansas Department of

Agriculture, Division of Water Resources.

The applicant stated that the 1999 surveillance report discusses the condition of the service

spillway. Some popouts and spalling have occurred and are being repaired as needed. The

ogee crest was grouted prior to 1999 and some minor seepage is returning. Emerging trees

were removed along the spillway channel in 1994 and 1999. The 2004 report states that

previous patching and grouting was holding up well. However, in 2006, it was found that the

previous repairs at joints in the floor of the service spillway chute have numerous shrinkage

cracks. Some of the repairs have broken loose exposing the original concrete. A work order

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was generated to address this condition. Some random cracking and spalling along the

concrete auxiliary spillway have been noted several times. The cracks were evaluated in 1999

and no serious deficiencies were determined. The approach and discharge channels have had

vegetation removed in the past and were reported clear of obstructions in the 2004 surveillance

report.

The staff reviewed the operating experience provided in the LRA and interviewed the

applicant's technical staff to confirm that the operating experience did not reveal degradations

that are not bounded by industry experience. In addition, the staff finds that the corrective

action program, which captures internal and external plant operating experience issues, will

ensure that operating experience is reviewed and incorporated in the future to provide objective

evidence to support the conclusion that the effects of aging are adequately managed.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A1.33, the applicant provided the USAR supplement for the

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

Program. The applicant committed (Commitment No. 18) to enhance procedures to: (1) inspect

the main dam service spillway and the auxiliary spillway, (2) clarify the scope of inspections for

the spillways, and add cavitation to the list of concrete aging effects for surfaces other than

spillways, and (3) add the 5-year inspection frequency for the main dam service spillway. The

staff reviewed this section and determines that the information in the USAR supplement is an

adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's "RG 1.127, Inspection of

Water-Control Structures Associated with Nuclear Power Plants Program," the staff determines

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent. Also, the staff reviewed the enhancements and confirms that their

implementation prior to the period of extended operation would make the existing AMP

consistent with the GALL AMP to which it was compared. The staff concludes that the applicant

has demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this

AMP and concludes that it provides an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

3.0.3.2.23 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Summary of Technical Information in the Application. LRA Section B2.1.36 describes the

existing Electrical Cable Connections Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program, as consistent, with enhancement, with GALL AMP XI.E6, "Electrical

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements."

The Electrical Cable Connections Not Subject to 10 CFR 50.49 EQ Requirements Program

manages the aging effects of loosening of bolted connections due to thermal cycling, ohmic

heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation so that

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electrical cable connections within the scope of license renewal not subject to 10 CFR 50.49 EQ

requirements can perform intended functions. Infrared thermography testing on a

representative sample of non-EQ electrical cable connections for active or passive components

within the scope of license renewal is part of the predictive maintenance program. The infrared

thermography testing detects loosening of bolted connections due to thermal cycling, ohmic

heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation. The

selected sample is based upon application (medium and low voltage), circuit loading

(energized, nonenergized during normal plant operations), and environment (plant indoor air).

The sample of non-EQ electrical cable connectors is representative, with reasonable

assurance, of non-EQ electrical cable connections within similar applications, circuit loading

conditions, and environments. The infrared thermography testing is on a six-month monitoring interval meeting the requirement of at least once every ten years. The sample of non-EQ

electrical cable connections within the scope of license renewal is tested for loosening of bolted

connections. The acceptance criteria for thermography testing are based on temperature rise

above the reference temperature. The reference temperature is the ambient temperature or the

baseline temperature data from the same type of connection as that tested. Corrective actions

for conditions adverse to quality are in accordance with the corrective action program as part of

the QA program. The corrective action process provides reasonable assurance that deficiencies

adverse to quality are either evaluated as acceptable or corrected promptly.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Electrical Cable Connections Not Subject to 10 CFR 50.49, Environmental

Qualification Requirements Program, as listed in the audit summary, including the license

renewal program evaluation report in which the applicant assessed whether the program

elements are consistent with GALL AMP XI.E6.

The GALL Report recommends tests, such as thermography, contact resistance testing or other

appropriate testing justified in the application. In addition, EPRI TR-104231, "Bolted Joint

Maintenance & Application Guide," recommends measuring contact resistance using a low ohm

meter to detect loose connections. In the Electrical Cable Connection Not Subject to

10 CFR 50.49 EQ Requirements Program, the applicant states that infrared thermography is

used to identify loose connections.

During the audit, the staff requested that the applicant explain how thermography is an effective

method for detecting loose connections or high resistance for cable connections in low current

or low load circuits where temperature rise may not be detectable.

In its response, the applicant stated that LRA Sections B2.1.36 and A1.36 will be amended to

include contact resistance testing, or other appropriate methods for low voltage, low current, or

low load circuit.

The staff finds the applicant's response acceptable because contact resistance testing is

effective for low voltage, low current, or low load circuit. Thermography may not be effective to

detect high resistance for cable connections in low voltage, low load, and low current circuits.

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By letter dated August 31, 2007, the applicant amended LRA Section B2.1.26 to state:

The acceptance criteria for thermography testing are based on the temperature rise

above the reference temperature. The reference temperature will be ambient

temperatures or the baseline temperature data from the same type of connections being

tested. A one-time inspection of a sample of low voltage low current or low load

connections will be performed prior to the period of extended operation. The inspection

will consist of contact resistance testing or other appropriate testing methods used to

identify loosening of low voltage low current or low load connections. The selected

sample will be based upon application (low voltage), circuit loading (low current or low

load), and environment (plant indoor air and outdoor air). The one-time inspection of a

sample of Non-EQ low voltage low current or low load connections is representative,

with reasonable assurance, of Non-EQ electrical cable connections within similar

applications, circuit loading conditions, and environments. The technical basis for the

sample selection will be documented. The acceptance criteria for each inspection are

defined by the specific type of test being performed on the connections. An engineering

evaluation will be performed when test acceptance criteria are not met. The evaluation

will include identifying the extent of condition, the potential root cause for not meeting

the test acceptance criteria, the likelihood of recurrence, and the need to expand the

sample size and/or frequency of the inspection.

The staff finds this acceptable because an appropriate testing program is identified for low

voltage, low current, or low load circuit connections.

The GALL Report also states that the location (e.g., high temperature, high humidity, etc.)

should be considered for cable connection sampling. In the Electrical Cable Connections Not

Subject to 10 CFR 50.49, Environmental Qualification Requirements Program, the applicant

stated that the selected sample only includes the plant indoor environment. The staff requested

that the applicant explain how the aging effect of loose connection or high resistance due to

corrosion is not a potential aging effect requiring management for electrical cable connections

in outdoor environment.

By letter dated August 31, 2007, the applicant amended LRA Section B2.1.26 to include

electrical cable connections in outdoor environments.

The staff finds the applicant's response acceptable because the cable connections in outdoor

environments are now included within the scope of this program and will be inspected. This

environment is consistent with the GALL Report.

Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program element "corrective action" Specifically, the enhancement stated:

Revise procedure I-ENG-005 to include an engineering evaluation that include

identifying the extent of condition to determine if the situation is applicable to

other in-scope Non-EQ electrical cable connections that are not part of the

testing sample, the potential root cause for not meeting the test acceptance

criteria and the likelihood of recurrence.

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The staff finds the enhancement acceptable because it will make the applicant's corrective

action element consistent with the GALL Report.

By letter dated August 31, 2007, the applicant amended LRA Section B2.1.26 to include the

following enhancement:

Enhancement 2. In the LRA, the applicant credited an enhancement to the GALL Report

program element "parameters monitored or inspected," "detection of aging effects," and

"acceptance criteria." Specifically, the enhancement stated:

A one-time inspection of a sample of low voltage low current or low load

connections will be performed prior to the period of extended operation. The

inspection will consist of contact resistance testing or other appropriate testing

methods used to identify loosening of low voltage, low current, or low load

connections.

The staff finds the enhancement acceptable because it will make the program consistent with

the staffs' proposed changes to GALL AMP X1 .E6 (Proposed License Renewal Interim Staff

Guidance LR-ISG-2007-02). The one time inspection, on a representative sampling basis, is to

ensure that aging of low voltage metallic cable connection is not occurring; hence, a periodic

inspection is not required.

The staff reviewed those portions of the Electrical Cables Connections Not Subject to

10 CFR 50.49, Environmental Qualification Requirements Program, for which the applicant

claims consistency with GALL AMP XI.E6 and finds that they are consistent with the GALL

AMP. The staff finds the applicant's enhancements to Electrical Cables Connections Not

Subject to 10 CFR 50.49, Environmental Qualification Requirements Program, acceptable

because it is consistent with the changes as recommended in the staff LR-ISG-2007-02.

Operating Experience. LRA Section B2.1.36 states that infrared thermography has been

performed routinely since 1989 on 189 electrical components. Plant-specific operating

experience shows a small number of scans of electrical connections with thermal anomaly. The

connections with these thermal anomalies were cleaned and re-tightened. The applicant stated

that no loss of component intended function has occurred.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Electrical Cable Connections Not Subject to 10 CFR 50.49

Requirements Program. The staff also interviewed selected onsite personnel who have

specialized knowledge of the program. The staff reviewed instances previously documented by

the applicant that identified issues with the Electrical Cable Connections Not Subject to

10 CFR 50.49 Requirements Program and where the applicant had implemented corrective

action. The staff finds that the operating experience did not reveal degradations that are not

bounded by industry experience and verified that the applicant's corrective actions were timely

and appropriate.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

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USAR Supplement. In LRA Section A1.36, the applicant provided the USAR supplement for the

Electrical Cable Connections Not Subject to 10 CFR 50.49, Environmental Qualification

Requirements Program. The applicant committed (Commitment No. 20) to enhance the infrared

thermograghy testing procedure to require an engineering evaluation when test acceptance

criteria are not met. This engineering evaluation will include identifying the extent of condition,

the potential root cause for not meeting the test acceptance, and the likelihood of recurrence.

By letter dated October 11, 2007, the applicant revised this commitment to state that a one-time

inspection of a representative sample of low voltage, low current, or low load connections will

be performed prior to the period of extended operation. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Electrical Cable Connections

Not Subject to 10 CFR 50.49, Environmental Qualification Requirements Program, the staff

determines that those program elements for which the applicant claimed consistency with the

GALL Report are consistent. Also, the staff reviewed the enhancements and confirms that their

implementation prior to the period of extended operation would make the existing

AMP consistent with the GALL AMP to which it was compared. The staff concludes that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement

for this AMP and concludes that it provides an adequate summary description of the program,

as required by 10 CFR 54.21 (d).

3.0.3.2.24 Metal Fatigue of Reactor Coolant Pressure Boundary

Summary of Technical Information in the Application. LRA Section B3.1 describes the existing

Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with

enhancements, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary."

The Metal Fatigue of Reactor Coolant Pressure Boundary Program manages cumulative fatigue

damage in metal components of the RCPB and analyzed Class 2 portions of the steam

generators. The program software counts operating transient cycles, applies analytical methods

to determine stress cycles and their contributions to fatigue usage factors, and tracks the

resulting fatigue cumulative usage factors (CUFs). The software maintains a record of CUFs at

bounding locations in Class 1 piping and vessels and in Class 2 steam generator parts with

Class 1 analyses. The Metal Fatigue of Reactor Coolant Pressure Boundary Program scope

includes applicable NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves

to Selected Nuclear Power Plant Components," monitoring locations (with one exception for

which the original fatigue analysis plus effects of the reactor coolant environment have been

validated for the period of extended operation). The program will include applicable action limits

for the NUREG/CR-6260 locations, allowances for environmental effects of the reactor coolant

as determined by NUREG/CR-6583 and NUREG/CR-5704 or, appropriate alternative methods,

and action limits for the bases of the leak-before-break (LBB) analysis and of the high-energy

line break (HELB) locations so they remain valid or appropriate corrective measures are taken.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancements, remains adequate to manage the aging effects for which it is credited.

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During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Metal Fatigue of Reactor Coolant Pressure Boundary Program, as listed in the

audit summary, including the license renewal program evaluation report in which the applicant

assessed whether the program elements are consistent with GALL AMP X.M1.

Enhancement 1. In the LRA, the applicant.credited an enhancement to the GALL Report

program elements "detection of aging effects" and "corrective actions." Specifically, the

enhancement stated:

Action levels of the Metal Fatigue of Reactor Coolant Pressure Boundary

Program will be enhanced to ensure that if the fatigue usage factor calculated by

the code analysis is reached at any monitored location, appropriate evaluations

and actions will be invoked to maintain the analytical basis of the LBB analysis

and of the HELB locations, or to revise them as required.

Action levels of the Metal Fatigue of Reactor Coolant Pressure Boundary

Program will be enhanced to ensure that appropriate evaluations and actions will

be invoked to maintain the bases of safety determinations that depend upon

fatigue analyses, if the fatigue usage factor at any of the monitored

NUREG/CR-6260 locations approaches 1.0 when multiplied by the

environmental effect factor FEN.

Action levels of the Metal Fatigue of Reactor Coolant Pressure Boundary

Program will be enhanced to ensure that appropriate evaluations and actions will

be invoked to maintain the bases of safety determinations that depend upon

fatigue analyses, if the fatigue usage factor at any monitored location

approaches 1.0.

Corrective actions of Metal Fatigue of Reactor Coolant Pressure Boundary

Program will be enhanced to ensure that on approach to an action limit, an

evaluation will determine whether the scope of the monitoring program must be

enlarged to include additional affected reactor coolant pressure boundary

locations; to ensure that other locations do not approach the code limit without

an appropriate action and that the bases of the LBB and HELB analyses are

maintained.

The staff reviewed the fatigue management procedure listed in the audit summary. The staff did

not find any action levels or corrective actions defined in the procedure. The staff requested

that the applicant explain what it meant by action levels and corrective actions and where they

are defined.

By letter dated October 3, 2007, the applicant amended this enhancement to:

(1) Include a cycle count action limit and corrective actions. An action limit

will be established that requires corrective action when the cycle count for

any of the critical thermal and pressure transients is projected to reach a

high percentage (e.g., 90%) of the design specified number of cycles

before the end of the next fuel cycle. If this action limit is reached,

acceptable corrective actions include:

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(a) Review of fatigue usage calculations:

" To determine whether the transient in question contributes

significantly to CUF

* To identify the components and analyses affected by the transient

in question

* To ensure that the analytical bases of the leak-before-break (LBB)

fatigue crack propagation analysis and of the high-energy line

break (HELB) locations are maintained.

(b) Evaluation of remaining margins on CUF based on cycle-based or

stress-based CUF calculations using the WCGS fatigue

management program software.

(c) Redefinition of the specified number of cycles (e.g., by reducing

specified numbers of cycles for other transients and using the

margin to increase the allowed number of cycles for the transient

that is approaching its specified number of cycles).

(2) Include a cumulative fatigue usage action limit and corrective actions. An

action limit will be established that requires corrective action when

calculated CUF (from cycle based or stress based monitoring) for any

monitored location is projected to reach 1.0 within the next 2 or 3 fuel

cycles. If this action limit is reached, acceptable corrective actions

include:

(a) Determine whether the scope of the monitoring program must be

enlarged to include additional affected reactor coolant pressure

boundary locations. This determination will ensure that other

locations do not approach design limits without an appropriate

action.

(b) Enhance fatigue monitoring to confirm continued conformance to

the code limit.

(c) Repair the component.

(d) Replace the component.

(e) Perform a more rigorous analysis of the component to demonstrate that

the design code limit will not be exceeded.

(f) Modify plant operating practices to reduce the fatigue usage

accumulation rate.

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(g) Perform a flaw tolerance evaluation and impose component-specific

inspections, under ASME Section XI Appendices A or C (or their

successors), and obtain required approvals by the NRC.

Corrective action limits for cumulative fatigue usage will be established to assure

that sufficient margin is maintained to allow one cycle of the highest fatigue

usage per cycle transient to occur without exceeding CUF = 1.0. (This includes

consideration of environmental effects for NUREG/CR6260 locations.) This may

require that corrective action is taken more than 2 or 3 fuel cycles before CUF is

projected to exceed 1.0.

This is because the projections will be based on historical experience, which is

not expected to include many of the low probability design transients. The low

probability design transients to be used in the evaluation will include:

" aux. spray actuation, spray water diff. >320 F

* excessive feedwater flow

* reactor trip - cooldown with no SI

* COMS

* reactor trip - no inadvertent cooldown with turbine over-speed

* reactor trip - cooldown with SI

* inadvertent RCS depressurization

* accumulator safety injection

* operating basis earthquake

(3) Include a 10 CFR 50 Appendix B procedural and record requirements.

The staff finds this response acceptable because appropriate action limits and associated

corrective actions have been defined. The staff finds the enhancement acceptable because,

when the enhancement is implemented, the Metal Fatigue of Reactor Coolant Pressure

Boundary Program will be consistent with the GALL Report.

Enhancement 2. In the LRA, the applicant credited an enhancement to the GALL Report

Program element "confirmation process." Specifically, the enhancement stated:

The WCGS Metal Fatigue of Reactor Coolant Pressure Boundary Program will

be enhanced to invoke Appendix B procedural and record requirements.

The staff finds that after implementation of this enhancement, the program element would be

consistent with the GALL Report. On this basis, the staff finds this enhancement acceptable.

The staff reviewed those portions of the Metal Fatigue of Reactor Coolant Pressure Boundary

Program for which the applicant claims consistency with GALL AMP X.M1 and finds that they

are consistent with the GALL AMP. The staff finds the applicant's Metal Fatigue of Reactor

Coolant Pressure Boundary Program acceptable because it conforms to the recommended

AMP, with the enhancements described.

Operating Experience. LRA Section B3.1 states that EPRI developed the methods of the

existing fatigue monitoring programs for the industry in response to staff concerns that early-life

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operating cycles at some units caused fatigue usage factors to accumulate more rapidly than

anticipated in design analyses. Therefore, the Metal Fatigue of Reactor Coolant Pressure

Boundary Program was designed to ensure that the code would not be exceeded in the

remainder of the licensed life. The operating experience program reviews applicable industry

experience with fatigue monitoring for evaluation and incorporation into plant analyses and

procedures. Any necessary evaluations are conducted under the plant corrective action

program.

The staff finds that the program has remained responsive to emerging issues and concerns,

particularly:

* Pressurizer surge and spray nozzle, hot leg surge nozzle, and surge line transients. This

concern prompted operation with continuous spray during startup and shutdown

transients and inclusion of these locations in the Metal Fatigue of Reactor Coolant

Pressure Boundary Program.

* Axisymmetric thermal shock and thermal striping in the steam generator feedwater

nozzles. Evaluation of low-flow transients in the feedwater (FW) nozzles raised concerns

over transients driven by thermal instability under these conditions with possible thermal

shock, thermal stratification bending, and skin-effect thermal striping. WCGS installed

additional monitoring points for the fatigue monitoring system to collect data during

operation and developed unique correlations ("transfer functions") to calculate these

effects.

* Reduction and equalization of fatigue usage factor accumulation rate in charginq

nozzles. Westinghouse and WCGS found that operating practices where cycling flow

through the active primary loop charging nozzle were performed more often than

necessary and failed to use the two nozzles equally, causing fatigue usage to

accumulate at a rate higher than that indicated by the code analysis. Operations

modified procedures and practices to reduce cycling and to equalize it between the two

charging nozzles. The Metal Fatigue of Reactor Coolant Pressure Boundary Program

evaluated the nozzle CUF to date and now tracks fatigue in these nozzles.

Results of fatigue monitoring to date indicate that the number of design transient events

assumed by the original design analysis is sufficient and that the design-basis fatigue CUF limit

of 1.0 will not be exceeded at the monitored locations for a 60-year licensed operating period.

During the audit, the staff reviewed implementing procedures and problem identification reports

related to the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program. The

staff also interviewed selected onsite personnel who have specialized knowledge of the

program. The staff reviewed instances previously documented by the applicant that identified

issues with the Metal Fatigue of Reactor Coolant Pressure Boundary Program and where the

applicant had implemented corrective action. The staff verified that the applicant's corrective

actions were timely and appropriate.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

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USAR Supplement. In LRA Section A2.1, the applicant provided the USAR supplement for the

Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant committed

(Commitment No. 21) to enhance the program. By letter dated October 3, 2007, as stated

under the staff evaluation, enhancement 1, the applicant amended this commitment to include:

(1) a cycle count action limit and corrective actions, (2) a cumulative fatigue usage action limit

and corrective actions, and (3) 10 CFR 50, Appendix B, procedural and record requirements.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Metal Fatigue of Reactor

Coolant Pressure Boundary Program, the staff determines that those program elements for

which the applicant claimed consistency with the GALL Report are consistent. Also, the staff

reviewed the enhancements and confirms that their implementation prior to the period of

extended operation would make the existing AMP consistent with the GALL AMP to which it

was compared. The staff concludes that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the USAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.25 Environmental Qualification (EQ) of Electrical Components

Summary of Technical Information in the Application. LRA Section B3.2 describes the existing

Environmental Qualification (EQ) of Electrical Components Program as consistent, with

enhancement, with GALL AMP X.E1, "Environmental Qualification (EQ) of Electrical

Components."

The Environmental Qualification (EQ) of Electrical Components Program manages component

thermal, radiation, and cyclical aging by evaluations based on 10 CFR 50.49(f) qualification

methods. As required by 10 CFR 50.49, EQ components not qualified for the current license

term must be refurbished or replaced or their qualifications extended prior to reaching the aging

limits established in the evaluation. EQ component aging evaluations that specify a qualification

of at least 40 years are considered time-limited aging analyses (TLAAs). The Environmental

Qualification (EQ) of Electrical Components Program is consistent with 10 CFR 50.49,

NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related

Electrical Equipment," and RG 1.89, "Environmental Qualification of Certain Electric Equipment

Important to Safety for Nuclear Power Plants," Revision 1, for maintenance of equipment

qualification. Qualified components and their service requirements and environments are

identified in controlled documents containing a master list of affected equipment, replacement

and maintenance information, and local environment descriptions.

Staff Evaluation. During its audit, the staff reviewed the applicant's claim of consistency with the

GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

During the audit, the staff interviewed the applicant's technical staff and reviewed documents

related to the Environmental Qualification (EQ) of Electrical Components Program, as listed in

the audit summary, including the license renewal program evaluation report in which the

applicant assessed whether the program elements are consistent with GALL AMP X.EI.

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Enhancement. In the LRA, the applicant credited an enhancement to the GALL Report program

element "acceptance criteria." Specifically, the enhancement stated:

The program documents will be enhanced to describe methods that may be used

for qualified life evaluations for the period of extended operation.

In LRA Section B3.2, the applicant states that components that are not qualified for the current

license term must be refurbished or replaced or their qualifications extended prior to reaching

the aging limits established in the evaluation. Furthermore, in the LRA, the applicant described

the methods that may be used for extending qualified life evaluation. These methods include

analytical methods, data collection and reduction methods, underline assumptions, and

acceptance criteria and corrective actions. The applicant also stated that the Environmental

Qualification (EQ) of Electrical Components Program is an existing program and, following

enhancement, will be consistent with the GALL Report.

During the audit, the staff requested that the applicant explain methods that may be used for

qualified life evaluation for the period of extended operation.

In its response, the applicant stated that LRA Sections A2.3 and B3.2, and Commitment No. 22

for Environmental Qualification (EQ) of Electrical Components Program will be amended to

remove this enhancement. The current plant program methods will be used for qualified life

evaluation during the period of extended operation.

The staff finds the applicant's response acceptable because the current Environment

Qualification (EQ) of Electrical Component Program already includes methods for extending the

qualified life of these electrical components pursuant 10 CFR 50.49. If the qualification life can

not be extended, the environmentally qualified component will be replaced or refurbished.

By letter dated August 31, 2007, the applicant amended LRA Section B3.2 to delete this

enhancement.

The staff reviewed those portions of the Environmental Qualification (EQ) of Electrical

Components Program for which the applicant claims consistency with GALL AMP X.E1 and

finds that they are consistent with the GALL AMP. The staff finds the applicant's Environmental

Qualification (EQ) of Electrical Components Program acceptable because it conforms to the

recommended AMP.

Operating Experience. LRA Section B3.2 states that the Environmental Qualification (EQ) of

Electrical Components Program is consistent with 10 CFR 50.49, NUREG-0599, and RG 1.89

and considers operating experience for determining qualification bases and conclusions,

including qualified life. Operating experience and system-, equipment-, or component-related

information as reported through NRC Bulletins, INs, GLs, and 10 CFR Part 21 Notifications are

evaluated for applicability. The applicant stated that when an emerging industry aging issue

affects the qualification of an EQ component, the affected component is evaluated and

appropriate corrective actions are taken. Any change to the qualification evaluations is

documented in the affected EQ work packages with any applicable corrective actions. Issues

addressing equipment aging are reconciled in sections that specifically document thermal-,

radiation-, and cyclic-qualified lives.

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During the audit, the staff requested that the applicant provides examples of operating

experience that the Environment Qualification (EQ) of Electrical Components Program has

succeeded in managing aging degradation in a timely manner. The staff also requested the

applicant describe any corrective action or program enhancement as a result of these operating

experiences.

In its response, the applicant stated that the preventive maintenance program manages

age-related replacement and refurbishment of equipment, and surveillance activities based on a

schedule dictated by the Environment Qualification Summary Document (EQSD) I1l. Any

unexpected adverse conditions identified during operational and maintenance activities with

regard to age degradation issues would be managed through the plant's corrective action

program or by generating a work order that should be assigned to the program engineer. The

environment qualification program engineer also reviews and evaluates industry operating

experience and other sources of information (e.g., Scientec's monthly newsletter) for

applicability to WCGS and, where necessary, implements the corrective actions.

The applicant also stated that no examples of age-related failure of environmentally qualified

equipment was identified. Several examples of industry operating experience that were

reviewed required no further action at WCGS.

The staff finds the applicant's response acceptable because the plant operating experience with

the existing Environment Qualification (EQ) of Electrical Components Program shows that the

implementation of this AMP has been successful managing age degradation.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A2.2, the applicant provided the USAR supplement for the

Environmental Qualification (EQ) of Electrical Components Program. By letters dated May 25

and August 31, 2007, the applicant revised LRA Sections A2.2 and B3.2 to remove the stated

enhancement and to delete Commitment No. 22. The staff reviewed this section and

determines that the information in the USAR supplement is an adequate summary description

of the program, as required by 10 CFR 54.21 (d).

Conclusion. On the basis of its audit and review of the applicant's Environmental Qualification

(EQ) of Electrical Components Program, the staff determines that those program elements for

which the applicant claimed consistency with the GALL Report are consistent. The staff

concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21 (d).

3.0.3.2.26 Concrete Containment Tendon Prestress

Summary of Technical Information in the Application. LRA Section B3.3 describes the existing

Concrete Containment Tendon Prestress Program as consistent, with enhancements, with

GALL AMP X.S1, "Concrete Containment Tendon Prestress."

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The Concrete Containment Tendon Prestress Program manages the loss of tendon prestress in

the post-tensioning system, which consists of inverted U-shaped tendons extending up through

the basemat through the full height of the cylindrical walls and over the dome and of horizontal

circumferential (hoop) tendons at intervals from the top of the basemat to about the 45-degree

elevation of the dome. The basemat is conventionally reinforced. The tendons are ungrouted in

grease-filled ducts.

Staff Evaluation. During its audit, the staff evaluated the applicant's claim of consistency with

the GALL Report. The staff reviewed the enhancement to determine whether the AMP, with the

enhancement, remains adequate to manage the aging effects for which it is credited.

Enhancement 1. In the LRA, the applicant credited an enhancement to the GALL Report

program element "scope of program." Specifically, the enhancement stated:

Procedures which list surveillance tendons will be extended to include random

samples for the 40, 45, 50, and 55-year surveillances.

The staff reviewed LRA Section B3.3 and identified areas in which additional information was

necessary to complete the review of the applicant's AMP. The applicant responded to the staff's

RAIs as discussed below.

In RAI B3.3-1 dated April 10, 2007, the staff requested that the applicant discuss the

differences between the enhanced procedures and the current procedures.

In its response, dated May 9, 2007, the applicant stated that the current procedures contain a

list of specific tendons for each surveillance up to and including year 35. Tendons for

surveillance have been selected in a random manner and are representative of the various

types of tendons and conditions of exposure existing in containment. This enhancement only

adds lists of additional randomly selected surveillance tendons for the 40, 45, 50 and 55-year

surveillances. These additional surveillance tendons will be selected on the same basis as the

surveillance tendons currently listed in the procedures for the intervals through year 35.

Based on its review, the staff finds the applicant's response to RAI B3.3-1 acceptable because

it clarified that the enhancement is credited to include additional randomly selected surveillance

tendons for the 40, 45, 50 and 55-year surveillances. Therefore, the staff's concern described in

RAI 63.3-1 is resolved.

Enhancement 2. In the LRA, the applicant credited an enhancement to the GALL Report

program elements "monitoring and trending," and "acceptance criteria." Specifically, the

enhancement stated:

Procedures will be enhanced to explicitly require a regression analysis for each

tendon group after every surveillance; and to invoke and describe regression

analysis methods used to construct the lift-off trend lines, including the use of

individual tendon data in accordance with Information Notice (IN) 99 10,

'Degradation of Prestressing Tendon Systems in Prestressed Concrete

Containments.'

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In RAI B3.3-2 dated April 10, 2007, the staff requested that the applicant discuss the

differences between the current regression analysis method and the enhanced regression

analysis method. The staff also requested that the applicant describe the regression analysis

methods used to construct the lift-off trend lines.

In its response, dated May 9, 2007, the applicant stated that there is no difference for the

regression analysis between the enhanced method for the period of extended operation and the

current method and that the method is consistent with NRC IN 99-10, "Degradation of

Prestressing Tendon System in Prestressed Concrete Containment."

Based on its review, the staff finds the applicant's response to RAI B3.3-2 acceptable because

it clarified that the regression analysis method is consistent with NRC IN 99-10. Therefore, the

staff's concern described in RAI B3.3-2 is resolved.

Enhancement 3. In the LRA, the applicant credited an enhancement to the GALL Report

program element "monitoring and trending." Specifically, the enhancement stated:

Surveillance program predicted force lines for the vertical and hoop tendon

groups will be extended to 60 years.

The staff finds this enhancement acceptable because it will make the applicant's program

elements consistent with the GALL Report.

Enhancement 4. In the LRA, the applicant credited an enhancement to the GALL Report

program element "corrective actions." Specifically, the enhancement stated:

Procedure descriptions of acceptance criteria action levels will be revised to

conform to the ASME Code, Subsection IWL 3221 descriptions.

The staff finds this enhancement acceptable because it will make the applicant's corrective

action program element consistent with the GALL Report.

Operating Experience. LRA Section B3.3 states that tendon inspections have shown no

evidence of significant corrosion or other effects that might damage wires, no wire breakage

(after initial installation), nor any accelerated loss of prestress due to high temperatures. The

most recent 20-year surveillance results of the Concrete Containment Tendon Prestress

Program include an examination and regression analysis of all tendon prestress surveillance

data through the most recent inspection consistent with IN 99-10, Attachment 3, (i.e., use of

individual-tendon data rather than averages); and therefore, incorporates the entire history of

tendon prestress surveillance at this unit. The applicant stated that the surveillance found that

loss of prestress in all tendons tested was less than that originally predicted. Extended to 60

years, the regression analysis demonstrated that prestress in both the vertical and horizontal

("hoop") tendon groups should remain above minimum required values for at least 60 years of

operation and that all tendons should maintain their design-basis function without retensioning

for the period of extended operation. Similarly, individual-tendon data from the "common

tendons" (one vertical and one horizontal, the prestress of which is measured at each

surveillance) or from other sample tendons tested to date show no loss of prestress sufficient to

indicate any possible need for retensioning for at least 60 years. In addition, the applicant

stated that the material conditions of other components (concrete, bearing surfaces, grease,

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buttonheads, etc.) showed only minor degradation in a few areas, none indicating any need for

significant corrective action.

The staff reviewed instances previously documented by the applicant that identified issues with

the Concrete Containment Tendon Prestress Program to determine whether the applicant had

implemented timely and appropriate corrective action. The staff finds that the tendon

inspections have shown no evidence of significant corrosion or other effects that might damage

wires, no wire breakage, nor any accelerated loss of prestress due to high temperatures. The

staff finds that there have been no incidents or material conditions requiring the need for

corrective actions.

The staff confirmed that the "operating experience" program element satisfies the criterion

defined in the GALL Report and in SRP-LR Section A. 1.2.3.10; therefore, the staff finds this

program element acceptable.

USAR Supplement. In LRA Section A2.3, the applicant provided the USAR supplement for the

Concrete Containment Tendon Prestress Program. The applicant committed (Commitment

No. 23) to enhance plant procedures to: (1) extend the list of surveillance tendons to include

random samples for the year 40, 45, 50, and 55-year surveillances, (2) require a regression

analysis for each tendon group after every surveillance, (3) invoke and describe regression

analysis methods used to construct the lift-off trend lines, (4) extend surveillance program

predicted force lines for the vertical and hoop tendon groups to 60 years, and (5) conform

procedure descriptions of acceptance criteria action levels to the ASME Code,

Subsection IWL 3221 descriptions. The staff reviewed this section and determines that the

information in the USAR supplement is an adequate summary description of the program, as

required by 10 CFR 54.21 (d).

Conclusion. On the basis of its review of the applicant's Concrete Containment Tendon

Prestress Program, the staff determines that those program elements for which the applicant

claimed consistency with the GALL Report are consistent. Also, the staff reviewed the

enhancement and confirms that their implementation prior to the period of extended operation

would make the existing AMP consistent with the GALL AMP to which it was compared. The

staff concludes that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the

USAR supplement for this AMP and concludes that it provides an adequate summary

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as plant-specific:

" Nickel Alloy Aging Management Program

* Reactor Coolant System Supplement

For AMPs not consistent with or not addressed in the GALL Report the staff performed a

complete review to determine their adequacy to monitor or manage aging. The staff's review of

these plant-specific AMPs is documented in the following sections.

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3.0.3.3.1 Nickel Alloy Aging Management Program

Summary of Technical Information in the Application. LRA Section B2.1.34 describes the

existing Nickel Alloy Aging Management Program as a plant-specific program.

The plant-specific Nickel Alloy Aging Management Program manages cracking due to PWSCC

in all plant locations that contain Alloy 600, with the exception of steam generator tubing,

including RCS pressure boundary, and non-pressure boundary, and ESF locations. Aging

management requirements for nickel alloy penetration nozzles welded to the upper reactor

vessel closure head noted in the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor

Vessel Closure Heads of Pressurized Water Reactors Program are included here for review

convenience. The term "Alloy 600" used throughout this program represents Nickel Alloy 600

material and Nickel Alloy 82/182 weld metal. Non-Alloy 600 components, such as components

made of Nickel Alloy 690 or Nickel Alloy 52/152, are not included in this program but are subject

to ASME Code Section XI Inservice Inspection Program requirements.

The Nickel Alloy Aging Management Program uses inspections, mitigation techniques, repair,

replacement, and monitoring of operating experience to manage Alloy 600 aging. Mitigation

techniques are implemented preemptively when appropriate to remove conditions that

contribute to PWSCC. Repair or replacement proactively removes or overlays Alloy 600 or

corrects unacceptable flaws in the material. Mitigation and repair or replacement are consistent

with the guidance of MRP-1 39. Operating experience was reviewed for the risk rankings of

each Alloy 600 location. Operating experience is monitored continuously to improve and modify

the Nickel Alloy Aging Management Program as needed.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in

LRA Section B2.1.34 on the applicant's demonstration of the Nickel Alloy Aging Management

Program to ensure that the effects of aging, as discussed above, will be adequately managed

so that the intended function(s) will be maintained consistent with the CLB for the period of

extended operation.

The staff reviewed LRA Section B.2.1.34 and identified areas in which additional information

was necessary to complete the review of the applicant's AMP. The applicant responded to the

staff's RAIs as discussed below.

In RAI B2.1.34-2 dated April 11, 2007, the staff noted that PWSCC of components made of

Alloy 600/82/182 in PWRs is an emerging material degradation issue. The industry has initiated

augmented inspections and mitigation of susceptible components to ensure safe operation of

the affected plants. Recent inspection findings of extensive circumferential cracking of

Alloy 82/182 dissimilar metal welds at WCGS has raised concerns regarding the adequacy of

the inspection scope and schedule based on industry initiatives. In addition, discussions with

the industry to resolve the staff's comments and recommendations to the inspection program

delineated in the Materials Reliability Program (MRP)-139, "Primary System Butt Weld

Inspection and Evaluation Guideline," is continuing.

Therefore, to ensure that the program is acceptable for implementation during the period of

extended operation and that the applicant will manage the effects of aging in accordance with

10 CFR 54.21 (a)(3), the staff requested that the applicant commit to continue to participate in

industry initiatives, such as the Westinghouse Owners Group and the EPRI MRP. The program

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inspection requirements of Alloy 600/82/182 components must be consistent with the latest

version of the staff accepted industry guidance, generic communications, orders, and

applicable regulatory requirements delineated in 10 CFR 50.55a. In addition, the staff

requested that the applicant submit the AMP inspection plan for staff review and approval at

least 24 months prior to entering the period of extended operation.

In its response, dated May 10, 2007, the applicant provided its commitment (Commitment

No. 30). By letter dated October 11, 2007, the applicant modified this commitment to state:

The WCNOC Nickel Alloy Aging Management Program will be supplemented

with implementation of applicable (1) NRC Orders, Bulletins and Generic Letters

associated with nickel alloys, (2) staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the

EPRI Materials Reliability Program, for managing aging effects associated with

nickel alloys, and (4) upon completion of these programs, but not less than 24

months before entering the period of extended operation, WCNOC will submit an

inspection plan for reactor coolant system nickel alloy pressure boundary

components to the NRC for review and approval.

The staff finds the applicant's responses to RAI B2.1.34-2 acceptable because the applicant

committed to continue to participate in industry initiatives, to incorporate inspection

requirements consistent with the staff accepted guidance, and to submit the inspection plan for

staff review and approval. The staff's concern described in RAI B2.1.34-2 is resolved.

In RAI B2.1.34-1 dated April 11, 2007, the staff noted that the Nickel Alloy Aging Management

Program at WCGS was submitted prior to the performance of pre-mitigation weld inspections

for the application of weld overlays on pressurizer connections with dissimilar metal butt welds.

The pre-mitigation inspection performed in 2006 identified extensive circumferential cracking at

three dissimilar metals welds associated with surge, relief, and safety nozzles.

The staff requested that the applicant revise this AMP to incorporate information pertaining to

the dissimilar metals butt weld inspection activities and findings. Therevised AMP should: (1)

discuss program enhancements incorporated as a result of the inspections, (2) provide

information regarding the mitigation and preventive actions, taken or planned, to reduce the

susceptibility of Alloy 600/82/182 components to PWSCC, (3) discuss the inspection frequency

and method of inspection of components susceptible to PWSCC covered under the scope of

this program, and (4) provide justification that the AMP will provide reasonable assurance that

PWSCC will be detected on a timely manner.

In its response, dated May 10, 2007, the applicant stated that the following changes to the

plant's Alloy 600 program resulted from the circumferential cracking identified in 2006:

(1) Examinations have been added to the program as a result of the 2006

operating experience. Visual examination of bottom mounted nozzles are

performed every other refueling outage. A baseline volumetric

examination was performed during Refueling Outage 14 (Spring 2005) on

all hot leg nozzles, cold leg nozzles and bottom mounted nozzles.

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(2) Wolf Creek Nuclear Operating Corporation's (WCNOC) program provides

for mitigation of reactor coolant system pipe butt welds containing alloy

600. Mitigation plans are prioritized in accordance with risk rankings listed

in WCNOC Procedure "Program Plan for Management of Alloy 600

Components and Alloy 82/182 Welds," WCRE-1 5 Attachment A.

Pressurizer surge, relief, safety, and spray nozzles containing alloy 600

material have been overlayed with alloy 690. WCNOC's program directs

subsequent examinations of these nozzles to be performed in

accordance with "Primary System Butt Weld Inspection and Evaluation

Guideline," Materials Reliability Program (MRP-139). Options for

mitigating reactor coolant loop nozzles are currently being evaluated.

(3) There have been no changes to the frequency or method of inspection

other than those identified in (1) and (2) above.

(4) The WCNOC alloy 600 program provides reasonable assurance that

primary water stress corrosion cracking (PWSCC) degradation will be

detected in a timely manner because examination plans optimize

inspection intervals and techniques, and maximize the likelihood of

detecting a flaw prior to impact on plant safety and reliability. Alloy 600

inspection activities are included as augmented actions in the Inservice

Inspection (ISI) program, and include bare metal visual (BMV), surface,

and volumetric examinations as directed by regulatory and industry

guidance. Inspection of components, where susceptible material is used

as a pressure boundary for the primary system, meets or exceeds

industry and regulatory guidance. The program incorporates

plant-specific and industry operating experience. WCNOC has taken a

proactive approach in mitigating the pressurizer nozzles via structural

weld overlay and has included locations having susceptible material

exposed to primary water in the Alloy 600 program. As part of this

program WCNOC is considering available options for repairing/mitigating

the reactor loop nozzles. This proactive approach applies to other high

risk or high probability locations as well.

In addition, by letter dated July 26, 2007, the applicant amended the Nickel Alloy Aging

Management Program described in LRA Section B2.1.34.

The staff reviewed the amended Nickel Alloy Aging Management Program against the

AMP elements found in SRP-LR Section A.1.2.3, and in SRP-LR Table A.1-1, focusing on how

the program manages aging effects through the effective incorporation of 10 elements (i.e., "scope of the program," "preventive actions," "parameters monitored or inspected," "detection of

aging effects," "monitoring and trending," "acceptance criteria," "corrective actions," "confirmation process," "administrative controls," and "operating experience").

The applicant indicated that prograri elements (7) "corrective actions," (8) "confirmation

process," and (9) "administrative controls" are parts of the site-controlled QA program. The

staff's evaluation of the QA program is documented in SER Section 3.0.4. Evaluation of the

remaining seven elements follows:

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(1) Scope of the Program - LRA Section 82.1.34 as amended, states with the exception of

steam generator tubing, which is managed by the Steam Generator Tube Integrity

Program, all Alloy 600 locations in plants systems such as RCS pressure boundary,

RCS non-pressure boundary, and ESF locations are included within the scope of this

program.

In RAI B2.1.34-6 dated April 11, 2007, the staff requested that the applicant identify all

nickel Alloy 600 components that are within the scope of this program and its

corresponding inspection plan.

In its response, dated May 10, 2007, the applicant provided a table which identified all

Alloy 600 component locations in the reactor vessel, pressurizer, steam generator,

reactor coolant piping and ESF.

During telephone conferences dated June 21, and August 17, 2007, the staff noted that

the applicant's response required clarification. The staff requested that the applicant

describe what kind of examinations will be performed at each component or weld

location and clarify the meaning of the term generator maintenance.

In its responses dated July 26, and September 27, 2007, the applicant provided

inspection methods and frequencies for these components. The applicant also defined

the term generator maintenance and added footnotes in the component table to provide

clarification and consistency.

The staff reviewed the table provided by the applicant and confirmed that, with the

exception of steam generator tubing, all Alloy 600 components are included within the

scope of this program.

The staff finds the applicant's responses to RAI B2.1.34-6 acceptable because it

adequately described the nickel Alloy components that are within the scope of the AMP.

The staff's concern described in RAI B2.1.34-6 is resolved.

The staff confirmed that the "scope of the program" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.1; therefore, the staff finds this program

element acceptable.

(2) Preventive Actions - LRA Section B2.1.34, as amended, states that the program has

many potential mitigation strategies that remove one or more of the three conditions that

control PWSCC (i.e., susceptible material, tensile stress field, supporting environment).

Mitigation activities that have been successfully performed at PWRs include weld

overlays, replacement of Alloy 600 (as a pre-planned activity), and mechanical stress

improvement process. Mechanical stress improvement process is a mechanical process

that places the component surface in contact with the primary water in a compressive

state, thereby removing the tensile which contribute to the initiation and growth of

PWSCC.

The applicant stated that full structural weld overlays may be used either as a mitigation

strategy or as a repair method. This method provides structural reinforcement at the

(potentially) flawed location, such that adequate load-carrying capability is provided by

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the overlay. The considerations used by the Nickel Alloy Aging Management Program in

selecting a mitigation strategy include availability of method, industry experience, plant

location, risk evaluation, and pre-implementation activities.

The applicant stated that the program lists the recommended mitigation strategies for all

of the Alloy 600 components. Mitigation strategies for several components must still be

determined. Specific mitigation strategies will be determined by plant-specific and

industry operating experience. The Water Chemistry Program provides preventive

actions for monitoring and control of the supporting environment for PWSCC.

As previously discussed, in its response to RAI B2.1.34-1 dated May 10, 2007, the

applicant stated that WCNOC has taken a proactive approach in mitigating the

pressurizer nozzles via structural weld overlay and has included locations having

susceptible material exposed to primary water in the Alloy 600 program.

During a telephone conference dated June 21, 2007, the staff requested that the,

applicant identify all the components of weld locations for which the proactive approach

will be applied.

,In its response dated July 26, 2007, the applicant stated that the proactive approach will

-apply to locations having susceptible material exposed to primary water in the Alloy 600

program. The approach uses mitigation strategies that occur before repair or

replacement actions become mandatory. Currently, the applicant is considering

available options for repairing or mitigating the reactor coolant loop nozzles. The

applicant clarified that no other mitigation strategies are projected for the next 5 years;

however, current locations may change over time based on plant and industry operating

experience.

The applicant stated that a full structural weld overlay was applied to the following

locations in the Fall of 2006 during Refueling Outage 15:

" pressurizer safety and relief nozzle safe-end weld

• pressurizer surge line nozzle safe-end weld

* pressurizer spray nozzle safe-end weld

The staff finds the applicant's response acceptable because it clarified how WCGS

applies the proactive approach and listed the components to which a weld overlay was

applied.

The staff confirmed that the "preventive actions" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.2; therefore, the staff finds this program element

acceptable.

(3) Parameters Monitored or Inspected - LRA Section B2.1.34, as amended, states that the

program utilizes various inspection and examination techniques for early detection of

PWSCC in Alloy 600 components. The examination techniques include: (1) visual

examination to detect evidence of leakage from pressure retaining components due to

through wall cracking and discontinuities and imperfections on the surface of the

component, (2) surface examinations to identify the presence of surface discontinuities,

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and (3) volumetric examination to identify the presence of cracking and discontinuities

throughout the volume of the materials.

In RAI B2.1.34-4 dated April 11, 2007, the staff noted that by letter dated July 27, 2004,

the applicant responded to NRC Bulletin 2004-01, "Inspection of Alloy 82/182/600

Materials Used in the Fabrication of Pressurizer Penetrations and Steam Space Piping

Connections at Pressurized Water Reactors." The staff requested that the applicant

confirm that WCGS is not taking any exception to the guidance provided in this bulletin.

The staff stated that if exceptions are identified, the applicant should address and justify

them, especially those in the following areas: (1) percentage of inspection coverage to

be achieved at each location, and (2) performance of an extent-of-condition evaluation,

sample expansion, and non-destructive examinations if circumferential cracking is

found. In addition, in view of the extensive PWSCC found at WCGS, the staff requested

that the applicant discuss any enhancements made to the WCGS inspection plan for

those components addressed in NRC Bulletin 2004-01.

In its response dated May 10, 2007, the applicant stated that the only exception taken to

the recommendations of NRC Bulletin 2004-01 was approved by the staff as part of a

relief request. The applicant clarified that the pressurizer surge, safety, relief and spray

nozzles have been overlayed with Alloy 690. The pressure boundary in these locations

is now the Alloy 690 overlay. The original Alloy 600 is no longer credited as the pressure

boundary.

The staff finds the applicant's responses to RAI B2.1.34-4 acceptable because it

clarified that the only exception taken the NRC Bulletin 2004-01 has been approved by

the staff. The staff's concern described in RAI B2.1.34-4 is resolved.

In RAI B2.1.34-5 dated April 11, 2007, the staff noted that NRC Bulletin 2003-02,

"Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor Coolant

Pressure Boundary Integrity," requested information from PWR licensees regarding the

RCPB integrity associated with the RPV lower head penetrations. WCNOC did not

discuss augmented inspection plans for these components in its response to this

Bulletin nor in its description of the AMP. In view of the extensive PWSCC found at

WCGS, the staff requested that the applicant discuss the inspection plan for the

components addressed in NRC Bulletin 2003-02, and provide a justification for its

adequacy.

In its response dated May 10, 2007, the applicant stated that in response to NRC

Bulletin 2003-02, WCNOC performed bare metal visual examinations of the lower RPV

head nozzles during the refueling outages in 2003 and 2005. In 2005, WCNOC also

performed ultrasonic, eddy current and visual examinations of the bottom mounted

nozzle welds from inside the vessel. No indications were found.

The applicant clarified that because the environmental conditions of the nozzles are

similar to the closure head, which requires visual inspections every three refueling

outages, WCNOC has chosen to reduce the frequency of the bare metal visual

examinations of these nozzles from each refueling outage to every other refueling

outage. Currently, WCNOC plans to conduct bare metal visual examinations, or a

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similar examination, every other refueling outage, with additional NDE exams (e.g., eddy

current, ultrasonic, and visual) when the lower core barrel is removed for ISI exams.

The staff finds the applicant's responses to RAI B2.1.34-5 acceptable because the

applicant addressed the actions taken in response to NRC Bulletin 2003-02. The staff

finds that the applicant is adequately adjusting the exam frequency based on industry

experience and guidance provided by the staff. The staff's concern described in

RAI B2.1.34-5 is resolved.

In RAI B2.1.34-7 dated April 11, 2007, the staff requested that the applicant clarify if the

equipment, method, and personnel used for these inspections meet the ASME Code,

Section XI requirements.

In its response dated May 10, 2007, the applicant stated that the equipment, methods,

and personnel used for Alloy 600 examinations are in accordance with NRC

Order EA-03-009, ASME Code, Section Xl, or the industry standard provided in

MRP-1139. The examination techniques used in each examination location are identified

in the plant procedure AP 29A-007, "Alloy 600 Program Management," Step 6.4, and the

requirements for each examination technique are described in WCNOC procedure

"Program Plan for Management of Alloy 600 Components and Alloy 82/182 Welds,"

WCRE-15 Section 4.1.

The applicant provided the following summary of the requirements for equipment,

methods, and personnel used for Alloy 600 examinations:

VT-2 examinations are performed with procedures meeting the ASME

Code Section XI requirements.

Bare Metal Visual (BMV) examinations are performed using a procedure that

meets the VT-2 requirements of ASME Section XI with the additional

requirements that the surface of the component be visible. Remote video

equipment is allowed but must be demonstrated to have the ability to fulfill

detection requirements. Personnel performing the examinations must be

qualified to a minimum of Level II in VT-2 method with additional training in the

detection of Boric Acid Leakage/Corrosion.

* Surface Examinations are performed in accordance with ASME Code Section XI

for method, equipment and personnel qualification requirements.

* The Code required volumetric examinations are in accordance with Appendix VIII

of ASME Section XI.

* Non-Code required examinations are in accordance with the appropriate industry

standard with equipment and procedure demonstrations as required. These are

examinations required by NRC such as under head examinations as well as

voluntary examinations of bottom mounted nozzles (BMN) which are performed

using personnel, equipment, and procedures qualified by performance

demonstrated methodology.

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The staff finds the applicant's response to RAI B2.1.34-7 acceptable because it

confirmed that the equipment, methods, and personnel used for the Alloy 600

examinationsconforms to regulatory or industry requirements. The applicant also

provided an adequate summary of the plant requirements for these Alloy 600

examinations. The staff's concern described in RAI B2.1.34-7 is resolved.

The staff confirmed that the "parameters monitored or inspected" program element

satisfies the criterion defined in SRP-LR Section A.1.2.3.3; therefore, the staff finds this

program element acceptable.

(4) Detection of Aging Effects - LRA Section B2.1.34, as amended, states that the program

utilizes various visual, surface and volumetric inspection and examination techniques for

early detection of PWSCC in Alloy 600 components. The applicant stated that three

types of visual-exams are used: (1) VT-2 exams which are conducted to detect evidence

of leakage from pressure retaining components, (2) bare metal visual exams which are

similar to VT-2 exams but require removal of insulation to allow direct access to the

metal surface, and (3) visual exams which are conducted to assess the general

condition of non-pressure boundary components.

The applicant stated that surface exams are used to indicate the presence of surface

discontinuities and are conducted by liquid penetrant or eddy current methods.

Volumetric exams indicate the presence of discontinuities throughout the volume of

material and are conducted by radiographic, ultrasonic, or eddy current methods, or a

combination.

The staff noted that the Nickel Alloy Aging Management Program was submitted by the

applicant prior to the finding of significant circumferential cracking at three dissimilar

metal welds. These welds are associated with the pressurizer surge, relief and safety

nozzles. As previously discussed, in RAI B2.1.34-1 dated April 11, 2007, the staff

requested that the applicant identify the changes made to the program as a result of

such findings.

In its response dated May 10, 2007, the applicant stated that as a result of these

findings visual examinations of bottom mounted nozzles are now performed every other

refueling outage. The applicant also stated that a baseline volumetric examination on all

hot leg nozzles, cold leg nozzles and bottom mounted nozzles was performed in 2005

during the Refueling Outage 14.

The applicant also stated that it implemented plans for mitigating RCS pipe butt welds

containing Alloy 600. The mitigation plans are prioritized in accordance with risk

rankings listed in WCRE-1 5, Attachment A. The inspection of'these welds follows the

guidance provided in MRP-1 39.

The applicant further stated that all Alloy 600 inspection activities are included as

augmented action in the ISI program and that it is taking a proactive approach in

mitigating the components susceptible to PWSCC.

The staff finds this is acceptable because the applicant has demonstrated that aging

effects are being adequately detected and managed.

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The staff confirmed that the "detection of aging effects" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.4; therefore, the staff finds this program

element acceptable.

(5) Monitoring and Trending - LRA Section B2.1.34, as amended, states that relative risk

rankings for Alloy 600 locations are included as part of this program. The rankings were

provided in a study conducted by Westinghouse and reflect conclusions based on

WCGS data. The applicant stated that the risk rankings may be modified as additional

information from the industry and WCGS is collected and analyzed. The Nickel Alloy

Aging Management Program provides the requirements for examination frequencies.

The examination frequencies are required by regulation, industry guidelines, and WCGS

good practices.

In RAI B2.1.34-8 dated April 11, 2007, the staff requested that the applicant address

how the relative risk rankings will be used in the inspection of Alloy600/82/182

components and whether this ranking methodology was approved by the NRC.

In its response dated May 10, 2007, the applicant stated that the ranking system is used

to prioritize the expenditure of resources for mitigation, replacement, or additional

inspections beyond regulatory and industry requirements. The initial relative risk ranking

for Alloy 600/82/182 reactor coolant system locations at Wolf Creek is provided in

WCAP 16228-P, "PWSCC Susceptibility Assessment of Alloy 600 and Alloy 82/182

Components in Wolf Creek."

During a telephone conference dated June 21, 2007, the staff noted that the applicant's

response required clarification. The staff requested that the applicant describe the

methodology and criteria used to apply the susceptibility ranking, describe the

monitoring and mitigating program for the components in the various susceptibility

categories, and discuss the assessment provided in WCAP 16228-P.

In its response dated July 26, 2007, the applicant stated that the relative risk rankings

for PWSCC susceptibility at various Alloy 600 locations are based on the application of

a phenomenological model that relates the kinetics or rate of crack initiation to the

materials, manufacturing, and environmentally controlled parameter known to influence

this mode of degradation. The relative risk rankings are developed from PWSCC

susceptibility indices established in WCAP-16228-P. The applicant clarified that

WCAP-1 6228-P is a proprietary document and has not been reviewed by staff.

However, the applicant provided details on the mitigating program, monitoring program,

and the relative risk ranking for each Alloy 600 location in its response to

RAIs B2.1.34-1 and B2.1.34-6, dated July 26, 2007.

The staff finds acceptable the use of a model that uses the rate of crack initiation to

produce risk rankings.

The staff finds the applicant's response to RAI B2.1.34-8 acceptable because it

adequately explains the methodology and criteria used to apply the susceptibility

ranking. The staff's concern described in RAI B2.1.34-8 is resolved.

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The staff confirmed that the "monitoring and trending" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.5; therefore, the staff finds this program

element acceptable.

(6) Acceptance Criteria - LRA Section B2.1.34, as amended, states that implementing

procedures or work orders specify examination requirements and acceptance criteria in

accordance with NRC Order EA-03-009 or ASME Code Section XI, or industry

guidelines. The applicant stated that for components included in the MRP-1 39, it

requires that all indications found during inspections must be evaluated in accordance

with the ASME Code Section XI requirements and indications that do not satisfy the

ASME Code IWB-3500 acceptance criteria must be dispositioned by analysis (such as

IWB-3600), repaired or replaced.

The staff noted that NEI has provided the industry the guidance in MRP-139 regarding

the inspection and evaluation of components with Alloy 82/182 butt welds. By letter

dated October 12, 2005, the staff provided NEI its comments and recommendations

regarding the subject report. The resolution of the staff comments and

recommendations is continuing.

In RAI B2.1.34-3 dated April 11, 2007, the staff requested that the applicant identify the

exceptions taken by WCNOC to the staff's comments and recommendations regarding

the implementation of MRP-139.

In its response dated May 10, 2007, the applicant stated that it takes exception to two

items:

(1) WCNOC may take exception to comment 2 with regard to the statement '"that

leak-before-break (LBB) welds shall be mitigated." Although WCNOC is pursuing

plans to mitigate our LBB welds, definitive mitigation strategies and dates have

not been set.

(2) WCNOC takes exception to comment 17. WCNOC does not interpret MRP-1 39

to permit volumetric coverage less than that required by the ASME code.

WCNOC considers MRP Section 1.2 to be consistent with ASME code in that

WCNOC does not interpret the guidelines set forth in 1.2 to reduce current

ASME Code requirements.

The staff noted that the applicant is pursuing plans to mitigate the LBB welds. However,

definitive mitigation strategies and dates have not been set. During a telephone

conference dated June 21, 2007, the staff noted that the applicant's response required

clarification. The staff requested that the applicant identify all the LBB nickel alloy welds

at WCGS.

In its response dated July 26, 2007, the applicant stated that there are two welds; the

reactor vessel outlet nozzle to safe-end weld (i.e., hot-leg) and the reactor vessel inlet

nozzle to safe-end weld (cold leg).

The resolution of the staff comments and recommendations to MRP-139 is currently

ongoing. However, the staff finds that the applicant's commitment (Commitment No. 30)

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to provide for staff review and approval, the Nickel Alloy Aging Management Program

inspection plan two years prior to entering the period of extended operation. This

commitment will provide an opportunity to the staff to ensure that the staff comments on

the MRP-1 39 have been taken in consideration and have been properly incorporated.

The staff finds that this provides reasonable assurance that the effects of aging will be

managed during the period of extended operation.

The staff finds the applicant's response to RAI B2.1.34-3 acceptable because it clearly

states the exceptions taken to the staff comments on the MRP-1 39. The staff has

reasonable assurance that the applicant's commitment to provide the inspection plan for

staff approval before the period of extended operation will ensure that the aging effects

will be adequately managed. The staff's concern described in RAI B2.1.34-3 is resolved.

The staff confirmed that the "acceptance criteria" program element satisfies the criterion

defined in SRP-LR Section A.1.2.3.6; therefore, the staff finds this program element

acceptable.

(10) Operating Experience - LRA Section B2.1.34, as amended, states that during the

refueling outage in 2005, through-wall cracking in the Alloy 82/182 weld metal of the

steam generator bowl drains was found. The weld metal was removed and replaced with

Alloy 52 weld metal. This mitigation was performed on all four steam generators, even

though cracking was found on only two of them.

During the refueling outage in 2006, circumferential indications were found on the

pressurizer surge, relief, and safety nozzles-to-safe end dissimilar metal welds. Full

structural weld overlays were applied to all of the pressurizer nozzles. The applicant

stated that the Alloy 600 program was modified as a result from these flaws.

The applicant stated that the Alloy 600 program examination plans optimize inspection

intervals and techniques, and maximize the likelihood of detecting a flaw prior to impact

on plant safety and reliability. Alloy 600 inspection activities are included as augmented

actions in the ISI program. Inspection of components where susceptible material is used

as a pressure boundary for the primary system meets or exceeds industry and

regulatory guidance. The program incorporates plant-specific and industry operating

experience.

The applicant also stated that it has taken a proactive approach in mitigating the

pressurizer nozzles via structural weld overlay and has included locations having

susceptible material exposed to primary water in the Alloy 600 program.

The staff finds that the applicant adequately modified its Alloy 600 program to account

for plant-specific operating experience with circumferential cracks. The applicant stated

that: (1) visual examinations of bottom mounted nozzles are now performed every other

refueling outage, (2) a baseline volumetric examination on all hot leg nozzles, cold leg

nozzles and bottom mounted nozzles was performed in 2005, (3) mitigation plans are

prioritized in accordance with risk rankings provided in the program and options for

mitigating reactor coolant loop nozzles are currently being evaluated, and (4) pressurizer

surge, relief, and safety nozzles containing Alloy 600 material have been overlayed with

Alloy 690.

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In RAI B2.1.34-9 dated April 11, 2007, the staff requested that the applicant provides

details and examples regarding the implementation of correction actions related to the

Nickel Alloy Aging Management Program.

In its response dated May 10, 2007, the applicant stated that the evaluations of the

WCGS and industry operating experience have been documented in the corrective

action program and improvements have been factored into the Alloy 600 program. In its

response, the applicant provided several examples to demonstrate how the industry

experience and guidance and the plant-specific operating experience were factored into

the development of the Alloy 600 program.

The staff finds the applicant's response to RAI B2.1.34-9 acceptable because it

demonstrates that the plant-specific and industry operating experience have been

considered and applied to plant procedures and programs. The applicant demonstrated

that the Alloy 600 program was modified to provide reasonable assurance that the aging

effects in nickel alloy components will be adequately managed during the period of

extended operation. The staff's concern described in RAI B2.1.34-9 is resolved.

The staff confirmed that the "operating experience" program element satisfies the

criterion defined in SRP-LR Section A.1.2.3.10; therefore, the staff finds this program

element acceptable.

The staff finds that the applicant addressed all the concerns raised by the staff and adequately

amended the Nickel Alloy Aging Management Program to incorporate operating experience

with circumferential crack at WCGS.

Based on its review, the staff finds that the Nickel Alloy Aging Management Program provides

reasonable assurance that PWSCC degradation will be detected in a timely manner because

the applicant's examination plans optimize inspection intervals and techniques, and maximize

the likelihood of detecting a flaw prior to impact on plant safety and reliability.

USAR Supplement. In LRA Section A1.34, the applicant provided the USAR supplement for the

Nickel Alloy Aging Management Program. By letters dated July 26, and August 31, 2007, the

applicant amended LRA Sections B2.1.34 and A1.34, respectively, to incorporate plant

operating experience. By letter dated October 11, 2007, the applicant amended Commitment

No. 30 to state:

The WCNOC Nickel Alloy Aging Management Program will be supplemented

with implementation of applicable (1) NRC Orders, Bulletins and Generic Letters

associated with nickel alloys and (2) staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the

EPRI Materials Reliability Program, for managing aging effects associated with

nickel alloys, (4) upon completion of these programs, but not less than 24

months before entering the period of extended operation, WCNOC will submit an

inspection plan for reactor coolant system nickel alloy pressure boundary

components to the NRC for review and approval.

The staff reviewed this section and finds the USAR supplement information is an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its technical review of the applicant's Nickel Alloy Aging

Management Program, the staff concludes that the applicant has demonstrated that the effects

of aging will be adequately managed so that the intended function(s) will be maintained

consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3). The staff also reviewed the USAR supplement for this AMP and concludes

that it provides an adequate summary description of the program, as required by

10 CFR 54.21 (d).

3.0.3.3.2 Reactor Coolant System Supplement

Summary of Technical Information in the Application. LRA Section B2.1.35 describes the new

Reactor Coolant System Supplement Program as a plant-specific program.

The plant-specific Reactor Coolant System Supplement Program supplements the Reactor

Coolant System Nickel Alloy Pressure Boundary Components and the Rector Vessel Internals

Programs with the following commitments in accordance with the recommendations of the

SRP-LR, Section 3.1.

Reactor Coolant System Nickel Alloy Pressure Boundary Components Program.

Implement applicable NRC Orders, Bulletins, GLs, and staff-accepted industry

guidelines associated with nickel alloys.

Rector Vessel Internals Program. Participate in the industry programs for investigating

and managing aging effects on reactor internals; evaluate and implement the results of

the industry programs as applicable to the reactor internals; and submit an inspection

plan for reactor internals to NRC, for review and approval, 24 months before entering

the period of extended operation.

Staff Evaluation. In accordance with 10 CFR 54.21 (a)(3), the staff reviewed the information in

LRA Section B2.1.35 on the applicant's demonstration of the Reactor Coolant System

Supplement Program to ensure that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation.

The staff finds that this is a plant-specific program that only consists of a commitment

(Commitment No. 19) related to RCS nickel alloy pressure boundary components and RVI.

Therefore, it is not possible to utilize the AMP program elements found in SRP-LR

Section A.1.2.3, and in SRP-LR Table A.1 -1, to evaluate how the program manages the aging

effects during the period of extended operation. Hence, the staff finds that this program can be

considered as a supplement to the list of AMPs.

The staff noted that the Nickel Alloy Aging Management Program, described in LRA

Section B2.1.34, was submitted by the applicant prior to the finding of significant circumferential

cracking at three dissimilar metal welds. By letter dated July 26, 2007, the applicant amended

the Nickel Alloy Aging Management Program to incorporate this operating experience. As a

result, the commitment in the Reactor Coolant System Supplement Program was also

amended.

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The staff reviewed the commitment for the RCS nickel alloy pressure boundary components for

compliance with applicable NRC Orders and USAR commitments. The staff determines that for

these components, the applicant's commitment to implement applicable NRC Orders, Bulletins,

GLs, and staff-accepted industry guidelines associated with nickel alloys is acceptable. The

applicant committed to participate in industry initiatives, and to submit for staff review and

approval, an inspection plan for these components 24 months before entering the period of

extended operation.

The staff notes that the plant-specific Nickel Alloy Aging Management Program is credited to

manage PWSCC in nickel alloy components. The staff's evaluation of the Nickel Alloy Aging

Management Program is documented in SER Section 3.0.3.3.1.

The staff reviewed the commitment for the RVI. The staff finds that the applicant's commitment

to participate in industry programs for investigating and managing aging effects on reactor

internals is acceptable. The applicant also committed to evaluate and implement the results of

these industry programs, and to submit for staff review and approval, an inspection plan for

these components 24 months before entering the period of extended operation.

The staff finds that this supplement AMP provides commitments that follow the

recommendations described in the GALL Report and, therefore is consistent with the staff

review criteria.

USAR Supplement. In LRA Section A1.35, the applicant provided the USAR supplement for the

Reactor Coolant System Supplement Program. By letter dated July 26, 2007, the applicant

amended LRA Sections A1.35 and B2.1.35, and its commitment (Commitment No. 19) to state:

(1) Reactor Coolant System Nickel Alloy Pressure Boundary Components

Implement applicable (1) NRC Orders, Bulletins and Generic Letters

associated with nickel alloys and (2) staff-accepted industry guidelines,

(3) participate in the industry initiatives, such as owners group programs

and the EPRI Materials Reliability Program, for managing aging effects

associated with nickel alloys, (4) upon completion of these programs, but

not less than 24 months before entering the period of extended

operation, WCNOC will submit an inspection plan for reactor coolant

system nickel alloy pressure boundary components to the NRC for review

and approval, and

(2) Reactor Vessel Internals

(1) Participate in the industry programs for investigating and managing

aging effects on reactor internals; (2) evaluate and implement the results

of the industry programs as applicable to the reactor internals; and (3)

upon completion of these programs, but not less than 24 months before

entering the period of extended operation, WCNOC will submit an

inspection plan for reactor internals to the NRC for review and approval.

The staff reviewed this section and determines that the information in the USAR supplement is

an adequate summary description of the program, as required by 10 CFR 54.21 (d).

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Conclusion. On the basis of its technical review of the applicant's Reactor Coolant System

Supplement Program, the staff concludes that the applicant has demonstrated that effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff

also reviewed the USAR supplement for this AMP and concludes that it provides an adequate

summary description of the program, as required by 10 CFR 54.21 (d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21 (a)(3), the applicant is required to demonstrate that the effects of

aging on SCs subject to an AMR will be adequately managed so that their intended function(s)

will be maintained consistent with the CLB for the period of extended operation. SRP-LR,

BTP RLSB-1, "Aging Management Review - Generic," describes ten elements of an acceptable

AMP. Elements (7), (8), and (9) are associated with the QA activities of "corrective actions," "confirmation process," and "administrative controls." BTP RLSB-1, Table A.1-1, "Elements of

an Aging Management Program for License Renewal," provides the following description of

these program elements:

(7) Corrective Actions - Corrective actions, including root cause determination and

prevention of recurrence, should be timely.

(8) Confirmation Process - The confirmation process should ensure that preventive actions

are adequate and that appropriate corrective actions are completed and effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and

approval process.

BTP IQMB-1, "Quality Assurance for Aging Management Programs," notes that AMP aspects

that affect the quality of safety-related SSCs are subject to the QA requirements of

10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the

applicant may use the existing 10 CFR Part 50, Appendix B, QA program to address the

elements of "corrective actions," "confirmation process," and "administrative controls."

BTP IQMB-1 provides the following guidance on the QA attributes of AMPs:

* Safety-related SCs are subject to 10 CFR Part 50, Appendix B, requirements which are

adequate to address all quality-related aspects of an AMP consistent with the CLB of

the facility for the period of extended operation.

* For nonsafety-related SCs that are subject to an AMR, an applicant has an option to

expand the scope of its 10 CFR Part 50, Appendix B, program to include these SCs to

address "corrective action," "confirmation process," and "administrative control" for aging

management during the period of extended operation. In this case, the applicant should

document such commitment in the USAR supplement in accordance with

10 CFR 54.21 (d).

3.0.4.1 Summary of Technical Information in the Application

In LRA Section B.1.3, the applicant described the elements of "corrective action," "confirmation

process," and "administrative controls" that are applied to the AMPs for both safety-related and

nonsafety-related components. A single QA program is used which includes the elements of

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corrective action, confirmation process, and administrative controls. Corrective actions,

confirmation, and administrative controls are applied in accordance with the plant's corrective

action program regardless of the safety classification of the components. Specifically, in LRA

Section B.1.3 the applicant stated that the QA program implements the requirements of

10 CFR Part 50, Appendix B. LRA Section B.2 provides a summary of AMPs.

3.0.4.2 Staff Evaluation

The staff reviewed the applicant's AMPs as described in LRA Appendices A and B. In addition,

the staff reviewed each individual AMP basis document to ensure consistency in the use of the

quality assurance attributes for each program. The purpose of this review was to assure that

the aging management activities were consistent with the staff's guidance described in

SRP-LR, Section A.2.

Based on the staff's evaluation, the descriptions and the applicability of the plant-specific AMPs

and their associated quality attributes provided in LRA Section B1.3 were determined to be

generally consistent with the staff's position regarding quality assurance for aging management.

However, the applicant had not sufficiently described the use of the quality assurance program

and its associated attributes (corrective action, confirmation process, and administrative

controls) in LRA Appendix A. In addition, AMP program descriptions in LRA Sections B2.1.1

and B2.1.3, discussed "Exceptions to NUREG 1801 ," and indicated that corrective actions was

an area to which an exception is being taken. However, there was no indication or description of

the use of an alternative method to the WCGS 10 CFR Part 50, Appendix B, quality assurance

program being applied to the area of corrective action.

The staff reviewed LRA Appendix B and identified an area in which additional information was

necessary to complete the staff's review of the applicant's quality assurance program attributes.

The applicant responded to the staff's RAI as discussed below.

In RAI 3.0.4-1 dated April 4, 2007, the staff requested that the applicant provides the following

information to address these issues:

(1) A supplement to the description in LRA Section Al, to clearly indicate the application of

the WCGS 10 CFR Part 50, Appendix B, quality assurance program, or an alternative,

for the corrective action, conformation process, and administrative control attributes in

each program. If any alternative approaches are identified to the application of the

WCGS 10 CFR Part 50, Appendix B, quality assurance program, provide a description

of sufficient detail such that the staff can determine if the quality attributes for the AMPs

are consistent with the review acceptance criteria described in SRP-LR Section A.2

(2) For AMPs, as described in LRA Appendix B, which take exceptions in the area of

corrective action, confirmation process, or administrative controls, indicate whether the

exceptions include an alternative to the application of the WCGS 10 CFR Part 50,

Appendix B, quality assurance program. If alternative approaches are identified, provide

a description of sufficient detail such that the staff can determine if the quality attributes

for the AMPs are consistent with the review of the acceptance criteria described in

SRP-LR Section A.2.

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In its response dated May 2, 2007, the applicant provided the following information:

(1) The applicant stated that LRA Section Al will be revised to indicate the application of

the WCNOC Quality Assurance Program to safety-related and nonsafety-related SSCs

during the period of extended operation.

(2) The applicant stated that, the AMPs discussed in LRA Sections B.2.1.1 and B.2.1.3

address exceptions taken to the corrective actions program element (Element 7) of the

GALL Report, Sections XI.M1 and XI.M3. Both of these program exceptions are general

exceptions to program elements 1, 3, 4, 5, 6 and 7 due to the fact that the WCGS

ASME Code Section XI ISI Program uses the ASME Code, 1998 Edition through the

2000 Addenda. GALL Report Sections XI.M1 and XI.M3 are based on the ASME Code,

2001 Edition through 2002 and 2003 Addenda. Corrective actions of the WCNOC QA

plan apply to activities discussed in LRA Sections B.2.1.1 and B.2.1.3.

By letter dated August 31, 2007, the applicant amended LRA Section Al to include a new

introductory paragraph, as follows:

Al Summary Descriptions of Aging Management Programs:

The integrated plant assessment and evaluation of time-limited aging analyses

(TLAA) identified existing and new aging management programs necessary to

provide reasonable assurance that components within the scope of License

Renewal will continue to perform their intended functions consistent with the

current licensing basis (CLB) for the period of extended operation. Sections Al

and A2 describe the programs and their implementation activities.

.Three elements common to all aging management programs discussed in

Sections Al and A2 are corrective actions, confirmation process, and

administrative controls. These elements are included in the WCNOC Quality

Assurance (QA) Program, which implements the requirements of 10 CFR 50,

Appendix B and are applicable to the safety-related and nonsafety-related

systems, structures and components that are subject to aging management

review activities.

Based on its review, the staff finds the applicant's response to RAI 3.0.4-1 acceptable because

the applicant indicated that the WCGS 10 CFR Part 50, Appendix B, QA program will be

applied to the AMP criteria of "corrective action," "confirmation process" and "administrative

controls" for safety-related and nonsafety-related SSCs subject to AMPs, during the period of

extended operation. In addition, the applicant indicated that the exceptions taken in the area of

corrective actions in the AMP program descriptions in LRA Sections B.2.1.1 and B.2.1.3 did not

affect the commitment to apply the WCGS 10 CFR Part 50, Appendix B, program to the area of

corrective action. The staff's concern described in RAI 3.0.4-1 is resolved.

3.0.4.3 Conclusion

On the basis of its review of the descriptions and applicability of the plant-specific AMPs and

their associated quality attributes provided in LRA Sections B.1.3 and B.2 and the

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RAI response, the staff finds that the applicant's approach is consistent with the staff's position

regarding QA for aging management. The staff concludes that the QA attributes (corrective

action, confirmation process, and administrative control) of the applicant's AMPs are consistent

with the requirements of 10 CFR 54.21 (a)(3).

3.1 Aging Management of Reactor Vessel, Reactor Vessel Internals, and Reactor

Coolant System

This section of the SER documents the staff's review of the applicant's AMR results for the

reactor vessel, RVI, and reactor coolant system components and component groups of:

* reactor vessel and internals

* reactor coolant system

* steam generators

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the reactor vessel, RVI, and reactor coolant system

components and component groups. LRA Table 3.1.1, "Summary of Aging Management

Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, and Reactor Coolant

System," is a summary comparison of the applicant's AMRs with those evaluated in the GALL

Report for the reactor vessel, RVI, and reactor coolant system components and component

groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the reactor vessel, RVI, and reactor

coolant system components within the scope of license renewal and subject to an AMR, will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.1.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

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were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.1.2.2.

The staff also conducted a te-chnical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's evaluations are

documented in SER Section 3.1.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.1-1. summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.1 and addressed in the GALL Report.

Table 3.1-1 Staff Evaluation for Reactor Vessel, Reactor Vessel Internals, and Reactor

Coolant System Components in the GALL Report

Component Group Aging Effect/ AMP in, -'Further AMP in LRA, Staff Evaluation

G Mechanism Reot GALL R ' -Evaluation Supplements, or

item NO.) 2 , in GALL 'Amendment

___,__,_ALLReport ?.•: ReportSteel pressure Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

vessel support skirt fatigue damage accordance with WCGS

and attachment 10 CFR 54.21(c) (See SER

welds Section

(3.1.1-1) 3.1.2.2.1)

Steel; stainless Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

steel; steel with fatigue damage accordance with PWRs

nickel-alloy or 10 CFR 54.21(c) (See SER

stainless steel and environmental Section

cladding; effects are to be 3.1.2.2.1)

nickel-alloy reactor addressed for

vessel components: Class 1 components

flanges; nozzles;

penetrations; safe

ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-2) 1

3-159
ýComponent Group .1 Aging Effect/! .-AMP in Further SAMP in LRA, IStaff Evaluation:

(GALL Report, '.,.'Mechanism GALL Repoin -Evaluation Supplements, or

Item No.) in.GALL Amendment

I_____ ______ _____ _ __ ýReport _ _ _ _ _ __ _ _ _ _ _

Steel; stainless Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

steel; steel with fatigue damage accordance with PWRs

nickel-alloy or 10 CFR 54.21(c) (See SER

stainless steel, and environmental . Section

cladding; effects are to be 3.1.2.2.1)

nickel-alloy RCPB addressed for

piping, piping Class 1 components

components, and

piping elements

exposed to reactor

coolant

(3.1.1-3)

Steel pump and Cumulative TLAA, evaluated in Yes Not applicable Not applicable to

valve closure bolting fatigue damage accordance with PWRs

(3.1.1-4) 10 CFR 54.21 (c) (SeeSER

check Code limits Section

for allowable cycles 3.1.2.2.1)

(less than

7000 cycles) of

thermal stress range

Stainless, steel and Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

nickel alloy FRVI fatigue damage accordance with TLAA (See SER

components 10 CFR 54.21(c) Section

(3.1.1-5) . 3.1.2.2.1)

Nickel Alloy tubes Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

and sleeves in a :fatigue damage accordance with TLAA (See SER

reactor coolant and 10 CFR 54.21 (c) Section

secondary 3.1.2.2.1)

FW/steam-,

environment

(3.1.1-6)

Steel and stainless Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

steel RCPB closure fatigue damage accordance with TLAA (See SER

bolting, head . 10 CFR 54.21 (c) Section

closure studs, 3.1.2.2.1)

support skirts and

attachment welds,

pressurizer relief.

tank components,

steam generator

components, piping

and components

external surfaces

and bolting

(3.1.1-7)

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Component Group• Aging Effect[ AMP in Further -AMP in LRA, Staff Evaluation

(GALL Report Mechanism 'GALL Report, Evaluation Supplements, or

Item No.) : . in GALL 'Amendment

_____ _____ ____ _____ ____ Report _ _ _ _ _ _ __ _ _ _ _ _ _

Steel; stainless Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

steel; and fatigue damage accordance with TLAA (See SER

nickel-alloy RCPB 10 CFR 54.21(c) Section

piping, piping and environmental . 3.1.2.2.1)

components, piping effects are to be

elements; flanges; addressed for

nozzles and safe Class 1 components.

ends; pressurizer

vessel shell heads

and welds; heater

sheaths and

sleeves;

penetrations; and

thermal sleeves (3.1.1-8) __ _ _ __ _ _

Steel; stainless Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

steel; steel with fatigue damage accordance with TLAA (See SER

nickel-alloy or, 10 CFR 54.21(c) Section

stainless steel and environmental 3.1.2.2.1)

cladding', effects are to be

nickel-alloy reactor addressed for

vessel components: Class 1 components

flanges; nozzles;

penetrations;

pressure housings;

safe ends; thermal

sleeves; vessel

shells, heads and

welds

(3.1.1-9)

Steel; stainless Cumulative TLAA, evaluated in Yes TLAA Fatigue is a

steel;steel with fatigue damage accordance with TLAA (See SER

nickel-alloy or 10 CFR 54.21 (c) ' Section

stainless steel, and environmental 3.1.2.2.1)

cladding; effects are to be

nickel-alloy steam addressed for

generator Class 1. components

components

(flanges;

penetrations;

nozzles; safe ends,

lower heads. and

welds)

(3.1.1-10)

Steel top head Loss of material Water Chemistry Yes Not applicable Not applicable to

enclosure (without due to general, and One-Time PWRs

cladding) top head pitting and Inspection (See SER

nozzles (vent, top crevice Section

head spray or RCIC, corrosion 3.1.2.2.2.1)

and spare) exposed

to reactor coolant

(3.1.1-1)1)

3-161
Component Group Aging Effect/ AMP in...;- Further AMP in LRA, 'Staff Evaluation

(GALL Report Mechanism* GALL Report Evaluation Supplements, or

Item No.) in GALL Amendment

_______________ ___________Reportj_______

Steel steam Loss of material Water Chemistry Yes Not applicable Not applicable to

generator shell due to general, and One-Time WCGS

assembly exposed pitting and Inspection (See SER

to secondary FW crevice Section

and steam corrosion 3.1.2.2.2.1)

(3.1.1-12)

Steel and stainless Loss of material Water Chemistry Yes Not applicable Not applicable to

steel isolation due to general and One-Time PWRs

condenser. (steel only), Inspection (See SER

components pitting and Section

exposed to reactor crevice 3.1.2.2.2.2)

coolant corrosion

(3.1.1-13)

Stainless steel, Loss of material Water Chemistry Yes Not applicable Not applicable to

nickel-alloy, and due to pitting and One-Time PWRs

steel with and crevice Inspection (See SER

nickel-alloy or corrosion Section

stainless steel 3.1.2.2.2.3)

cladding reactor

vessel flanges,

nozzles,

penetrations, safe

ends, vessel shells,

heads and welds

(3.1.1-14) _

Stainless steel; steel Loss of material Water Chemistry Yes Not applicable Not applicable to

with nickel-alloyor due to pitting and One-Time PWRs

stainless steel and crevice Inspection (See SER

cladding; and . corrosion Section

nickel-alloy RCPB 3.1.2.2.2.3)

components

exposed to reactor.

coolant

(3.1.1-15)

Steel steam Loss of material Inservice Yes ASME Code Consistent with

generator upper and due to general, Inspection (IWB, Section XI the GALL Report

lower shell and pitting and * IWC, and IWD), and Inservice (See SER

transition cone, crevice * Water Chemistry: Inspection, Section

exposed to corrosion and, for. Subsections IWB, 3.1.2.2.2,

secondary FW and Westinghouse IWC, and IWD for item (4))

steam * Model 44 and Class 2

(3.1.1-16) 51 S/G, if general components

and pitting corrosion (B2.1.1) and

of the shell is known Water Chemistry

to exist, additional (B2.1.2)

inspection

procedures are to

be developed.

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-component Group* Aging Effect/ AMP in Further AMP in LRA, Staff EvaluationE'

(GALL Report Mechanism GALL Report Evaluation Supplements, or

Iltem No.) - in GALL Amendment :

___ __ ___ ___ ___ _ ___ _ _ :.Report j

Steel (with or Loss of fracture. TLAA, evaluated in Yes TLAA Loss.of fracture

without stainless toughness due accordance with toughness is a

steel cladding) to neutron 10 CFR 50, TLAA (See SER

reactor Vessel irradiation. Appendix G, and Section

beltline shell, embrittlement RG 1.99. The 3.1.2.2.3.1)

nozzles, and welds applicant may

(3.1.1-17) chooseto

demonstrate that.

the materials of the

nozzles are not

controlling for the

TLAA evaluations.

Steel (with or Loss of fracture Reactor Vessel Yes Reactor Vessel Consistent with

without stainless toughness due Surveillance Surveillance the GALL Report

steel cladding) to neutron (B2.11.15) (See SER

reactor vessel irradiation Section

beltline shell, embrittlement. 3.1.2.2.3.2)

nozzles, and welds;

safety injection

nozzles

(3.1.1-18)

Stainless steel and Cracking due to. A plant-specific Yes Not applicable Not applicable to

nickel alloy top head SCC and aging management PWRs

enclosure vessel:! IGSCC program is to be (See SER

flange% leak evaluated. Section

detection line 3.1.2.2.4.1)

(3.1.1-19)

Stainless steel Cracking due to Inservice Yes Not applicable Not applicable to

isolation condenser SCC and Inspection (IWB, PWRs

components IGSCC IWC, and IWD), (See SER

exposed to reactor Water Chemistry, Section

coolant * and plant-specific: 3.1.2.2.4.2)

(3.1.1-20). verification program

Reactor vessel shell Crack growth TLAA Yes TLAA Crack growth

fabricated of due to cyclic due to cyclic

.SA508-CI 2.forgings loading loading is a

clad with stainless TLAA (See SER

steel using a Section

high-heat-input 3.1.2.2.5)

welding process

(3.1.1-21)

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,Component Group Aging Effect/ AMP in, Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism GALL Report Evaluation Supplements, or

Item No.) in GALL Amendment

- __ ___ ___ ___ ____ ___ Report

Stainless steel and Fatigue is a FSAR supplement No, but Reactor'Coolant Consistent with

nickel alloy RVI TLAA (See commitment to commitment Supplement the GALL Report

components SER (1) participate in tobe Program (See SER

exposedto reactor Section 3.1.2.2. industry RVI aging confirmed commitments Section

coolant and neutron 1) programs (B2.1.35) 3.1.2.2.6)

flux (2) implement

(3.1.1-22) applicable results

(3) submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel. Cracking due to A plant-specific Yes ASME Code Consistent with

reactor vessel SCC -aging management Section Xl the GALL Report

closure head flange program is to be Inservice. (See SER

leak detection line evaluated. Inspection, Section

and Subsections IWB, 3.1.2.2.7.1)

bottom-mounted . IWC, and IWD.for

instrument guide Class 1

tubes components

(3.1.1-23). (B2.1.1) and

Water Chemistry

(B2.1.2)

Class 1 CASS Cracking due to Water Chemistry Yes Water Chemistry Consistent with.

piping, piping. SCC and, for CASS (B2.1.2) and the GALL Report

components, and components that do ASME Code (See SER

piping elements not meet the Section Xl Section

exposed to reactor NUREG-0313 Inservice 3.1.2.2.7.2)

coolant . guidelines, a Inspection,

(3.1.1-24) plant-specific AMP Subsections IWB,

IWC and IWD

(B2.1.11)

Stainless steel jet Cracking due to A plant-specific Yes Not applicable Not applicable to

pump sensing line cyclic loading aging management .. . PWRs

(3.1.1-25) * •program is to be (See SER

evaluated. Section

3.1.2.2.8.1)

Steel and stainless Cracking due to: Inservice Yes Not applicable Not applicable to

steel isolation cyclic loading Inspection (IWB, PWRs

condenser IWC, and IWD) and (See SER

components plant-specific Section

exposed to reactor* . " verification program 3.1.2.2.8.2)

coolant .

(3.1.1-26)

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Component Group Aging Effect/l ýAMP in Further AMP in LRA.. StaffEvaluation;,

:•"::;:.(GALL Report Mechanism GALL Report Evaluation Supplements, or

ItemNo.) in GALL., Amendment

______________ _____ _____ __________..,.Report _ _ _ _ _ _ _ _ _ _ _

Stainless-steel and Loss of preload FSAR supplement No, but Reactor Coolant Consistent with

nickel alloy RVI due to stress commitment to commitment. Supplement the.GALL Report

screws, bolts, tie relaxation (1) participate in to be Program, (See SER

rods, and hold-down industry RVI aging confirmed commitments Section,

springs programs (B2.1.35) 3.1.2.2.9)

(31.1-27) (2) implement

applicable results

(3),submit for NRC

approval >. 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Steel steam Loss of material A plant-specific. Yes Not applicable Not applicable to

generator FW due to erosion aging management WCGS

impingement plate program is to be (See SER

and support evaluated.. .. Section

exposed to 3.1.2.2.10)

secondary FW .

(3.1.1-28) ....

Stainless steel*.. Cracking dueto. A plant-specific Yes Not applicable. Not applicable to

steam dryers flow-induced * aging management PWRs

exposed to reactor vibration program is to be "(See SER

coolant evaluated. Section.

(3.1.1-29) • 3.1.2.2.11)

3-165
Component Group Aging Effect/l 1 AMP in .,,Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism .GALL Report iEvaluation Supplements, or

Item No.),Y - In GALL ,Amendment

_____ _ _________ ___ Report

Stainless steel RVI Cracking due to Water Chemistry No, but Reactor Coolant Consistent with

components SCC, IASCC and FSAR commitment Supplement the GALL Report

(e.g., Upper cracking supplement to be -Program (See SER

internals assembly, commitment to confirmed commitments Section

rod guide control (1) participate in (B2.1.35) and 3.1.2.2.12)

assembly guide industry RVI aging Water Chemistry

tube assemblies, programs (B2.1.2)

Baffle/former (2) implement

assembly, Lower applicable results

internal assembly, (3) submit for.NRC"

shroud assemblies, approval > 24

Plenum cover and months before the

plenum cylinder, extended period an

Upper grid RVI inspection plan

assembly, Control based on industry

rod guide tube recommendation.

assembly,. Core..

support shield "

assembly, Core

barrel assembly,

Lower grid

assembly, Flow

distributor

assembly, Thermal

shield,

Instrumentation

support structures)

(3.1.1-30) ,_ __ _

Nickel alloy and Cracking due to Inservice No, but Reactor Coolant Consistent.with

steel with PWSCC Inspection (IWB, commitment Supplement the GALL Report

nickel-alloy cladding IWC, and IWD) and to be Program . (See SER

piping, piping Water Chemistry confirmed commitments Section

component, piping and FSAR (B2.1.35), ASME 3.1.2.2.13)

elements, supplement Section XI

penetrations, commitment to Inservice

nozzles, safe ends, implement Inspection,

and welds (other "applicable plant Subsections IWB,

than reactor vessel commitments to IWC, and

head);. pressurizer (.1) NRC Orders, IWD (B2.1.1),

heater sheaths,. Bulletins, and Water Chemistry

sleeves, diaphragm Generic Letters (B2.1.2) and

plate, manways and associated with Nickel Alloy Aging

flanges; core • nickel alloys and Management

support pads/core (2) staff-accepted Program

guide lugs - industry guidelines. (82.1.34)

(3.1.1-31)

Steel steam Wall thinning A plant-specific Yes Steam Generator Consistent with

generatorFW inlet due to aging management Tube Integrity the GALL Report

ring and supports flow-accelerate program is to be (B2.1.8) and (See SER

(3.1.1-32) d corrosion evaluated. Water Chemistry Section

(B2.1.2) 3.1.202.14)

3-166
Component Group Aging Effect/ AMP in >Further AMP In LRA, . Staff Evaluation

(GALL Report. Mechanism GALL Report Evaluation Supplements, or

Item No.).•-. , in GALL i Amendment

____ ____ ____ __ _ ____ __ Report~

Stainless steel and Changes in FSAR supplement I.No, but Reactor Coolant Consistent with

nickel alloy RVI dimensions due commitment to commitment Supplement the GALL.Report

components to void swelling (1) participate in to be Program (See SER

(3.1.1-33) industry RVI aging• confirmed commitments Section

programs . . (B2.1.35) 3.1.22:.15)

(2) implement

applicable results

(3).submit for NRC

approval > 24

months before the

extended period an

RVI inspection plan

based on industry

recommendation.

Stainless steel and Cracking due to Inservice No, but Water Chemistry Consistent with

nickel alloy reactor SCC and Inspection. (IWB, commitment (B2.1.2) and the GALL Report

CRD head PWSCC IWC, and IWD) and to be ASME Code (See SER

penetration Water Chemistry confirmed Section Xl Section

pressure housings and for nickel alloy, Inservice 3.1.2.2.16.1)

(3.1.1-34) comply with Inspection,

applicable NRC . Subsections IWB,

Orders and provide IWC, and IWD

a commitment. in the (B2.1.1)

FSAR supplement

to implement

.,.applicable

(1). Bulletins and

Generic Letters and

(2) staff-accepted

.. _ _ industry guidelines.

Steel with stainless Cracking due to Inservice .* No, but Not applicable Not applicable.to

steel or nickel alloy SCC and 'Inspection (IWB, commitment WCGS

cladding primary PWSCC IWC, and IWD) and to be (See SER

side components; Water Chemistry confirmed Sections

steam generator and for nickel alloy, 3.1.2.1.1 and

upperand lower comply with 3.1.2.2.16.1)

heads, tubesheets applicable NRC

and tube-to-tube. . Orders and provide

sheet welds' a commitment in 'the

(3.1.1-35) FSAR supplement

to implement

* .. applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted .

industry guidelines.

3-167
,Component Group Aging Effect/ AMP in Further 'AMP In LRA, Staff. Evaluation:

(GALL Repori Mechanism GALL Report Evaluation Supplements, or

Item ~~ , '.* in GALL Am den

______________ ~Report _______

Nickel alloy, Cracking due to Water Chemistry No, Unless Water Chemistry Consistent with

stainless steel SCC and and One-Time commitment:: (B2.1.2) and the GALL Report

pressurizer spray. PWSCC Inspectionand, for needs to be One-Time (See SER

head nickel alloywelded confirmed Inspection Section

(3.1.1-36) spray heads, (B2.1.16) 3.1.2.2.16.2)

comply with

applicable NRC

Orders and provide

a commitment in the

FSAR supplement

.to implement

applicable

(1) Bulletins and

Generic Letters and

(2) staff-accepted

•___________ . • industry guidelines. _ _-.

Stainless steel.and Cracking due to Water Chemistry No, but Reactor Coolant Consistent with

nickel alloy RVI SCC, PWSCC, and FSAR commitment ;Supplement the GALL Report

components .. IASCC cracking supplement to be Program • (See SER

(e.g.,. upper.. commitment to confirmed commitments Section

intemals assembly, T(1) participate in .. . (B2.1.35) and 3.1.2.2.17)

rod guide con *itrol• industry RVI aging Water Chemistry

assembly guide- programs (B2.1.2)

tube assemblie•s, .(2) implement

lower intemral applicable. results

assembly, CEA . (3) submit for NRC

shroud assemblies, approval> 24

core shroud months before the

assembly, core extended period an

support shield RVi inspection plan

assembly; core based on industry

barrel assembly, recommendation.

lower grid assembly,

flow distributor

assembly)

(3.1.1-37) ___

.Steel (with or. Cracking due. to BWR Control Rod No Not applicable Not applicable

without stainless' cyclic loading Drive Return Une to PWRs

steel cladding) CRD Nozzle

return line nozzles

exposed to reactor

coolant

(3.1.1-38) __

Steel"(with ore. Cracking BWR Feedwater No Not applicable Not applicable to

without stainless due to cyclic Nozzle PWRs

steel cladding) loading

FW nozzles

exposed to

reactor coolant

(3.1".1-39) •_'___

3-168
Component Group Aging Effect/ AMP in Further AMP in LRA,, Staff Evaluation

(GALL-Report Mechanism* GALL Report Evaluation Supplements, or,

Item No.)> in GALL ,Amendment''

________ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Report _ _ _ _ _ _ _ _

Stainless steel and Cracking due to BWR Penetrations No Not applicable Not applicable to,

nickel alloy SCC, and Water PWRs

penetrations for: Intergranular Chemistry

ORD stub tubes stress corrosion

instrumentation, jet cracking, cyclic

pump loading

instrumentation,

standby liquid,

control, flux monitor,

and drain line

exposed to reactor

coolant

(3.1.1-40) ___ ___"_-_

Stainless'steel and Cracking due to 1BWR Stress No Not applicable Not applicable to

nickel alloy piping, SCC and Corrosion Cracking PWRs

pipingcomponents, IGSCC and Water

and piping elements Chemistry

greater than or

equal to 4 NPS;

nozzle safe ends.

and associated.

welds

(3.1.1-41) ___ _

Stainless steel and Cracking due to BWR Vessel ID No Not applicable Not applicable to

nickel alloy vessel sCC and Attachment Welds PWRs

shell attachment IGSCC and Water

welds exposed to: Chemistry

reactor coolant

(3.1.1-42) .

Stainlesssteel fuel Cracking due to BWR Vessel No Not applicable Not applicable to

supports and'CRD SCC and Intemals and Water PWRs

assemblies CRD IGSCC Chemistry

housing e6xpo.sed to

reactor coolant'.

(3.1.1-43) " . _ _. _

Stainless steel and Cracking due to BWR Vessel No Not applicable Not applicable to

nickel alloy core sCC, IGSCC, Intemals and Water PWRs

shroud, core plate, IASCC cracking Chemistry

core plate bolts,-

support structure,

top guide,- core

spray lines,'

spargers, jet pump

assemblies, CRD

housing, nuclear

instrumentation

guide' tubes

(3.1.1-44)

.3-169
Component Group Aging Effect/ AMP in Further: AMP in LRA, Staff Evaluation

(GALL Report Mechanism GALL Report ý'Evaluation Supplements, or

Item No.)' in GALL 'Amendment _____________ _____ ____ ___________ .-Report _ _ _ _ _ _ _ _ _ _ _ _

Steel piping, piping Wall thinning Flow-Accelerated No Not applicable Not applicable to

components, and due to Corrosion PWRs.

piping elements flow-accelerate

exposed to reactor d corrosion

coolant

[(3.1.1-45) " - _[ " 

Nickel alloy core Cracking due to Inservice No Not applicable Not applicable to

shroud and core SCC, IGSCC, Inspection (IWB, PWRs

plate access hole' IASCC cracking IWC, and IWD), and

cover (mechanical Water Chemistry

covers)

(3.1.1-46) , ,_,

Stainless steel and Loss of material Inservice No Not applicable Not applicable to

nickel-alloy RVI due to pitting Inspection (IWB, PWRs

exposed to reactor and crevice. IWC, and IWD), and

coolant corrosion Water Chemistry

(3.1.1-47)

Steel and.stainless Cracking due to Inservice No Not applicable Not applicable to

steel Class 1 piping, SCC, IGSCC Inspection (IWB, PWRs

fittings and branch (for stainless IWC, and IWD),

connections steel only), and Water chemistry,

< NPS 4 exposed to thermal and and One-Time

reactor coolant mechanical Inspection of ASME

(3.1.1-48) loading Code Class 1

Smallkbore Piping

Nickel alloy core Cracking due to Inservice No Not applicable Not applicable to

shroud and core SCc, IGSCC, Inspection (IWB, PWRs

plate access hole IASCC cracking IWC, and IWD),

cover (welded Water Chemistry,

covers) and, for BWRs with

(3.1.1-49) a crevice in the

access hole covers,

augmented

inspection using UT

or other

, demonstrated

acceptable

inspection of the

• access hole cover

welds

High-strength low Cracking due to Reactor Head No Not applicable Not applicable to

alloy steel top head SCC and Closure Studs PWRs

closure studs and IGSCC

nuts exposed to air

with reactor coolant

leakage.

(3.1.1-50)

3-170
Component Group:e ,Aging Effect/ AMP in Further AMP in LRA, Staff Evaluation

(GALL Report Mechanism GALL Report Evaluation Supplements, or

,Item No.) in GALL Amendment

Report

CASS Jet pump... Loss of fracture Thermal Aging and No Not applicable Not applicable to

assembly castings; toughness due Neutron Irradiation PWRs

orificed fuel support to thermal Embrittlementof

(3.1.1-51) :aging and CASS

neutron*

irradiation

embrittlement

Steel and stainless Cracking .due to Bolting Integrity No Bolting Integrity Consistent with

steel RCPB (RCPB) SCC, loss of (B2.J.7) the GALL Report

pump and valve'', material due to

closure bolting, wear, loss of

manway and preload due to

holding bolting, thermal effects,

flange b0oting,'and gasket creep,

closure bolting in and

high-pressure and self-loosening

high-temperature.

systems

(3.1.1-52) • _ _ _

Steel piping, piping Loss of material Closed-Cycle No. Closed-Cycle Consistent with.

components, and due to general, Cooling Water Cooling Water the GALL Report

piping elements: pitting and System System (B2.1.10)

exposed to closed crevice

cycle cooling water corrosion

(3.1.1-53)

Copper alloy piping, Loss of material. Closed-Cycle No Closed-Cycle Consistent with

piping components, due to pitting, Cooling Water • Cooling Water the GALL Report

and piping elements crevice, and System System (B2.1.10)

exposed to closed galvanic

cycle coolinrg water corrosion

(3.1.1-54): ..

CASS Class 1 pump Loss of fracture Inservice No ASME Code Consistent with

casings, and valve toughnessdue Inspection (IWB, Section XI the GALL Report

bodies and.bonnets to thermal IWC, and IWD). Inservice

exposed to reactor * aging . Thermal aging . Inspection,

coolant > 250°C'. embrittlement susceptibility " . Subsections IWB,

(> 482°F) * screening is not IWC, and IWD

(3.1.1-55) . ... necessary, inservice (B2.1.1)

inspection

requirements are

sufficient for

managing these

aging effects. ASME..

Code Case N-481

also provides an

alternative for pump

______________ ___________casings. ______ ________

3-171
Component Group ',Aging Effectl AMP in Further ,AMP in LRA,, ý'Staff Evaluation'

*(GALL Report Mechanism GALL Report Evaluation 'Supplements, or,

Item No.) ' in GALL ,Amendment,- - _ _ _ _ _ _ _ _ _ _ _ Report _ _ _ _ _ _

Copper alloy Loss of material Selective Leaching No Not applicable Not applicable to

> 15% Zn piping,: due to selective of Materials WCGS (See

piping components, leaching SER Section

and piping elements .. 3.1.2.1.1)

exposed to closedcycle cooling water

(3.1.1-56) ' ___

CASS Class 1. Loss of fracture Thermal Aging No Not applicable Not applicable to

piping, piping toughness due Embrittlement of. WCGS

component, and tothermal CASS (See SER

piping elements and aging• Section

CRD pressure . embrittlement 3.1.2.1.1)

housings exposed

to'reactor coolant

> 250'C (> 4820F)

(3.1.1-57) ._ ._". _ _ _ _ _ 

Steel RCPB external Loss of material Boric Acid Corrosion No Boric Acid Consistent with

surfaces exposed, to due to boric Corrosion the GALL Report

air with borated. acid corrosion (B2.1.4)

water leakage

(3.1.1-58) _ _1 _

Steel steam . . Wall thinning. Flow-Accelerated No Flow-Accelerated Consistent with

generator steam dueto . Corrosion Corrosion the GALL Report

nozzle and safe. flow-accelerate (B2.1.6)

end, FW nozzle and d corrosion

safe end, AFW

nozzles and safe

ends exposed to

secondary

FW/steam

(3.1.1-59) ,___ _

Stainless steel flux Loss of material Flux Thimble Tube No Flux Thimble Consistent with

thimble tubes (with due to wear Inspection Tube Inspection the GALL Report

or without chrome (B2.1 .21)

plating)

(3.1.1-60)

Stainless steel, steel Cracking due to. Inservice No ASME Code Consistent with

pressurizer integral cyclic loading Inspection (IWB, Section XI the GALL Report

support exposed to IWC, and IWD) Inservice

air with metal .... *Inspection,

temperature up to Subsections IWB,

288 0C (5500 F) IWC, and IWD

(3.1.1-61) (B2.1.1)

3-172
'Component Group Aging Effect/ AMP in Further AMP: in LRA, Staff Evaluation

(GALL Report Mechanism GALL Report Evaluation,, or.Supplements, 

-item No.) ........ ....................... in GALL K Amendment

_ _ _ _ _ _ _ _ _ _ _ ____ ___ Report

Stainless steel, steel Cracking due to Inservice No ASME Code Consistent with

with stainless steel cyclic loading Inspection (IWB, Section Xl the GALL Report

cladding reactor'.. IWC, and IWD). Inservice

coolant system cold Inspection,

leg, hot.leg, surge Subsections IWB,

line, and spray]ine IWC, and IWD

piping and fittings (B2.1.1)

exposed to reactor

coolant

(3.1.1-62) • • •

Steel reactor vessel Loss of material Inservice No ASME.Code Consistent with

flange, stainless.. due to wear Inspection (IWB, Section Xl the GALL Report

steel and~nickel IWC, and IWD) Inservice (See Section

alloy RVI exposed to Inspection, 3.1.2.1.2)

reactor coolant', Subsections IWB,

(e.g., upper and IWC, and IWD

lower intemals (B2.1.1)

assembly,"CEA.!ýý

shroud assembly,

core support barrel,

Upper grid

assembly., core•

support shield,

assembly, lower grid

assembly).

(3.1.1-63) " ..,

Stainless steel and Cracking due to Inservice No ASME Code Consistent with

steel with stainless. SCC, PWSCC Inspection (IWB, Section XI the GALL Report

steel or nickel alloy, IWC, and IWD) and Inservice

cladding pressurizer Water Chemistry Inspection,

components Subsections IWB,

(3.1.1-64) * IWC, and IWD for

Class 1

components

(B2.1.1) and

Water Chemistry

(B2.1.2)

3-173
Component Group, Aging Effect/ AMP in Further AMP in LRA, Staff Evaluation,

(GALL Report: Mechanism-,E GALL Report valuatloný i Supplements, or

Item No.)'.' in GALL::' ~Arnndment _________ _______ ~Report _ _ _ _ _ _ _

Nickel alloy reactor Cracking due to Inservice No ASME Code Consistent with

vessel upper head PWSCC Inspection (IWB. SectionXlI the GALL Report and CRD. IWC,.and IWD)-and Inservice

penetration nozzles,, Water-Chemistry •nspection,

instrument tubes'," and Nickel-Alloy Subsections IWB,

head Vent pipe (top Penetration Nozzles IWO, and IWD

head), and welds... Welded to the: (B2..1),

(3.1.1-65) :'Upper Reactor Water Chemistry

Vessel Closure (B2.1.2), and

Heads of XI.M11-A,

Pressurized Water Nickel-Alloy

Reactors Penetration

Nozzles Welded

to the. Upper

Reactor Vessel

Closure Heads of

Pressurized

WaterReactors .: :(B2.1 - !• .5):

Steel steam Loss of material Inservice No Not applicable Not applicable to

generator due to erosion Inspection (IWB, WCGS

secondary manways IWC, and IWD) for (See SER

and handholds'. Class 2 components Section

(coveronly) 3.1.2.1.1)

exposed to air with

leaking

secondary-side

water and/or steam (3.1 .1-66). ___"________..._.

Steel with stainless Cracking due to Inservice No ASME Code Consistent with

steel, or nickel alloy cyclic loading Inspection (IWB, Section Xl the GALL Report

cladding or . IWC, and IWD), and . Inservice

stainless steel Water Chemistry . :-Inspection,

pressurizer " Subsections IWB,

components IWCO' and IWD for

exposed to reactor Class 1

coolant ' components

(3.1.1-67) (B2.1.1) and

Water Chemistry

.... .... __ (B2.1.2 ) _

3-174

A
ýComponent Group ..Aging Effectl AMP in - Further APiLR, Staff Evaluation

(GALL Report -.-Mechanism GALL Report Evaluation ,Supplements, or,

Item No.) in GALL :ýAmendment.

________ _ _ _ _ _ _ ________ Report _ _ _ _ _ _ _ _

Stainless steel, steel Cracking due to Inservice No ASME Code Consistent with

with stainless steel SCC Inspection (IWB, Section Xl the GALL Report

cladding. Class 1 IWC, and IWD), and Inservice (See SER

piping;,fittings, Water Chemistry Inspection, Section

pump casings, valve Subsections IWB, 3.1.2.1.3):

bodies, nozzles, IWC, and IWD for

safe ends, Class 1

manways, flanges, components

CRD housing; (B2.1.1) and

pressurizer heater Water Chemistry

sheaths, sleeves, (B2.1.2)

diaphragm plate;

pressurizer relief,..

tank components,

reactor coolant

system cold leg,, hot

leg, surge line, and

spray linepiping

and fittings

(3.1.1-68) ,

Stainless steel, Cracking due to Inservice No For stainless steel Consistent with

nickel alloy'safety SCC, PWSCC Inspection (IWB, components: the GALL Report

injection nozzles, IWC; and IWD), and ASME Code

safe ends,.and .. Water Chemistry Section Xl

associated welds Inservice

and buttering Inspection,

exposed to reactor Subsections IWB,

coolant IWC, and IWD for

(3.1.1-69). Class 1

coimponents

(B2.1.1) and

Water Chemistry

(B2.1.2)

For nickel alloy

components:

Nickel Alloy Aging Management

(B2.1.34),

ASME Code

Section Xl

Inservice

Inspection,

Subsections IWB,

IWC,,and IWD

(B2.1.1) for

Class 1

components,

Water Chemistry (B2,.1.2),Reactor

Coolant

Supplement

Program

______ .:, (B2.1.35)

3-175
"Component Group:, Aging Effectl APIn Further AMP in LRA, - 'Staff Evaluation,

:(GALL Report** Mechanism, GALL Report .Evaluation Supplements, or,-

Item No.)- , - in GALL Amendment.,

- _________ ___________ Report, _ _ _ _ _ _ _ _ _

Stainless steel; steel Cracking due to Inservice No ASME Code Consistent with

with stainless steel SCC, thermal Inspection (IWB, Section XI the GALL Report

cladding Classl and mechanical IWC, and IWD), Inservice

piping, fittings and loading Water chemistry, . Inspection,

branch connections and One-Time Subsections IWB,

< NPS 4 exposedto Inspection of ASME IWC, and IWD for

reactor coolant Code Class 1 Class 1

(3.1.1-70). Small-bore Piping components

(92.1.1),

Water Chemistry

(B2.1.2) and

One-Time

Inspection Of

ASME

Code Class 1

Small-Bore Piping

(82.1.19)

High-strength low Cracking due to Reactor Head No Reactor Head Consistent with

alloy steel closure SCC; loss of Closure Studs Closure Studs the GALL Report

head stud assembly material due to (B2.1.3)

exposed to air with wear

reactor coolant

leakage.:.

(3.1.1-71) . . ...

Nickel alloy steam . Cracking dueto Steam.Generator No Steam Generator Consistent with

generator tubes and OD SCC and Tube Integrity and Tube Integrity the GALL Report

sleeves exposed to intergranular Water Chemistry (B2.1.8) and

secondary attack, 1oss of Water Chemistry

FW/steam material due to ""(B2.1.2)

(3.1.1-72) . fretting and.

wear

Nickel alloy steam Cracking due to Steam Generator No Steam Generator Consistent with

generator tubes, PWSCC Tube Integrity and Tube Integrity the GALL Report

repair sleevesiand Water-Chemistry (B2.1.8) and

tube plugs exposed Water Chemistry

to reactor coolant (82.1.2)

(3.1.1-73) . " .

Chromeplated*, Cracking due to Steam Generator No Steam Generator Consistent with

steel, stainless-_ SCC, loss of. Tube Integrity and Tube Integrity the GALL Report

steel, nickel.alloy, . material due to Water Chemistry (82.1.8) and

steam generator crevice Water Chemistry

anti-vibration bars corrosion and (82.1.2)

exposed to fretting

secondary . .

FW/stearn -

(3.1.1-74) :_

3-176
Component Group Aging Effect/ "AMP in Further - AMP in LRA, Staff Evaluation

(GALL Report Mechanism -:GALL Report Evaluation: Supplements, or

item No.) In GALL Amendment

Report.

Nickel alloy Denting due to Steam Generator No Not applicable Not applicable to

once-through steam corrosion of, Tube Integrity and WCGS

generator tubes .... carbon steel Water Chemistry (See SER

exposed to : tube support Section

secondary plate 3.1.2.1.1)

FW/steam

(3.1.1-75)

Steel steam Loss of material Steam Generator No Steam Generator Consistent with

generator tube due to erosion, Tube Integrity and Tube integrity the GALL Report

support plate, tube general, pitting, Water Chemistry (B2.1.8) and

bundle wrapper and crevice Water Chemistry

exposed to corrosion, (B2.1.2)

secondary ligament

FW/steam . cracking due to

(3.1.1-76) corrosion

Nickel'alloy steam Loss of material Steam Generator No Not applicable Not applicable to

generator tubes.-and due to wastage Tube Integrity and WCGS

sleeves exposed to and pitting Water Chemistry (See SER

phosphate corrosion Section

chemistry in - 3.1.2.1.1)

secondary

FW/steam

(3.1.1-77)

Steel steam Wall thinning Steam Generator No Not applicable Not applicable to

generator tube -. due to Tube Integrity and WCGS

support lattice bars flow-accelerate Water Chemistry (See:SER

exposed to d corrosion Section

secondary 3.1.2.1.1)

FW/steam

(3.1.1-78)

Nickel alloy steam Denting due to Steam Generator No Steam Generator Consistent with

generator tubes corrosion of Tube Integrity; Tube Integrity the GALL Report

exposed to . steel tube Water Chemistry (B2.1.8) and (See SER

secondary support plate and, for plants that Water Chemistry Section

FW/steam could experience (B2.1.2) 3.1.2.1.4)

(3.1.1-79) . denting at the upper.

support plates,

evaluate potential

for rapidly

propagating cracks

and then develop

and take corrective

actions consistent

with NRC

_Bulletin 88-02.

3-177
Component Group Aging Effect/ - AMP in 'ýFurther AMP in LRA, Staff Evaluation

(GALL Report Mechanism GALL ReportEvaluation Supplements, or..'

Item No.) M . in GALL -' Amendment

- ___________ ______________ :Report _ _ _ _ _ _ _ _ _ _ _ _ _

CASS RVI Loss of fracture Thermal Aging and No Not applicable Not applicable to

(eig., upper toughness due Neutron Irradiation WCGS

intemals:assembly, to thermal Embrittlementof (See SER

lower internal *. aging and CASS Section

assembly, CEA... neutron 3.1.2.1.1)

shroud assemblies, irradiation

control rod guide • embrittlernent

tube assembly, core

support shield

assembly, lowergrid

assembly)"

(3.1.1-80) .. _ -

Nickel alloY or Cracking due to Water Chemistry No Water Chemistry Consistent with

nickel-alloy clad PWSCC (B2.1.2) the GALL Report

steam generator.

divider plate

exposed ,to reactor

coolant (3.1.1-81) V __ ' ..

Stainless steel Cracking due to Water Chemistry No *Not applicable Not applicable to

steam generator. SCC WCGS

primary side.divider (See SER

plate exposed to Section

reactor coolant!.ý' 3.1.2.1.1)

(3.1.1-82) .. _ _i

Stainless steel; steel Loss of material Water Chemistry No Water Chemistry Consistent with

with nickel-alloy or due to pitting (B2.1.2) the GALL Report

stainless steel and crevice

cladding; and corrosion

nickel-alloy RVI and

RCPB components

exposed to reactor

coolant

(3.1.1-83) . _.

Nickel alloy steam Cracking due to :Water Chemistry No Not applicable Not applicable to

generator • SCC and One-Time WCGS

components such .. Inspection or (See SER

as, secondary side Inservice Section

nozzles .... Inspection (IWB, 3.1r2.1.1)

(vent, drain, and - IWC, and IWD).

instrumentation)

exposed to

secondary

FW/steam

(3.1.1-84)

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'Component Group: Aging Ettectl AMP in Further AMP in LRA, Staff Evaluation.

(GALL Report Mechanism GALL Report 'Evaluation Supplements, or

Item No.) in GALL ' Amendment -

_____________ Report, _ _ _ _ _ _ _ _ _ _ _

Nickel alloy piping, None None No None Consistent with

piping components, the GALL Report

and piping elements

exposed to air -

indoor Uncontrolled

(external)

(3.1.1-85). "_

Stainless steel None None No None Consistent with

piping, piping the GALL Report

components, and

pipingellements

exposedto air -

indoor uncontrolled

(External); air with

borated water **...

leakage; concrete;

gas (3.1.1-86) __ _ _ _ __ _ _ _ __ _ _ __ _ _ _ _

Steel piping, piping None None No Not applicable Not applicable to

components, and WCGS

piping elements in (See SER

concrete Section

(3.1.1-87) _ _ __ 13.1.2.1.1)

The staff's review of the reactor vessel, RVI, and reactor coolant system component groups

followed any one of several approaches. One approach, documented in SER Section 3.1.2.1,

reviewed AMR results for components that the applicant indicated are consistent with the GALL

Report and •require no further evaluation. Another approach, documented in SER

Section 3.1.2.2, reviewed AMR results for components that the applicant indicated are

consistent with the GALL Report and for which further evaluation is recommended. Athirdc

approach, documented in SER Section 3.1.2.3, reviewed AMR results for components that the

applicant indicated are not consistent with or not addressed in'the GALL Report. The staff's

review of AMPs credited to manage or monitor aging effects of the reactor vessel, RVI, and.

reactor coolant system components is documented in SER Section 3.0.3.

3.1.2.1 AMR Results That Are Consistent with the GALL Report

LRA Section 3.1.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the reactor vessel, RVI, and reactor coolant system components:

* ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

. Water Chemistry.

: Boric dAcid Corrosion

• Bolting Integrity

* Closed-Cycle Cooling Water System

S-One-Time :Inspection

* One-Time Inspection of ASME Code Class 1 Small-Bore Piping

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" External Surfaces Monitoring

• Lubricating Oil Analysis

" Nickel Alloy Aging Management

" Reactor Coolant System Supplement

* Flow-Accelerated Corrosion

* Flux Thimble Tube Inspection

* Reactor Head Closure Studs

* Reactor Vessel Surveillance

* Steam Generator Tube Integrity

* Nickel Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of

Pressurized Water Reactors

LRA Tables 3.1.2-1 through 3.1.2-3 summarize AMRs for the reactor vessel, RVI, and reactor

coolant system components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

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consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

The staff completed its audit and review of the LRA. The staff did not repeat its review of the

matters described in the GALL Report; however, the staff verified that the material presented in

the LRA was applicable and that the applicant identified the appropriate GALL Report AMRs.

The staff's evaluation follows.

3.1.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.1.1, the applicant states in items 35, 66, 75, and 84 that the corresponding AMR

result lines in the GALL Report are not applicable because WCGS has recirculating steam

generators rather than once-through steam generators.

The staff reviewed the documentation supporting the applicant's AMR evaluations and

confirmed the applicant's statement that WCGS does not have once-through steam generators.

The staff also confirmed that the corresponding AMR result lines in the GALL Report apply only

for once-through steam generators. On the basis that WCGS does not have once-through

steam generators, the staff agrees with the applicant's determination that these AMR result

lines are not applicable to WCGS.

In LRA Table 3.1.1, item 56, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because WCGS has no copper alloy components with greater

than 15 percent zinc exposed to closed cycle cooling water within the scope of license renewal.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that WCGS has no copper alloy components with greater than 15 percent

zinc exposed to closed cycle cooling water that are within the scope of license renewal. On the

basis that WCGS does not have this component and material combination, the staff agrees with

the applicant's determination that the corresponding AMR result line in the GALL Report is not

applicable to WCGS.

In LRA Table 3.1.1, item 57, the applicant states that the aging effect of loss of fracture

toughness due to thermal aging embrittlement is not applicable for this material and

environment combination at WCGS because the molybdenum and ferrite values for these

components are below the industry accepted thermal aging embrittlement significance

threshold (i.e., less than 0.5 percent molybdenum and less than 20 percent ferrite).

The staff reviewed GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic

Stainless Steel (CASS)," and found that the susceptibility to thermal aging embrittlement of

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CASS components is determined in terms of casting method, molybdenum content, and ferrite

content. For low molybdenum content steels (i.e., 0.5 weight percent maximum), only static-cast

steels with greater than 20 percent ferrite are potentially susceptible to thermal embrittlement.

Static-cast low molybdenum steels with less than 20 percent ferrite and all centrifugal-cast low

molybdenum steels are not susceptible.

The staff requested that the applicant provides the actual maximum molybdenum and ferrite

values for the WCGS Class 1 CASS piping, piping components, piping elements, and control

rod drive (CRD) pressure housings, and to provide copies of applicable certified material test

reports for the staff review.

In its response, the applicant stated that the actual maximum molybdenum content is

0.35 percent and the actual maximum ferrite content is 19.5 percent.

The staff reviewed the applicant's certified material test reports and confirmed the maximum

values as stated by the applicant. On the basis that the applicant's Class 1 CASS piping, piping

components, piping elements, and control rode drive pressure housings are below the

molybdenum and ferrite threshold limits for susceptibility to thermal aging embrittlement, the

staff agrees with the applicant's determination that the aging effect of loss of fracture toughness

due to thermal aging embrittlement is not applicable to WCGS and finds that the aging

management evaluation result in the GALL Report, Volume 1, Table 1, item 57, is not

applicable.

In LRA Table 3.1.1, item 77, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because WCGS does not use phosphate chemistry.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that WCGS does not use phosphate chemistry in the FW system. On the

basis that WCGS does not have an environment of phosphate chemistry in the secondary FW

or steam systems, the staff agrees with the applicant's determination that the corresponding

AMR result line in the GALL Report is not applicable to WCGS.

In LRA Table 3.1.1, item 78, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because the WCGS steam generators do not contain lattice

bars.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that the steam generators do not contain lattice bars. On the basis that

WCGS does not have these components, the staff agrees with the applicant's determination

that the corresponding AMR result line in the GALL Report is not applicable to WCGS.

In LRA Table 3.1.1, item 80, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because the WCGS reactor internals are forged stainless steel,

not CASS.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that the WCGS reactor internals are forged stainless steel, not CASS. On

the basis that WCGS does not use CASS as a material of construction for its internal

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components, the staff agrees with the applicant's determination that the corresponding AMR

result line in the GALL Report is not applicable to WCGS.

In LRA Table 3.1.1, item 82, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because the primary side divider plates in the WCGS steam

generators are made of nickel alloy.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that the primary side divider plates in the WCGS steam generators are

made of nickel alloy. On the basis that the primary side divider plates in the steam generators

are made of nickel alloy, not stainless steel, the staff agrees with the applicant's determination

that the corresponding AMR result line in the GALL Report is not applicable to WCGS.

In LRA Table 3.1.1, item 87, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because WCGS has no components in the reactor vessel,

internals, and reactor coolant system within the scope of license renewal that are in concrete.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

the applicant's claim that WCGS has no components in the reactor vessel, internals, and

reactor coolant system within the scope of license renewal that are in concrete. On the basis

that the WCGS has no components in concrete in the reactor vessel, internals, and reactor

coolant system within the scope of license renewal, the staff agrees with the applicant's

determination that the corresponding AMR result line in the GALL Report is not applicable to

WCGS.

3.1.2.1.2 Loss of Material Due to Wear

In LRA Table 3.1.1, item 63, the applicant states that the AMR result is consistent with the

GALL AMP, with exceptions. The applicant further states that the AMP is the ASME Code

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD. The staff's evaluation of this

AMP is documented in SER Section 3.0.3.2.1.

The staff reviewed the individual AMR result lines that reference LRA Table 3.1.1, item 63 and

was unable to find an AMR result line for the lower internal assembly, radial keys, and inserts.

The staff requested that the applicant clarify whether these components are subject to the

aging effect of loss of material due to wear and whether the components are included within the

scope of the ASME Code Section XI, Inservice Inspection, Subsections IWB, IWC, and IWD

Program.

In its response, the applicant stated that the clevis insert bolts, radial keys, and the clevis

inserts are subject to the aging effect of loss of material due to wear. The applicant stated that

LRA Table 3.1.2-1 will be amended to include a new line for clevis insert bolts, radial keys, and

clevis inserts made of nickel alloy in a reactor coolant environment. The line will reference an

aging effect of loss of material that is managed by the ASME Code Section XI Inservice

Inspection, Subsections IWB, IWC, and IWD Program. The applicant stated that the new

component line in LRA Table 3.1.2-1 will refer to LRA Table 3.1.1, item 63, and GALL Report,

item IV.B2-34.

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By letter dated August 31, 2007, the applicant amended the LRA to add a new line into LRA

Table 3.1.2-1. The new line adequately includes the components, material, aging effect, and

AMP discussed.

The staff finds that the ASME Code Section XI Inservice Inspection, Subsection IWB, IWC, and

IWD Program provides adequate management for the aging effect of loss of material due to

wear. On the basis that the LRA amendment makes this AMR result line consistent with the

GALL Report, the staff finds the applicant's response acceptable.

3.1.2.1.3 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Table 3.1.1, item 68 and found that there are components referring to

this line in LRA Tables 3.1.2-2, 3.1.2-3, 3.2.2-10, 3.2.2-11, and 3.3.2-7. The staff noted that for

most of these AMR results, the material is stainless steel, the environment is reactor coolant,

the aging effect is cracking, and the AMPs credited are the ASME Code Section XI Inservice

Inspection, Subsections IWB, IWC, and IWD and Water Chemistry Programs. However, in LRA

Table 3.1.2-2, there are six lines where the component types are flow element, piping,

pressurizer relief tank, rupture disc, thermowell, and valve, for which the results are consistent

with the GALL Report. These six lines have an environment of treated borated water and the

AMP credited is the Water Chemistry Program. For these six lines, the applicant applied note E,

indicating that the component, material, environment, and aging effect are consistent with the

GALL Report; however, the AMP is different from the one recommended in the GALL Report.

The staff requested that the applicant clarify this inconsistency and explain the difference in the

AMR results for the stainless steel components in a reactor coolant or treated water

environment.

In its response, the applicant stated that the components for which the ASME Code Section Xl

Inservice Inspection, Subsections IWB, IWC, and IWD Program was not used are components

that do not provide a RCPB function and that do not require inspection under the provisions of

ASME Code Section XI. The applicant stated that these AMR result lines for non-ASME

Code Section XI components should have been identified with GALL Report, item V.D1 -31,

where the material is stainless steel, the environment is treated borated water, the aging effect

is cracking, and the recommended AMP is the Water Chemistry Program. The applicant stated

that the LRA will be revised for these six items, to reference GALL Report, item V.D1-31, and

LRA Table 3.2.2, item 48. The applicant stated that note B will be applied to these lines,

indicating that the component, material, environment, aging effect, and AMP are consistent with

the GALL Report; however, the AMP takes some exceptions to the GALL AMP. By letter dated

August 31, 2007, the applicant adequately amended the LRA to make these changes (with

adequate justifications to be consistent with the GALL Report).

The staff finds that the affected AMR result lines are consistent with the GALL Report. Based

on their consistency with corresponding AMR result lines in the GALL Report, the staff finds the

applicant's response acceptable.

3.1.2.1.4 Denting Due to Corrosion of Steel Tube Support Plate

In LRA Table 3.1.1, item 79, the applicant states that the use of ferritic stainless steel support

plates is expected to prevent denting for the life of the steam generators; therefore, corrective

actions consistent with NRC Bulletin 88-02 are not applicable to WCGS.

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The staff reviewed NRC Bulletin 88-02 and determined that it is applicable for steam generators

having carbon steel support plates. The staff found that the Westinghouse Model F steam

generators in use by WCGS are not listed in the bulletin. On the basis that the actions

described in NRC Bulletin 88-02 are not applicable for steam generators which use stainless

steel support plates, the staff finds the AMR result line in the LRA to be consistent with the

GALL Report and; therefore, acceptable.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the reactor vessel, RVI, and reactor coolant system components and

provides information concerning how it will manage the following aging effects and related QA:

* cumulative fatigue damage

* loss of material due to general, pitting, and crevice corrosion

• loss of fracture toughness due to neutron irradiation embrittlement

* cracking due to SCC and IGSCC

* crack growth due to cyclic loading

• loss of fracture toughness due to neutron irradiation embrittlement and void swelling

* cracking due to SCC

* cracking due to cyclic loading

* loss of preload due to stress relaxation

* loss of material due to erosion

* cracking due to flow-induced vibration

* cracking due to SCC and irradiation-assisted stress corrosion cracking (IASCC)

• cracking due to PWSCC

* wall thinning due to flow-accelerated corrosion

* changes in dimensions due to void swelling

* cracking due to SCC and PWSCC

* cracking due to SCC, PWSCC, and IASCC

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in SRP-LR Section 3.1.2.2. The staff's review of the

applicant's further evaluation follows.

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3.1.2.2.1 Cumulative Fatigue Damage

LRA Section 3.1.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1).

In LRA Table 3.1.1, item 1, the applicant states that the AMR result line in the GALL Report is

not used because WCGS has a Westinghouse reactor vessel and does not have a pressure

vessel support skirt.

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed

that WCGS does not have a pressure vessel support skirt. On the basis that WCGS does not

have a pressure vessel support skirt, the staff agrees with the applicant's determination that the

AMR result line in the GALL Report is not applicable to WCGS.

In LRA Table 3.1.1, items 2, 3, and 4, the applicant states that the AMR result lines are not

applicable.

The staff reviewed the corresponding AMR result lines in the SRP-LR and noted that they apply

only to boiling water reactors (BWRs). On this basis, the staff agrees with the applicant's

determination that LRA Table 3.1.1, items 2, 3, and 4, are not applicable, because WCGS is a

PWR.

The staff noted that LRA Table 3.1.1, items 5 through 10, are AMR result lines with an aging

effect of cumulative fatigue. SER Section 4.3 documents the staff's review of the applicant's

evaluation of these TLAAs.

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR

Section 3.1.2.2.2:

(1) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in PWR steam generator shell assembly exposed to FW and steam. The

applicant stated that this aging effect is not applicable because WCGS has recirculating

steam generators, not once-through steam generators; therefore, the applicable GALL

Report line item was not used.

SRP-LR Section 3.1.2.2.2 specifies that loss of material due to general, pitting, and

crevice corrosion may occur in the steel PWR steam generator shell assembly exposed

to secondary FW and steam. Loss of material due to general, pitting, and crevice

corrosion also may occur in the steel top head enclosure (without cladding) top head

nozzles (vent, top head spray or reactor core isolation cooling (RCIC), and spare)

exposed to reactor coolant.

In LRA Table 3.1.1, item 11, the applicant states that the line is not applicable because it

applies to BWRs only.

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The staff noted that this item applies to BWR systems and; therefore, is not applicable

to WCGS because WCGS is a PWR. On this basis, the staff finds that this aging effect

is not applicable to this component type.

In LRA Table 3.1.1, item 12, the applicant states that WCGS has recirculating steam

generators, not once-through steam generators; therefore, the applicable GALL Report

line was not used.

The staff noted that GALL Report, item 12, is applicable only for once-through steam

generators and that GALL Report, item 16, is used for recirculating steam generators

with the same material, environment, and aging effect combination. On the basis that

WCGS does not have once-through steam generators, the staff agrees with the

applicant's determination that this line is not applicable to WCGS.

(2) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in BWR isolation condenser components exposed to reactor coolant. The

applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.1.2.2.2 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel BWR isolation condenser components exposed to

reactor coolant. Loss of material due to general, pitting, and crevice corrosion may occur

in steel BWR isolation condenser components.

In LRA Table 3.1.1, item 13, the applicant states that the AMR result line is not

applicable.

The staff reviewed the corresponding AMR result line in the SRP-LR and confirmed that

it applies only to a BWR. On this basis, the staff agrees with the applicant's

determination that LRA Table 3.1.1, item 13, is not applicable because WCGS is a

PWR.

(3) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in reactor vessel components exposed to reactor coolant. The applicant stated

that this section of the SRP-LR describing further evaluation is not applicable because

WCGS is a PWR.

SRP-LR Section 3.1.2.2.2 specifies that loss of material due to pitting and crevice

corrosion may occur in stainless steel, nickel alloy, and steel with stainless steel or

nickel alloy cladding flanges, nozzles, penetrations, pressure housings, safe ends, and

vessel shells, heads, and welds exposed to reactor coolant.

In LRA Table 3.1.1, items 14 and 15, the applicant states that these lines are not

applicable because they apply only for BWRs.

The staff noted that the GALL Report, items 14 and 15, provide AMR results for

components in a BWR reactor coolant environment, and GALL Report, item 83,

provides AMR results for similar components in a PWR reactor coolant environment. On

the basis of this review, the staff agrees with the applicant's determination that GALL

Report, items 14 and 15, are applicable only to BWRs.

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(4) LRA Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in steam generator shell and transition cone exposed to secondary FW and

steam. The applicant stated that augmented inspection for loss of material is not

applicable at WCGS because the steam generators at WCGS are Model F, and

augmented inspection is recommended for Westinghouse Model 44 and 51 steam

generators, if general and pitting corrosion of the shell exist due to the high stress in the

shell to transition cone weld.

SRP-LR Section 3.1.2.2.2 specifies that loss of material due to general, pitting, and

crevice corrosion may occur in the steel PWR steam generator upper and lower shell

and transition cone exposed to secondary FW and steam. The existing program controls

chemistry to mitigate corrosion and ISI to detect loss of material. The extent and

schedule of the existing steam generator inspections are designed to ensure that flaws

cannot attain a depth sufficient to threaten the integrity of the welds; however, according

to NRC Information Notice (IN) 90-04, the program may not be sufficient to detect pitting

and crevice corrosion, if general and pitting corrosion of the shell is known to occur. The

GALL Report recommends augmented inspection to manage this aging effect.

Furthermore, the GALL Report clarifies that this issue is limited to Westinghouse

Model 44 and 51 steam generators with a high-stress region at the shell to transition

cone weld.

The staff confirmed that the WCGS steam generators are Westinghouse Model F. On

this basis, the staff finds that the applicant's statement is consistent with the GALL

Report and; therefore, is acceptable. The AMR result in the LRA states that the aging

effect of loss of material due to general, pitting, and crevice corrosion will be managed

by the ASME Code Section XI Inservice Inspection, Subsection IWB, IWC, and IWD

and Water Chemistry Programs (without augment inspection). The staff finds the AMR

result acceptable because it is consistent with the GALL Report (the staff's review

criteria).

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.2

criteria.

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Section 3.1.2.2.3 against the criteria in SRP-LR Section 3.1.2.2.3:

(1) LRA Section 3.1.2.2.3 states that neutron irradiation embrittlement is a TLAA, as defined

in 10 CFR 54.3.-Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1). SER Section 4.2 documents the staff's review of the applicant's

evaluation of this TLAA.

(2) LRA Section 3.1.2.2.3 addresses loss of fracture toughness due to neutron irradiation

embrittlement. The applicant stated that the Reactor Vessel Surveillance Program

manages this aging effect in carbon steel components clad with stainless steel exposed

to reactor coolant. The last coupons examined were exposed to a fluence approximately

equal to 54 effective full power years, the projected fluence through the period of

extended operation. The examination of these coupons demonstrated that beltline

materials will remain limiting, and that adequate adjusted reference temperature,

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upper-shelf energy, and PTS screening temperature margin will remain at the end of the

60-year operating period. The applicant stated that subsequent revisions to

pressure-temperature limits will provide adequate operating margin, without the use of

special methods.

SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron

irradiation embrittlement may occur in BWR and PWR reactor vessel beltline shell,

nozzle, and welds exposed to reactor coolant and neutron flux. A reactor vessel

materials surveillance program monitors neutron irradiation embrittlement of the reactor

vessel. Reactor vessel surveillance programs are plant-specific, depending on matters

such as the composition of limiting materials, availability of surveillance capsules, and

projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant

is required to submit its proposed withdrawal schedule for approval prior to

implementation. Untested capsules placed in storage must be maintained for future

insertion. Thus, further staff evaluation is required for license renewal. Specific

recommendations for an acceptable AMP are provided in GALL Report Chapter Xl,

Section M31.

The staff noted that LRA Section 3.2.2.3-1 states that since beltline materials remain

limiting, nozzles were not evaluated separately.

The staff reviewed LRA Section 3.1.2.2.3-1 and identified an area in which additional

information was necessary to complete the staff's review of the applicant's AMRs. The

applicant responded to the staff's RAI as discussed below.

In RAI 3.1.2.2.3-1 dated April 9, 2007, the staff stated that in accordance with

10 CFR Part 50, Appendix H, Section III, if the end of life (EOL) peak neutron fluence

exceeds 1017 n/cm 2 (i.e., E greater than 1 MeV) the material must be monitored through

a surveillance program. The staff requested that the applicant confirm that the increase

in peak 60-year EOL fluence for the nozzles will not exceed this value. The staff

requested that the applicant provides appropriate data for the inclusion of nozzle

materials in the surveillance program, or explain how the nozzle materials are

adequately monitored by the proposed AMP.

In its response dated May 9, 2007, the applicant stated that the original selection of the

limiting beltline material was made for an expected 32 EFPY peak beltline clad-based

metal fluence of 3.14 x 1019 n/cm2 (i.e., E greater than 1 MeV), before the change to low

leakage cores. With low-leakage cores, the expected 54 EFPY peak fluence is

3.51 x 10'V n/cm2 (i.e., E greater than 1 MeV), an increase of only 12 percent. The

change is smaller than the 20 percent tolerance described in RG 1.190, "Calculational

and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence." Analysis of

upper-shelf energy and reference temperature nil ductility transition (RTNDT) values for

the nozzles determines that the nozzle materials will not become limiting; therefore, they

will be adequately monitored by the Reactor Vessel Surveillance Program.

The staff's evaluation of the applicant's response and Reactor Vessel Surveillance

Program. The results of the staff's evaluation of the applicant's Reactor Vessel

Surveillance Program is documented in SER Section 3.0.3.1.2. The results of the staff's

evaluation of the applicant's reactor vessel neutron embrittlement TLAA is documented

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in SER Section 4.2. The staff noted that four capsules have been removed for testing.

The capsule withdrawal schedule was revised by the removal of the last two capsules, at

fluence exposures greater than those expected at the beltline wall at 60 years. The staff

finds that this meets the ASTM E 185-82 criterion which states that capsules may be

removed when the capsule neutron fluence is between one and two times the limiting

fluence calculated for the vessel at the expected EOL. The staff finds that the

surveillance specimens in the last capsule removed, Capsule X, were exposed to

fluences equivalent to approximately 60 years (i.e., 54 EFPY) of vessel operation. On

the basis of its review, the staff finds this acceptable.

The staff determines that the LRA correctly identifies WCGS components that are

subject to the aging effect of loss of fracture toughness due to neutron irradiation

embrittlement and that associated AMR results in LRA Tables 3.1.1 and 3.1.2-1 are

consistent with the recommendations in the GALL Report.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion

Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR

Section 3.1.2.2.4:

(1) SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the

stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection

lines.

LRA Section 3.1.2.2.4 addresses cracking due to SCC and intergranular stress

corrosion cracking (IGSCC) in BWR top head enclosure, vessel flange leak detection

lines. The applicant stated that this aging effect is not applicable because WCGS is a

PWR.

The staff noted that this line item applies to BWR top head enclosures, vessel flange

detection lines and; therefore, is not applicable to WCGS because WCGS is a PWR. On

this basis, the staff finds that this aging effect is not applicable to this component type.

(2) LRA Section 3.1.2.2.4 addresses cracking due to SCC and IGSCC in BWR isolation

condenser components exposed to reactor coolant. The applicant stated that this aging

effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in

stainless steel BWR isolation condenser components exposed to reactor coolant.

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The staff noted that this line item applies to BWR isolation condenser components and;

therefore, is not applicable to WCGS because WCGS is a PWR. On this basis, the staff

finds that this aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.4

criteria.

3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5 indicates that growth of intergranular separations (underclad cracks) in

the heat affected zone under austenitic steel cladding is a TLAA, as defined in 10 CFR 54.3.

Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.7

documents the staff's review of the applicant's evaluation of this TLAA.

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void

Swelling

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.

LRA Section 3.1.2.2.6 addresses loss of fracture toughness due to neutron irradiation

embrittlement and void swelling. The applicant stated that this aging effect in nickel alloy and

stainless steel reactor internals components exposed to reactor coolant will be managed by (1)

participating in the industry programs for investigating and managing aging effects on reactor

internals; (2) evaluating and implementing the results of the industry programs as applicable to

the reactor internals; and (3) submitting an inspection plan for reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

SRP-LR Section 3.1.2.2.6 states that loss of fracture toughness due to neutron irradiation

embrittlement and void swelling may occur in stainless steel and nickel alloy RVI components

exposed to reactor coolant and neutron flux. The GALL Report recommends no further AMR if

the applicant commits in the final safety analysis report (USAR) supplement (1) to participate in

industry programs for investigating and managing aging effects on reactor internals, (2) to

evaluate and implement the results of the industry programs as applicable to the reactor

internals, and (3) upon completion of these programs, but not less than 24 months before

entering the period of extended operation, to submit an inspection plan for reactor internals to

the staff for review and approval.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff finds that, for the RCS nickel alloy pressure boundary components, the applicant

committed (Commitment No. 19) to: (1) implement applicable NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) implement applicable staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the EPRI Materials

Reliability Program, for managing aging effects associated with nickel alloys, and (4) submit an

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inspection plan for RCS nickel alloy pressure boundary components to the NRC, for review and

approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the nickel alloy and stainless steel

reactor internals components. The staff finds that this commitment is consistent with the

recommendations in the GALL Report; therefore, no further AMR evaluation is necessary.

Based on the program identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to LRA Section 3.1.2.2.6, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.7 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.7 against the following criteria in SRP-LR

Section 3.1.2.2.7, as a part of the staff's audit of the applicant's AMR/AMP:

(1) LRA Section 3.1.2.2.7 addresses cracking due to SCC in PWR stainless steel reactor

vessel flange leak detection lines. The applicant stated that for managing this aging

effect in stainless steel components exposed to reactor coolant, the Water Chemistry

Program will be augmented by the ASME Code Section XI Inservice Inspection,

Subsections IWB, IWC, and IWD Program to ensure that adequate inspection methods

detect cracks.

SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in the PWR

stainless steel reactor vessel flange leak detection lines and bottom-mounted instrument

guide tubes exposed to reactor coolant. The GALL Report recommends that a

plant-specific AMP be evaluated to ensure that this aging effect is adequately managed.

The staff noted that the LRA includes only one AMR result line that references LRA

Table 3.1.1, item 23, where the material is stainless steel in a reactor coolant

environment and the aging effect is cracking due to stress corrosion. However, the

SRP-LR discussion and the GALL Report include two AMR result lines that refer to

GALL Report, item 23. The GALL Report identifies the first as bottom-mounted guide

tubes components and the second as closure head, vessel flange leak detection line

components. The staff noted that the LRA components in the AMR result line are

identified as reactor vessel penetrations (i.e., instrument tubes (top head), and high

pressure conduits). The staff requested that the applicant clarify whether the

components identified in the LRA are the same as the components listed in the GALL

Report and justify any differences.

In its response, the applicant stated that the high pressure conduits are the guide tubes

that enclose the flux thimble tubes from the bottom of the vessel, and provide a

pressure boundary function for the reactor coolant; they are the same as the

components called bottom-mounted guide tubes in the GALL Report. The applicant

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stated that the instrument tubes (top head) are stainless steel instrument lines attached

to vessel head penetrations, but they do not include the vessel flange leak detection

line. The applicant stated that the vessel flange leak detection line (i.e., O-ring leak

monitoring tube) is included in LRA Table 2.3.1-1; however, it is made of nickel alloy and

therefore is not evaluated under GALL Report, item 23, where the material is stainless

steel.

The applicant stated that the AMR result line for the vessel flange leak detection line

references LRA Table 3.1.1, item 65, and credits the ASME Code Section Xl Inservice

Inspection, Subsections IWB, iWC, and IWD, the Water Chemistry, and the Nickel-Alloy

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized

Water Reactors Programs.

The staff requested, as a part of the staff's audit of the applicant's AMR/AMP, that the

applicant clarify whether there are any nickel alloy welds associated with the

bottom-mounted instrument guide tubes and, if so, to identify where the AMR results for

those welds are presented in the LRA.

In its response, the applicant stated that there are nickel alloy welds associated with the

bottom-mounted instrument guide tubes, including the J-groove welds of the flux thimble

guide tube penetrations to the vessel bottom and the welds of the flux thimble guide

tube penetrations to the bottom-mounted instrument guide tubes. The applicant stated

that these welds are included in the AMR results for reactor vessel penetrations (i.e.,

flux thimble guide tube penetrations), which references LRA Table 3.1.1, item 31, for the

aging effect of cracking due to primary water stress corrosion, and LRA Table 3.1.1,

item 83, for the aging effect of loss of material due to pitting and crevice corrosion.

The staff finds the applicant's response acceptable because the nickel alloy welds

associated with the bottom-mounted instrument guide tubes have been included in the

AMR results provided in the LRA. The staff's evaluation of the AMPs credited by the

applicant to manage the aging effects in vessel flange leak detection line are

documented in SER Sections 3.0.3.2.1, 3.0.3.2.2, and 3.0.3.2.5, respectively.

However, the staff noted that the title of LRA Section 3.1.2.2.7.1, "PWR stainless steel

reactor vessel flange leak detection lines," appears to be inconsistent with the

applicant's response because the title implies that the reactor vessel flange leak

detection line is made of stainless steel.

In its response, the applicant stated that the title of LRA Section 3.1.2.2.7.1 and the note

in LRA Table 3.1.1, item 23, would be amended to remove the inconsistency and

provide clarification.

By letter dated August 31, 2007, the applicant amended the LRA as follows:

The title of LRA Section 3.1.2.2.7.1 was changed to read, "PWR stainless

steel reactor vessel instrument tubes and bottom-mounted flux thimble

guide tubes."

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The discussion column of LRA Table 3.1.1, item 3.1.1.23, was changed

to state that the reactor vessel O-ring lead monitoring tubes are made of

nickel alloy.

Based on the applicant's response, the staff determines that the LRA includes AMR

results for all the components referenced in GALL Report, item 23. For the WCGS

bottom-mounted instrument guide tubes and other vessel instrument tubes, which are

made of stainless steel and in a reactor coolant environment, the staff finds that the

applicant's use of the Water Chemistry Program, along with the ASME Code Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD Program is adequate to manage

the aging effect of cracking due to SCC. The staff finds that the Water Chemistry

Program provides mitigation of the aging effect, and the ASME Code Section XI

Inservice Inspection Subsections IWB, IWC, and IWD Program provides ongoing

confirmation of the effectiveness of the Water Chemistry Program.

On the basis that the LRA includes AMR results for all components described in the

GALL Report, item 23, and in SRP-LR Subsection 3.1.2.2.7.1, and that the Water

Chemistry and the ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC,

and IWD Programs are suitable to manage the aging effect of cracking in stainless steel

components in a reactor coolant environment, the staff finds the applicant's AMR result

for the affected components acceptable. The staff finds that the AMPs credited by the

applicant include activities that are consistent with the recommendations in the GALL

Report, and are adequate to manage aging effect of cracking due to SCC in stainless

steel bottom-mounted instrument guide tubes and other stainless steel vessel

instrumentation tubes.

(2) LRA Section 3.1.2.2.7 addresses cracking due to SCC in CASS reactor coolant system

piping and components exposed to reactor coolant. The applicant stated that for

managing this aging effect in CASS piping components exposed to reactor coolant, the

Water Chemistry Program will be augmented by the ASME Code Section Xl Inservice

Inspection, Subsections IWB, IWC, and IWD Program to ensure that adequate

inspection methods detect cracks. The CASS in the RCS piping at WCGS meets the

NUREG-0313 requirements for ferrite content but not for carbon content. A flaw

evaluation methodology for CASS components is not necessary because CASS piping

at WCGS is not susceptible to thermal aging embrittlement. Based on a review of

Certified Material Test Reports, the molybdenum and ferrite values for these

components are below the industry accepted thermal aging embrittlement significance

threshold (less than 0.5 percent molybdenum, less than 20 percent ferrite).

SRP-LR Section 3.1.2.2.7 states that cracking due to SCC may occur in Class 1 PWR

CASS reactor coolant system piping, piping components, and piping elements exposed

to reactor coolant. The existing program controls water chemistry to mitigate SCC;

however, SCC may occur in CASS components that do not meet the NUREG-0313

guidelines with regard to ferrite and carbon content. The GALL Report recommends

further evaluation of a plant-specific program for these components to ensure this aging

effect is adequately managed.

The staff noted that for Class 1 piping and piping components made of CASS, the GALL

Report recommends: (a) monitoring and control of primary water chemistry in

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accordance with the guidelines of EPRI TR-1 05714 (Revision 3 or later) to minimize the

potential for SCC, and (b) material selection in accordance with NUREG-0313,

Revision 2, guidelines, which specify a maximum carbon content of 0.035 percent and a

minimum ferrite content of 7.5 percent. For CASS components that do not meet either

the maximum carbon or the minimum ferrite guideline, the GALL Report recommends a

plant-specific AMP that should include: (a) adequate inspection methods to ensure

detection of cracks, and (b) flaw evaluation methodology for CASS components that are

susceptible to thermal aging embrittlement.

In LRA Table 3.1.1, item 24, the applicant states that the aging effect of cracking due to

SSC in CASS piping exposed to reactor coolant will be managed using the Water

Chemistry Program. The LRA states that this program will be augmented with the ASME

Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

because the CASS in the reactor coolant system piping does not meet the limit for

maximum carbon content specified in NUREG-0313.

The staff requested, as a part of the staff's audit of the applicant's AMR/AMP, that the

applicant provides the actual carbon content of the CASS piping at WCGS and describe

the ASME Code Section XI examinations used for the CASS piping.

In its response, the applicant stated that the carbon content of CASS piping at WCGS is

in the range of 0.05 to 0.08 percent, which is above the 0.035 percent maximum carbon

content limit specified in NUREG-0313. The applicant also stated that ASME

Code Section XI examinations of CASS piping welds are performed in accordance with

the examination requirements of ASME Code Section XI, Table IWB-2500-1,

Examination Category B-J, items B9.10 and B9.1 1, which require surface and volumetric

examinations. The applicant stated that volumetric examination is performed using UT

because it is a proven industry technique for detection of weld and adjacent base metal

cracking caused by SCC.

The staff's evaluation of the applicant's Water Chemistry, and ASME Code Section XI

Inservice Inspection, Subsections IWB, IWC, and IWD Programs is documented in SER

Sections 3.0.3.2.2 and 3.0.3.2.1, respectively. On the basis of its evaluations of these

programs, the staff finds that the applicant's use of the Water Chemistry Program

augmented by the ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC,

and IWD Program is consistent with the recommendations in the GALL Report for a

plant-specific program that includes adequate inspection methods to ensure detection of

cracks.

In LRA Section 3.1.2.2.7.2, the applicant states that the molybdenum and ferrite content

of the Class 1 CASS piping, piping components, and piping elements are below the

thermal aging embrittlement threshold.

The staff requested, as a part of the staff's audit of the applicant's AMR/AMP, that the

applicant provides the actual maximum molybdenum and ferrite values for the WCGS

Class 1 CASS piping, piping components, and piping elements, and provide copies of

applicable certified material test reports for the staff review.

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In its response, the applicant stated that the actual maximum molybdenum content is

0.35 percent and the actual maximum ferrite content is 19.5 percent. The staff reviewed

the applicant's certified material test reports and confirmed the values as stated by the

applicant. From the reports, the staff also noted that the CASS pipes, but not the pipe

fittings, were fabricated using a centrifugal casting method.

The staff assessed the susceptibility of the WCGS Class 2 CASS piping to thermal

aging embrittlement using the guidance in GALL AMP XI.M12, "Thermal Aging

Embrittlement of Cast Austenitic Stainless Steel (CASS)." The GALL Report states that

the susceptibility to thermal aging embrittlement of CASS components is determined in

terms of casting method, molybdenum content, and ferrite content. For low molybdenum

content steels (i.e., 0.5 weight percent maximum), only static-cast steels with greater

than 20 percent ferrite are potentially susceptible to thermal embrittlement. Static-cast

low molybdenum steels with less than or equal to 20 percent ferrite and all

centrifugal-cast low molybdenum steels are not susceptible.

On the basis that the applicant's Class 1 CASS piping, piping components, and piping

elements are below the molybdenum and ferrite threshold limits for susceptibility to

thermal aging embrittlement, the staff finds that a flaw evaluation methodology for CASS

components is not necessary, and the AMPs credited by the applicant are acceptable.

The AMR result for the affected components is consistent with the recommendations of

the GALL Report.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.7 criteria. For those line items that apply to LRA Section 3.1.2.2.7, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.8 Cracking Due to Cyclic Loading

The staff reviewed LRA Section 3.1.2.2.8 against the following criteria in SRP-LR

Section 3.1.2.2.8:

(1) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in BWR jet pump

sensing lines. The applicant stated that this aging effect is not applicable because

WCGS is a PWR.

SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the

stainless steel BWR jet pump sensing lines.

The staff noted that this line item applies to BWR jet pump sensing lines and; therefore,

is not applicable to WCGS because WCGS is a PWR. On this basis, the staff finds that

this aging effect is not applicable to this component type.

(2) LRA Section 3.1.2.2.8 addresses cracking due to cyclic loading in BWR isolation

condenser components exposed to reactor coolant. The applicant stated that this aging

effect is not applicable because WCGS is a PWR.

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SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel

and stainless steel BWR isolation condenser components exposed to reactor coolant.

The staff noted that this line item applies to BWR isolation condenser components and;

therefore, is not applicable to WCGS because WCGS is a PWR. On this basis, the staff

finds that this aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.8

criteria.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9.

LRA Section 3.1.2.2.9 addresses loss of preload due to stress relaxation. The applicant stated

that loss of preload due to stress relaxation for nickel alloy and stainless steel reactor internals

components exposed to reactor coolant will be managed by (1) participating in the industry

programs for investigating and managing aging effects on reactor internals; (2) evaluating and

implementing the results of the industry programs as applicable to the reactor internals; and

(3) submitting an inspection plan for reactor internals to the NRC, for review and approval,

24 months before entering the period of extended operation.

SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation may occur in

stainless steel and nickel alloy PWR RVI screws, bolts, tie rods, and hold-down springs

exposed to reactor coolant. The GALL Report recommends no further AMR if the applicant

commits in the FSAR supplement (1) to participate in the industry programs for investigating

and managing aging effects on reactor internals, (2) to evaluate and implement the results of

the industry programs as applicable to the reactor internals, and (3) upon completion of these

programs, but not less than 24 months before entering the period of extended operation, to

submit an inspection plan for reactor internals to the staff for review and approval.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff finds that, for the RCS nickel alloy pressure boundary components, the applicant

committed (Commitment No. 19) to: (1) implement applicable NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) implement applicable staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the EPRI Materials

Reliability Program, for managing aging effects associated with nickel alloys, and (4) submit an

inspection plan for RCS nickel alloy pressure boundary components to the NRC, for review and

approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the nickel alloy and stainless steel

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reactor internals components. The staff finds that this commitment is consistent with the

recommendations in the GALL Report; therefore, no further AMR evaluation is necessary.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.1.2.2.9 criteria. For those line items that apply to LRA Section 3.1.2.2.9, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.10 Loss of Material Due to Erosion

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10.

LRA Section 3.1.2.2.10 addresses loss of material due to erosion. The applicant stated that this

aging effect is not applicable because WCGS does not have impingement plates.

SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steam

generator FW impingement plates and supports exposed to secondary FW.

The staff confirmed that WCGS uses Westinghouse Model F steam generators, which do not

have FW impingement plates. On the basis that WCGS does not have FW impingement plates,

the staff agrees with the applicant's determination that this AMR result in the SRP-LR and in the

GALL Report is not applicable to WCGS.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.10

criteria.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

LRA Section 3.1.2.2.11 addresses cracking due to flow induced vibration. The applicant stated

that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.1.2.2.11 states that cracking due to flow induced vibration could occur in the

BWR stainless steel steam dryers exposed to reactor coolant.

The staff noted that this line item applies to BWR steam dryers and; therefore, is not applicable

to WCGS because WCGS is a PWR. On this basis, the staff finds that this aging effect is not

applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.1.2.2.11

criteria.

3.1.2.2.12 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress

Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12.

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LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC. The applicant stated that

for managing this aging effect in stainless steel reactor internals components exposed to

reactor coolant, water chemistry will be augmented by (1) participating in the industry programs

for investigating and managing aging effects on reactor internals; (2) evaluating and

implementing the results of the industry programs as applicable to the reactor internals; and (3)

submitting an inspection plan for reactor internals to the NRC, for review and approval, 24

months before entering the period of extended operation.

SRP-LR Section 3.1.2.2.12 states that cracking due to SCC and IASCC may occur in PWR

stainless steel reactor internals exposed to reactor coolant. The existing program controls water

chemistry to mitigate these aging effects. The GALL Report recommends no further AMR if the

applicant commits in the FSAR supplement (1) to participate in the industry programs for

investigating and managing aging effects on reactor internals, (2) to evaluate and implement

the results of the industry programs as applicable to the reactor internals, and (3) upon

completion of these programs, but not less than 24 months before entering the period of

extended operation, to submit an inspection plan for reactor internals to the staff for review and

approval.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the stainless steel reactor internals

components. The staff finds that this commitment is consistent with the recommendations in the

GALL Report; therefore, no further AMR evaluation is necessary.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to LRA Section 3.1.2.2.12,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.13 Cracking Due to Primary Water Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13.

LRA Section 3.1.2.2.13 addresses cracking due to PWSCC. The applicant stated that for

managing this aging effect in nickel alloy components exposed to reactor coolant, water

chemistry and ISI will be augmented by the plant-specific Nickel Alloy Aging Management

Program, and by implementing applicable (1) NRC Orders, Bulletins, and Generic Letters

associated with nickel alloys and (2) staff-accepted industry guidelines.

SRP-LR Section 3.1.2.2.13 states that cracking due to PWSCC may occur in PWR components

made of nickel alloy and steel with nickel alloy cladding, including RCPB components and

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penetrations inside the reactor coolant system such as pressurizer heater sheathes and

sleeves, nozzles, and other internal components. Except for reactor vessel upper head nozzles

and penetrations, the GALL Report recommends ASME Code Section XI ISI (for Class 1

components) and control of water chemistry. However, for nickel alloy components, no further

AMR is necessary if the applicant complies with applicable NRC orders and commits in the

FSAR supplement to implement applicable (1) bulletins and generic letters, and

(2) staff-accepted industry guidelines.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff finds that, for the RCS nickel alloy pressure boundary components, the applicant

committed (Commitment No. 19) to: (1) implement applicable NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) implement applicable staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the EPRI Materials

Reliability Program, for managing aging effects associated with nickel alloys, and (4) submit an

inspection plan for RCS nickel alloy pressure boundary components to the NRC, for review and

approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the nickel alloy and stainless steel

reactor internals components. The staff finds that this commitment is consistent with the

recommendations in the GALL Report; therefore, no further AMR evaluation is necessary.

The staff also reviewed the applicant's Nickel Alloy Aging Management Program which is

credited to manage PWSCC. The staff's evaluation of the Nickel Alloy Aging Management

Program is documented in SER Section 3.0.3.3.1. The staff finds that this program will

adequately manage the aging effects in nickel alloy components so that the intended functions

will be maintained consistent with the CLB during the period of extended operation.

The staff finds that, similar to the commitment (Commitment No. 19) provided by the applicant

in the Reactor Coolant System Supplement Program, the Nickel Alloy Aging Management

Program commitment (Commitment No. 30) implements: (1) NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) staff-accepted industry guidelines, and (3) participation in

industry initiatives, such as owners group programs and the EPRI Materials Reliability Program,

for managing PWSCC. In addition, the staff finds that the applicant will submit the Nickel Alloy

Aging Management Program inspection plan to the NRC, for its review and approval, 24

months before entering the period of extended operation.

The staff finds that this commitment provides reasonable assurance that an acceptable

AMP will be implemented and that the aging effects will be adequately managed during the

period of extended operation.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.13 criteria. For those line items that apply to LRA Section 3.1.2.2.13,

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the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP-LR Section 3.1.2.2.14.

LRA Section 3.1.2.2.14 addresses wall thinning due to flow-accelerated corrosion. The

applicant stated that feedring wall thinning was described in NRC IN 91-19. Evaluation of this

condition is not applicable to WCGS and no action is required; however, the Water Chemistry

and the Steam Generator Tube Integrity Programs are conservatively credited to manage wall

thinning due to flow-accelerated corrosion for the feedring.

SRP-LR Section 3.1.2.2.14 states that wall thinning due to flow-accelerated corrosion may

occur in steel FW inlet rings and supports. The GALL Report references IN 91-19, "Steam

Generator Feedwater Distribution Piping Damage," for evidence of flow-accelerated corrosion in

steam generators and recommends that a plant-specific AMP be evaluated because existing

programs may not be capable of mitigating or detecting wall thinning due to flow-accelerated

corrosion.

The staff reviewed NRC IN 91-19 and noted that it describes a problem with Combustion

Engineering steam generator designs which are not used at WCGS. The staff also noted that

the applicant credits the Water Chemistry and the Steam Generator Tube Integrity Programs to

manage the aging effect of wall thinning in the FW ring, should it occur in the Westinghouse

designed steam generators at WCGS.

The staff noted that the description of the Steam Generator Tube Integrity Program in the LRA

and in the GALL Report does not indicate that the steam generator FW ring is within the scope

of the AMP. The staff requested that the applicant clarify whether the scope of this

AMP provides for inspections of the FW ring to manage loss of material (i.e., wall thinning) due

to flow-accelerated corrosion.

In its response, the applicant stated that the scope of its Steam Generator Tube Integrity

Program is consistent with NEI 97-06, "Steam Generator Program Guidelines," which

recommends that secondary side components that are susceptible to degradation be monitored

if their failure could affect the intended function of the steam generator. The applicant stated

that its Steam Generator Tube Integrity Program includes the FW rings and J-tubes as part of

the secondary side inspections and that the program provides instructions for visual inspections

of the upper steam drum, including FW ring and J-tubes on, at least, one steam generator at

each refueling outage.

The staff's evaluation of the applicant's Water Chemistry and Steam Generator Tube Integrity

Programs is documented in SER Sections 3.0.3.2.2 and 3.0.3.2.8, respectively. Based on the

staff's evaluation of these programs and the additional information describing secondary side

component inspections provided in the applicant's response, the staff finds that the applicant's

Water Chemistry Program provides mitigation and the applicant's Steam Generator Tube

Integrity Program provides detection for the aging effect of wall thinning. The staff finds that

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these programs include activities that are consistent with the recommendations in the GALL

Report, and are adequate to manage the aging effect of wall thinning due to flow-accelerated

corrosion in the FW ring during the period of extended operation.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.14 criteria. For those line items that apply to LRA Section 3.1.2.2.14,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.15 Changes in Dimensions Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15.

LRA Section 3.1.2.2.15 addresses changes in dimensions due to void swelling. The applicant

stated that changes in dimensions due to void swelling for nickel alloy and stainless steel

reactor internals components exposed to reactor coolant will be managed by (1) participating in

the industry programs for investigating and managing aging effects on reactor internals; (2)

evaluating and implementing the results of the industry programs as applicable to the reactor

internals; and (3) submitting an inspection plan for reactor internals to the NRC, for review and

approval, 24 months before entering the period of extended operation.

SRP-LR Section 3.1.2.2.15 states that changes in dimensions due to void swelling may occur in

stainless steel and nickel alloy PWR internal components exposed to reactor coolant. The

GALL Report recommends no further AMR if the applicant commits in the FSAR supplement

(1) to participate in the industry programs for investigating and managing aging effects on

reactor internals, (2) to evaluate and implement the results of the industry programs as

applicable to the reactor internals, and (3) upon completion of these programs, but not less than

24 months before entering the period of extended operation, to submit an inspection plan for

reactor internals to the staff for review and approval.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff finds that, for the RCS nickel alloy pressure boundary components, the applicant

committed (Commitment No. 19) to: (1) implement applicable NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) implement applicable staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the EPRI Materials

Reliability Program, for managing aging effects associated with nickel alloys, and (4) submit an

inspection plan for RCS nickel alloy pressure boundary components to the NRC, for review and

approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the nickel alloy and stainless steel

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reactor internals components. The staff finds that this commitment is consistent with the

recommendations in the GALL Report. Therefore, no further AMR evaluation is necessary.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to LRA Section 3.1.2.2.15,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.16 Cracking Due to Stress Corrosion Cracking and Primary Water Stress Corrosion

Cracking

The staff reviewed LRA section 3.1.2.2.16 against the criteria in SRP-LR Section 3.1.2.2.1.16:

(1) LRA Section 3.1.2.2.16 addresses cracking due to SCC and PWSCC in steam

generator heads, tubesheets, and welds made or clad with stainless steel. The applicant

stated that these CRD mechanism and pressurizer components are stainless steel for

WCGS. Therefore, no additional commitments or further evaluation is required.

SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on the primary

coolant side of PWR steel steam generator upper and lower heads, tubesheets, and

tube-to-tube sheet welds made or clad with stainless steel. Cracking due to PWSCC

may occur on the primary coolant side of PWR steel steam generator upper and lower

heads, tubesheets, and tube-to-tube sheet welds made or clad with nickel alloy. The

GALL Report recommends ASME Code Section XI ISI and control of water chemistry to

manage this aging effect and recommends no further AMR for PWSCC of nickel alloy if

the applicant complies with applicable NRC orders and commits in the FSAR

supplement to implement applicable (1) bulletins and generic letters, and

(2) staff-accepted industry guidelines.

The staff noted that the SRP-LR and the GALL Report, items 34 and 35, referto the

further evaluation discussion in SRP-LR Section 3.1.2.2.16.1. Item 34 applies to

stainless steel and nickel alloy CRD head penetration pressure housings. Item 35

applies to steel with stainless steel or nickel alloy cladding primary side components of

once-through steam generators (i.e., steam generator upper and lower heads,

tubesheets, and tube-to-tube sheet welds). For both items, the recommended AMPs are

the "Inservice Inspection (IWB, IWC, and IWD) and Water Chemistry, and for nickel

alloy, FSAR supplement commitment to implement applicable plant commitments to: (1)

NRC orders, bulletins, and generic letters associated with nickel alloys, and

(2) staff-accepted industry guidelines." For both items, the statement in the further

evaluation column of the SRP-LR and the GALL Report is, "No, but applicant

commitment needs to be confirmed."

During its review of LRA Section 3.1.2.2.16.1, the staff noted that the title of the

Section refers only to steam generator components. However, the text discusses CRD

mechanisms and pressurizer components, not steam generator components. The staff

requested that the applicant clarify this discrepancy.

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In its response, the applicant stated that the title of LRA Section 3.1.2.2.16.1 will be

revised to include the CRD head penetration pressure housings. The applicant also

stated that the discussion should not have included pressurizer components, and that

the text in the LRA will be revised to delete mention of pressurizer components and to

add a statement that WCGS has recirculating steam generators, not once-through

steam generators, and that the further evaluation for the steam generator components is

not applicable to WCGS.

By letter dated August 31, 2007, the applicant amended LRA Section 3.1.2.2.16.1 to

state:

3.1.2.2.16.1 Cracking on Steam Generator Heads, Tube Sheets, Control

Rod Drive Head Penetration Pressure Housings and Welds

These control rod drive mechanism housings are stainless steel for

WCGS; therefore, no additional commitments or further evaluation is

required. WCGS has a recirculating steam generator, not a once-through

steam generator; so the further evaluation for steam generator

components is not applicable to WCGS.

The staff finds the LRA amendment acceptable because it eliminates an inconsistency

between the title (labeling) of LRA Section 3.1.2.2.16.1 and its discussion. The staff

finds that this is consistent with the further evaluation discussion in the SRP-LR.

The staff noted that in the LRA, one AMR result line refers to LRA Table 3.1.1, item 34.

This AMR result i5 for the reactor vessel CRD head penetrations (i.e., flange, cap, latch

housing, rod travel housing) construction is stainless steel, not nickel alloy. The staff

requested that the applicant clarify whether the CRD head penetration pressure

housings include nickel alloy welds and, if so, clarify where the AMR results for those

nickel alloy welds are presented in the LRA.

In its response, the applicant stated that there are Alloy 82/182 welds in the CRDM

housings to the CRDM penetration tubes. Also, there are Alloy 82/182 J-groove welds in

the CRDM penetration tubes to the lower surface of the vessel head. The applicant

stated that aging management of these welds is evaluated in LRA Table 3.1.2-1, as part

of the CRDM penetration tubes that are made of nickel alloys. The applicant stated that

the AMPs credited to manage the aging effect of cracking are the ASME Code

Section XI Inservice Inspection, Subsection IWB, IWC, and IWD, the Water Chemistry,

and the Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure

Heads of Pressurized Water Reactor Programs. The AMP that manages the aging

effect of loss of material is the Water Chemistry Program.

The staff reviewed the applicant's response and details of the applicant's AMR

evaluations and found no omissions with regard to materials of construction for these

components. The staff's evaluation of the ASME Code Section XI Inservice Inspection,

Subsection IWB, IWC, and IWD, Water Chemistry, and Nickel-Alloy Penetration

Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water

Reactor Programs is documented in SER Sections 3.0.3.2.1, 3.0.3.2.2, and 3.0.3.2.5,

respectively.

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On the basis of its evaluation of the specified AMPs, the staff finds the applicant's use of

the ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD and

the Water Chemistry Programs to manage the aging effects in the stainless steel CRDM

housing components acceptable. The staff also finds the use of the Nickel-Alloy

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized

Water Reactor Program to manage the aging effects in Alloy 82/182 welds in the CRDM

housings acceptable. The staff confirmed that for the reactor coolant system nickel alloy

pressure boundary components, the applicant committed (Commitment No. 19) to

implement applicable NRC Orders, Bulletins and GLs associated with nickel alloys, and

staff-accepted industry guidelines. On the basis that the LRA provides aging

management for stainless steel components, and that the applicant has included the

recommended commitment related to aging management of nickel alloy pressure

boundary components as recommended in the GALL Report, the staff finds that the

AMR results are acceptable.

(2) LRA Section 3.1.2.2.16 addresses cracking due to SCC and PWSCC in pressurizer

spray head cracking. The applicant stated that the Water Chemistry and the One-Time

Inspection Programs will manage this aging effect in stainless steel components

exposed to reactor coolant. The one-time inspection will include selected components at

susceptible locations where contaminants could accumulate (e.g., stagnant flow

locations). In addition, the applicant stated that WCGS does not have nickel alloy

pressurizer spray heads within the scope of license renewal.

SRP-LR Section 3.1.2.2.16 states that cracking due to SCC may occur on stainless

steel pressurizer spray heads. Cracking due to PWSCC may occur on nickel-alloy

pressurizer spray heads. The existing program controls water chemistry to mitigate this

aging effect. The GALL Report recommends one-time inspection to confirm that

cracking has not occurred. For nickel alloy welded spray heads, the GALL Report

recommends no further AMR if the applicant complies with applicable NRC orders and

commits in the FSAR supplement to implement applicable (1) bulletins and generic

letters, and (2) staff-accepted industry guidelines.

The staff noted that there are two AMR result lines referring to LRA Table 3.1.1, item 36.

The components listed on those lines are non-pressure boundary piping and valves,

made of stainless steel, in an environment of reactor coolant, with the aging effect of

cracking that will be managed by the Water Chemistry and the One-Time Inspection

Program. For these lines, the applicant applied note D indicating that the components

are different, but the material, environment, and aging effect is consistent with the GALL

Report. The note also indicates that the AMPs credited take some exceptions to the

recommendations in the GALL Report. The staff requested that the applicant clarify

whether the pressurizer spray head is included in these lines.

In its response, the applicant stated that the pressurizer spray head is not safety-related,

that it is not a pressure boundary component, and that it is used to support normal

operation. Its function is not credited in any design basis events. The applicant stated

that on this basis, the pressurizer spray head is not included within the scope of license

renewal and is not subject to an AMR pursuant to 10 CFR Part 54.

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The staff reviewed the applicant's response and the Westinghouse topical report

WCAP-14574-A, "Licensing Renewal Evaluation: Aging Management Evaluation for

Pressurizers," which was found acceptable by the NRC as documented in a safety

evaluation dated October 26, 2000. The staff noted that the topical report is applicable

for the WCGS pressurizer and that in the topical report, the pressurizer spray head was

determined to be outside of the scope of license renewal and, therefore, does not

require an AMR pursuant to 10 CFR Part 54. The staff's evaluation of the pressurizer

spray head scoping and screening results is documented in SER Section 2.3.1.2.2. On

the basis that the pressurizer spray head is not within the scope of license renewal and

that this determination has been justified satisfying the scoping and screening guidance,

the staff finds the applicant's response acceptable.

The staff noted that for the non-pressure boundary piping and valves that refer to LRA

Table 3.1.1, item 36, the applicant stated that the aging effect of cracking due to SCC or

PWSCC will be managed by the Water Chemistry and the One-Time Inspection

Programs. The staff's evaluations of these AMPs is documented in SER

Sections 3.0.3.2.2 and 3.0.3.1.3, respectively.

Based on its evaluation of the specified AMPs and on the consistency of the material,

environment, and aging effect with other AMR result lines in the GALL Report, the staff

finds the applicant's use of the Water Chemistry and the One-Time Inspection Programs

to manage these aging effects acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.1.2.2.16 criteria. For those line items that apply to LRA Section 3.1.2.2.16,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17.

LRA Section 3.1.2.2.17 addresses cracking due to SCC, PWSCC, and IASCC. The applicant

stated that for managing this aging effect in nickel alloy and stainless steel reactor internals

components exposed to reactor coolant, water chemistry will be augmented by (1) participating

in the industry programs for investigating and managing aging effects on reactor internals; (2)

evaluating and implementing the results of the industry programs as applicable to the reactor

internals; and (3) submitting an inspection plan for reactor internals to the NRC, for review and

approval, 24 months before entering the period of extended operation.

SRP-LR Section 3.1.2.2.17 states that cracking due to SCC, PWSCC, and IASCC may occur in

PWR stainless steel and nickel alloy RVI components. The existing program controls water

chemistry to mitigate these aging effects; however, the existing program should be augmented

to manage these aging effects for RVI components. The GALL Report recommends no further

AMR if the applicant commits in the FSAR supplement (1) to participate in the industry

programs for investigating and managing aging effects on reactor internals, (2) to evaluate and

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implement the results of the industry programs as applicable to the reactor internals, and

(3) upon completion of these programs, but not less than 24 months before entering the period

of extended operation, to submit an inspection plan for reactor internals to the staff for review

and approval.

The staff finds that, for the RVI, the applicant committed (Commitment No. 19) to: (1)

participate in industry programs for investigating and managing aging effects on reactor

internals, (2) evaluate and implement the results of the industry programs as applicable to the

reactor internals, and (3) submit an inspection plan for the reactor internals to the NRC, for

review and approval, 24 months before entering the period of extended operation.

The staff finds that, for the RCS nickel alloy pressure boundary components, the applicant

committed (Commitment No. 19) to: (1) implement applicable NRC Orders, Bulletins and GLs

associated with nickel alloys, (2) implement applicable staff-accepted industry guidelines, (3)

participate in the industry initiatives, such as owners group programs and the EPRI Materials

Reliability Program, for managing aging effects associated with nickel alloys, and (4) submit an

inspection plan for RCS nickel alloy pressure boundary components to the NRC, for review and

approval, 24 months before entering the period of extended operation.

The staff's evaluation of the applicant's commitment provided in the Reactor Coolant System

Supplement Program is documented in SER Section 3.0.3.3.2. The staff finds that this

commitment is acceptable to manage the aging effects in the nickel alloy and stainless steel

reactor internals components. The staff finds that this commitment is consistent with the

recommendations in the GALL Report, therefore, no further AMR evaluation is necessary.

Based on the program identified above, the staff concludes that the applicant's program meets

SRP-LR Section 3.1.2.2.17 criteria. For those line items that apply to LRA Section 3.1.2.2.17,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.1.2-1 through 3.1.2-3, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-3, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

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that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.1.2.3.1 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging

Management Evaluation - Reactor Vessel and Internals - LRA Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the

reactor vessel and internals component groups.

The staff noted that the AMR results for the reactor vessel nozzles, reactor vessel shell, and

reactor vessel shell head components that are made of carbon steel with stainless steel

cladding, and that are exposed to an environment of reactor coolant have an aging effect of

crack growth due to cyclic loading. In the LRA, the applicant stated that at WCGS, evaluation of

crack growth in these components is not a TLAA, as defined in 10 CFR 54.3. The applicant

applied note I for these AMR results, indicating that the aging effect in the GALL Report for this

component, material, and environment combination is not applicable to WCGS.

In LRA Section 3.1.2.2.5, the applicant stated that there are no plant-specific analysis of

underclad flaw growth in the reactor vessel forgings at WCGS. Therefore, there are no such

TLAAs. The applicant also stated that the Westinghouse topical report, WCAP-1 5338-A, "A

Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants,"

provides evaluation of growth of possible underclad flaws in PWRs and demonstrates that for a

60-year design life "... flaw growth is insignificant for any type flaw which might exist at the

clad-base metal interface..." The applicant further stated that, since the evaluation was

originally performed for the period of extended operation rather than for the current licensed

operating period, this analysis is not a TLAA, in accordance with 1OCFR 54.3(a).

The staff noted that WCAP-1 5338-A has been found acceptable for all Westinghouse RPVs

and has been approved by the staff as a reference in LRAs, as documented in the revised

safety evaluation for WCAP-1 5338, "A Review of Cracking Associated with Weld Deposited

Cladding in Operating PWR Plants." The staff requested that the applicant clarify whether

WCAP-15338-A is being credited in the LRA for evaluation of underclad flaws at WCGS.

In its response, the applicant stated that the NRC safety evaluation of WCAP-1 5338-A notes

that "Underclad cracks... have been reported... only in SA-508, Class 2 reactor vessel forgings

manufactured to a coarse grain practice and clad by high-heat-input submerged arc

processes," and that in the WCGS vessel, the carbon steel forgings are SA-508, Class 2 or 3.

The applicant also stated that although the vessel contains SA-508 forgings clad by

high-heat-input processes, the cladding weld process was qualified in accordance with the

recommendations of RG 1.43, Revision 0, "Control of Stainless Steel Weld Cladding of

3-208
Low-Alloy Steel Components," as described in USAR Section 5.3.1.2.g and USAR

Appendix 3A. Therefore, the applicant concluded that underclad cracking should not occur at

WCGS. The applicant stated that no underclad flaws have been detected or analyzed for the

WCGS reactor vessel. Therefore, WCAP-15338-A has not been invoked for evaluation of

underclad flaws at WCGS.

The applicant noted that the applicability of WCAP-15338-A at WCGS is discussed in LRA

Section 4.7.2, "Absence of a TLAA for Reactor Vessel Underclad Cracking Analysis." LRA

Section 4.7.2 states that WCAP-1 5338-A could be applied to WCGS because the cyclic and

transient load assumptions of the topical report bound those expected in the WCGS vessel

during the period of extended operation. The assessment states that, if invoked,

WCAP-1 5338-A would be valid for the period of extended operation.

On the basis that the WCGS cladding process was qualified to the recommendations described

in RG 1.43 and no underclad flaws have been found at WCGS, the staff finds that there is

reasonable assurance that the WCGS reactor vessel has no underclad flaws in which the aging

effect of crack growth due to cyclic loading can occur. On the basis that there are no underclad

flaws, the staff finds that the aging effect of crack growth due to cyclic loading of carbon steel

with stainless steel cladding for the component types of reactor vessel nozzles, reactor vessel

shell, and reactor vessel shell head exposed to an environment of reactor coolant, is not

applicable at WCGS. The staff finds that the applicant's use of note I is appropriate, and that

the applicant's AMR results are acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.2 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging

Management Evaluation - Reactor Coolant System - LRA Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for the

reactor coolant system component groups.

Nickel Alloy Closure Bolting Exposed to Borated Water Leakage (Loss of Preload). The staff

noted that the applicant proposed to manage loss of preload in nickel alloys in closure bolting

exposed to an external environment of borated water leakage by using the Bolting Integrity

Program. The applicantapplied note F for this AMR result, indicating that the material for this

component is not in the GALL Report.

The staff's evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7.

The Bolting Integrity Program description states that the program manages the aging effects of

cracking, loss of material, and loss of preload for pressure retaining bolting and ASME

components support bolting. The program includes pre-load control, selection of bolting

material, use of lubricants and sealants consistent with EPRI good practices, and periodic

inspections for indications of aging effects.

3-209
On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff finds that, since the applicant will use pre-load control and periodic inspection for these

components, the aging effect of loss of pre-load in nickel alloy closure bolting can be effectively

managed by using the Bolting Integrity Program.

Stainless Steel Piping and Valves Exposed to Demineralized Water. The staff noted that the

applicant proposed to manage loss of material in stainless steel for component types piping and

valves exposed to an internal environment of demineralized water using the Water Chemistry

and the One-Time Inspection Programs. The applicant applied note G for these AMR results,

indicating that the material and environment combination for these components is not in the

GALL Report. However, these lines appear to have the same component, material and

environment combination described in GALL Report, line V.C-4. The staff requested that the

applicant explain why note G was used for these lines. By letter dated August 31, 2007, the

applicant amended the LRA to revise these lines to reference GALL Report item V.C-4 and

note D.

The staff finds that these line items are now consistent with the GALL Report and; therefore,

the applicant's response is acceptable.

CASS Piping Exposed to Reactor Coolant. The staff noted that the applicant stated that the

aging effect of thermal aging embrittlement of CASS for piping exposed to an internal

environment of reactor coolant is not applicable at WCGS. The applicant did not propose an

AMP to manage this aging effect. The applicant applied note I for these AMR results, indicating

that the aging effect in the GALL Report for this component, material, and environment

combination is not applicable.

The applicant stated that the WCGS reactor coolant system loops are constructed of CASS and

that the straight piping pieces are centrifugally-cast and the fittings are statically-cast. The

applicant stated that the molybdenum and ferrite values for these components are below the

industry accepted thermal aging embrittlement significance thresholds (i.e., less than

0.5 percent molybdenum and less than 20 percent ferrite). Therefore, thermal aging

embrittlement of CASS piping in the reactor coolant system is not applicable at WCGS.

The staff noted that GALL AMP XI.M12, "Thermal Aging Embrittlement of Cast Austenitic

Stainless Steel (CASS)," states that the susceptibility to thermal aging embrittlement of CASS

components is determined in terms of casting method, molybdenum content, and ferrite

content. For low molybdenum content steels (i.e., 0.5 weight percent maximum), only static-cast

steels with greater than 20 percent ferrite are potentially susceptible to thermal embrittlement.

Static-cast low molybdenum steels with less than or equal 20 percent ferrite and all

centrifugal-cast low molybdenum steels are not susceptible.

The staff requested that the applicant provides the actual maximum molybdenum and ferrite

values for the Class 1 CASS piping, piping components, and piping elements, and provide

copies of applicable certified material test reports for the staff review.

In its response, the applicant stated that the actual maximum molybdenum content is

0.35 percent and the actual maximum ferrite content is 19.5 percent. The staff reviewed the

applicant's certified material test reports and confirmed these values.

3-210
On the basis that the CASS piping in the reactor coolant system has molybdenum and ferrite

values that are below the threshold limits, the staff finds that the aging effect of thermal aging

embrittlement is not applicable for this component, material, and environment combination at

WCGS and that no AMP is needed to manage this aging effect.

Nickel Alloy Closure Bolting Exposed to Borated Water Leakage (Cumulative Fatigue). The

staff noted that the applicant proposed to manage the aging effect of cumulative fatigue

damage in nickel alloys in closure bolting components exposed to an external environment of

borated water leakage using a TLAA evaluated for the period of extended operation. The

applicant applied note F for this AMR result, indicating that the material for this component is

not in the GALL Report. The staff's evaluation of the applicant's TLAA is documented in SER

Section 4.3.

On the basis of its review of this TLAA, the staff finds the AMR result acceptable.

The staff noted that in the AMR result for cumulative fatigue damage in the stainless steel

pressurizer relief tank that is exposed to an internal environment of treated borated water, the

applicant stated that no vessel, tank, pump, or heat exchanger designs at WCGS are supported

by TLAAs. The applicant stated that the only exception is the ASME Class 1 components and

Class 2 portions of the steam generators. The applicant applied note I for this AMR result,

indicating that the aging effect in the GALL Report for this component, material, and

environment combination is not applicable at WCGS. The staff's evaluation of the applicant's

TLAA is documented in SER Section 4.3. On the basis that the CLB does not include a TLAA

for the pressurizer relief tank, the staff finds the AMR result acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.2.3.3 Reactor Vessel, Internals, and Reactor Coolant System - Summary of Aging

Management Evaluation - Steam Generators - LRA Table 3.1.2-3

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the

steam generators component groups.

The staff noted that in the AMR result for the aging effect of cumulative fatigue damage in the

nickel alloy steam generator tubes exposed to an external environment of secondary water, the

applicant stated that at WCGS cumulative fatigue damage of steam generator tubes is not a

TLAA, as defined in 10 CFR 54.3. The applicant applied note I for this AMR result, indicating

that the aging effect in the GALL Report for this component, material, and environment

combination is not applicable at WCGS. The staff's evaluation of the applicant's TLAA is

documented in SER Section 4.3. Based on its review and on the basis that the CLB does not

necessitate a TLAA for the steam generator tubes (i.e., not needed), the staff finds the AMR

result acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

3-211
Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the reactor vessel, RVI, and reactor coolant system components within

the scope of license renewal and subject to an AMR will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

3.2 Aging Management of Engineered Safety Features

This Section of the SER documents the staff's review of the applicant's AMR results for the

engineered safety features components and component groups of:

• nuclear sampling system

• containment spray system

• containment integrated leak rate test system

• decontamination system

• liquid radwaste system

• reactor makeup water system

• containment purge HVAC system

* breathing air system

* hydrogen control system

" high pressure coolant injection system

* residual heat removal system

3.2.1 Summary of Technical Information in the Application

LRA Section 3.2 provides AMR results for the engineered safety features components and

component groups. LRA Table 3.2.1, "Summary of Aging Management Evaluations in

Chapter V of NUREG-1801 for Engineered Safety Features," is a summary comparison of the

applicant's AMRs with those evaluated in the GALL Report for the engineered safety features

components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the engineered safety features

components within the scope of license renewal and subject to an AMR will be adequately

3-212
managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent.with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.2.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed'that the applicant's further evaluations

were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff's audit

evaluation's are documented in SER Section 3.2.2.2.

The staff also conducted a technical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and Whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's evaluations are

documented in iSER Section 3.2.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.2-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.2 and addressed in the GALL Report.

Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the GALL

Report

Componient Group: Aging Effectl AMP in GALL 'Further'ý AM P In LRA, . Staff

~(GALL Report' Mechanism Report ~Evaluation, Su Ipplements, or Evaluation

.tem , .. .in GALL Amendments

________________ ~Report~ __________ _______

Steel and stainless Cumulative TLAA, evaluated in Yes TLAA Consistent with

steel pipingipiping fatigue damage accordance with GALLrReport

components, and 10 CFR 54.21(c) (See SER

piping elements in Section 3.2.2.2.

ECCS 1)

(3.2.1-1)

3-213
:Component Group }Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report• Mechanism Report Evaluation 'Supplements, or Evaluation

Item No.).j3⁄4--, in GALL: zý•r!Amendments

- -. __________ ______________ Report. _ _ _ _ __ _ _ _ __ _ _ _

Steel with stainl6ss Loss of material A plant-specific Yes Not applicable Not applicable

steel cladding pump due to cladding aging management to WCGS

casing exposed to breach -program is to be (See SER

treated borated evaluated. . Section 3.2.2.2.

water 2)

(3.2.1-2) Reference NRC

IN 94-63,

."Boric Acid

Corrosion of

Charging Pump

Casings Caused by

Cladding Cracks"

Stainless steel Loss of material Water Chemistry Yes . Water Chemistry Consistent with

containment due to pitting and One-Time (B2.1 .2) and GALL Report

isolationrpiping and and crevice Inspection One-Time (See SER

components internal corrosion Inspection (B2.1.16) Section 3.2.2.2.

surfaces exposed to 3.1)

treated water

(3.2.1-3) ,__ . ... _ _

Stainless steel . Loss of material A'plant-specific Yes Buried Piping and Consistent with

piping, piping due to pitting aging management Tanks Inspection GALL Report

components, and and crevice , program is to be. (B2.1.18) (See SER

piping elements corrosion evaluated. Section 3.2.2.2.

exposed to soil . 3.2)

(3.2!-4) _ _ _ _ _ __......

Stainless steel and Loss of material. Water Chemistry Yes Not applicable Not applicable

aluminum piping, due to pitting and One-Time to PWRs

piping components, and crevice Inspection (See SER

and piping elements corrosion Section 3.2.2.2.

exposdd:to treated . 3.3)

water .

(3.2.1-5) _:!

Stainless steel and Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

copper alloy piping, due to pitting Analysis and Analysis (B2.1.23) GALL Report

piping components, and crevice One-Time and One-Time (See SER

and piping elements corrosion. . Inspection Inspection (B2.1.16) Section 3.2.2.2.

exposed to :.3.4)

lubricating oil

(3.2.1-6):

3-214
'Component Group Aging Effect/ AMP in GALL' Furher- AMP inLRA, i Staff,.

(GALL Reportý ýMechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

- K ______________ ~~~Report __ _ _ _ _ _ _ _ _ _ _ _ _

Partially encased Loss of material A plant-specific Yes -Not applicable Not applicable

stainless steel tanks due to pitting aging management to WCGS

with breached and crevice program is to be'. (See SER

moisture barrier corrosion evaluated for pitting Section 3.2.2.2.

exposed to raw and 'crevice, 3.5)

water corrosion of tank

(3.2.1-7) bottoms because

moisture and water

can egress under

the tank due to

cracking of the

perimeter seal from

weathering. _

Stainless steel Loss of material A plant-specific Yes Not applicable Not applicable

piping, piping due to pitting aging management toWCGS

components, piping and crevice program is to be (See SER

elements, and tank corrosion evaluated. Section 3.2.2.2.

internal surfaces 3.6)

exposed to

condensation

(internal)

(3.2.1-8) _ _ _

Steel, stainless Reduction of Lubricating Oil Yes Lubricating Oil Consistent with

steel, and copper heat transfer• Analysis and Analysis (B2.1.23) GALL Report

alloy heat due to fouling One-Time and One-Time (See SER

exchanger tubes Inspection Inspection (B2.1 .16) Section 3.2.2.2.

exposed to 4.1)

lubricating oil-

(3.2.1-9) __ _ _ "

Stainless steel heat Reduction of Water Chemistry Yes Not applicable Notiapplicable

exchanger tubes heat transfer and One-Time to WCGS

exposed to treated due to fouling Inspection (SeeSER

water ' Section 3.2.2.2.

(3.2.1-10) .. __....4.2)

Elastomer seals and Hardening and A plant-specific Yes Not applicable Not applicable

components in loss of strength aging management to PWRs

standby gas due to program is to be (See SER

treatment system elastomer evaluated. Section 3.2.2.2.

exposed to air.- degradation 5)

indoor uncontrolled

(3.2.1-11)

Stainless steel Loss of material A plant-specific Yes Not applicable Not applicable

high'prewsure safety due to erosion aging management to WCGS

injection (charging) program is to be (See SER

pump miniflow. .evaluatedfor, Section3.2.2.2.

orifice exposed to erosion of the orifice 6)

treated borated due to extended use

water, of the centrifugal

(3.2.1-12) .HPSI pump. for

normal charging. . .. _ _

3-2.15
Component Group 'Aging Effect/ AMP in. GALL. Further , AMP in LRA, ~ 'Utff

.(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.)' -, - in GALL Amendments

Steel drywell and Loss of material A plant-specific Yes Not applicable Not applicable suppression due to general aging management to PWRs

chamber spray, corrosion and program is to be (See SER

system nozzle and fouling evaluated. Section 3.2.2.2.

flow orifice internal 7)

surfaces exposed to

air - indoor

uncontrolled

(internal)

(3.2.1-13)

Steel piping, piping Loss of material Water Chemistry Yes Not applicable Not applicable

components, and due to general, and One-Time to PWRs

piping elements pitting, and Inspection (See SER

exposed.totreated crevice Section 3.2.2.2.

water corrosion 8.1)

(3.2.1-14).

Steel containment Loss of material Water Chemistry Yes Water Chemistry Consistent with

isolation piping, due to general, and One-Time (B2.1.2) and One- GALL Report

piping components, pitting, and Inspection Time Inspection (See SER

and piping elements crevice (B2.1.16) Section 3.2.2.2.

internal surfaces corrosion . 8.2)

exposed to treated

water

(3.2.1-15)

Steel piping, piping Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

components, and due to general, Analysis and Analysis (B2.1.23) GALL Report

piping elements pitting, and One-Time and One-Time (See SER

exposed to crevice Inspection Inspection (B2.1.16) Section 3.2.2.2.

lubricating oil corrosion 8.3)

(3.2.1-16)

Steel (with or Loss of material Buried Piping and No Not applicable Not applicable

without coating or due to general, Tanks Surveillance to -WCGS

wrapping) piping, pitting, crevice, (See SER

piping components, and micro or Section 3.2.2.2.

and piping elements biologically- 9)

buried in soil influenced Buried Piping and Yes

(3.2.1-17) corrosion Tanks Inspection

Stainless steel Cracking due to BWR Stress No Not applicable Not applicable

piping, piping SCC and Corrosion Cracking to PWRs

components, and IGSCC and Water

piping elements Chemistry

exposed to treated

water > 606C

(> 140'F)

(3.2.1-18).

3-216
CZomponent Group Aging Effect/ -AMP in GALL., Further AMP in LRA,. Saf

:(GALLReport Mechanism -i i'Report Evaluation 'Supplements, or :Evaluation

Item No.) In GALL Amendments

• ReportA LRe or_____ ~~.........

Steel piping, piping Wall thinning Flow-Accelerated No Not applicable Not applicable,

components, and due to Corrosion to PW Rs

piping elements flow-accelerate

exposed to steam or d corrosion

treated water

(3.2.1-19) .

CASS piping, piping Loss of fracture Thermal Aging No Not applicable. 'Not applicable

components, and toughness due Embrittlement of to PWRs

piping elements, to thermal CASS

exposed to treated aging

water (borated or embrittlement

unborated) > 2500C

(> 482°F)..

(3.2.1-20) _

High-strength steel Cracking due to Bolting Integrity No Not applicable Not applicable

closure bolting. cyclic loading, to WCGS (See

exposed to air with SGC SER

steam or water Section 3.2.2.1.

leakage 1)

(3.2.1-21)

Steel closure bolting Loss of material Bolting Integrity No Not applicable Not applicable

exposed to airwith due to general to WCGS (See

steam or water corrosion . SER

leakage Section 3.2.2.1.

(3.2.1-22) . 1)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting due to general, (B2.1.7) GALL Report

exposed to air - pitting, and

outdoor.(extemal), crevice

or air - indoor corrosion

uncontrolled

(external)-

(3.2..1-23) _

Steel closure bolting Loss of preload Bolting Integrity No Bolting Integrity Consistent with

exposed to air-- due to thermal (B2.1.7) GALL Report

indoor uncontrolled effects, gasket

(external) creep, and

(3.2.1-24) self-loosening

Stainless steel . Cracking due to Closed-Cycle No Closed-Cycle Consistent with

piping, piping . SCC Cooling Water * Cooling Water GALL Report

components, and System System (B2.1.10)

piping elements

exposed to closedcycle cooling Water

> 60'C.(> 140'F)

1(3.2.1-25)

3-217
Component Group Aging Effect/• -AMP in GALL Further, AMP in LRA, Staff,

.(GALL Report Mechanism Report , Evaluation i Supplements, or Evaluation

Item No.) in GALL Amendments

________ - ,~-Report~2_ _ _

Steel piping, piping Loss of material Closed-Cycle No Ciosed-Cycle Consistent with

components, and, due to general, Cooling Water Cooling Water GALL Report

piping elements pitting, and System System (B2.1.10)

exposed to closed- crevice

cycle cooling water corrosion

(3.2.1-26): _

Steel heat . Loss of material Closed-Cycle No Closed-Cycle Consistent with

exchanger, due to general, Cooling Water Cooling Water GALL Report

components pitting, crevice, System System (B2.1.10)

exposed to closed- and galvanic

cycle cooling water" corrosion

(3.2.1-27) ' . ._

Stainless steel Loss of material Closed-Cycle No Closed-Cycle Consistent with

piping, piping due to pitting Cooling Water CoolingWater GALL Report

components, piping aknd crevice System System (B2.1.10)

elements, and heat corrosion

exchanger"

components,

exposed to

closed'cycle cooling

water

(3.2.1-28). _ _ _ _ _ _ _

Copper alloy piping, Loss of material Closed-Cycle No Closed-Cycle Consistent with

piping components, due to pitting, Cooling Water Cooling Water GALL Report

piping elements, crevice, and System System (B2. 1.10)

and heat exchanger galvanic

components. corrosion

exposed to closedcycle cooling water

(3.2.1-29) _____

Stainless steel and Reduction of Closed-Cycle No Closed-Cycle Consistent with

copper alloy heat heat transfer Cooling Water Cooling Water GALL Report

exchanger tubes due to fouling System System (B2.1.10)

exposed to closedcycle cooling water

(3.2.1-30) _ _ _ __I_

3-218
"Component Group Aging Effect? AMP in GALL Further FAMP in LRA, Staff

(GALL Report Mechanism Report :Evaluation Supplements, or Evaluation

Itemn No.)., in GALL Amendments

________ __________ Report, _ _ _ _ _ _ _ _ _ _

External surfaces of Loss of material External Surfaces No External Surfaces Consistent with

steel components due to general Monitoring Monitoring (B2.1 .20) GALL Report

including ducting, corrosion

piping, ducting

closure bolting,, arnd

containment

isolation piping

external surfaces

exposed to air'-

indoor uncontrolled

(external);

condensation

(external) and air -

outdoor (external)

(3.2.1-31) -. _ .. .

Steel piping and.. Loss of material Inspection of No Not applicable Not applicable

ducting components due to general Internal Surfaces in to WCGS (See

and internal corrosion Miscellaneous SER Section

surfaces exposed to Piping and Ducting 3.2.2.1.1)

air - indoor . Components

uncontrolled

(Internal)

(3.2.1-32) ..

Steel encapsulation Loss of material Inspection of No Inspection of Consistent with

components due to general, Internal Surfaces in. Internal Surfaces in GALLReport

exposed to air - pitting, and Miscellaneous Miscellaneous

indoor uncontrolled crevice Piping and Ducting Piping and Ducting

,(internal) . corrosion Components ". Components

(3.2.1-33) . (B2.1.22)

Steel piping, piping Loss of material Inspection of . No Inspection of Consistent with

components, and. due to general, Internal Surfaces in Internal Surfaces in GALL Report

piping elements pitting,.and Miscellaneous Miscellaneous

exposed to crevice Piping and Ducting .Piping and Ducting

condensation.. corrosion Components Components

(internal) : (B2.1.22)

(3.2.1-34). .. _, 

Steel containment Loss of material Open-Cycle Cooling No Not applicable Not applicable

isolation piping and due to general, Water System to WCGS (See

components internal, pitting, crevice, SER

surfaces exposed to and micro Section 3.2.2.1.

raw water biologically- " 1)

(3.2.1-35) influenced

corrosion, and

fouling

3-219
ý-Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

ItmNo.) n nGALL Amendments

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Report _ _ _ _

Steel heat Loss of material Open-Cycle Cooling No Not applicable Not applicable

exchanger due to general, Water System to WCGS (See

components pitting, crevice, SER

exposed to raw galvanic, and Section 3.2.2.1.

water micro 1)

(3.2.1-36)1 biologicallyinfluenced

corrosion, and.

fouling _

Stainless steel Loss, of material Open-Cycle Cooling No Not applicable Not applicable

piping, piping due to pitting, Water System to WCGS (See

components, and crevice, and SER

piping elements micro Section 3.2.2.1.

exposed to raw biologically- 1)

water . influenced

(3.2.1-37) corrosion

Stainless steel Loss of material Open-Cycle Cooling No Not applicable Not applicable

containment due to pitting, Water System to WCGS (See

isolation piping and crevice, and SER

components internal micro Section 3.2.2.1.

surfaces exposed:to biologically- 1)

raw water influenced

(3.2.1-38) corrosion, and

fouling

Stainless steel heat Loss of material Open-Cycle Cooling No Not applicable Not applicable

exchanger due to pitting, Water System to WCGS (See

components crevice, and SER

exposed to raw micro Section 3.2.2.1.

water biologically- • 1)

(3.2.1-39) influenced

corrosion, and

fouling

Steel and stainless Reduction of Open-Cycle Cooling No Not applicable Not applicable

steel heat heat transfer Water System . to WCGS (See

exchanger tubes due to fouling SER

(serviced by Section 3.2.2.1.

OCCW) exposed to 1)

raw water

(3.2.1-40)

Copper alloy Loss of material Selective Leaching No Not applicable Not applicable

> 15% Zn piping, due to selective of Materials to WCGS (See

piping components, leaching SER

piping elements, Section 3.2.2.1.

and heat exchanger 1)

components

exposed to closed

cycle cooling water

(3.2.1-41)

3-220
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

- (GALL Repo.V.,, Mechanism: Report' Evaluation, :;Supplements, or Evaluation

Item No.)- ..... in GALL' 'Amendments

_ _ _ _ _ _ ________ ~Report, _ _ _ __ _ _ _

Gray cast iron'. Loss of material Selective Leaching No Not applicable Not applicable

piping, piping: due to selective of Materials to WCGS (See

components, piping leaching SER

elements. exposed. Section 3.2.2.1.

to closed-cycle . 1)

cooling water.:

(3.2.1-42).

Gray cast iron . Loss of material Selective Leaching No Not applicable Not applicable

piping, piping due to selective of Materials to WCGS (See

components, and leaching SER

piping elements " Section 3.2.2.1.

exposed to0soil ''1)

(3.2.1-43) ___. _ __" "_i "

Gray cast iron motor Loss of material Selective Leaching, No Not applicable Not applicable

cooler exposed to due to selective of Materials to WCGS (See

,treated water leaching SER

(3.2.1-44) Section 3.2.2.1. _____________ _______......____________ 1)

Aluminum, copper Loss of material Boric Acid Corrosion No Boric Acid Corrosion Consistent with

alloy > 15% Zn, and due to Boric (B2.11.4) GALL Report

steel external acid corrosion

surfaces, bolting,; "

and piping, piping

components, and

piping elements

exposed to air with

borated water.

leakage

(3.2.1-45) . _

Steel encapsulation Loss of material. Inspection of No Not applicable Not applicable

components due to general, Internal Surfaces in to WCGS'(See

exposed to air:with pitting, crevice -. Miscellaneous SER

borated water and boric.acid. Piping and Ducting Section 3.2.2.1.

leakage (intemal).. corrosion Components 1)

CASS piping, piping Loss of fracture Thermal Aging No Not applicable Not applicable

components, and toughness due Embrittlement of to WCGS (See

piping elements,.;" to thermal -CASS SER

exposed to treated aging Section 3.2.2.1.

borated water , embrittlement 1).

> 250oC (> 4829F),

(3.2.1-47) -__-_ _- 

3-221
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff"

.(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Itemý No.). in GALL Amendments

.. . .,,..... . .... _,_________-____,________-_ _-Report .-

Stainless steel or Cracking due to. Water Chemistry No Water Chemistry Consistent with

stainless-steel-clad SCC (B2.1.2) GALL Report

steel piping,-piping.

components, Piping

elements, andtanks

.(including safety:

injections..

tanks/accumulators)

exposed to treated .

borated water:

> 600

'C(> 140'F)

(3.2.1-48) :_ __"_ __ _

Stainless steel Loss of material Water Chemistry No Water Chemistry Consistent with

piping, piping due to pitting (B2.1.2) GALL.Report

components, Piping and crevice,

elements, andltanks corrosion

exposed to treate"

borated water.-'.

(3.2.1-49) .

Aluminum piping, None None No None Consistent with

piping components, GALL Report

and piping elements

exposed to air

indoor uncontrolled

(intemal/external)

(3!2.1-50) ._:_ __ __ _

Galvanized steel None 'None No Not applicable Not applicable

ducting exposed:to to WCGS (See

air - indoor SER

controlled (external) Section 3.2.2.1.

(3.2.1-51) _ _ _ _ _ 1)

Glass piping None None 'No None Consistent with•

elements exposed GALL Report

to air -:indoor

uncontrolled

(extemal),

lubricating oil, raw

water, treated water,

or treatedborated

water

(3.2.1-52) . ._ _ __:_ _ _

Stainless steel, None None No None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping. components,

and~piping elements

exposed to air - ,.

indoor uncontrolled

(external).

(3.2.1-53)

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,.Component Group... Aging Effect/ AMMP In GALL Further AMP in LRA, Staff

(GALL Report Mechanism ' Report Evaluation Supplements, or Evaluation

htemN No.) in GALL: Amendments

. 'Report

Steel piping, piping None None No Not applicable Not applicable

components, and to WCGS (See

piping elements SER

exposed.to air - Section 3.2.2.1.

indoor controlled 1)

(eXtemal)

(3.2.1-54) _

Steel and stainless None None No None Consistent with

steel piping, piping GALL Report

components, and

piping elements in

concrete

(3.2.1-55)

Steel, stainless None None No None Consistent with

steel, and copper GALL Report

alloy piping, piping

components, and

piping elements

exposed to gas

(3.2.1-56) _

Stainless steel and None None No Not applicable Not applicable

copper alloy. to WCGS (See

< 15% Znpiping, SER

piping components, Section 3.2.2.1.

and piping elements 1)

exposed to air with

borated Water

leakage

(3.2.1-57)

The staff's review of the engineered safety features component groups followed any one of

several approaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results

for components that the applicant indicated are consistent with the GALL Report require no

further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR

results for components that the' applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A thirdapproach, documented in SER

Section 3.2.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the engineered safety features components is documented

in SER Section 3.0.3.

3.2.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the engineered safety features components:

• ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD

• Water Chemistry

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" Boric Acid Corrosion

" Flow-Accelerated Corrosion

• Bolting Integrity

• Closed-Cycle Cooling Water System

• One-Time Inspection

• Selective Leaching of Materials

* Buried Piping and Tanks Inspection

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping

* External Surfaces Monitoring

* Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

* Lubricating Oil Analysis

* Nickel Alloy Aging Management

LRA Tables 3.2.2-1 through 3.2.2-11 summarize AMRs for the engineered safety features

components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

3-224
AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

The staff completed its audit and review the information in the LRA. The staff did not repeat its

review of the matters described in the GALL Report; however, the staff did verify that the

material presented in the LRA was applicable and that the applicant identified the appropriate

GALL Report AMRs. The staff's evaluation follows.

3.2.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.3.1, the applicant identifies items 21, 22, 32, 35, 36, 37, 38, 39, 40, 41, 42, 43,

44, 46, 47, 51, 54, and 57, as not applicable since the component, material, and environment

combination does not exist at WCGS. For each of these items, the staff reviewed the LRA and

the applicant's supporting documents, and confirmed the applicant's claim that the component,

material, and environment combination does not exist at WCGS. On the basis that WCGS does

not have this combination, the staff finds that these AMRs are not applicable to WCGS.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the engineered safety features components and provides information

concerning how it will manage the following aging effects and related QA:

° cumulative fatigue damage

* loss of material due to cladding

* loss of material due to pitting and crevice corrosion

* reduction of heat transfer due to fouling

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* hardening and loss of strength due to elastomer degradation

" loss of material due to erosion

* loss of material due to general corrosion and fouling

" loss of material due to general, pitting, and crevice corrosion

" loss of material due to general, pitting, crevice, and microbiologically-influenced

corrosion

" QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in SRP-LR Section 3.2.2.2. The staff's review of the

applicant's further evaluation follows.

3.2.2.2.1 Cumulative Fatigue Damage

LRA Section 3.2.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.2.2.2.2 Loss of Material Due to Cladding

The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2.

LRA Section 3.2.2.2.2 addresses loss of material due to cladding (breach). The applicant stated

that this aging effect is not applicable because WCGS does not have steel with stainless steel

cladding pump casing exposed to treated borated water in the ECCS within the scope of license

renewal. Therefore, the applicable GALL Report line item was not used.

SRP-LR Section 3.2.2.2.2 states that loss of material due to cladding breach may occur in PWR

steel pump casings with stainless steel cladding exposed to treated borated water.

The staff noted that this item applies to steel pump casings with stainless steel cladding. The

staff finds that this item is not applicable because WCGS does not have steel pump casings

with stainless steel cladding exposed to treated borated water.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.2.2.2.2

criteria.

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR

Section 3.2.2.2.3:

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(1) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion on

internal surfaces of stainless steel containment isolation piping and components

exposed to treated water. The applicant stated that the Water Chemistry and the

One-Time Inspection Programs will manage this aging effect in stainless steel

components exposed to demineralized water. The one-time inspection will include

selected components at susceptible locations where contaminants could accumulate

(e.g., stagnant flow locations).

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur on internal surfaces of stainless steel containment isolation piping,

piping components, and piping elements exposed to treated water. The existing

AMP monitors and controls water chemistry to mitigate degradation. However, control of

water chemistry does not preclude loss of material due to pitting and crevice corrosion

at locations with stagnant flow conditions; therefore, the effectiveness of water chemistry

control programs should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to verify the effectiveness of water

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

The staff reviewed the Water Chemistry Program, which monitors chlorides, fluorides,

and dissolved oxygen to limit the contaminants, thus, minimizing the occurrences of

aging effects and maintaining the component's ability to perform its intended functions.

The applicant stated that it will use the One-Time Inspection Program to verify the

effectiveness of the Water Chemistry Program. The One-Time Inspection Program

inspects select stainless steel components exposed to treated water at susceptible

locations, such as stagnant areas, for loss of material due to pitting and crevice

corrosion.

The staff's evaluation of the Water Chemistry and the One-Time Inspection Program is

documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The staff finds that

these programs include activities that are consistent with the recommendations in the

GALL Report, and are adequate to manage loss of material due to pitting and crevice

corrosion on internal surfaces of stainless steel containment isolation piping and

components exposed to treated water.

(2) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping and components exposed to soil. The applicant stated that the

Buried Piping and Tanks Inspection Program will manage this aging effect for the

stainless steel external surfaces of buried piping.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that the aging effect is adequately managed.

The staff noted that in the discussion column of LRA Table 3.2.1, item 4, the applicant

stated that loss of material in stainless steel piping exposed to an external environment

3-227
of buried is managed by the Buried Piping and Tank Inspection Program. LRA

Table 3.2.1, item 4, is referenced in LRA Table 3.2.2-10.

The staff noted that the applicant applied note E to the AMR result, indicating that the

component type, material, environment, and aging effect are consistent with the GALL

Report. However, where the GALL Report recommends a plant-specific program, the

applicant proposed using the Buried Piping and Tank Inspection Program.

The staff reviewed the Buried Piping and Tanks Inspection Program and finds that this

program will provide planned inspections for loss of material due to pitting and crevice

corrosion for stainless steel components exposed to soil, within ten years from entering

the period of extended operation, unless an opportunistic inspection has occurred within

this 10-year period. The staff finds that the Buried Piping and Tanks Inspection Program

is consistent with the recommendations of the GALL Report, and is adequate to manage

loss of material due to pitting and crevice corrosion in stainless steel piping and

components exposed to soil.

(3) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

BWR stainless steel and aluminum piping and components exposed to treated water.

The applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in BWR stainless steel and aluminum piping, piping components,

and piping elements exposed to treated water.

The staff noted that this item applies to BWR system components and; therefore, is not

applicable because WCGS is a PWR plant. On this basis, the staff finds that this aging

effect is not applicable to this component type.

(4) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

stainless steel and copper piping and components exposed to lubricating oil. The

applicant stated that the Lubricating Oil Analysis and the One-Time Inspection Programs

will manage this aging effect in copper alloys, copper nickel, and stainless steel

components exposed to lubricating oil, except for the RCP lube oil leakage collection

system. The one-time inspection will include selected components at susceptible

locations where contaminants such as water could accumulate.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel and copper alloy piping, piping components, and

piping elements exposed to lubricating oil. The existing program periodically samples

and analyzes lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment that is not conducive to corrosion. However, control of lube

oil contaminants may not always be fully effective in precluding corrosion; therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion does

not occur. The GALL Report recommends further evaluation to verify the effectiveness

of lubricating oil programs. A one-time inspection of selected components at susceptible

locations is an acceptable method to ensure that corrosion does not occur and that

component intended functions will be maintained during the period of extended

operation.

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The staff reviewed the Lubricating Oil Analysis Program, which monitors oil chemical

and physical properties, wear metals, contaminants, additives, and water, thus,

minimizing the occurrences of aging effects and maintaining the component's ability to

perform its intended functions. The effectiveness of the Lubricating Oil Analysis

Program is verified by the One-Time Inspection Program. The staff finds that the

One-Time Inspection Program provides inspection of select stainless steel and copper

alloy components exposed to lubricating oil for loss of material due to pitting and crevice

corrosion. The staff's evaluation of the Lubricating Oil Analysis and the One-Time

Inspection Programs is documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3,

respectively. The staff finds that these programs include activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to pitting and crevice corrosion in stainless steel and copper piping and

components exposed to lubricating oil.

(5) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

partially encased stainless steel tanks exposed to raw water. The applicant stated that

this aging effect is not applicable because WCGS does not have stainless steel tanks

with a moisture barrier configuration exposed to raw water in the ECCS; therefore, the

applicable GALL Report line item was not used.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in partially encased stainless steel tanks exposed to raw water due

to cracking of the perimeter seal from weathering.

The staff noted that this item is applicable to partially encased stainless steel tanks

exposed to raw water. The staff agrees with the applicant's determination that this item

in SRP-LR Section 3.2.2.2.3 does not apply because WCGS does not have stainless

steel tanks with a moisture barrier configuration exposed to raw water in the ECCS.

(6) LRA Section 3.2.2.2.3 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping, components, and tanks exposed to internal condensation. The

applicant stated that this aging effect is not applicable because WCGS does not have

stainless steel piping, piping components, piping elements, and tank internal surfaces

exposed to condensation (internal) in the containment spray and ECCSs within the

scope of license renewal. Therefore, the applicable GALL Report line item was not

used.

SRP-LR Section 3.2.2.2.3 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, piping elements, and

tanks exposed to internal condensation.

The staff noted that this item is applicable to stainless steel piping, components, and

tanks exposed to internal condensation. The staff agrees with the applicant's

determination that this item in SRP-LR Section 3.2.2.2.3 does not apply because WCGS

does not have stainless steel piping, piping components, piping elements, and tank

internal surfaces exposed to condensation in the containment spray and ECCSs within

the scope of license renewal.

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Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.2.2.2.4 against the following criteria in SRP-LR

Section 3.2.2.2.4:

(1) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling in stainless

steel and copper heat exchanger tubes exposed to lubricating oil. The applicant stated

that the Lubricating Oil Analysis and the One-Time Inspection Programs will manage

reduction of heat transfer due to fouling for copper nickel components exposed to

lubricating oil. The one-time inspection will include selected components at susceptible

locations where contaminants such as water could accumulate.

SRP-LR Section 3.2.2.2.4 states that reduction of heat transfer due to fouling may occur

in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating

oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of

heat transfer due to fouling. However, control of lube oil chemistry may not always be

fully effective in precluding fouling; therefore, the effectiveness of lube oil chemistry

control should be verified to ensure that fouling does not occur. The GALL Report

recommends further evaluation of programs to verify the effectiveness of lube oil

chemistry control. A one-time inspection of selected components at susceptible

locations is an acceptable method to determine whether an aging effect is occurring or

is slowly progressing such that the component's intended functions will be maintained

during the period of extended operation.

The staff reviewed the Lubricating Oil Analysis Program, which monitors oil chemical

and physical properties, wear metals, contaminants, additives, and water, thus,

minimizing the occurrences of aging effects and maintaining the component's ability to

perform its intended functions. The effectiveness of the Lubricating Oil Analysis

Program is verified by the One-Time Inspection Program. The One-Time Inspection

Program provides inspections of stainless steel and copper heat exchanger tubes

exposed to lubricating oil for reduction of heat transfer due to fouling at susceptible

locations where contaminants can accumulate. The staff's evaluation of the Lubricating

Oil Analysis and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.16 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage. reduction of heat transfer due to fouling in stainless steel and

copper heat exchanger tubes exposed to lubricating oil.

(2) LRA Section 3.2.2.2.4 addresses reduction of heat transfer due to fouling in stainless

steel heat exchanger tubes exposed to treated water. The applicant stated that this

aging effect is not applicable to WCGS because WCGS does not have stainless steel

heat exchanger tubes exposed to treated water in the containment spray system that

3-230
are within the scope of license renewal. Therefore, the applicable GALL Report line item

was not used.

SRP-LR Section 3.2.2.2.4 states that .reduction of heat transfer due to fouling may occur

in stainless steel heat exchanger tubes exposed to treated water.

The staff noted that this item is applicable to stainless steel heat exchanger tubes

exposed to treated water. The staff agrees that this item of SRP-LR Section 3.2.2.2.4

does not apply because WCGS does not have stainless steel heat exchanger tubes

exposed to treated water in the containment spray system that are within the scope of

license renewal.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.4 criteria. For those line items that apply to LRA Section 3.2.2.2.4, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.

LRA Section 3.2.2.2.5 addresses hardening and loss of strength due to elastomer degradation.

The applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer seals and components of the BWR standby gas treatment

system ductwork and filters exposed to air - indoor uncontrolled.

The staff noted that this item applies to BWR standby gas treatment system ductwork and

filters and; therefore, is not applicable because WCGS is a PWR plant. On this basis, the staff

finds that this aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.2.2.2.5

criteria.

3.2.2.2.6 Loss of Material Due to Erosion

The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.

LRA Section 3.2.2.2.6 addresses loss of material due to erosion. The applicant stated that this

aging effect is not applicable because WCGS does not use the safety injection pumps for

normal charging; therefore, the applicable GALL Report line item was not used.

SRP-LR Section 3.2.2.2.6 states that loss of material due to erosion may occur in the stainless

steel high-pressure safety injection (HPSI) pump miniflow recirculation orifice exposed to

treated borated water.

3-231
During its review, the staff requested that the applicant provides procedures and/or other

documentation to show the infrequent use of the HPSI pumps. In its response, the applicant

provided documentation for staff review. The staff noted that the HPSI mini-flow recirculation

lines containing flow orifices are only used during ECCS injection or during HPSI pump testing,

and that the HPSI pumps are only actuated during testing and are not used during normal

charging. Since loss of material due to erosion can only occur in these components if they are

frequently operated, the staff finds that erosion is not plausible in the HPSI pumps and flow

orifices at WCGS. On this basis, the staff agreesthat this item in SRP-LR Section 3.2.2.2.4

does not apply to WCGS.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.2.2.2.6

criteria.

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

LRA Section 3.2.2.2.7 addresses loss of material due to general corrosion and fouling. The

applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling may

occur on steel drywell and suppression chamber spray system nozzle and flow orifice internal

surfaces exposed to air - indoor uncontrolled and may cause plugging of the spray nozzles and

flow orifices.

The staff noted that this item applies to BWR steel drywell and suppression chamber spray

system and; therefore, is not applicable because WCGS is a PWR plant. On this basis, the staff

finds that this aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.2.2.2.7

criteria.

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.8 against the following criteria in SRP-LR

Section 3.2.2.2.8:

(1) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion in BWR piping and components exposed to treated water. The applicant

stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur in BWR steel piping, piping components, and piping elements

exposed to treated water.

The staff noted that this line item applies to BWR steel piping, piping components, and

piping elements and; therefore, is not applicable WCGS is a PWR plant. On this basis,

the staff finds that this aging effect is not applicable to this component type.

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(2) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion on internal surfaces of containment isolation piping and components exposed

to treated water. The applicant stated that the Water Chemistry and the One-Time

Inspection Programs will manage this aging effect in carbon steel components exposed

to demineralized water. The one-time inspection will include selected components at

susceptible locations where contaminants could accumulate (e.g., stagnant flow

locations).

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur on the internal surfaces of steel containment isolation piping, piping

components, and piping elements exposed to treated water. The existing AMP monitors

and controls water chemistry to mitigate degradation. However, control of water

chemistry does not preclude loss of material due to general, pitting, and crevice

corrosion at locations with stagnant flow conditions; therefore, the effectiveness of water

chemistry control programs should be verified to ensure that corrosion does not occur.

The GALL Report recommends further evaluation of programs to verify the

effectiveness of water chemistry control programs. A one-time inspection of selected

components at susceptible locations is an acceptable method to determine whether an

aging effect is occurring or is slowly progressing such that the component's intended

functions will be maintained during the period of extended operation.

The staff reviewed the Water Chemistry Program which monitors chlorides, fluorides,

and dissolved oxygen to limit the contaminants, thus, minimizing the occurrences of

aging effects and maintaining the component's ability to perform its intended functions.

The applicant stated that it will use the One-Time Inspection Program to verify the

effectiveness of the Water Chemistry Program. The One-time Inspection Program

provides inspections of select steel components exposed to treated water at susceptible

locations, such as stagnant areas, for loss of material due to general, pitting, and

crevice corrosion. The staff's evaluation of the Water Chemistry and the One-time

Inspection Programs is documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3,

respectively. The staff finds that these programs include activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to general, pitting, and crevice corrosion on internal surfaces of

containment isolation piping and components exposed to treated water.

(3) LRA Section 3.2.2.2.8 addresses loss of material due to general, pitting, and crevice

corrosion in steel piping and components exposed to lubricating oil. The applicant stated

that the Lubricating Oil Analysis and the One-Time Inspection Programs will manage

this aging effect in carbon steel (including galvanized) components exposed to

lubricating oil, except for the RCP lube oil leakage collection system. The one-time

inspection will include selected components at susceptible locations where contaminants

such as water could accumulate.

SRP-LR Section 3.2.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements exposed to

lubricating oil. The existing program periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

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control should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation to verify the effectiveness of lubricating oil programs. A

one-time inspection of selected components at susceptible locations is an acceptable

method to ensure that corrosion does not occur and that component intended functions

will be maintained during the period of extended operation.

The staff reviewed the Lubricating Oil Analysis Program, which monitors oil chemical

and physical properties, wear metals, contaminants, additives, and water, thus,

minimizing the occurrences of aging effects and maintaining the component's ability to

perform its intended functions. The applicant stated that it will use the One-Time

Inspection Program to verify the effectiveness of the Lubricating Oil Analysis Program.

The One-Time Inspection Program provides inspections of steel piping and components

exposed to lubricating oil for loss of material due to general, pitting, and crevice

corrosion at susceptible locations where contaminants can accumulate. The staff's

evaluation of the Lubricating Oil Analysis and the One-Time Inspection Programs is

documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3, respectively. The staff finds that

these programs include activities that are consistent with the recommendations in the

GALL Report, and are adequate to manage loss of material due to general, pitting, and

crevice corrosion in steel piping and components exposed to lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.2.2.2.8 criteria. For those line items that apply to LRA Section 3.2.2.2.8, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9.

LRA Section 3.2.2.2.9 addresses loss of material due to general, pitting, crevice, and MIC. The

applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC

may occur in steel (with or without coating or wrapping) piping, piping components, and piping

elements buried in soil. Buried piping and tanks inspection programs rely on industry practice,

frequency of pipe excavation, and operating experience to manage the aging effects of loss of

material from general, pitting, and crevice corrosion, and MIC. The effectiveness of the buried

piping and tanks inspection program should be verified by evaluation of an applicant's

inspection frequency and operating experience with buried components to ensure that loss of

material does not occur.

In the LRA, the applicant stated that SRP-LR Section 3.2.2.2.9 does not apply because WCGS

is a PWR plant. During the review, the staff requested that the applicant explain why it stated

that buried piping is only found in BWRs.

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In its response, the applicant stated that SRP-LR Section 3.2.2.2.9 is a rollup item from the

standby gas treatment systems, which is a BWR-specific system, and that there is no buried

carbon steel piping associated with the engineered safety features systems at WCGS. On this

basis, the staff finds that at WCGS, this aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.2.2.2.9

criteria.

3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-11, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-11, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation of the listed LRA Notes (above) is documented in the following sections.

3.2.2.3.1 Engineered Safety Features - Summary of Aging Management Evaluation - Nuclear

Sampling System - LRA Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the

nuclear sampling system component groups.

In LRA Table 3.2.2-1, the applicant applied note F for stainless steel closure bolting exposed to

an external environment of borated water leakage, indicating that this component material is not

in the GALL Report. The staff reviewed the GALL Report and concludes that the AMR item,

stainless steel closure bolting, is not evaluated for a borated water leakage environment for loss

of pre-load and accordingly, the applicant's use of note F is appropriate. The staff's evaluation

of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting Integrity

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Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

AMP is consistent with the recommendations of the GALL Report. On the basis of its review of

the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of loss of pre-load in stainless steel closure bolting exposed to an external environment of

borated water leakage will be adequately managed by using the Bolting Integrity Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.2 Engineered Safety Features - Summary of Aging Management Evaluation -

Containment Spray System - LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the

containment spray system component groups.

In LRA Table 3.2.2-2, the applicant applied note G for stainless steel piping, valves, and tanks

exposed to a sodium hydroxide environment, indicating that the environment for this component

and material is not in the GALL Report. On the basis of its review, the staff finds that the

applicant's use of note G is appropriate for this component, material, and environment

combination. The applicant credited the Water Chemistry and the One-Time Inspection

Programs to manage loss of material due to pitting and crevice corrosion.

The staff finds that the Water Chemistry Program ensures the sodium hydroxide levels are

maintained to a normal value of 29.8 weight percentage in accordance with plant procedures.

The staff noted that all stainless steels are resistant to general corrosion at all sodium

hydroxide levels up to 150 OF. Therefore, adherence to this limit will minimize the potential for

pitting and crevice corrosion provided that the temperature does not exceed 150 OF.

The applicant stated that the One-Time Inspection Program will verify that loss of material or

cracking will not be a problem during the period of extended operation provided that operating

temperature is below 150 OF and 212 OF, respectively.

The staff noted that above these temperatures, loss of material and cracking can be expected,

and it appears that a one-time inspection would not be sufficient to manage these aging effects

through the period of extended operation.

During the audit, the staff requested that the applicant provides the temperature range of

operation for these components.

In its response, the applicant stated that the piping design and nominal operating temperatures

are 125 OF and 100 OF, respectively, and the tank operating temperature is 120 OF. On the basis

that operating temperatures are below 150 OF, the staff finds that cracking is not plausible and

loss of material due to pitting and crevice corrosion is not likely. The staff's evaluation of the

Water Chemistry and the One-time Inspection Programs is documented in SER

Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. On this basis, the staff finds that the Water

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Chemistry and the One-Time Inspection Programs are adequate to manage loss of material

due to pitting and crevice corrosion for containment spray system stainless steel piping, valves,

and tanks exposed to sodium hydroxide environment during the period of extended operation.

The staff noted that the applicant applied note F for stainless steel closure bolting exposed to

an external environment of borated water leakage, indicating that the component material is not

in the GALL Report. The staff reviewed the GALL Report and concludes that the AMR item for

stainless steel closure bolting is not evaluated in a borated water leakage environment for loss

of pre-load. The staff finds that the applicant's use of note F is appropriate.

The applicant credited the Bolting Integrity Program for managing loss of preload. The staff's

evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting

Integrity Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

program is consistent with the recommendations of the GALL Report. On the basis of its review

of the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of loss of pre-load in stainless steel closure bolting exposed to an external environment of

borated water leakage will be adequately managed by using the Bolting Integrity Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, -as required by 10 CFR 54.21 (a)(3).

3.2.2.3.3 Engineered Safety Features - Summary of Aging Management Evaluation -

Containment Integrated Leak Rate Test System - LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the

containment integrated leak rate test system component groups. On the basis of its review, the

staff finds that all AMR results described in LRA Table 3.2.2-3 are consistent with the GALL

Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.4 Engineered Safety Features - Summary of Aging Management Evaluation -

Decontamination System - LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the

decontamination system component groups. On the basis of its review, the staff finds that all

AMR results described in LRA Table 3.2.2-4 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.2.2.3.5 Engineered Safety Features - Summary of Aging Management Evaluation - Liquid

Radwaste System - LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the

liquid radwaste system component groups.

In LRA Table 3.2.2-5, the applicant applied note F for stainless steel closure bolting exposed to

an external environment of borated water leakage, indicating that the component material is not

in the GALL Report. The staff reviewed the GALL Report and concludes that the AMR item for

stainless steel closure bolting is not evaluated for a borated water leakage environment for loss

of preload. The staff finds that the applicant's use of note F is appropriate.

The applicant credited the Bolting Integrity Program for managing loss of pre-load. The staff's

evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting

Integrity Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

program is consistent with the recommendations of the GALL Report. On the basis of its review

of the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of loss of pre-load in stainless steel closure bolting exposed to an external environment of

borated water leakage will be adequately managed by using the Bolting Integrity Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.6 Engineered Safety Features - Summary of Aging Management Evaluation - Reactor

Makeup Water System - LRA Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the

reactor makeup water system component groups. On the basis of its review, the staff finds that

all AMR results described in LRA Table 3.2.2-6 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.7 Engineered Safety Features - Summary of Aging Management Evaluation -

Containment Purge HVAC System - LRA Table 3.2.2-7

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the

containment purge HVAC system component groups.

In LRA Table 3.2.2-7, the applicant applied note H for steel closure bolting exposed to an

external environment of atmosphere weather indicating that the aging effect for this component,

material, and environment combination is not evaluated in the GALL Report. The staff reviewed

the GALL Report and concludes that the AMR item for steel closure bolting is not evaluated in

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an external environment of atmosphere weather for loss of preload. The staff finds that the

applicant's use of note H is appropriate.

The applicant credited the Bolting Integrity Program for managing loss of preload. The staff's

evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting

Integrity Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

program is consistent with the recommendations of the GALL Report. On the basis of its review

of the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of loss of pre-load in steel closure bolting exposed to an external environment of

atmosphere weather will be adequately managed by using the Bolting Integrity Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.8 Engineered Safety Features - Summary of Aging Management Evaluation - Breathing

Air System - LRA Table 3.2.2-8

The staff reviewed LRA Table 3.2.2-8, which summarizes the results of AMR evaluations for the

breathing air system component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.2.2-8 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.9 Engineered Safety Features - Summary of Aging Management Evaluation - Hydrogen

Control System - LRA Table 3.2.2-9

The staff reviewed LRA Table 3.2.2-9, which summarizes the results of AMR evaluations for the

hydrogen control system component groups.

In LRA Table 3.2.2-9, the applicant applied note G for carbon steel piping and valves, indicating

that the internal environment of ventilation atmosphere for this component material is not in the

GALL Report. The staff finds that the applicant's use of note G for this component, material,

and environment combination is appropriate.

The applicant credited the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program for management of loss of material due to general, pitting, and crevice

corrosion. In its review of the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program, the staff noted that visual inspections of internal surfaces of

plant components will be performed during periodic maintenance, predictive maintenance,

surveillance testing, and corrective maintenance activities. The staff's evaluation of the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is

documented in SER Section 3.0.3.1.7. On the basis of its review of the applicant's plant-specific

and industry operating experience, the staff finds that the aging effect of loss of material in

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carbon steel piping and valves exposed to an internal environment of ventilation atmosphere

will be adequately managed by using the Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.10 Engineered Safety Features - Summary of Aging Management Evaluation - High

Pressure Coolant Injection System - LRA Table 3.2.2-10

The staff reviewed LRA Table 3.2.2-10, which summarizes the results of AMR evaluations for

the high pressure coolant injection system component groups.

In LRA Table 3.2.2-10, as amended by letter dated August 31, 2007, the applicant applied

note G for stainless steel piping and tanks and heat exchanger tube side, indicating that the

external environment of ventilation atmosphere weather for these components material is not in

the GALL Report. The staff finds that the applicant's use of note G is appropriate for this

component, material, and environment combination.

The applicant did not credit an AMP because there are no aging effects in stainless steel

exposed to weather. The staff noted that there are no plausible aging effects for stainless steel

exposed to weather. Therefore, the staff agrees that no AMP is necessary for this component,

material, and environment combination.

In LRA Table 3.2.2-10, the applicant applied note F for the nickel alloy accumulator. The GALL

Report, Section V.D1, does not include any nickel alloy components. The staff finds that the

applicant's use of note F is appropriate for this component, material, and environment

combination.

The applicant credited the Water Chemistry Program for managing loss of material caused by.

pitting and crevice corrosion. The staff noted that'crediting only the Water Chemistry Program

will provide effective management of loss of material in nickel alloys exposed to treated borated

water where there is no stagnant flow. However, control of water chemistry alone does not

preclude loss of material under low flow conditions. The staff noted that accumulators typically

have low flow and additional actions may be necessary to verify that long term corrosion is not

occurring. The staff requested that the applicant clarify if additional provisions will be taken to

ensure that corrosion is not progressing slowly.

By letter dated August 31, 2007, the applicant amended LRA Table 3.2.2-10 to include the

One-Time Inspection Program for managing the loss of material due to pitting and crevice

corrosion. The staff noted that a one-time inspection is an acceptable method to determine

whether or not loss of material is occurring slowly such that the component's intended function

will be maintained during the period of extended operation. On this basis, the staff finds that the

Water Chemistry and the One-Time Inspection Programs are adequate to manage loss of

material due to pitting and crevice corrosion in nickel alloy accumulators during the period of

extended operation.

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In LRA Table 3.2.2-10, the applicant applied note F for stainless steel closure bolting exposed

to an external environment of borated water leakage, indicating that the component material is

not in the GALL Report. The staff reviewed the GALL Report and concludes that the AMR line

item for stainless steel closure bolting is not evaluated in a borated water leakage environment

for loss of pre-load. The staff finds that the applicant's use of note F is appropriate.

The applicant credited the Bolting Integrity Program for managing loss of pre-load. The staff's

evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting

Integrity Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

program is consistent with the recommendations of the GALL Report. On the basis of its review

of the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of loss of pre-load in stainless steel closure bolting exposed to an external environment of

borated water leakage will be adequately managed by using the Bolting Integrity Program.

The staff noted that the applicant credited the Nickel Alloy AMP to manage PWSCC in nickel

alloy components in the accumulator. The applicant credited note 2 for these AMR line items

indicating that the accumulator nozzles in the HPCI system contain nickel alloy 82/182 weld

metal. The staff noted that Alloy 82/182 is known to be susceptible to SCC, such as PWSCC

and IGSCC, depending on environment. The susceptibility to SCC requires the presence of

three conditions, namely, the susceptible material, the aggressive environment and the tensile

stresses. If any of these three conditions is absent, the degradation due to SCC will not occur.

The staff determines that the subject nickel alloy components in the HPCI accumulator will not

be susceptible to PWSCC because the subject components are not exposed to the reactor

coolant. As stated in LRA Table 3.1.2.3, the subject components are exposed to treated

borated water; therefore, these components may be subject to IGSCC.

As discussed in SER Section 3.0.3.3.1, in its response to RAI B.2.1.34-6 dated July 26, 2007,

the applicant stated, in note 2 to the table, that the system and piping temperature at the

accumulator nozzle locations is ambient containment temperature (i.e., approximately 100 'F).

Therefore, the staff finds that even if the subject components are susceptible to IGSCC, its

degree of susceptibility should be very low because it would take a long time for the cracks to

be initiated at such a low temperature. The staff finds that in the Nickel Alloy Aging

Management Program, the subject components will be visually inspected (i.e., VT-2) every ISI

period.

On the basis of its review, the staff determines that the proposed examination in the Nickel

Alloy Aging Management Program is adequate to monitor the potential degradation due to

PWSCC or IGSCC.

The staff finds that the applicant's Nickel Alloy AMP commitment (Commitment No. 30) will

implement: (1) NRC Orders, Bulletins and GLs associated with nickel alloys, (2) staff-accepted

industry guidelines, and (3) participation in industry initiatives, such as owners group programs

and the EPRI Materials Reliability Program, for managing aging effects associated with nickel

alloys. The staff finds that the applicant will submit the Nickel Alloy Aging Management Program

inspection plan to the NRC, for review and approval, 24 months before entering the period of

extended operation.

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The staff finds that this commitment provides reasonable assurance that an acceptable Nickel

Alloy AMP will be implemented and that the aging effects will be adequately managed during

the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.2.3.11 Engineered Safety Features.- Summary of Aging Management Evaluation -

Residual Heat Removal System - LRA Table 3.2.2-11

The staff reviewed LRA Table 3.2.2-11, which summarizes the results of AMR evaluations for

the residual heat removal system component groups.

In LRA Table 3.2.2-11, the applicant applied note G for stainless steel heat exchanger materials

indicating that an internal environment of treated borated water for this component material is

not in the GALL Report. The staff finds that the applicant's use of note G is appropriate for this

component, material, and environment combination.

The applicant credited the Water Chemistry and One-Time Inspection Programs for

management of reduction of heat transfer. The staff noted that water chemistry control provides

effective management of loss of material in stainless steel exposed to treated borated water,

while a one-time inspection will verify that loss of material due to pitting and crevice corrosion is

not progressing slowly. On this basis, the staff finds that loss of material due to pitting and

crevice corrosion in stainless steel heat exchanger materials will be adequately managed during

the period of extended operation.

The staff noted that the applicant applied note F for stainless steel closure bolting exposed to

an external environment of borated water leakage, indicating that the component material is not

in the GALL Report. The staff reviewed the GALL Report and concludes that the AMR line item

for stainless steel closure bolting is not evaluated in a borated water leakage environment for

loss of preload. The staff finds that the applicant's use of note F is appropriate.

The applicant credited the Bolting Integrity Program for managing loss of pre-load. The staff's

evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7. The Bolting

Integrity Program includes good bolting practices and requirements for proper disassembling,

inspecting, and assembling of connections with threaded fasteners. The staff finds that this

program is consistent with the recommendations of the GALL Report. On the basis of its review

of the applicant's plant-specific and industry operating experience (reflecting the adequacy of

the program and is consistent with the recommendations of the GALL Report), the staff finds

that the aging effect of loss of pre-load of stainless steel closure bolting exposed to an external

environment of borated water leakage will be adequately managed by using the Bolting Integrity

Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

3-242
adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the engineered safety features components within the scope of license

renewal and subject to an AMR will be adequately managed so that the intended function(s) will

be maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21 (a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff's review of the applicant's AMR results for the

auxiliary systems components and component groups of:

* fuel handling - fuel storage and handling system

* fuel pool cooling and cleanup system

* essential service water system

* component cooling water system

* containment cooling system

* compressed air system

* " chemical and volume control system

* auxiliary building HVAC system

* control building HVAC system

* .fuel building HVAC system

* essential service water pumphouse building HVAC system

* miscellaneous buildings HVAC system

* diesel generator building HVAC system

• fire protection system

* emergency diesel engine fuel oil storage and transfer system

* emergency diesel engine system

* floor and equipment drains system

* oily waste system

* cranes, hoists and elevator systems

* turbine building HVAC system

* miscellaneous auxiliary systems in-scope only based on criterion 10 CFR 54.4(a)(2)

3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary systems components and component

groups. LRA Table 3.3.1, "Summary of Aging Management Evaluations in Chapter VII of

NUREG-1 801 for Auxiliary Systems," is a summary comparison of the applicant's AMRs with

those evaluated in the GALL Report for the auxiliary systems components and component

groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

3-243
condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report initially.

3.3.2 Staff Evaluation

The staff reviewed LRA Section 3.3 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the auxiliary systems components within

the scope of license renewal and subject to an AMR will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.3.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.3.2.2.

The staff also conducted a technical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's evaluations are

documented in SER Section 3.3.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.3-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.3 and addressed in the GALL Report.

3-244
Table 3.3-1 Staff Evaluation for Auxiliary Systems in the GALL Report

Component Group Aging Effectl AMP in GALL Further , AMP in LRA,, Staff

(GALL Report Mechanism Report Evaluation S!Supplements, or Evaluation

Item No.) -I•n GALL 1 Amendments

______________+!+: ___________+;++ __________ _ i Report•' ______________ ___

Steel cranes - Cumulative TLAA to be Yes TLAA TLAA

structural girders fatigue damage evaluated for (See SER

exposed to air - structural girders of Section

indoor uncontrolled cranes. See the 3.3.2.2.1)

(external) SRP-LR,

(3.3.1-1) Section 4.7 for

generic guidance

for meeting the

requirements of

10 CFR 54.21 (c)(1)

Steel and stainless Cumulative TLAA, evaluated in Yes Not applicable Not applicable

steel piping, piping fatigue damage accordancewith to WCGS

components,piping 10 CFR 54.21(c) (See SER

elements, and heat Section 3.3.2.2.

exchanger• 1)

components

exposedto air -

indoor uncontrolled,

treated borated

water or treated

Water

(3.3.1-2)

Stainless steel heat Reduction of Water Chemistry Yes Not applicable Not applicable

exchanger tubes heat transfer due and One-Time to PWRs

exposed to treated to fouling Inspection (See SER

water Section 3.3.2.2.

(3.3.1-3) 2)

Stainless steel Cracking due to Water Chemistry Yes Not applicable Not applicable

piping, piping SCC and One-Time to PWRs

components, and Inspection (See SER

piping elements Section 3.3.2.2.

exposed to sodium 3.1)

pentaborate solution

>•600C (> 1400 F)

(3.3.1.4)

Stainless steel and Cracking due to A p!ant-specific Yes Not applicable Not applicable

stainless clad steel SCC aging management to PWRs

heat exchanger program is to be (See SER

components evaluated. Section 3.3.2.2.

exposed to treated 3.2)

water > 60'C

(>140.0F)

(3.3.1-5)

3-245
'Component Group Aging Effectl AMP in GALL Further -..-AMP in LRA, staff

(GALL Report, Mechanism Report Evaluation Supplements, or Evaluation

.ItemNo.)• ! in GALL Amendments

- >.~~Report __ _ __ _ _ _

Stainless steel:. Cracking due to A plant-specific Yes Inspection of Consistent with

diesel engine: SCC aging management Internal Surfaces in GALL Report

exhaust piping, program is to be Miscellaneous (See SER

piping components, evaluated. Piping and Ducting Section 3.3.2.2.

and piping elements Components 3.3)

exposed to diesel .(B2.1.22)

exhaust

(3.3.1-6)

Stainless steel Cracking due to Water Chemistry Yes Not applicable Not applicable

non-regenerative SCC and cyclic and a plant-specific to WCGS

heat exchanger loading verification (See SER

components program. An Section 3.3.2.2.

exposed to treated acceptable 4.1)

borated water verification

> 60'C (> 140'F) program is to

(3.3.1-7) include

. temperature and

radioactivity

monitoring of the

shell side water,

and eddy current

i testing of tubes..

Stainless steel Cracking due to Water Chemistry Yes Water Chemistry Consistent with

regenerative heat SCC and cyclic and a plant-specific (B2.1.2) and GALL Report

exchanger - loading verification One-Time (See SER

components program. The. "Inspection (B2.1.16) Section 3.3.2.2.

exposed to treated AMP is to be 4.2)

borated water . augmented by

> 60'C (> 140'F) verifying the

(3.3.1-8) absence of

cracking due to.

stress corrosion

*.cracking and cyclic

loading. A

plant-specific aging

management

program is to be,

evaluated.

3-246
Component Group Aging Effect/' AMP in GALL Further %AMP In LRA,' Staff

(GALL Report :Mechanism Report Evaluation Supplements, or ,Evaluation

,Item No.):• in GALL Amendments

____ ___ ___ ____ __ ___ ___ ___ Report

Stainless steel Cracking due to Water Chemistry Yes Water Chemistry Consistent with

high-pressure pump SCc and cyclic and a plant-specific (B2.1.2) and GALL Report

casing in PWR loading verification One-Time (See SER

CVCS program. The Inspection (B2.1.16) Section 3.3.2.2.

(3.3.1-9) AMP is to be 4.3)

augmented by

verifying the

absence of

cracking due to

stress corrosion

cracking and cyclic

loading; A

plant-specific aging

management

program is to be

evaluated.

,High-strength steel Cracking due to. Bolting Integrity. Yes Not applicable Not applicable

closure bolting .. SCC, cyclic The AMP is to be toWCGS

exp0sed'to air with loading augmented by (See SER

steam or water,, appropriate Section 3.3.2.2.

leakage. . inspection to -detect 4.4)

(3.3.1-10), cracking if the bolts

are not otherwise

replaced during

maintenance.

Elastomersealsand Hardening and A plant-specific Yes Inspection of Consistent with

components .. loss of strength aging management Intemal GALL Report

exposed to air due to elastomer program is to be Surfaces in (See SER

indoor uncontrolled degradation evaluated. Miscellaneous Section 3.3.2.2.

(internal/external) Piping and Ducting 5.1).

(3.3.1.41) Components

(B2.1.22),

Extemal Surfaces

Monitoring (B2.1.20)

and Fire Protection

(B2.11.12)

Elastomer lining, Hardening-and A plant-specific Yes Not applicable 'Not applicable

exposed to treated loss of strength aging management toWCGS

water or treated' due to elastomer program is to be (See SER

borated water degradation evaluated. Section 3.3.2.2.

(3.3.1-12) ... . 5.2)

Boral, boron steel Reduction of . A plant-specific Yes None Consistent with

spent fuel storage . neutron-absorbin aging management GALL Report

racks .... g capacity and program is to be (See SER

neutron-absorbing loss of material evaluated. Section 3.3.2.2.

sheets: exposed to due to general. 6)

treated water or corrosion

treated borated

water

(3.3.1-13) I

3-247
Ctomponent Group Aging Effect/ AMP in GALL Further AMP in LRA, 'JýStaff

":(GALL Report :,Mechanism ý ýReport Evaluation Supplements, or ý:Evaluation

Item No.) in GALL •Amendments

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Report _ _ _ _ _ _ _

.Steel piping, piping Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

component, and due to general, -Analysis and Analysis (B2.1.23) GALL Report

piping elements pitting, and One-Time and One-Time (See SERI

exposed .to crevice corrosion Inspection Inspection (B2.1.16) Section 3.3.2.2.

lubricatingoil ".7.1),

(3.3.1-14) • :_ .... _ _• .... 

Steel reactor Loss of material Lubricating Oil Yes Inspection of Consistent with

coolant pump oil due to general, Analysis and Intemal Surfaces in IGALL Report

collection system pitting, and One-Time Miscellaneous (See SER

piping, tubing, and crevice corrosion Inspection Piping and Ducting Section 3.3.2.2.

valve bodies. Components 7.1)

exposed to (B2.1.22)

lubricating oil.

(3.3.1715) .... _ _:_

Steel reactor . Loss of material Lubricating Oil Yes Not applicable Not applicable

coolant pump oil due to general, Analysis and to WCGS

collection system pitting, and One-Time (See SERý

tankbexposed to crevice corrosion Inspection to section 3.3.2.2.

lubricatinig oil evaluate the 7.1)

(3.3.1-16). thickness of the

lower portion of the

tank

Steel piping, piping Loss of material Water Chemistry Yes Not applicable Not applicable

components,.and due to general, and One-Time to PWRs

piping elements pitting, and Inspection (See SER

exposed to treated crevice corrosion .* Section 3.3.22.

water I. . -72)

(3.3.1-17) :,, "

Stainless steel and Loss of material/ A plant-specific .Yes Inspection of Consistent with

steel diesel engine general (steel:. aging management Intemal Surfacesin GALL Report

exhaust 'piping, only), pitting and program is to be Miscellaneous (See SER

piping components, crevice corrosion evaluated. Piping and Ducting Section-3.3.2.2.

and piping elements Components 7.3)

exposed to diesel (B2.1.22)

exhaust... (3-3-1"18). ___ __ __. __ _ _ _ _ _ _ __ __ __

Steel (with or . r. Loss of material - Buried Piping and No Buried Piping and Consistent with

without coating or due to general, Tanks Surveillance Tanks Inspection GALL Report

wrapping) piping; pitting, crevice. . (B2.1.18) (See SER

piping components, and MIC or ... . ' Section 3.3.2.2.

and piping elements " 8)

exposed to soil Buried Piping and Yes

(3.3.119) . Tanks Inspection

Steel piping, piping, Loss of material FuelOil Chemistry. Yes Fuel Oil Chemistry Consistent with

components, piping due to general,. and One:Time (B2.1.14) and One- GALL Report

elements, and tanks pitting, crevice, Inspection Time Inspection (See SER

exposed to fuel oil and MIC, and (B2.1.16) Section 3.3.2.2.

(3.3.1-20) fouling 19.1)

3-248
Component Group Aging Effect/ 'AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation 'Supplements, or Evaluation

Item ,No.) in GALL ~~Amendments _____ _ _____ ___ _____ _ ___ _____ __ '-Report _ _ _ _ _ _ _ _ _ _ _ _

Steel heat Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

exchanger due to general, Analysis and Analysis (B2.1.23) GALL Report

components pitting, crevice, One-Time andOne-Time (See SER

exposed to and MIC, and Inspection Inspection (B2.1.16) Section 3.3.2.2.

lubricating oil fouling 9.2).

(3.3.1-21).. ._"_-._,._.. .. •_ _._

Steel with elastomer Loss of material Water Chemistry Yes Not applicable Not applicable

lining or stainless due to pitting and One-Time . to WCGS

steel cladding,,'' and crevice Inspection .. (See SER

piping, piping corrosion (only Section 3.3.2.2.

components, and for steel after•. 10.1)

piping qelements.., lining/cladding

exposed to treated, degradation)

water and'.treatfd

borated water

(3.3.1-22), ..______" "

Stainless steel.and Loss of material Water Chemistry Yes Not applicable Not applicable

steel with stainless due to pitting and One-Time to PWRs

steel cladding heat and crevice Inspection (See SER

exchanger corrosion Section 3.3.2.2.

components 10.2)

exposed totreated

water

(3.3.1-23)

Stainless steel and Loss of material Water Chemistry Yes Not applicable Not applicable

aluminum.piping, due to pitting and One-Time to PWRs

piping components, and crevice Inspection (See SER

and piping elements corrosion Section 3.3.2.2.

exposed to treated• 10.2)

water

(3.3.1-24). _ " " _ " 

Copper alloy HVAC Loss of material A plant-specific. Yes Inspection of Consistent with

piping, piping due to pitting aging management Internal GALL Report

components,.piping and crevice program is.to be Surfaces in (See SER

elements exposed corrosion evaluated. .. ,Miscellaneous• Section 3.3.2.2.

to condensation Piping and. Ducting, 10.3)

(extemal): Components

(3.3.1-25) (B2.1.22) and

.External Surfaces. ,.__ :._ _.. _ _..__.__. "_ .Monitoring (B2.1.20)

Copper alloy~pipig, Loss otmaterial Lubricating Oil Yes Lubricating Oil Consistent with

piping componnts, due to pitting Analysis and Analysis,(B2.1.23). GALL Report

and piping.elements and crevice .. One-Time and One-Time (See SER

exposed to corrosion Inspection •Inspection (B2.1.16) Section 3.3.2.2.

lubricating oil 10.4)

(3.3.1-26) _ _ _ _ . _ ._.._.._.

3-249
,Component Group Aging Effect/ AMP in GALL. Further AMP in LRA, 'Staff

(GALL Report :Mechanism Report Evaluation Supplements, or Evaluation.

Item No.) in GALL Amendments

- __ ____ ___ ____ ____ ___ Report,,

Stainlesssteel Loss of material A plant-specific Yes Inspection of Consistent with

HVAC ducting and due to pitting aging management Intemal Surfaces in GALL Report

aluminum HVAC and crevice program is to be Miscellaneous (See SER

piping, piping, corrosion evaluated. Piping and Ducting Section 3.3.2.2.

components and Components 10.5)

piping elements (B2.1.22)

exposed to

condensation

(3.3.1-27)

Copper alloy fire• Loss of material A plant-specific Yes Inspection of Consistent with

protection piping, due to pitting aging management Intemal Surfaces in GALL Report

piping components, and crevice program is to be Miscellaneous (See SER

and piping elements corrosion evaluated. .Piping and Ducting Section 3.3.2.2.

exposed to Components 10.6)

condensation (B2.1.22)

(intemal)

(3.3.1-28)

Stainless steel Loss of material A plant-specific. Yes Not applicable Not applicable

piping, piping due to pitting aging management to WCGS

components, and and crevice program is to be (See SER

piping elements corrosion evaluated. Section 3.3.2.2.

exposed.to soil .10.7)

(3.3.1-29). __.

Stainless steel Loss of material Water Chemistry Yes Not applicable Not applicable

piping, piping ' due to pitting and One-Time.: to PWRs

components, and and crevice Inspection (See SER

piping elements corrosion Section 3.3.2.2.

exposedto sodium 10.8)

pentaborate solution.

(3.3.1.-30) _

Copper alloy piping, Loss of material Water Chemistry Yes Not applicable Not applicable

piping components, due to pitting, and One-Time to PWRs

and piping elements crevice, and Inspection (See SER

exposed to treated galvanic Section 3.3.2.2.

water corrosion 11)

(3.3.1-31)

Stainless steel,

aluminum and.

copper alloy piping,

piping components,

and piping elements

exposed to fuel oil

(3.3.1-32) "

Loss of material

due to pitting,

crevice, and MIC

Fuel Oil Chemistry

and One-Time

Inspection

Yes Fuel Oil Chemistry

(B2.1.14) and OneTime Inspection

(B2.1.16)

Consistent with

GALL Report

(See SER

Section 3.3.2.2.

1ý21)

3-250
,Component Group Aging Effect/. AMP in GALL Further- AMP in LRA, Staff

'(GALL Report Mechanism' ... "Report Evaluationw ;Supplements, or Evaluation::

'Item No.) in GALL: i- Amendments - - ~~Report<____

Stainless steel Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

piping, piping due to pitting, Analysis and Analysis (B2.1.23) GALL Report

components, and crevice, and MIC One-Time and One-Time (See SER

piping elements. Inspection Inspection (B2.1.16) Section 3.3.2.2.

exposed to Inspection of 12.2)

lubricating oil Internal'Surfaces in

i(3.3.1-33) Miscellaneous

Piping and Ducting

Components

(B2.1 .22)

Elastomer seals and Loss of. material A plant-specific Yes Not applicable Not applicable

components due to wear aging management to WCGS

exposed to air - program is to be (See SER

indoor uncontrolled evaluated. Section 3.3.2.2.

(internal or external) 13)

(3.3.1-34).

Steel with stainless Loss of material A plant-specific Yes Not applicable Notapplicable

steel cladding pump due to cladding aging management to WCGS

casing exposed to breach program is to be. (See SER

treated borated' evaluated. Section 3.3.2.2.

water Reference NRC 14)

(3.3.1-35) IN 94-63, "Boric

Acid Corrosion of

Charging Pump

Casings Caused

by Cladding

Cracks."

Boraflex spent fuel Reduction of Boraflex Monitoring No Not applicable Not applicable

storage racks . neutron-absorbin to PWRs

neutron-absorbing g capacity due to

sheets exposed to boraflex.

treated water degradation

(3.3.1-36)

Stainless steel Cracking due to BWR Reactor No Not applicable Not applicable

piping, piping. SCC, IGSCC. Water Cleanup to PWRs

com•0onents,: and . System

piping, elements

exposed to treated

water > 60'C

(> 140'F)

(3.3.1-37). ,

Stainless steel Cracking due to BWR Stress No Notapplicable Not applicable

piping, piping SCC Corrosion Cracking . to PWRs

components, and and Water

piping elements Chemistry

exposed to treated

water 60°C

(> 140°F).

(3.3.1-38) • .... 1 

3-251
Component Group Aging Effect/: AMP in GALL Further AMP in LRA,.' -Staff'

(GALL Report Mechanism eport Evaluation Supplements, or Evaluation.

.Item No.), . ' -in GALL .Amendments

' R~~~~Feport ______ ____

Stainless steel BWR Cracking due to Water Chemistry No Not applicable Not applicable

spent fuel storage SoC to PWRs

racks exposed to

treated water

> 60'0 (> 140'F)

(3.3.1-39) •

Steel tanks in diesel Loss of material Aboveground Steel No Not applicable -Not applicable

fuel oil system due to general,: Tanks to'WCGS

exposed to air pitting, and. (See SER

outdoor (external) crevice corrosion Section 3.3.2.1.

(3.3.1-40) " ... 1)

High-strength steel Cracking due to Bolting Integrity No Not applicable Not applicable

closure bolting. cyclic loading, to WCGS

exposed to air with SCC (See SER

steam or water *. Section 3.3.2.1.

leakage 1)

(3.3.1-41) .. " _ ...

Steel closure bolting• Loss of material Bolting Integrity No Not applicable Not applicable

exposed to air with due to general to.WCGS

steam or water " corrosion (See SER

leakage.. . Section 3.3.2.1.

(373.1-42) . • .!)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting due to general, (B2.1.7) GALL Report

exposed to air .. pitting, and

indoor uncontrolled crevice corrosion

(extemal) or air "

outdoor (extemal)

(3.3.1-43) . • . _ 

Steel compressed Loss of material Bolting Integrity No Not applicable Not applicable

air system closure due to general, to WCGS

bolting, exposed to pitting, and (See SER

condensation . crevice corrosion . Section 3.3.2.1.

(3.3.1-44) . • 1)

Steel closure bolting Loss of preload Bolting Integrity No Bolting Integrity Consistent with

exposed to air - due to thermal (B2.1.7) GALL Report

indoor uncontrolled effects, gasket

(external) creep, and

(3.3.1-45) self-loosening _

3-252
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Itemn No.) ~. -in GALL Amendments

_____ __ _____ _____ __ __ _____ ____ Report _ _ _ _ _ _ _ _ _ _ _ _

Stainless steel and Cracking due to Closed-Cycle No Closed-Cycle Consistent with

stainless clad steel SCC Cooling Water Cooling Water GALL Report,

piping, piping System System (B2.1.10)

components, piping

elements; and heat

exchanger

components

exposed to closed

cycle cooling,

water.> 60'C

(> 140'F)

(3.3.1-46)

Steel piping, piping Loss of material Closed-Cycle No Closed-Cycle Consistent with

components, piping due to general, Cooling Water Cooling Water GALL Report

elements, tanks- pitting, and System Systemr(B2.1.10)

and heatexchanrger crevice corrosion,

components

exposed to closed

cycle cooling water

(3.3.1-47)

Steel piping, piping Loss of material. Closed7Cycle No Closed-Cycle Consistent with

components, piping due to general, . Cooling Water Cooling Water GALL Report

elements,:tanks,: pitting, crevice, System System (B2.1.10)

and heat exchanger and galvanic

components corrosion

exposed to.closed

cycle cooling water (3.3.1-48) .. __ __ __ __ _ . ,. .

Stainless steel; steel Loss of material Closed-Cycle No Not applicable Not applicable.

with stainless steel due to MIC Cooling Water to PWRs

cladding heati System

exchanger.y

components

exposed to closed

cycle cooling water

(3.3.1-49_)

Stainless steel. . Loss of material Closed-Cycle No Closed-Cycle Consistent with

piping, piping due to pitting Cooling Water Cooling Water GALL Report

components, and and crevice System System (B2,1.10)

piping elements * corrosion

exposed to0closed

cycle cooling water

(3.3.1-50) . _

3-253
Component Group Aging Effect• AMP in GALL Further AMP in LRA, sItaff

(GALL.Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.)-. . . in GALL Amendments

______________ . ~~~Report _ _ _ _ _ _ _ _ _ _ _ _

Copper alloy piping, Loss of material Closed-Cycle No Closed-Cycle Consistent with

piping components, due to pitting, Cooling Water Cooling•Water GALL Report

piping elements,. . crevice, and System System (B2.1.10)

and heat exchanger galvanic

components corrosion

exposed to closed.

cycle cooling water:

(3.3.1-51)

Steel; stainless Reduction of Closed-Cycle No Closed-Cycle Consistent with

steel, and copper heat transfer due Cooling Water CoolingWater GALL Report

alloy heat to fouling System System (B2.1.10)

exchanger.tubes

exposed to closed

cycle cooling water

(3.3.1-52) : _ . _

Steel compressed Loss of material Compressed Air No Inspections of Consistent with

air. system piping, due to general. Monitoring Intemal Surfaces In GALL Report

pipingcormponents, and pitting Miscellaneous (See SER

and piping elements corrosion Piping and Ducting Section 3.3.2.1.

exposed to Components 3)

condensation 1(B2.1.22), or

(intemal) 10 CFR Part 50,

(3.3.1-53) Appendix J

(B2.1.30)

Stainless steel Loss of material Compressed Air No Not applicable Not applicable

compressed air * due to pitting Monitoring to WCGS

system piping, and crevice (See SER

piping components, corrosion Section 3.3.2.1.

and piping elements 1)

exposed to intemal

condensation

(3.3.1-54).

Steel ducting Loss of material External Surfaces No External Surfaces Consistent with

closure bolting due to general Monitoring Monitoring (B2.1.20) GALL Report

exposed to air - corrosion

indoor uncontrolled

(external)

(3.3.1-55)

Steel HVAC ducting Loss of. material External Surfaces No External Surfaces Consistent with

and components due to general Monitoring Monitoring (B2.1.20) GALL Report

external surfaces : corrosion

exposed to air -

indoor uncontrolled

(external)

(3.3.1-56)

3-254
Component Group 'Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) J n GALL, Amendments

__________ __ ______ ____ ____ ________ ,Report-",_ __ _ _ __ _ _ _

Steel piping and Loss of material External Surfaces No External Surfaces Consistent with

components due to general Monitoring Monitoring (B2.1.20) GALL Report

external surfaces corrosion

exposed to air -

indoor uncontrolled

(external)

(3.3.1-57) _ . . .

Steel.external Loss of material External Surfaces No External Surfaces Consistent with

surfaces exposed to due to general Monitoring ,Monitoring.(B2.1.20) GALL Report

air - indoor " corrosion . and Inspection of

uncontrolled Overhead Heavy

(external),, air - and Light Load

outdoor (external), (Related to

and condensation. Refueling) Handling

(external): Systems. (B2. 1.11)

(3.3.1-58)

Steel heat Loss of material. External Surfaces No External Surfaces Consistent with

exchanger due to general, Monitoring Monitoring (B2.1.20) GALL Report

components pitting, and

exposed to air - crevice corrosion.

indoor uncontrolled

(external) or air:

-outdoor (external)

(3.3.1-59) ,.

Steel piping, piping Loss of material External Surfaces. No External Surfaces Consistent with

components, and due to general, Monitoring: Monitoring (B2.1.20) GALL Report

piping elements.. pitting, and

exposed to air -. crevice corrosion

outdoor -(external).

(3.3.1-60)

Elastomer fire Increased Fire Protection No . Fire Protection Consistent with

barrier penetration, hardness, (B2.1.12) GALL Report

seals exposed to shrinkage and

air - outdoor or loss of strength

air- indoor due to

uncontrolled weathering

(3.3.1-61)

Aluminum piping, Loss of material Fire Protection No. Not. applicable Not applicable

piping components, due to oitting. to WCGS

and piping elements and crevice (See SER

exposed to raw, corrosion Section 3.3.2.1.

water . 1)

(3.3..1-62).

Steel fire rated Loss of material Fire Protection No Fire Protection Consistent with

doors exposed to air due to wear (B2.1.12) GALL Report

- outdoor or .

air - indoor

uncontrolled

(3.3.1-63) • __ _

3-255
,Component Group. Aging Effectl AMP in GALL- - Further ":AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation •Supplements, or Evaluation

Item No.)~ in GALL Amendments

______________ ~~~Report:' _ _ _ __ _ _ _ __ _ _ _

Steel. piping, piping Loss of material Fire Protection and No Fire Protection Consistent with

components, and due to general, Fuel Oil Chemistry (B2.1.12) and Fuel GALL Report

piping elements pitting, and Oil Chemistry

exposed to fuel oil crevice corrosion (B2.1.14)

(3.3.1-64)

Reinforced concrete Concrete Fire Protection and No Fire Protection Consistent with

structural~fire cracking and Structures (B2.1.12) and GALL Report

barriers - walls, spalling due to Monitoring Structures

ceilings and floors aggressive Program Monitoring Program

exposed to air - chemical attack, (B2.1.32)

indoor uncontrolled and reaction with

(3.3.1-65) aggregates

Reinforced concrete Concrete Fire Protection and No Fire Protection Consistent with

structural fire cracking and Structures (B2.1.12) and GALL Report

barriers - walls, spalling due to Monitoring Structures

ceilings and floors' freeze thaw, Program Monitoring Program

exposed to air -. aggressive 1(B2.1.32)

outdoor chemical attack,

(3.3.1-66). and reaction with

aggregates

Reinforced concrete Loss of material Fire Protection and No Fire Protection Consistent with

structural fire due to corrosion Structures ((B2.1.12) and GALL Report

barriers - walls, . of embedded Monitoring Structures

ceilings and floors, steel Program Monitoring Program

exposed to air- (B2.1.32)

outdoor or air -

indoor uncontrolled

(3.3.1-67)

Steel piping, piping Loss of material Fire Water System No Fire Water System Consistent with

components, and' due to general, (B2.1.13) and GALL Report

piping elements.. pitting, creVice, Inspection of (See SER

exposed to raw and MIC, and Internal Surfaces in Section 3.3.2.1.

water fouling Miscellaneous 4)

(3.3.1-68)- Piping and Ducting

Components

•_ (B2.1.22)

Stainless steel. Loss of material Fire Water System No Fire Water System Consistent with

piping, piping due to pitting (B2.1.13) and GALL Report

components, and. and crevice Inspection of (See SER

piping elements corrosion, and Internal Surfaces in Section 3.3.2.1.

exposed to raw fouling Miscellaneous 4)

water Piping and Ducting

(3.3.1-69) Components

_(B211.22)

3-256
-Component Group 'Aging Effect[ AMP in GALL - i Further AMP In LRA, ....... Staff

,(GALL Report Mechanism Report !Evaluation Supplements, or Evaluation

Item No.) : - in GALL Amendments:

______ _____ ______ _____ ______ _____ Report _ _ _ _ _ _ _

Copper alloy piping, Loss of material Fire Water System No Fire Water System Consistent with piping components, due to pitting, (B2.1.13) and GALL Report

and piping elements crevice, and Inspection of (See SER

exposed to raw MIC, and fouling Internal Surfaces in Section 3.3.2.1.

water Miscellaneous 4)

(3.3.1-70) Piping and Ducting

Components __ _ _ _ __ _ _ _ _ __ _ _ _ _ _ _ _ _ (B2.1 .22) _ _ _ _ _

Steel piping, piping Loss of material Inspection of No Inspection of Consistent with

components, and due to general, Internal Surfaces in InternalSurfaces in GALL Report

piping elements,, pitting, and Miscellaneous Miscellaneous

exposed to moist air crevice-corrosion Piping and Ducting Piping 'and Ducting. or condensation Components Components

(internal) . (B2.1.22)

(3.3.1-71)

Steel HVAC ducting Loss of material Inspection of No Inspection of Consistent with

and components due to general,. Internal Surfaces in Internal Surfaces in GALL Report

internal surfaces. pitting, crevice, Miscellaneous.. Miscellaneous

exposed to and (for drip Piping and Ducting Piping and Ducting

condensation pans and drain. Components Components

(internal) lines) MIC (B2.1.22)

(3.3.1-72)

Steel crane Loss of material Inspection of No Inspection of Consistent with

structural girders in due to general Overhead Heavy Overhead Heavy GALL Report

load handling, corrosion Load and Light Load and Light Load

systemrexposed to Load (Related to (Related to

air 7 indoor Refueling) Refueling) Handling

uncontrolled Handling Systems Systems(B2.1.11)

(extemal):

(3.3.1-73) .__

Steel cranes rails Loss of material Inspection of No Inspection of Consistent with

exposed to air - due to wear Overhead Heavy Overhead Heavy - GALL Report

indoor uncontrolled Load and Light Load and Light Load

(external) . Load (Related to (Related to

(3.3.1-74) Refueling) Refueling) Handling

Handling Systems Systems (B2.1.11)

Elastomer seals and Hardening and Open-Cycle No Not applicable Not applicable

components loss of strength Cooling Water to WCGS

exposed to raw due to elastomer System (See SER

water . degradation; loss Section 3.3.2.1.

(3.3.1-75) of material due 1)

to erosion

3-257
Component Group, Aging Effect/ AMP in GALL Further :AMP in LRA, staff

(GALL Report Mechanism Report •!Evaluation' Supplements, or Evaluation

Itemn No.) .in - GALL 'Amendments

___________ __________ __________ Report _ __ _ _ _ _ _ _ _

Steel piping, piping Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

components, and due to general, Cooling Water Water System GALL Report

piping elements pitting, crevice, System (B2.1 .9) and (See SER

(without lining/ andMIC, fouling, Inspection of Section 3.3.2.1.

coating. or with and Internal Surfaces in 5)

degraded lining/coating Miscellaneous

lining/coating) degradation. -Piping and Ducting

exposed to raw. Components

water (B2.1.22)

(3.3.1-76)

Steel heat Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

exchanger due to general, Cooling Water Water System GALL:Report

components pitting, crevice, System (B2.1.9)

exposed to raw galvanic, and

water MIC, and fouling

(3.3.1-77)

Stainless steel,. Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

nickel alloy, and due to pitting Cooling Water Water System GALL Report

copper alloypiping; and crevice System (B2.1.9)

piping components, corrosion

and piping elements.

exposed to raw

water

(3.3.1-78)

Stainless steel Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

piping, piping due to pitting Cooling Water Water System GALL Report

components, and and crevice System (B2.1.9) and (See SER

piping elements- corrosion, and Inspection of Section 3.3.2.1.

exposed to raw fouling "Internal Surfaces in 6)

water Miscellaneous

(3.3.1-79) Piping and Ducting

Components

__(B2.1 .22)

Stainless stee! and Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

copper alloy piping, due to pitting, Cooling Water Water System GALL Report

piping components, crevice, and MIC System (B2.1.9)

and piping elements

exposed to raw.

water,

(3.3.1-80) ....... :

Copper alloy piping, Loss of material Open-Cycle No Not applicable Not applicable

piping components, due to pitting, Cooling Water to WCGS

I and piping crevice, and System (See SER

elements, exposed MIC, and fouling Section 3.3.2.1.

to raw water .1))

(3.3.1ý81)

3-258
-Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

<Item:No.) inGALL Amnendments

Copper alloy heat Loss of material Open-Cycle No Open-Cycle Cooling Consistent with

exchanger due to pitting, Cooling Water Water System GALL Report

components crevice, System (B2.1.9)

exposed to raw galvanic, and

water MIC, and fouling

(3.3.1-82) . .

Stainless steel and Reduction of Open-Cycle No Open-Cycle Cooling Consistent with

copper alloy heat heat transfer due Cooling Water Water System GALL Report

exchanger tubes to fouling System (B2.1.9)

exposed to raw

water

(3.3.1-83)

Copper alloy Loss of material Selective Leaching No Selective Leaching Consistent with

>1 15% Zn piping, due to selective of Materials . of. Materials GALL Report

piping components, leaching (B2.1.17)

piping elements,

and heat exchanger

components

exposed to raw

water, treated water,

or closed cycle

cooling water.

(3.3.1-84) .

Gray cast iron Loss of material Selective Leaching No Selective Leaching Consistent with

piping, piping due to selective of Materials . of Materials GALL Report

components, and leaching (B2.1 .17)

Piping elements

exposed to soil, raw

water, treated water,

or closed-cycle

cooling water

(3.3.1;85) "_ _ _

Structural steel (new Loss of material Structures No Structures Consistent with

fuel storage rack, due to general, Monitoring Monitoring Program GALL Report

assembly) exposed pitting, and Program (B2.1.32)

to air - indoor crevice corrosion

uncontrolled

(external) .

(3.3.1-86) ' _ _ _ i

Boraflex spent'fuel Reduction of Boraflex Monitoring No Not applicable Not applicable

storage racks neutron-absorbin to WCGS

neutron-absorbing g capacity due to (See SER

sheets exposed to boraflex Section 3.3.2.1.

treated borated degradation 1)

water

(3.3.1-87)

3-259
Component Group Aging Effect/ AMP in GALL Further AMP in LRA,, Staff

(GALL Report Mechanism Report' Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

______________ ____________::!i;: : :-Report: __" __.___ __ ___ ___ __

Aluminum and Loss of material Boric Acid No Not applicable Not applicable

copper alloy due to boric acid Corrosion toWCOGS

> 15% Zn piping, corrosion (See SER

piping components, Section 3.3.2.1.

and piping elements 1)

exposed to airwith

borated water

leakage

(3.3.1-88)

Steel bolting and Loss of material Boric Acid No Not applicable Not applicable

external surfaces due to boric acid Corrosion to WCGS

exposed to air with corrosion . (See SER

borated water Section 3.3.2.1.

leakage . 1)

(3.3.1-89)

Stainless steel and Cracking due to Water Chemistry No Water Chemistry Consistent with

steel with.stainless SCC (B2.1.2) GALL-Report

steel cladding

piping,. piping

components, piping

elements, tanks,

and fuel storage

racks exposed to.

treated borated

water> 60'C..

(>. 140OF)

(3.3.1-90)

Stainless steel and Loss of material Water Chemistry No Inspection of Consistent with

steel with stainless due to pitting Internal Surfaces in GALL Report

steel cladding and crevice Miscellaneous (See SER

piping, piping corrosion Piping and Ducting Section 3.3.2.1.

components, and Components 7)

piping elements (B2.1.22)

exposed to treated

borated water

(3.3.1-91)

* Galvanized steel None (N/A) None (N/A) No (N/A) None (N/A) Consistent with

piping, piping GALL Report

components, and

piping elements

exposed to air -

indoor uncontrolled

(3.3.1-92) _

3-260
,Component Group : Aging Effect/ AMP in GALL Further AMP in LRA, - Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

R hem No.) in GALL • Amendments

- _______ ________ ~Report _ _ _ _ _ _ _ _ _

Glass piping None None No None Consistent with

elements exposed GALL Report

to air, air -. indoor:

uncontrolled. (external), fuel oil,"

lubricating oil, raw

water, treated water,

and treated borated

water

(3.3.1-93) .. ..

Stainless steel ,.and None None No None Consistent with

nickel alloy piping, GALL Report

piping components,

and piping elements

exposed to air.

indoor uncontrolled

(extemai)..

(3.3.1-94) ._ _ __..

Steel and aluminum None None No None Consistent with

piping, piping_ GALL Report

components, and

piping-elements

exposed to0air--.

indoor controlled

(external) ..:

(3.3.1-95) . " _ _._ __.

Steel andstainless None -None No None Consistent with

steel piping, piping GALL Report.

components, and

piping elements in

concrete

(3.3.1-96)

Steel, stainless None None No None Consistent with

steel, aluminum,; GALL Report

apnd copper alloy

piping, piping

components, and

piping elements

exposed to:gas

(3.3.1-97) . _ _...

Steel, staIinless . None None No None Consistent with

steel, and copper GALL Report

alloy piping, piping

components, and

piping elements.

exposed to dried. air (3.3.1-9.8)

3-261
Component Group Aging Effectl AMP In GALL Further AMP in LRA, " .Staff

(GALL Report 'Mechanism Report. Evaluation Supplements, or Evaluation

Item No.), in GALL Amendments

____ ____ ____ ___:____ _._ _.Report

Stainless steel and None None No None Consistent with

copper alloy GALL Report

< 15% Zn piping,

piping components,

and piping elements

exposed to air with

boratedc water

leakage

1(3.3.1-799)

The staff's review of the auxiliary systems component groups followed one of several

approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for

components that the applicant indicated are consistent with the GALL Report and require no

further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed .AMR

results for components that the applicant indicated are consistent with.the GALL Report and for

which further ýevaluation is recommended. A third approach, documented in SER

Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the auxiliary systems components is documented in SER

Section 3.0.3.'

3.3.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the auxiliary systems components:

* ASME Code Section Xl Inservice Inspection, Subsections IWB, IWC, and IWD

* "Water Chemistry

* Bolting Integrity

* Open-Cycle Cooling Water System

* Closed-Cycle Cooling Water System

, Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling

Systems

* Fire Protection

* Fire Water System

* Fuel Oil Chemistry

* One-Time Inspection

* Selective Leaching of Materials

" Buried Piping and Tanks Inspection

* One-Time Inspection of ASME Code Class 1 Small-Bore Piping

3-262
" External Surfaces Monitoring

* Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

* Lubricating Oil Analysis

* 10 CFR 50, Appendix J

* Structures Monitoring

LRA Tables 3.3.2-1 through 3.3.2-21 summarize AMRs for the auxiliary systems components

and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

3-263
whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but Credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs. The staff's evaluation follows.

3.3.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.3.1, the staff identified items 40, 41, 42, 44, 54, 62, 75, 81, 87, 88, and 89 as

not applicable because the component, material, and environment combination does not exist

at WCGS. For each of these line items, the staff reviewed the LRA and the applicant's

supporting documents, and confirmed the applicant's claim that the component, material, and

environment combination does not exist at WCGS. On the basis that WCGS does not have

these combinations, the staff finds that these AMRs are not applicable.

3.3.2.1.2 Cracking Due to Stress Corrosion Cracking

In LRA Table 3.3.1, item 46, the applicant states that cracking of stainless steel and stainless

clad steel piping, piping components, piping elements, and heat exchanger components

exposed to closed cycle cooling water with a temperature greater than 140 OF is managed by

the Closed-Cycle Cooling Water System Program.

During the audit, the staff determined that the inspection aspect of the program is implemented

using a plant procedure. However, it was not clear how the use of this procedure would manage

cracking. The staff requested that the applicant clarify how this procedure would detect

cracking.

In its response, the applicant stated that the procedure will be enhanced to define cracking,

provide additional guidance for detection of cracking, and include specific acceptance criteria.

relating to "as-found" cracking.

By letter dated May 25, 2007, the applicant amended the LRA to include a commitment

(Commitment No. 32) to enhance its plant procedure.

On the basis that the applicant committed to define cracking and provided guidance for

acceptance criteria in implementing the procedure, the staff finds the response acceptable.

3.3.2.1.3 Loss of Material due to General and Pitting Corrosion

In LRA Table 3.3.1, item 53, the applicant states that loss of material in steel piping, piping

components, and piping elements exposed to an internal environment of condensation is

3-264
managed by the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting

Components Program, or the 10 CFR Part 50, Appendix J Program, as appropriate.

During the audit, the staff noted that for the AMR results line that references LRA Table 3.3.1,

item 53, the applicant applied note E.

The staff reviewed LRA Table 3.3.2-6 for the AMR results lines that reference note E and

determines that the component type, material, environment, and aging effect are consistent

with the GALL Report. The staff noted that where the GALL Report recommends AMP XI.M24, "Compressed Air Monitoring Program," the applicant proposed using the 10 CFR Part 50,

Appendix J Program for compressed air piping penetrating the containment and the Inspections

of Internal Surfaces In Miscellaneous Piping and Ducting Components Program for other

compressed air piping.

The AMP recommended by the GALL Report states that.testing of air quality is performed as

part of preventive actions to mitigate degradation by keeping contaminants within specified

limits. The staff requested that the applicant clarify if the Inspections of Internal Surfaces In

Miscellaneous Piping and Ducting Components Program will perform air quality checks.

In its response, the applicant stated that the wetted gas environment listed in LRA Table 3.3.2-6

for the compressed air system applies to two sections of piping and components. The first

section has an internal environment of dry nitrogen vent piping that discharges to atmosphere.

A wetted gas environment was conservatively chosen since there could be moisture introduced

from the outside. Periodic internal visual inspection of the piping and components provides a

positive means for detection of aging effects.

The staff reviewed the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting

Components Program, which includes in its scope the compressed air system piping and

components, and determines that it performs periodic visual inspection of internal surfaces for

age related degradation during surveillance activities. On the basis that periodic visual

inspections are performed, the staff finds the applicant's use of the Inspections of Internal

Surfaces In Miscellaneous Piping and Ducting Components Program acceptable.

In its response, the applicant also stated that the second section is a portion of service air

piping that is safety-related for containment isolation, and the attached piping is

nonsafety-related for structural integrity purposes. The applicant credited the 10 CFR Part 50,

Appendix J Program for this piping.

The staff noted that the 10 CFR Part 50, Appendix J Program performs seat leakage testing of

containment isolation valves and visual inspection of external surfaces to ensure no leakage

through containment. The staff requested that the applicant explain how loss of material on the

inside surface of piping and valves will be detected by the 10 CFR Part 50, Appendix J

Program.

By letter dated August 31, 2007, the applicant amended the LRA to add the Inspections of

Internal Surfaces In Miscellaneous Piping and Ducting Components Program to manage loss of

material in the service air containment penetration piping internal surfaces. The applicant

amended LRA Table 3.1.1, item 53, to state that the Inspections of Internal Surfaces In

Miscellaneous Piping and Ducting Components and/or the 10 CFR Part 50, Appendix J

3-265
Program is credited, as appropriate, to manage aging effects for the piping and components

that are within the scope of license renewal.

On the basis that periodic visual inspections are performed, the staff finds the applicant's use of

the Internal Surfaces In Miscellaneous Piping and Ducting Components Program, in addition to

the 10 CFR Part 50, Appendix J Program, acceptable.

On the basis of its review of AMR result lines and the recommendations in the GALL Report,

the staff finds that the applicant addressed the aging effects management adequately, as

recommended by the GALL Report.

3.3.2.1.4 Loss of Material due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion, and Fouling; Loss of Material due to Pitting and Crevice Corrosion, and Fouling; and

Loss of Material due to Pitting, Crevice, and Micro Biologically Influenced Corrosion, and

Fouling

In LRA Table 3.3.1, items 68, 69, and 70, the applicant states that loss of material of steel and

copper alloy piping, piping components, and piping elements exposed to raw water environment

is managed by the Fire Water System Program in conjunction with the Inspections of Internal

Surfaces In Miscellaneous Piping and Ducting Components Program.

During the audit, the staff noted that the applicant applied note E to these items.

LRA Table 3.3.1, items 68, 69, and 70, are referenced in LRA Table 3.3.2-14. The staff

reviewed the AMR results lines that reference note E and determines that the component type,

material, environment, and aging effect are consistent with the GALL Report. However, the staff

noted that where the GALL Report recommends AMP XI.M27, "Fire Water System," the

applicant proposed using the Fire Water System and the Inspections of Internal Surfaces In

Miscellaneous Piping and Ducting Components Programs. The staff requested that the

applicant explain how these two programs will work with each other.

In its response, the applicant stated that the Fire Water System Program is used to conduct an

air or water flow test through spray or sprinkle nozzle to verify that there is no fouling, and for

testing a representative sample of sprinkler heads. However, the Inspections of Internal

Surfaces In Miscellaneous Piping and Ducting Components Program is used for visual

inspections to evaluate for wall thickness as recommended by the GALL Report.

The staff reviewed the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting

Components Program and determines that this program detects wall thinning by identifying

corrosion, surface or finish discontinuities, or a lack of symmetry of the component dimensions.

If degradation is unacceptable, deficiencies would be resolved in the plant's corrective action

program.

On the basis that periodic visual inspections are performed to evaluate wall thickness as

recommended by the GALL Report, the staff finds that the use of the Fire Water System and

the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting Components

Programs is acceptable to manage these aging effects.

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On the basis of its review of AMR result lines and the recommendations in the GALL Report,

the staff finds that the applicant addressed the aging effects management adequately, as

recommended by the GALL Report.

3.3.2.1.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion, Fouling, and Lining/Coating Degradation

In LRA Table 3.3.1, item 76, the applicant states that loss of material of steel components

exposed to a raw water environment in the secondary liquid waste and oily waste systems is

managed by the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting

Components Program.

During the audit, the staff noted that the applicant applied note E to the AMR result line that

reference item 76.

LRA Table 3.3.1, item 76, is referenced in LRA Tables 3.3.2-18 and 3.3.2-21. The staff

reviewed the AMR result lines referring note E and determines that the component type,

material, environment, and aging effect are consistent with the GALL Report. However, the staff

noted that where the GALL Report recommends AMP XI.M20, "Open-Cycle Cooling Water

System," the applicant proposed the Inspections of Internal Surfaces In Miscellaneous Piping

and Ducting Components Program. The staff noted that the GALL Report recommends

AMP XI.M20; however, the staff noted that the environment for these components is potentially

contaminated raw water that is not within the scope of the Open-Cycle Cooling Water System

Program. The Internal Surfaces In Miscellaneous Piping and Ducting Components Program

uses periodic visual inspections to inspect representative samples of nonsafety-related

components affecting safety-related systems, including the AMR result lines referencing

item 76. On the basis that periodic visual inspections will be performed, the staff finds that the

applicant's use of the Internal Surfaces In Miscellaneous Piping and Ducting Components

Program is acceptable.

Based on its review of AMR result lines and recommendations in the GALL Report, the staff

finds that the applicant addressed the aging effects management adequately, as recommended

by the GALL Report.

3.3.2.1.6 Loss of Material due to Pitting and Crevice Corrosion and Fouling

In LRA Table 3.3.1, item 79, the applicant states that loss of material of stainless steel

components exposed to a raw water environment in the secondary liquid waste, yard drainage,

chemical and detergent waste, and oily waste systems is managed by the Inspections of

Internal Surfaces In Miscellaneous Piping and Ducting Components Program.

During the audit, the staff noted that the applicant applied note E to the AMR result line that

reference item 79.

LRA Table 3.3.1, item 79, is referenced in LRA Tables 3.3.2-18 and 3.3.2-21. The staff

reviewed the AMR result lines that reference note E and determines that the component type,

material, environment, and aging effect are consistent with the GALL Report. However, the staff

noted that where the GALL Report recommends AMP XI.M20, "Open-Cycle Cooling Water

System," the applicant proposed the Inspections of Internal Surfaces In Miscellaneous Piping

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and Ducting Components Program. The GALL Report recommends AMP XI.M20; however, the

staff noted that the environment for these components is potentially contaminated raw water

that is not within the scope of the Open-Cycle Cooling Water System Program. The Internal

Surfaces In Miscellaneous Piping and Ducting Components Program uses periodic visual

inspections to inspect representative samples of nonsafety-related components affecting

safety-related systems, including the AMR result lines referencing item 79. On the basis that

periodic visual inspections will be performed, the staff finds that the applicant's use of the

Internal Surfaces In Miscellaneous Piping and Ducting Components Program is acceptable.

On the basis of its review of AMR result lines and the recommendations in the GALL Report,

the staff finds that the applicant addressed the aging effects management adequately, as

recommended by the GALL Report.

3.3.2.1.7 Loss of Material due to Pitting and Crevice Corrosion

In LRA Table 3.3.1, item 91, the applicant states that loss of material of stainless steel and steel

with stainless steel cladding components exposed to a treated borated water environment in the

floor and equipment drains system is managed by the Inspections of Internal Surfaces In

Miscellaneous Piping and Ducting Components Program.

During the audit, the staff noted that the applicant applied note E to the AMR result line that

reference item 91.

LRA Table 3.3.1, item 91, is referenced in LRA Table 3.3.2-17. The staff reviewed the AMR

result lines that reference note E and determines that the component type, material,

environment, and aging effect are consistent with the GALL Report. However, the staff noted

that where the GALL Report recommends AMP XI.M2, "Water Chemistry," the applicant

proposed the Inspections of Internal Surfaces In Miscellaneous Piping and Ducting

Components Program. The GALL Report recommends AMP XI.M2; however, the staff noted

that the environment for these components is potentially contaminated raw water that is not

within the scope of the Water Chemistry Program. The Internal Surfaces In Miscellaneous

Piping and Ducting Components Program, visually inspects representative samples of

safety-related systems on a periodic basis, including the AMR result lines that reference

item 91. On the basis that periodic visual inspections will be performed, the staff finds the

applicant's use of the Internal Surfaces In Miscellaneous Piping and Ducting Components

Program acceptable.

On the basis of its review of the AMR result lines and the recommendations in the GALL

Report, the staff finds that the applicant addressed the aging effects management adequately,

as recommended by the GALL Report.

3.3.2.1.8 Loss of Material due to General, Pitting, Crevice, and Galvanic Corrosion; Loss of

Material due to Pitting and Crevice Corrosion; and Reduction of Heat Transfer due to Fouling

In LRA Table 3.3.2-2, the applicant credited the Closed-Cycle Cooling Water System Program

to manage loss of material and reduction of heat transfer in steel piping and valves, and

stainless steel thermowells and heat exchangers. The staff reviewed the Closed-Cycle Cooling

Water System Program basis documents to determine if the fuel pool cooling and cleanup

system (FPCCS) was included within the scope of this program. The staff determined that the

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FPCCS was not included within the scope of the Closed-Cycle Cooling Water System Program.

The staff requested that the applicant justify why the system was not included.

In its response, the applicant added the FPCCS to the Closed-Cycle Cooling Water System

Program by using a project change tracking form. The staff reviewed this form and finds the

response acceptable.

In LRA Table 3.3.2-7, the applicant credited the Closed-Cycle Cooling Water System Program

to manage loss of material and reduction of heat transfer aging effects in steel heat exchanger,

piping pump, tank, and valves, and stainless steel flow elements, heat exchanger, instrument

bellows, piping, thermowells tubing, and valves. The staff reviewed the Closed-Cycle Cooling

Water System Program basis documents to determine if the CVCS was included within the

scope of this program. The staff determined that the CVCS was not included in the

Closed-Cycle Cooling Water System Program. The staff requested that the applicant justify why

the system was not included.

In its response, the applicant added the CVCS within the scope of the Closed-Cycle Cooling

Water System Program by using a project change tracking form. The staff reviewed this form

and finds the response acceptable.

On the basis of its review of the AMR result lines and the recommendations in the GALL

Report, the staff finds that the applicant addressed the aging effects management adequately,

as recommended by the GALL Report.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the auxiliary systems components and provides information concerning

how it will manage the following aging effects and related QA:

* cumulative fatigue damage

* reduction of heat transfer due to fouling

* cracking due to SCC

* cracking due to SCC and cyclic loading

* hardening and loss of strength due to elastomer degradation

* reduction of neutron-absorbing capacity and loss of material due to general corrosion

* loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and MIC

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* loss of material due to general, pitting, crevice, MIC and fouling

* loss of material due to pitting and crevice corrosion

* loss of material due to pitting, crevice, and galvanic corrosion

" loss of material due to pitting, crevice, and MIC

* loss of material due to wear

* loss of material due to cladding breach

" QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues that were further evaluated. In addition, the staff reviewed the applicant's

further evaluations against the criteria contained in SRP-LR Section 3.3.2.2. The staff's review

of the applicant's further evaluation follows.

3.3.2.2.1 Cumulative Fatigue Damage

LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.3.2.2.2 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.

LRA Section 3.3.2.2.2 addresses reduction of heat transfer due to fouling. The applicant stated

that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.3.2.2.2 states that reduction of heat transfer due to fouling may occur in

stainless steel heat exchanger tubes exposed to treated water. The existing program controls

water chemistry to manage reduction of heat transfer due to fouling. However, control of water

chemistry may be inadequate; therefore, the GALL Report recommends that the effectiveness

of water chemistry control programs should be verified to ensure that reduction of heat transfer

due to fouling does not occur. A one-time inspection is an acceptable method to ensure that

reduction of heat transfer does not occur and that component intended functions will be

maintained during the period of extended operation.

The staff noted that this line item is applicable to BWR spent fuel pool heat exchangers and;

therefore, is not applicable because WCGS is a PWR. On this basis, the staff finds that this

aging effect is not applicable to this component type.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.3.2.2.2

criteria.

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3.3.2.2.3 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.3.2.2.3 against the following criteria in SRP-LR

Section 3.3.2.2.3:

(1) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel piping and

components of BWR standby liquid control system exposed to sodium pentaborate. The

applicant stated that this aging effect is not applicable because WCGS is a PWR.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in the stainless

steel piping, piping components, and piping elements of the BWR standby liquid control

system that are exposed to sodium pentaborate solution greater than 60 0C (140 OF).

The staff noted that this line item is applicable to BWR standby liquid control system

piping and components and; therefore, is not applicable because WCGS is a PWR. On

this basis, the staff finds that this aging effect is not applicable to this component type.

(2) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel heat exchanger

components exposed to treated water. The applicant stated that this aging effect is not

applicable because WCGS is a PWR.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel

and stainless clad steel heat exchanger components exposed to treated water greater

than 60 °C (140 OF). The GALL Report recommends further evaluation of a

plant-specific AMP to ensure that these aging effects are adequately managed.

The staff noted that this line item applies to BWR reactor water cleanup system heat

exchangers and; therefore, is not applicable. WCGS is a PWR. On this basis, the staff

finds that this aging effect is not applicable to this component type.

(3) LRA Section 3.3.2.2.3 addresses cracking due to SCC in stainless steel diesel engine

exhaust piping and components exposed to diesel exhaust. The applicant stated that the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program will manage cracking due to SCC in stainless steel internal surfaces exposed

to diesel exhaust.

SRP-LR Section 3.3.2.2.3 states that cracking due to SCC may occur in stainless steel

diesel engine exhaust piping, piping components, and piping elements exposed to diesel

exhaust. The GALL Report recommends further evaluation of a plant-specific AMP to

ensure that the aging effect is adequately managed.

The staff noted that the plant-specific AMP proposed by the applicant is the Inspection

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The

staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program and determines that the aging effect of cracking will be

adequately managed by using visual techniques to inspect representative samples of

diesel exhaust components. The staff's evaluation of the Inspection of Internal Surfaces

in Miscellaneous Piping and Ducting Components Program is documented in SER

Section 3.0.3.1.7. The staff finds that this program includes activities that are consistent

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with the recommendations in the GALL Report and that these activities are adequate to

manage cracking in stainless steel diesel engine exhaust piping, piping components,

and piping elements exposed to diesel exhaust.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.3.2.2.3 criteria. For those line items that apply to LRA Section 3.3.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR

Section 3.3.2.2.4:

(1) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel PWR non-regenerative heat exchanger components exposed to borated water.

The applicant stated that this aging effect is not applicable and other available GALL

Report line items were used.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in stainless steel PWR nonregenerative heat exchanger components exposed to treated

borated water greater than 60 °C (140 OF) in the CVCS. The existing AMP monitors and

controls primary water chemistry in PWRs to manage the aging effects of cracking due

to SCC. However, control of water chemistry does not preclude cracking due to SCC

and cyclic loading; therefore, the effectiveness of water chemistry control programs

should be verified to ensure that cracking does not occur. The GALL Report

recommends that a plant-specific AMP be evaluated to verify the absence of cracking

due to SCC and cyclic loading to ensure that these aging effects are adequately

managed. An acceptable verification program is to include temperature and radioactivity

monitoring of the shell side water and eddy current testing of tubes.

The staff noted that the GALL Report line item applicable to this section is item VII.E1 -9.

The staff requested that the applicant identify what other available GALL Report line

items were used.

In its response, the applicant stated that the GALL Report item VII.E1-5 was used and

was evaluated as equivalent. However, item VII.E1-5 is for regenerative heat

exchangers, not for non-regenerative heat exchangers as stated in this SRP-LR section.

The staff noted that the GALL Report recommends a different AMP verification for

item VII.E1-9 than for item VII.E1-5 and; therefore, cannot be considered equivalent.

The staff requested that the applicant justify how it considers the two line items to be

equivalent.

By letter dated August 31, 2007, the applicant amended this item in the LRA to state:

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Not applicable. The letdown, excess letdown, and seal water heat

exchangers are exposed to treated borated water greater than 140 F

(tube-side) and component cooling water shell side. The shell side is

managed by the Closed-Cycle Cooling Water System Program using

item number 3.3.1-46. The tube-side is managed by Water Chemistry

and One-Time Inspection Programs using item number 3.3.1-08. The

Closed-Cycle Cooling Water System Program (B2.2.10) includes eddy

current testing for heat exchanger testing for shell side components

exposed to component cooling water. Radiation monitors are installed in

each train of the component cooling water system and alarm when

abnormal radioactivity levels are detected. Heat exchanger outlet

temperatures are not typically monitored; this was noted as a program

exception to the Closed-Cycle Cooling Water System Program.

On the basis that the applicant is verifying the effectiveness of water chemistry by

means of eddy current testing and monitoring of radioactivity under a separate LRA

Table 3.3.1 line item, the staff finds the applicant's response acceptable. The staff

confirms that this line item is not applicable to WCGS. The staff's evaluation of the

Closed-Cycle Cooling Water System Program is documented in SER Section 3.0.3.2.9.

(2) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel PWR regenerative heat exchanger components exposed to borated water. The

applicant stated that the Water Chemistry and the One-Time Inspection Programs will

manage cracking due to SCC and cyclic loading for stainless steel heat exchangers

exposed to treated borated water. The one-time inspection will include selected

components at susceptible locations.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in stainless steel PWR regenerative heat exchanger components exposed to treated

borated water greater than 60 °C (140 OF). The existing AMP monitors and controls

primary water chemistry in PWRs to manage the aging effects of cracking due to SCC.

However, control of water chemistry does not preclude cracking due to SCC and cyclic

loading; therefore, the effectiveness of water chemistry control programs should be

verified to ensure that cracking does not occur. The GALL Report recommends that a

plant-specific AMP be evaluated to verify the absence of cracking due to SCC and cyclic

loading to ensure that these aging effects are adequately managed.

In LRA Table 3.3.1, item 8, the applicant does not credit the AMP recommended in the

GALL Report. The GALL Report recommends the Water Chemistry Program and a

plant-specific verification program. In LRA Table 3.3.1, item 8, the applicant only credits

a plant-specific program. The staff requested that the applicant clarify this

discrepancy/deviation.

By letter dated August 31, 2007, the applicant amended LRA Table 3.3.1, item 8, to

state:

Water Chemistry (B2.1.2) and plant-specific verification program. The

AMP is to be augmented by verifying the absence of cracking due to

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stress corrosion cracking and cyclic loading. A plant-specific aging

management program is to be evaluated.

The staff reviewed the Water Chemistry Program, which monitors chlorides, fluorides,

and dissolved oxygen to limit the contaminants, thus, minimizing the occurrences of

aging effects and maintaining the component's ability to perform its intended functions.

The applicant stated that the One-Time Inspection Program will verify the effectiveness

of the Water Chemistry Program. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Water Chemistry and the One-Time Inspection

Programs is documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The

staff finds that these programs include activities that are consistent with the

recommendations in the GALL Report, and are adequate to manage cracking due to

SCC and cyclic loading in stainless steel PWR regenerative heat exchanger

components exposed to treated borated water with a temperature greater than 140 OF.

(3) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in stainless

steel pump casings in the CVCS. The applicant stated that the Water Chemistry and the

One-Time Inspection Programs will manage cracking due to SCC and cyclic loading for

stainless steel pump casings exposed to treated borated water. The one-time inspection

will include selected components at susceptible locations.

SRP-LR Section 3.3.2.2.4 states that cracking due to SCC and cyclic loading may occur

in the stainless steel pump casing for the PWR high-pressure pumps in the CVCS. The

existing AMP monitors and controls primary water chemistry in PWRs to manage the

aging effects of cracking due to SCC. However, control of water chemistry does not

preclude cracking due to SCC and cyclic loading; therefore, the effectiveness of water

chemistry control programs should be verified to ensure that cracking does not occur.

The GALL Report recommends that a plant-specific AMP be evaluated to verify the

absence of cracking due to SCC and cyclic loading to ensure that these aging effects

are adequately managed.

In LRA Table 3.3.1, item 9, the applicant does not credit the AMP recommended in the

GALL Report. The GALL Report recommends the Water Chemistry Program and a

plant-specific verification program. In LRA Table 3.3.1, item 9, the applicant only credits

a plant-specific program. The staff requested that the applicant clarify this discrepancy.

By letter dated August 31, 2007, the applicant amended LRA Table 3.3.1, item 9, to

state:

Water Chemistry (B2.1.2) and plant-specific verification program.

The AMP is to be augmented by verifying the absence of cracking

due to stress corrosion cracking and cyclic loading. A

plant-specific aging management program is to be evaluated.

The staff reviewed the Water Chemistry Program, which monitors chlorides, fluorides,

and dissolved oxygen to limit the contaminants, thus, minimizing the occurrences of

aging effects and maintaining the component's ability to perform its intended functions.

The applicant stated that the One-Time Inspection Program will verify the effectiveness

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of the Water Chemistry Program. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Water Chemistry and the One-Time Inspection

Programs is documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The

staff finds that these programs include activities that are consistent with the

recommendations in the GALL Report, and are adequate to manage cracking due to

SCC and cyclic loading in stainless steel pump casing for the PWR high-pressure

pumps in the CVCS.

(4) LRA Section 3.3.2.2.4 addresses cracking due to SCC and cyclic loading in high

strength bolting exposed to steam or water leakage. The applicant stated that this aging

effect is not applicable because WCGS does not have high-strength steel closure

bolting exposed to air with steam or water leakage in the CVCS within the scope of

license renewal. Therefore, the applicable GALL Report line item was not used.

The staff noted that this item is applicable to high-strength steel closure bolting. On the

basis that WCGS does not have high-strength steel closure bolting exposed to air with

steam or water leakage in the CVCS within the scope of license renewal, the staff finds

that the use of this item is not applicable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.4 criteria. For those line items that apply to LRA Section 3.3.2.2.4, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR

Section 3.3.2.2.5:

(1) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer

degradation in elastomer seals of HVAC systems exposed to plant indoor air

(uncontrolled). The applicant stated that the External Surfaces Monitoring Program will

manage this aging effect in elastomer external surfaces exposed to plant indoor air

(uncontrolled) in locations where the ambient temperature cannot be shown to be less

than 95 °F. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program will manage the hardening and loss of strength from elastomer

degradation for elastomer internal surfaces exposed to ventilation atmosphere in

locations where the ambient temperature cannot be shown to be less than 95 OF. In

general, ambient temperature in HVAC equipment spaces is expected to be below

95 'F, in which thermal aging of elastomers is not considered significant.

SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer seals and components of heating and ventilation

systems exposed to air - indoor uncontrolled (internal/external). The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that these aging

effects are adequately managed.

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The staff noted that the plant-specific AMPs proposed by the applicant are the External

Surfaces Monitoring and the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Programs. The staff reviewed the External Surfaces Monitoring

Program and finds that it performs periodic visual inspections of external surfaces

during system engineer walkdowns. These walkdowns are performed at least every

refueling outage. The staff also reviewed the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program and finds that it performs

periodic visual inspections of internal surfaces during periodic maintenance, predictive

maintenance, surveillance testing, and corrective maintenance to detect aging effects

that could result in a loss of component intended function. The staff's evaluation of the

External Surfaces Monitoring and the Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components Programs is documented in SER Sections 3.0.3.1.5

and 3.0.3.1.7, respectively.

In LRA Table 3.3.1, item 11, the applicant credited an exception to the GALL Report for

duct flex connections in the control building HVAC system, where the temperature is

less than 95 OF.

By letter dated August 31, 2007, the applicant amended the LRA to remove this

exception from LRA Table 3.3.1, item 11.

GALL Report, item VII.F1 -7, specifies hardening and loss of strength as the aging

mechanism for item 11. However, the GALL Report also states that if the temperature

threshold is not exceeded, that elastomer thermal aging is insignificant. Therefore, on

this basis, the staff finds that the deletion of this exception is acceptable because it

makes the line consistent with the GALL Report. The staff requested that the applicant

identify where the flex connections were located.

In its response, the applicant stated that these flex connections are associated with the

Halon cylinder banks located in the auxiliary building, communications corridor and

control building. The applicant stated that the general thermal environment in the control

building is maintained below 95 OF and the general thermal environment in the auxiliary

building is less than 104 OF. Thus, the applicant stated that it must consider thermal

aging for Halon cylinder flexible hoses in the auxiliary building and communications

corridor because it cannot be shown that the equipment spaces are maintained below

95 OF.

The applicant credited the Fire Protection Program to manage the aging effect of

hardening and loss of strength for these flex hoses. By letter dated August 31, 2007, the

applicant amended LRA Table 3.3.1, Item 11, to credit the Fire Protection Program. LRA

Section 3.3.2.2.5.1 was amended to add the following paragraph.

The Fire Protection Program (B2.1.12) will manage the hardening and

loss of strength from elastomer degradation for Halon fire suppression

system flexible hoses not periodically replaced in locations where the

ambient temperature cannot be shown to be less than 95 OF.

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The staff noted that the Fire Protection Program will be enhanced to include visual

inspections of Halon tank flexible hoses for hardening or loss of strength. The staff's

evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that these programs include activities that are consistent with the

recommendations in the GALL Report, and are adequate to manage hardening and loss

of strength due to elastomer degradation in elastomer seals and components of heating

and ventilation systems exposed to an internal and external environment of uncontrolled

indoor air.

(2) LRA Section 3.3.2.2.5 addresses hardening and loss of strength due to elastomer

degradation in elastomer linings in spent FPCCSs. The applicant stated that this aging

effect is not applicable because WCGS does not have elastomer lined components

exposed to treated water or treated borated water in the FPCCS that are within the

scope of license renewal. Therefore, the applicable GALL Report line items were not

used.

SRP-LR Section 3.3.2.2.5 states that hardening and loss of strength due to elastomer

degradation may occur in elastomer linings of the filters, valves, and ion exchangers in

spent FPCCSs (BWR and PWR) exposed to treated water or treated borated water. The

GALL Report recommends that a plant-specific AMP be evaluated to determine and

assess the qualified life of the linings in the environment to ensure that these aging

effects are adequately managed.

The staff noted that this item is applicable to elastomer linings. On the basis that WCGS

does not have elastomer lined components exposed to treated water or treated borated

water in the FPCCS that are within the scope of license renewal, the staff finds that this

item is not applicable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.5 criteria. For those line items that apply to LRA Section 3.3.2.2.5, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General

Corrosion

The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.

LRA Section 3.3.2.2.6 addresses reduction of neutron-absorbing capacity and loss of material

due to general corrosion. The applicant stated that the original boraflex spent fuel pool racks

were replaced in 1999 with boral spent fuel pool racks. The WCGS Technical Specifications,

Section 4.3, require that the spent fuel storage racks be maintained for reactivity (k-effective) at

or below 0.95 if fully flooded with unborated water. This threshold includes an allowance for

uncertainties as described in USAR Section 9.1A. The applicant stated that the new racks are

designed, fabricated, and installed to ensure operation for a period of 60 years. Amendment

No. 120 incorporated this modification into the WCGS operating license. In regard to the boral

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spent fuel pool racks modification, WCGS responded to an RAI from the NRC stating that there

is no net loss of aluminum cladding during the passivation process in which aluminum slightly

corrodes before forming an impervious hydrated aluminum oxide film. The response also noted

that, since operational experience shows no degradation of neutron absorption capability for

boral exposed to spent fuel pool environments, no special corrosion measures are necessary.

The NRC SER dated March 22, 1999, agreed that the materials for the new racks were

compatible with the environment in the spent fuel pool, and that the racks would not undergo

material degradation which could affect their ability to safely store fuel.

SRP-LR Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of

material due to general corrosion may occur in the neutron-absorbing sheets of BWR and PWR

spent fuel storage racks exposed to treated water or treated borated water. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are

adequately managed.

The staff reviewed the SER dated March 22, 1999. Based on the design, fabrication, and

installation of the new racks, the staff finds that there are no aging effects that need aging

management for boral spent fuel racks in a borated water environment. The staff reviewed the

operating experience since the new racks were installed and found no issues related to age

related degradation of these new racks. Therefore, the staff finds this item acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.6 criteria.

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7:

(1) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in stainless steel piping and components in the RCP oil collection system

exposed to lubricating oil. The applicant stated that the Lubricating Oil Analysis and the

One-Time Inspection Programs will manage this aging effect in carbon steel (including

galvanized) and cast iron components exposed to lubricating oil. The one-time

inspection will include selected components at susceptible locations where contaminants

such as water could accumulate. For the RCP lubricating oil collection system, the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program will manage loss of material due to general, pitting, and crevice corrosion for

carbon steel components exposed to lubricating oil.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements, including

the tubing, valves, and tanks in the RCP oil collection system, exposed to lubricating oil

(as part of the fire protection system). The existing AMP periodically samples and

analyzes lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment not conducive to corrosion. However, control of lube oil

contaminants may not always be fully effective in precluding corrosion; therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion does

not occur. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of the lubricating oil program. A one-time inspection

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of selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation. In addition, corrosion may occur at locations in

the RCP oil collection tank where water from wash-downs may accumulate; therefore,

the effectiveness of the program should be verified to ensure that corrosion does not

occur. The GALL Report recommends further evaluation of programs to manage loss of

material due to general, pitting, and crevice corrosion, including determination of the

thickness of the lower portion of the tank. A one-time inspection is an acceptable

method to ensure that corrosion does not occur and that component intended functions

will be maintained during the period of extended operation.

The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The One-Time Inspection Program verifies the

effectiveness of the Lubricating Oil Analysis Program. The staff reviewed the One-Time

Inspection Program, which is a new program that, when implemented, will be consistent

with the GALL Report. The staff's evaluation of the Lubricating Oil Analysis and the

One-Time Inspection Programs is documented in SER Sections 3.0.3.2.16

and 3.0.3.1.3, respectively. The staff determines that these programs include activities

that are consistent with the recommendations in the GALL Report, and are adequate to

manage loss of material due to general, pitting, and crevice corrosion in steel piping,

piping components, and piping elements, including the tubing, valves, and tanks in the

RCP oil collection system, exposed to lubricating oil.

The staff noted that the RCP oil collection system environment is potentially

contaminated oil that is not managed by the Lubricating Oil Analysis Program. Instead,

the applicant proposed the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program to manage the aging effect of loss of material. The staff

reviewed the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program and finds that it performs periodic visual inspections of internal

surfaces during periodic maintenance, predictive maintenance, surveillance testing, and

corrective maintenance to detect aging effects that could result in a loss component

intended function. The staff's evaluation of the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program is documented in SER

Section 3.0.3.1.7. The staff finds that this program includes activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to general, pitting, and crevice corrosion in steel piping, piping

components, and piping elements, including the tubing, valves, and tanks in the RCP oil

collection system, exposed to potentially contaminated lubricating oil.

(2) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in steel piping and components in BWR reactor water cleanup and shutdown

cooling systems exposed to treated water. The applicant stated that this aging effect is

not applicable because WCGS is a PWR.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements in the

BWR reactor water cleanup and shutdown cooling systems exposed to treated water.

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The staff noted that this item is applicable to steel piping and components in BWRs and;

therefore, is not applicable because WCGS is a PWR. On this basis, the staff finds that

this aging effect is not applicable to this component type.

(3) LRA Section 3.3.2.2.7 addresses loss of material due to general, pitting, and crevice

corrosion in steel diesel exhaust piping and components exposed to diesel exhaust. The

applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program will manage the loss of material from general (carbon

steel (including galvanized) and cast iron only), pitting, and crevice corrosion for

stainless steel, carbon steel (including galvanized) and cast iron internal surfaces

exposed to ventilation atmosphere, wetted gas, and diesel exhaust.

SRP-LR Section 3.3.2.2.7 states that loss of material due to general (steel only), pitting,

and crevice corrosion may occur in steel and stainless steel diesel exhaust piping,

piping components, and piping elements exposed to diesel exhaust. The GALL Report

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is

adequately managed.

The staff noted that the plant-specific program proposed by the applicant is the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program. The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program and finds that it performs periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance

testing, and corrective maintenance to detect aging effects that could result in a loss of

the component's intended function. The staff's evaluation of the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program is documented in

SER Section 3.0.3.1.7. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report, and are adequate to manage

loss of material due to general, pitting, and crevice corrosion in stainless steel, carbon

steel (including galvanized), and cast iron internal surfaces exposed to ventilation

atmosphere, wetted gas, and diesel exhaust.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.7 criteria. For those line items that apply to LRA Section 3.3.2.2.7, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8.

LRA Section 3.3.2.2.8 addresses loss of material due to general, pitting, crevice, and MIC. The

applicant stated that the Buried Piping and Tanks Inspection Program will manage this aging

effect in the carbon steel external surfaces of buried components (including cast iron and

ductile iron). The buried steel piping applicable to this item in WCGS is coated and/or wrapped

in accordance with industry standards. A review of plant-specific operating history indicated one

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case of a pin hole leak failure of a fire protection system piping that is within the scope of

license renewal. The failure resulted from a loss of material due to external pitting corrosion

underneath a holiday (discontinuity) in the protective coating, which was subsequently weld

repaired. In addition, the applicant stated that WCGS does not have any documented below

grade aggressive environment conditions, and that although all buried piping within the scope of

license renewal is protected by the cathodic protection system, no credit is taken for this for

aging management. Based on the above discussion, the applicant concluded that application of

the wrapping and/or coating, and programmatic inspection of their condition will be adequate to

manage loss of material due to external corrosion.

SRP-LR Section 3.3.2.2.8 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel (with or without coating or wrapping) piping, piping

components, and piping elements buried in soil. Buried piping and tanks inspection programs

rely on industry practice, frequency of pipe excavation, and operating experience to manage the

effects of loss of material from general, pitting, and crevice corrosion, and MIC. The

effectiveness of the buried piping and tanks inspection program should be verified to evaluate

an applicant's inspection frequency and operating experience with buried components, ensuring

that loss of material does not occur.

The staff reviewed the Buried Piping and Tanks Inspection Program, which is a new program

that, when implemented, will be consistent with the GALL Report. The applicant stated that an

opportunistic or planned inspection will be performed during the 10-year period before entering

the period of extended operation. The staff's evaluation of the Buried Piping and Tanks

Inspection Program is documented in SER Section 3.0.3.1.4. The staff finds that this program

includes activities that are consistent with the recommendations in the GALL Report, and are

adequate to manage loss of material due to general, pitting, and crevice corrosion, and MIC in

steel piping (with or without coating or wrapping), piping components, and piping elements

buried in soil.

Based on the program identified above, the staff concludes that the applicant's program meet

SRP-LR Section 3.3.2.2.8 criteria. For those line items that apply to LRA Section 3.3.2.2.8, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced

Corrosion and Fouling

The staff reviewed LRA Section 3.3.2.2.9 against the following criteria in SRP-LR

Section 3.3.2.2.9:

(1) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, and

MIC and fouling in steel piping and components exposed to fuel oil. The applicant stated

that the Fuel Oil Chemistry and the One-Time Inspection Programs will manage this

aging effect in carbon steel components in the fuel oil system. The one-time inspection

will include selected components at susceptible locations where contaminants could

accumulate (e.g., stagnant flow locations and tank bottoms).

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SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and fouling may occur in steel piping, piping components, piping

elements, and tanks exposed to fuel oil. The existing AMP relies on fuel oil chemistry

programs to monitor and control fuel oil contamination to manage loss of material due to

corrosion or fouling. Corrosion or fouling may occur at locations where contaminants

accumulate. The effectiveness of fuel oil chemistry programs should be verified to

ensure that corrosion does not occur. The GALL Report recommends further evaluation

of programs to manage loss of material due to general, pitting, and crevice corrosion,

MIC, and fouling to verify the effectiveness of fuel oil chemistry programs. A one-time

inspection of selected components at susceptible locations is an acceptable method to

ensure that corrosion does not occur and that component intended functions will be

maintained during the period of extended operation.

The staff reviewed the Fuel Oil Chemistry Program and finds that it includes monitoring

and controlling fuel oil contaminants, draining, cleaning, visual inspection of fuel oil

tanks, and inspection of new fuel oil before it is introduced into storage tanks. The staff

finds that the One-Time Inspection Program is used to verify the effectiveness of the

Fuel Oil Chemistry Program. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Fuel Oil Chemistry and the One-Time Inspection

Programs is documented in SER Sections 3.0.3.2.13 and 3.0.3.1.3, respectively. The

staff finds that these programs include activities that are consistent with the

recommendations in the GALL Report, and are adequate to manage loss of material

due to general, pitting, and crevice corrosion, and MIC and fouling in steel piping and

components exposed to fuel oil.

(2) LRA Section 3.3.2.2.9 addresses loss of material due to general, pitting, crevice, and

MIC and fouling in steel heat exchanger components exposed to lubricating oil. The

applicant stated that the Lubricating Oil Analysis and the One-Time Inspection Programs

will manage this aging effect in carbon steel components exposed to lubricating oil. The

one-time inspection will include selected components at susceptible locations where

contaminants such as water could accumulate.

SRP-LR Section 3.3.2.2.9 states that loss of material due to general, pitting, and crevice

corrosion, MIC, and fouling may occur in steel heat exchanger components exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

control should be verified to ensure that corrosion does not occur. The GALL Report

recommends further evaluation of programs to manage corrosion to verify the

effectiveness of lubricating oil programs. A one-time inspection of selected components

at susceptible locations is an acceptable method to ensure that corrosion does not occur

and that component intended functions will be maintained during the period of extended

operation.

The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

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component's intended function. The staff finds that the One-Time Inspection Program is

used to verify the effectiveness of the Lubricating Oil Analysis Program. The staff

reviewed the One-Time Inspection Program, which is a new program that, when

implemented, will be consistent with the GALL Report. The staff's evaluation of the

Lubricating Oil Analysis and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.16 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to general, pitting, and crevice corrosion,

and MIC and fouling in steel heat exchanger components exposed to lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.9 criteria. For those line items that apply to LRA Section 3.3.2.2.9, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.3.2.2.10 against the following criteria in SRP-LR

Section 3.3.2.2.10:

(1) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

elastomer lined and stainless steel clad components exposed to treated water or treated

borated water. The applicant stated that this aging effect is not applicable because

WCGS does not have components constructed of steel with elastomer lining or steel

with stainless steel cladding exposed to treated water or treated borated water in the

FPCCS that are within the scope of license renewal. Therefore, the applicable GALL

Report line items were not used.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in BWR and PWR steel piping with elastomer lining or stainless

steel cladding exposed to treated water and treated borated water if the cladding or

lining is degraded. The existing AMP monitors and controls reactor water chemistry to

manage the aging effects of loss of material from pitting and crevice corrosion.

However, high concentrations of impurities in crevices and with stagnant flow conditions

may cause pitting or crevice corrosion; therefore, the effectiveness of water chemistry

control programs should be verified to ensure that corrosion does not occur. The GALL

Report recommends further evaluation of programs to manage loss of material from

pitting and crevice corrosion to verify the effectiveness of water chemistry control

programs. A one-time inspection of select components at susceptible locations is an

acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that this item is applicable to steel piping with elastomer lining or

stainless steel cladding. On the basis that WCGS does not have steel piping with

elastomer lining or stainless steel cladding exposed to treated water or treated borated

water in the FPCCS that are within the scope of license renewal, the staff finds that this

line is not applicable to WCGS.

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(2) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

stainless steel, aluminum, and stainless steel clad heat exchanger components exposed

to treated water. The applicant stated that this aging effect is not applicable because

WCGS is a PWR.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel and aluminum piping, piping components, piping

elements, and for stainless steel and steel with stainless steel cladding heat exchanger

components exposed to treated water. The existing AMP monitors and controls reactor

water chemistry to manage the aging effects of loss of material from pitting and crevice

corrosion. However, high concentrations of impurities in crevices and with stagnant flow

conditions may cause pitting or crevice corrosion; therefore, the effectiveness of water

chemistry control programs should be verified to ensure that corrosion does not occur.

The GALL Report recommends further evaluation of programs to manage loss of

material from pitting and crevice corrosion to verify the effectiveness of water chemistry

control programs. A one-time inspection of select components at susceptible locations is

an acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that this item is applicable to BWR reactor water cleanup, shutdown

cooling, and spent FPCCS components and; therefore, is not applicable WCGS is a

PWR. On this basis, the staff finds that this aging effect is not applicable to this

component type.

(3) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

copper alloy HVAC piping and components exposed to condensation (external). The

applicant stated that the External Surfaces Monitoring Program will manage this aging

effect in copper, copper alloy, copper-nickel, and brass external surfaces exposed to

plant indoor air. The Inspection of Internal Surfaces of Miscellaneous Piping and Ducting

Components Program will manage this aging effect in copper, copper alloy,

copper-nickel, and brass internal surfaces exposed to ventilation atmosphere.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy HVAC piping, piping components, and piping

elements exposed to condensation (external). The GALL Report recommends further

evaluation of a plant-specific AMP to ensure that the aging effect is adequately

managed.

The staff noted that the plant-specific AMPs proposed by the applicant are the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components and

the External Surfaces Monitoring Programs.

The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program and finds that it performs periodic visual inspections of

internal surfaces during periodic maintenance, predictive maintenance, surveillance

testing, and corrective maintenance to detect aging effects that could result in a loss of

component intended function.

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The staff reviewed the External Surfaces Monitoring Program and finds that it performs

periodic visual inspections of external surfaces during system engineer walkdowns.

These walkdowns are performed during, at least, every refueling outage.

In LRA Tables 3.3.2-8, 3.3.2-9, 3.3.2-10, and 3.3.2-12, the applicant credited the

External Surface Monitoring Program to manage loss of material in external surfaces of

heat exchanger tube side component exposed to a plant indoor air environment. The

staff requested that the applicant clarify how a visual inspection of external surfaces

during a system walkdown will identify the aging effect on a tube side component which

would be inside a heat exchanger.

In its response, the applicant stated that the heat exchanger tube side components are

not heat exchanger tubes, but part of the heat exchanger header assembly. However,

the applicant stated that a review of the drawings showed that the header assembly

protrudes only about 3 inches outside the ducting. Therefore, the majority of the header

assembly is located inside the ducting.

By letter dated August 31, 2007, the applicant amended the LRA to place these

components in an environment of external ventilation atmosphere. The applicant

credited the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program to manage the aging effects of loss of material in these

components.

On the basis that the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program performs visual inspections of internal surfaces when the

component is disassembled during maintenance activities or during surveillance

procedures, the staff finds this response acceptable.

The staff's evaluation of the External Surfaces Monitoring and the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Programs is documented in

SER Sections 3.0.3.1.5 and 3.0.3.1.7, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to pitting and crevice corrosion in external

surfaces of copper alloy HVAC piping and components exposed to condensation.

(4) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

copper alloy piping and components exposed to lubricating oil. The applicant stated that

the Lubricating Oil Analysis and the One-Time Inspection Programs will manage loss of

material due to pitting and crevice corrosion for copper, bronze, and brass components

exposed to lubricating oil. The one-time inspection will include selected components at

susceptible locations where contaminants such as water could accumulate.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP periodically samples and analyzes

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment not conducive to corrosion. However, control of lube oil contaminants may

not always be fully effective in precluding corrosion; therefore, the effectiveness of

lubricating oil control should be verified to ensure that corrosion does not occur. The

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GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of lubricating oil programs. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion

does not occur and that component intended functions will be maintained during the

period of extended operation.

The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The staff noted that the One-Time Inspection Program

is used to verify the effectiveness of the Lubricating Oil Analysis Program. The staff

reviewed the One-Time Inspection Program, which is a new program that, when

implemented, will be consistent with the GALL Report. The staff's evaluation of the

Lubricating Oil Analysis and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.16 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to pitting and crevice corrosion in copper,

bronze, and brass components exposed to lubricating oil.

(5) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

HVAC aluminum piping and components and stainless steel ducting and components

exposed to condensation. The applicant stated that the Inspection of Internal Surfaces

in Miscellaneous Piping and Ducting Components Program will manage this aging effect

in stainless steel internal surfaces exposed to wetted gas.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in HVAC aluminum piping, piping components, and piping elements

and stainless steel ducting and components exposed to condensation. The GALL

Report recommends further evaluation of a plant-specific AMP to ensure that the aging

effect is adequately managed.

The staff noted that the plant-specific program proposed by the applicant is the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program. The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program and finds that it performs periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance

testing, and corrective maintenance to detect aging effects that could result in a loss of

the component's intended function. The staff's evaluation of the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program is documented in

SER Section 3.0.3.1.7. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report, and that it is adequate to

manage loss of material due to pitting and crevice corrosion in HVAC aluminum piping

and components and stainless steel ducting and components exposed to condensation.

(6) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

copper alloy piping and components exposed to internal condensation. The applicant

stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program will manage this aging effect in bronze internal surfaces exposed

to wetted gas.

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SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy fire protection system piping, piping components,

and piping elements exposed to internal condensation. The GALL Report recommends

further evaluation of a plant-specific AMP to ensure that the aging effect is adequately

managed.

The staff noted that the plant-specific program proposed by the applicant is the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program. The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program and finds that it performs periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance

testing, and corrective maintenance to detect aging effects that could result in a loss of

the component's intended function. The staff's evaluation of the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program is documented in

SER Section 3.0.3.1.7. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report, and are adequate to manage

loss of material due to pitting and crevice corrosion in copper alloy piping and

components exposed to internal condensation.

(7) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping and components exposed to soil. The applicant stated that this

aging effect is not applicable because WCGS does not have stainless steel components

exposed to soil in the OCCW, ultimate heat sink, fire protection, diesel fuel oil, or EDG

systems that are within the scope of license renewal. Therefore, the applicable GALL

Report line items were not used.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that these aging effects are adequately managed.

The staff noted that this item applies to stainless steel piping, piping components, and

piping elements exposed to soil. On the basis that WCGS does not have stainless steel

components exposed to soil in the open cycle cooling water, ultimate heat sink, fire

protection, diesel fuel oil, or EDG systems that are within the scope of license renewal,

the staff finds that this line item is not applicable to WCGS.

(8) LRA Section 3.3.2.2.10 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping and components of BWR standby liquid control system exposed to

sodium pentaborate. The applicant stated that this aging effect is not applicable

because WCGS is a PWR.

SRP-LR Section 3.3.2.2.10 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel piping, piping components, and piping elements

of the BWR standby liquid control system exposed to sodium pentaborate solution.

The staff noted that this item applies to BWR systems and; therefore, is not applicable

because WCGS is a PWR. On this basis, the staff finds that this aging effect is not

applicable to this component type.

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Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.10 criteria (as applicable). For those line items that apply to LRA

Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report and

that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

LRA Section 3.3.2.2.11 addresses loss of material due to pitting, crevice, and galvanic

corrosion. The applicant stated that this aging effect is not applicable because WCGS is a

PWR.

SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic

corrosion may occur in copper alloy piping, piping components, and piping elements exposed to

treated water.

The staff noted that this item applies to BWR systems and; therefore, is not applicable because

WCGS is a PWR. On this basis, the staff finds that this aging effect is not applicable to this

component type.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.3.2.2.11 criteria. The staff determines that the LRA is consistent with the

GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.3.2.2.12 against the following criteria in SRP-LR

Section 3.3.2.2.12:

(1) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and MIC in

stainless steel, aluminum, and copper alloy piping and components exposed to fuel oil.

The applicant stated that the Fuel Oil Chemistry and the One-Time Inspection Programs

will manage this aging effect in stainless steel and brass components exposed to fuel

oil. The one-time inspection will include selected components at susceptible locations

where contaminants could accumulate (e.g., stagnant flow locations).

SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice

corrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping,

piping components, and-piping elements exposed to fuel oil. The existing AMP relies on

the fuel oil chemistry program for monitoring and control of fuel oil contamination to

manage loss of material due to corrosion; however, corrosion may occur at locations

where contaminants accumulate and the effectiveness of fuel oil chemistry control

should be verified to ensure that corrosion does not occur. The GALL Report

.recommends further evaluation of programs to manage corrosion to verify the

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effectiveness of the fuel oil chemistry control program. A one-time inspection of selected

components at susceptible locations is an acceptable method to ensure that corrosion

does not occur and that component intended functions will be maintained during the

period of extended operation.

The staff reviewed the Fuel Oil Chemistry Program and finds that it includes monitoring

and controlling fuel oil contaminants, draining, cleaning and visual inspection of fuel oil

tanks, and inspection of new fuel oil before it is introduced into storage tanks. The staff

finds that the One-Time Inspection Program is used to verify the fuel oil chemistry. The

staff reviewed the One-Time Inspection Program, which is a new program that, when

implemented, will be consistent with the GALL Report. The staff's evaluation of the Fuel

Oil Chemistry and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.13 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to pitting, crevice, and MIC in stainless

steel, aluminum, and copper alloy piping and components exposed to fuel oil.

(2) LRA Section 3.3.2.2.12 addresses loss of material due to pitting, crevice, and MIC in

stainless steel piping and components exposed to lubricating oil. The applicant stated

that the Lubricating Oil Analysis and the One-Time Inspection Programs will manage

this aging effect in stainless steel components exposed to lubricating oil. The one-time

inspection will include selected components at susceptible locations where contaminants

such as water could accumulate. For the RCP lubricating oil collection system, the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program will manage this aging effect in stainless steel components exposed to

lubricating oil.

SRP-LR Section 3.3.2.2.12 states that loss of material due to pitting and crevice

corrosion, and MIC may occur in stainless steel piping, piping components, and piping

elements exposed to lubricating oil. The existing program periodically samples and

analyzes lubricating oil to maintain contaminants within acceptable limits, thereby

preserving an environment not conducive to corrosion. However, control of lube oil

contaminants may not always be fully effective in precluding corrosion; therefore, the

effectiveness of lubricating oil control should be verified to ensure that corrosion does

not occur. The GALL Report recommends further evaluation of programs to manage

corrosion to verify the effectiveness of lubricating oil programs. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The staff finds that the One-Time Inspection Program is

used to verify the effectiveness of the Lubricating Oil Analysis Program. The staff

reviewed the One-Time Inspection Program, which is a new program that, when

implemented, will be consistent with the GALL Report. The staff's evaluation of the

Lubricating Oil Analysis and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.16 and 3.0.3.1.3, respectively. The staff finds that these programs

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include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to pitting, crevice, and MIC in stainless

steel piping and components exposed to lubricating oil.

The staff noted that the environment for the RCP lubricating oil collection system is

contaminated oil and is not within the scope of the Lubricating Oil Analysis Program.

Instead, the applicant proposed the Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components Program to manage the aging effects of loss of

material. The staff reviewed the Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program and finds that it performs periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance

testing, and corrective maintenance to detect aging effects that could result in a loss

component intended function. The staff's evaluation of the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program is documented in

SER Section 3.0.3.1.7. The staff finds that these programs include activities that are

consistent with the recommendations in the GALL Report, and are adequate to manage

loss of material due to pitting, crevice, and MIC in stainless steel piping and components

exposed to contaminated lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.3.2.2.12 criteria. For those line items that apply to LRA Section 3.3.2.2.12,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.3.2.2.13 Loss of Material Due to Wear

The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13.

LRA Section 3.3.2.2.13 addresses loss of material due to wear. The applicant stated that this

aging effect is not applicable because WCGS does not have in-scope elastomer components

exposed to air - indoor uncontrolled (internal or external) with relative motion with other

components to produce an aging effect of loss of material due to wear; therefore, the applicable

GALL Report line items were not used.

SRP-LR Section 3.3.2.2.13 states that loss of material due to wear may occur in the elastomer

seals and components exposed to air - indoor uncontrolled (internal or external). The GALL

Report recommends further evaluation to ensure that these aging effects are adequately

managed.

The staff noted that this item applies to elastomer seals. On the basis that WCGS does not

have elastomer components with relative motion with other components that are exposed to an

internal and external environment of indoor uncontrolled air, the staff finds that it is not plausible

to have an aging effect of loss of material due to wear. The staff finds that this aging effect is

not applicable to this component type.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.3.2.2.13 criteria. The staff determines that the LRA is consistent with the

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GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.14 Loss of Material Due to Cladding Breach

The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section,3.3.2.2.14.

LRA Section 3.3.2.2.14 addresses loss of material due to cladding breach. The applicant stated

that this aging effect is not applicable because WCGS does not have pumps in the CVCS that

are steel with stainless steel cladding exposed to treated borated water within the scope of

license renewal. Therefore, the applicable GALL Report line item was not used.

SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach may occur in

PWR steel charging pump casings with stainless steel cladding exposed to treated borated

water. The GALL Report references IN 94-63 and recommends further evaluation of a

plant-specific AMP to ensure that the aging effect is adequately managed.

The staff noted that this item applies to steel charging pump casings. On the basis that WNCGS

does not have steel with stainless steel cladding pumps exposed to treated borated water in the

CVCS that are within the scope of license renewal, the staff finds that this aging effect is not

applicable to this component type.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.3.2.2.14 criteria. The staff determines that the LRA is consistent with the

GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.2.15 Quality Assurance for Aging Management of Nonsafey-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.3.2-1 through 3.3.2-21, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-21, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

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Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.3.2.3.1 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Handling - Fuel

Storage and Handling System - LRA Table 3.3.2-1

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the

fuel handling - fuel storage and handling system component groups.

In LRA Table 3.3.2-1, the applicant proposed to manage cumulative fatigue damage of spent

fuel racks as a TLAA. SER Section 4.3 documents the staff's review of the applicant's

evaluation of this TLAA.

In LRA Table 3.3.2-1, the applicant identified no aging effects for boral neutron absorbers in an

external environment of treated borated water. The boraflex spent fuel racks were replaced in

1999 with boral. This modification was incorporated in the WCGS operating license

Amendment 120. Additionally, with regards to the boral spent fuel pool racks modification, the

applicant stated that there is no net loss of aluminum cladding during the passivation process,

in which aluminum slightly corrodes, before forming an impervious hydrated aluminum oxide

film. The applicant also noted that, since operational experience does not show degradation of

neutron absorption capability for boral exposed to spent fuel pool environments, no special

corrosion measures are necessary. The NRC SER approving operating license

Amendment 120 dated March 22, 1999, states that the staff found that the materials for the

new racks were compatible with the environment in the spent fuel pool, and that the racks

would not undergo material degradation which could affect their ability to safely store fuel.

Based on information provided in the SER dated March 22, 1999 and the design, fabrication,

and installation of the new racks, the staff finds that there are no aging effects requiring aging

management in the boral spent fuel racks exposed to a borated water environment. The staff

reviewed the operating experience since the racks were installed and did not find any issues

related to age related degradation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.3.2.3.2 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Pool Cooling

and Cleanup System - LRA Table 3.3.2-2

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the

FPCCS component groups.

In LRA Table 3.3.2-2, the applicant proposed to manage cracking in stainless steel closure

bolting, flow element, heat exchanger tube side, expansion joint bellows, mechanical

penetrations, piping, pump, thermowell, tubing, and valve component types exposed to an

internal and external environment of borated water by using the Water Chemistry Program.

The staff's evaluation of the Water Chemistry Program is documented in SER Section 3.0.3.2.2.

The staff finds that the Water Chemistry Program monitors chlorides, fluorides, and dissolved

oxygen to limit the contaminants, thus, minimizing the occurrences of aging effects and

maintaining the component's ability to perform its intended functions. The Water Chemistry

Program is consistent with the GALL Report, with some exceptions that are applicable to the

steam generators only, and in accordance with the latest revision of the EPRI water chemistry

guidelines.

The staff finds that the One-Time Inspection Program will be used to verify the effectiveness of

the Water Chemistry Program. The staff's evaluation of the One-Time Inspection Program is

documented in SER Section 3.0.3.1.3. The staff confirms that the FPCCS is included within the

scope of the One-Time Inspection Program, where enhanced visual (i.e., VT-1 or equivalent)

and/or volumetric (i.e., RT or UT) inspections are performed to detect cracking.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff finds that the aging effect of cracking in stainless steel components exposed to an internal

and external environment of borated water will be adequately managed using the Water

Chemistry and One-Time Inspection Programs.

In LRA Table 3.3.2-2, the applicant proposed to manage loss of pre-load in stainless steel

closure bolting exposed to an exterior environment of treated borated water or borated water

leakage using the Bolting Integrity Program.

The staff's evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7.

The staff finds that the Bolting Integrity Program includes good bolting practices and

requirements for proper disassembling, inspecting, and assembling of connections with

threaded fasteners. The staff finds that this program is consistent with the recommendations of

the GALL Report. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff finds that the aging effect of loss of pre-load in stainless steel

closure bolting exposed to an exterior environment of treated borated water or borated water

leakage will be adequately managed by using the Bolting Integrity Program.

In LRA Table 3.3.2-2, the applicant proposed to manage reduction of heat transfer in stainless

steel heat exchanger tube sides exposed to an internal environment of treated borated water by

using the Water Chemistry and One-Time Inspection Programs.

The staff's evaluation of the Water Chemistry and One-Time Inspection Programs is

documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The staff finds that the

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Water Chemistry Program monitors chlorides, fluorides, and dissolved oxygen to limit the

contaminants, thus, minimizing the occurrences of aging effects and maintaining the

component's ability to perform its intended functions. The Water Chemistry Program is

consistent with the GALL Report, with some exceptions that are applicable to the steam

generators only, and in accordance with the latest revision of the EPRI water chemistry

guidelines. The staff confirms that the FPCCS is included within the scope of the One-Time

Inspection Program, where enhanced visual (i.e., VT-1 or equivalent) and/or volumetric (i.e., RT

or UT) inspections are performed to detect reduction of heat transfer. On the basis of its review

of the applicant's plant-specific and industry operating experience, the staff finds that the aging

effect of reduction of heat transfer in stainless steel heat exchanger tube side components

exposed to an internal environment of borated water will be adequately managed using the

Water Chemistry and One-Time Inspection Programs.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.3 Auxiliary Systems - Summary of Aging Management Evaluation - Essential Service

Water System - LRA Table 3.3.2-3

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the

ESWS component groups.

In LRA Table 3.3.2-3, the applicant proposed to manage loss of pre-load in carbon steel closure

bolting exposed to an exterior environment of atmosphere weather using the Bolting Integrity

Program. The staff's evaluation of the Bolting Integrity Program is documented in SER

Section 3.0.3.2.7. The staff finds that the Bolting Integrity Program includes good bolting

practices and requirements for proper disassembling, inspecting, and assembling of

connections with threaded fasteners. The staff finds that the program is consistent with the

recommendations of the GALL Report. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff finds that the aging effect of loss of

pre-load in carbon steel closure bolting exposed to an exterior environment of atmosphere

weather will be adequately managed by using the Bolting Integrity Program.

The staff noted that in LRA Table 3.3.2-3, the applicant identified no aging effects for stainless

steel flow element exposed to an exterior environment of atmosphere weather. The staff finds

that stainless steel material is susceptible to aging only if exposed to an aggressive chemical,

salt water or buried environments. In a normal atmosphere environment, where rain water

would tend to wash the exterior surface material rather than concentrate contaminants, the

stainless steel material will have no aging effects. On this basis, the staff finds that stainless

steel in an atmosphere weather environment exhibits no aging effect, and that the component

or structure will remain capable of performing its intended functions consistent with the CLB

during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

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adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.4 Auxiliary Systems - Summary of Aging Management Evaluation - Component Cooling

System - LRA Table 3.3.2-4

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the

component cooling system component groups. On the basis of its review, the staff finds that all

AMR results described in LRA Table 3.3.2-4 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.5 Auxiliary Systems - Summary of Aging Management Evaluation - Containment

Cooling Water System - LRA Table 3.3.2-5

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the

containment cooling water system component groups.

In LRA Table 3.3.2-5, the applicant identified no aging effects for stainless steel instrument

bellows, piping, and tubing exposed to a silicone fluid environment. The staff finds that the

silicone fluid associated with the containment water cooling system is nearly chemically inert

and has no adverse effect on metals such as aluminum and stainless steel. On this basis, the

staff finds that stainless steel in a silicone fluid environment exhibits no aging effect, and the

component or structure will remain capable of performing its intended functions consistent with

the CLB during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.6 Auxiliary Systems - Summary of Aging Management Evaluation - Compressed Air

System - LRA Table 3.3.2-6

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the

compressed air system component groups.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of pre-load in copper alloy closure

bolting exposed to an exterior environment of plant indoor air by using the Bolting Integrity

Program. The staff's evaluation of the Bolting Integrity Program is documented in SER

Section 3.0.3.2.7. The Bolting Integrity Program includes good bolting practices and

requirements for proper disassembling, inspecting, and assembling of connections with

threaded fasteners. The staff finds that this program is consistent with the recommendations of

the GALL Report. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff finds that the aging effect of loss of pre-load in copper alloy

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closure bolting exposed to an exterior environment of plant indoor air will be adequately

managed by using the Bolting Integrity Program.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material in carbon steel piping

and valves exposed to an interior environment of plant indoor air by using the Inspection of

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff's

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program is documented in SER Section 3.0.3.1.7. The staff finds that the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

performs periodic visual inspections of internal surfaces during periodic maintenance, predictive

maintenance, surveillance testing, and corrective maintenance to detect aging effects that could

result in a loss of the component's intended function. On the basis of its review of the

applicant's plant-specific and industry operating experience, the staff finds that the aging effect

of loss of material in carbon steel piping and valves exposed to an interior environment of plant

indoor air will be adequately managed by using the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program.

In LRA Table 3.3.2-6, the applicant identified no aging effects for stainless steel piping exposed

to an interior environment of plant indoor air. The staff finds that stainless steel is highly

resistant to corrosion in dry atmospheres in the absence of corrosive species (which would be

reflective of an indoor uncontrolled air), as cited in the American Society for Metals

International, Metals Handbook, Volumes 3 and 13, dated 1980 and 1987, respectively. The

staff finds that components are not subject to moisture in a dry air environment and that indoor

uncontrolled air would have limited humidity and condensation. Therefore, the staff finds that

stainless steel in an indoor, uncontrolled air environment exhibits no aging effects, and the

component or structure will remain capable of performing its intended functions consistent with

the CLB during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.7 Auxiliary Systems - Summary of Aging Management Evaluation - Chemical and

Volume Control System - LRA Table 3.3.2-7

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the

CVCS component groups.

In LRA Table 3.3.2-7, the applicant proposed to manage loss of pre-load of stainless steel

closure bolting exposed externally to an exterior environment of borated water leakage by using

the Bolting Integrity Program. The staff's evaluation of the Bolting Integrity Program is

documented in SER Section 3.0.3.2.7. The Bolting Integrity Program includes good bolting

practices and requirements for proper disassembling, inspecting, and assembling of

connections with threaded fasteners. The staff finds that this program is consistent with the

recommendations of the GALL Report. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff finds that the aging effect of loss of

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pre-load in stainless steel closure bolting exposed to an exterior environment of borated water

leakage will be adequately managed by using the Bolting Integrity Program.

In LRA Table 3.3.2-7, the applicant proposed to manage reduction of heat transfer and loss of

material in copper-nickel and stainless steel heat exchanger tube side exposed to an internal

and external environment of treated borated water by using the Water Chemistry and One-Time

Inspection Programs. The staff's evaluation of the Water Chemistry and One-Time Inspection

Programs is documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively.

The staff finds that the Water Chemistry Program monitors chlorides, fluorides, and dissolved

oxygen to limit the contaminants, thus, minimizing the occurrences of aging effects and

maintaining the component's ability to perform its intended functions. The staff finds that the

Water Chemistry Program is consistent with the GALL Report, with some exceptions which are

applicable to steam generators only, and in accordance with the latest revision of the EPRI

water chemistry guidelines. The staff also confirmed that the CVCS is included within the scope

of the One-Time Inspection- Program, where enhanced visual (i.e., VT-1 or equivalent) and/or

volumetric (i.e., RT or UT) inspections are performed to detect reduction of heat transfer. On

the basis of its review of the applicant's plant-specific and industry operating experience, the

staff finds that the aging effect of reduction of heat transfer and loss of material in stainless

steel heat exchanger tube side components exposed to an internal environment of borated

water is effectively managed by using the Water Chemistry and One-Time Inspection

Programs.

In LRA Table 3.3.2-7, the applicant stated that cumulative fatigue damage of stainless steel

heat exchangers exposed to an internal environment of treated borated water is a TLAA. The

applicant applied note I for this item and referenced a GALL Report, Volume 2 item and a

Table 3.3.1 item. Since note I implies that this line item is not consistent with the GALL Report,

the staff requested that the applicant explain why a GALL Report, Volume 2 item and a

Table 3.3.1 item were referenced in this item.

In its response, the applicant stated that no vessel, tank, pump, or heat exchanger designs at

WCGS are supported by TLAAs as defined in 10 CFR 54.3, except ASME Code Class 1,

components and the Class 2 portionsof the steam generators. The applicant stated that the

design of this WCGS component is not supported by TLAAs.

By letter dated August 31, 2007, the applicant amended LRA Table 3.3.2-7 to delete this TLAA

item and notes I and 7. On the basis that there is no TLAA for this line item, the staff finds that

deletion of this line item is acceptable.

In LRA Table 3.3.2-7, the applicant identified no aging effects for copper alloy sight glass and

valve exposed to an interior environment of plant indoor air. The applicant applied notes G

and 1 for this item. However, in other tables, the applicant referenced a GALL Report, Volume 2

item and applied note A, which implies that the item is consistent with the GALL Report. The

staff requested that the applicant clarify this discrepancy.

By letter dated August 31, 2007, the applicant amended the LRA to change this line item to

reference note A and GALL Report, item VIII.I-2. The staff finds that the GALL Report line item

applies to copper alloy piping, piping components, and piping elements in an environment of

uncontrolled indoor air with no aging effects and no aging management recommended. On the

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basis that the line item is now consistent with the GALL Report, the staff finds the applicant's

response acceptable.

In LRA Table 3.3.2-7, the applicant identified no aging effects for insulation material comprised

of aluminum, stainless steel, calcium silicate, and foamglass in a plant indoor air environment.

The applicant applied note 6 indicating that this thermal insulation is located in an indoor

non-aggressive environment (i.e., the insulation is not exposed to contaminants). On the basis

of its review of current industry research and operating experience, the staff finds that plant

indoor air on thermal insulation material will not result in aging that will be of concern during the

period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.8 Auxiliary Systems - Summary of Aging Management Evaluation - Auxiliary Building

HVAC System - LRA Table 3.3.2-8

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the

auxiliary building HVAC system component groups.

The staff noted that in LRA Table 3.3.2-8, the applicant proposed to manage loss of material in

copper-alloy valves exposed to an internal environment of demineralized water by using the

Water Chemistry and One-Time Inspection Programs.

The staff's evaluation of the Water Chemistry and One-Time Inspection Programs is

documented in SER Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The staff finds that the

Water Chemistry Program monitors chlorides, fluorides, and dissolved oxygen to limit the

contaminants, thus, minimizing the occurrences of aging effects and maintaining the

component's ability to perform its intended functions. The staff finds that the Water Chemistry

Program is consistent with the GALL Report, with some exceptions that are applicable to steam

generators only, and in accordance with the latest revision of the EPRI water chemistry

guidelines. The staff also confirmed that the auxiliary building HVAC system is included within

the scope of the One-Time Inspection Program, where enhanced visual (i.e., VT-1 or

equivalent) and/or volumetric (i.e., RT or UT) inspections are performed to detect loss of

material. On the basis of its review of the applicant's plant-specific and industry operating

experience, the staff finds that the aging effect of loss of material in copper-alloy valves

exposed to an internal environment of demineralized water will be adequately managed by

using the Water Chemistry and One-Time Inspection Programs.

In LRA Table 3.3.2-8, the applicant identified no aging effects for copper heat exchanger tube

sides exposed to an exterior environment of plant indoor air. The staff noted that ASTM

comprehensive tests conducted over a 20-year period have confirmed the suitability of copper

and copper alloys for atmospheric exposure as referenced in the American Society for Metals

International, Metals Handbook, Volume 13, dated 1987. Therefore, the staff finds that copper

in an indoor air internal environment has no aging effect.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.9 Auxiliary Systems - Summary of Aging Management Evaluation - Control Building

HVAC System - LRA Table 3.3.2-9

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the

control building HVAC system component groups.

In LRA Table 3.3.2-9, the applicant identified no aging effects for elastomers flex connectors

exposed to an exterior environment of plant indoor air. The applicant applied note I and

referenced a GALL Report item and a Table 1 item. Since note I implies that this line item is not

consistent with the GALL Report, the staff requested that the applicant clarify why a GALL

Report item and a Table 1 item was referenced.

In its response, the applicant stated that flexible connectors for the control building HVAC

system are synthetic elastomers (i.e., neoprene) exposed to an uncontrolled indoor air

environment. The general thermal environment in the control building is maintained below

95 OF. The aging effect listed for GALL Report, item VII.F1 -7, is hardening and loss of strength,

elastomer degradation. The GALL Report defines elastomers as:

Materials rubber, EPT, EPDM, PTFE, ETFE, viton, vitril, neoprene, and silicone

elastomer. Hardening and loss of strength of elastomers can be induced by

elevated temperature (over about 95 °F (35 'C), and additional aging factors

such as exposure to ozone, oxidation, and radiation.

The applicant stated that the GALL Report defines uncontrolled indoor air with temperatures

above 95 OF and discusses the temperature threshold for elastomer thermal aging by stating:

If ambient is <95 OF, then any resultant thermal aging of organic materials can be

considered to be insignificant, over the 60-year period of interest." The EPRI

guideline, Non-Class 1 Mechanical Implementation Guideline and Mechanical

Tools, Appendix D Section 2.1.8, states in part that, "synthetic rubbers are not

affected by ozone and are typically much more resistant to sunlight (or other

forms of ultraviolet radiation).

The staff noted that GALL Report, item VII.F1 -7, specifies hardening and loss of strength as the

aging mechanism. However, the GALL Report also states that if the temperature threshold is

not exceeded, that elastomer thermal aging is insignificant. The EPRI guide states that

synthetic rubbers such as neoprene are not affected by ozone, sunlight, or other forms of

ultraviolet radiation. Therefore, the staff finds that hardening and loss of strength of the control

building HVAC flexible connectors is not expected.

By letter dated August 31, 2007, the applicant amended the LRA as follows:

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LRA Table 3.3.2-9, Control Building HVAC System, Component Type "Flexible

Connectors" was amended to eliminate reference to GALL line VII.F1-7. A

Non-GALL row was created. The Non-GALL row has the identical material,

environment, aging effect, and AMP as currently listed for the flexible

connectors. The footnote was revised to "H,1." Note 1 was included describing

why these elastomers are not subject to hardening (similar to discussion above).

LRA Table 3.3.1, item 3.3.1.11, was amended to remove discussion of the

exception to NUREG-1 801 for control building flexible connectors.

On the basis of its review, the staff finds this response acceptable because hardening and loss

of strength of the control building HVAC flexible connectors is not expected.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.10 Auxiliary Systems - Summary of Aging Management Evaluation - Fuel Building

HVAC System - LRA Table 3.3.2-10

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for

the fuel building HVAC system component groups.

In LRA Table 3.3.2-10, the applicant applied note A for carbon steel adsorber in an internal

environment of ventilation atmosphere; however, a GALL Report item and a Table 1 item were

not referenced. Since note A implies that this line is consistent with the GALL Report, the staff

requested that the applicant identify the GALL Report and the Table 1 items. The staff noted

that if the line is not consistent, the applicant should clarify this discrepancy.

In its response, the applicant stated that note A was inadvertently used. Unlike other carbon

steel ventilation components, it is unlikely that an adsorber would have condensation as an

internal environment. The adsorbers first stage contains moisture separators to ensure

moisture does not impregnate in the charcoal filters. Therefore, a separate plant-specific aging

evaluation was created.

By letter dated August 31, 2007, the LRA was amended as follows:

LRA Table 3.3.2-10, Fuel Building HVAC System, Component Type "Adsorber"

was amended to use note "G,3" in lieu of note "A." A plant-specific note 3 was

added that states, "GALL row VII.F2-3 has an internal environment of

condensation. Unlike other carbon steel ventilation components, it is unlikely that

an adsorber would have condensation as an internal environment. The

adsorbers first stage contains moisture separators to ensure moisture does not

impregnate the charcoal filters. Therefore, a separate (non condensation) row

needed to be created."

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The staff finds that a dry environment will have an insignificant aging effect on carbon steel.

Carbon steel needs a wet or humid environment to generate corrosion. The GALL Report

confirms that carbon steel in a dried air environment has no aging effects and that no aging

management program is necessary. Since the moisture separators ensure that the air is dry,

the staff finds the applicant response acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.11 Auxiliary Systems - Summary of Aging Management Evaluation - Essential Service

Water Pumphouse Building HVAC System - LRA Table 3.3.2-11

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for

the essential service water pumphouse building HVAC system component groups. On the basis

of its review, the staff finds that all AMR results described in LRA Table 3.3.2-11 are consistent

with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.12 Auxiliary.Systems - Summary of Aging Management Evaluation - Miscellaneous

Buildings HVAC System - LRA Table 3.3.2-12

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for

the miscellaneous buildings HVAC system component groups. On the basis of its review, the

staff finds that all AMR results described in LRA Table 3.3.2-12 are consistent with the GALL

Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.13 Auxiliary Systems - Summary of Aging Management Evaluation - Diesel Generator

Building HVAC System - LRA Table 3.3.2-13

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for

the DG building HVAC system component groups. On the basis of its review, the staff finds that

all AMR results described in LRA Table 3.3.2-13 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.14 Auxiliary Systems - Summary of Aging Management Evaluation - Fire Protection

System - LRA Table 3.3.2-14

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The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for

the fire protection system component groups.

In LRA Table 3.3.2-14, the applicant proposed to manage loss of material in cast iron strainer

exposed to an interior environment of plant indoor air by using the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff's evaluation of

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

is documented in SER Section 3.0.3.1.7. The staff finds that the Inspection of Internal Surfaces

In Miscellaneous Piping And Ducting Components Program performs periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance testing,

and corrective maintenance to detect aging effects that could result in a loss of the

component's intended function. On the basis of its review of the applicant's plant-specific and

industry operating experience, the staff finds that the aging effect of loss of material in cast iron

strainer exposed to an interior environment of plant indoor air will be adequately managed by

using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program.

In LRA Table 3.3.2-14, the applicant identified no aging effects for elastomers flex hoses

exposed to an exterior environment of plant indoor air and an internal environment of dry air.

The applicant applied note 1, which states that ambient temperatures in these spaces is

expected to be below 95 OF, and below this temperature, thermal aging is not considered

significant. The staff requested that the applicant identify where these flex hoses are located in

the plant since some areas could be considered to have a temperature higher than 95 OF.

In its response, the applicant stated that the flex hoses are associated with the Halon cylinder

banks. Halon cylinder banks are located in the auxiliary building, communications corridor, and

control building. The general thermal environment in the control building is maintained below

95 OF. The general thermal environment in the auxiliary building is less than 104 OF. However,

flexible hoses for Halon storage cylinders in areas other than the control building may exceed

the temperature threshold for elastomer degradation.

The staff finds that for Halon cylinder flexible hoses in the auxiliary building and

communications corridor, thermal aging must be considered because it cannot be shown that

the equipment spaces for these components are maintained below 95 OF.

By letter dated August 31, 2007, the LRA was amended as follows:

LRA Table 3.3.2-14, Fire Protection System, Component Type "Flexible Hoses"

(control building), environment "dry gas" will be amended to use note G,1 in lieu

of note J. Plant-specific note 1 will be amended to state, "Ambient temperature in

control building spaces is expected to be below 95 OF. Below 95 OF, thermal

aging of elastomers is not considered significant."

LRA Table 3.3.2-14, Fire Protection System, Component Type "Flexible Hoses"

(control building), environment "plant indoor air" will be amended to use note G,1

in lieu of note J. plant-specific note 1 will be amended to state, "Ambient

temperature in control building spaces is expected to be below 95 OF degrees.

Below 95 OF degrees, thermal aging of elastomers is not considered significant."

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The staff noted that the GALL Report defines uncontrolled indoor air as temperature greater

than 95 °F. The GALL Report also discusses the temperature threshold for elastomer thermal

aging by stating "If ambient is <95 'F, then any resultant thermal aging of organic materials can

be considered to be insignificant, over the 60-year period of interest." On this basis, the staff

finds that plant indoor air and dry air on elastomers in the control building will not result in aging

that will be of concern during the period of extended operation.

By letter dated August 31, 2007, the LRA was amended to add the following component:

Component type: "Flexible Hoses" (auxiliary building/communications corridor)

Material: Elastomer

Environment: Plant indoor air (external)

Aging Effect: Hardening and loss of strength - elastomer degradation

Aging Management Program: XI.M26 - Fire Protection

NUREG-1801 Volume 2 No.: VII.F2-7

Table 1 Item: 3.3.1.11

Note: E,3

Plant-specific Note 3: Thermal aging of Halon flexible hoses in the auxiliary

building and communication corridor must be considered because it cannot be

shown that these areas are below 95 OF.

Component type: "Flexible Hoses" (auxiliary building/communications corridor)

Material: Elastomer

Environment: Dry gas (internal)

Aging Effect: Hardening and loss of strength - elastomer degradation

Aging Management Program: XI.M26 - Fire Protection

NUREG-1801 Volume 2 No.: None

Table 1 Item: None

Note: G,3

Plant-specific Note3: Thermal aging of Halon flexible hoses in the auxiliary

building and communication corridor must be considered because it cannot be

shown that these areas are below 95 OF.

The staff finds that since the environment indicates that the general temperature in the area

could be greater than 95 OF, hardening and loss of strength will be an aging effect requiring

management for elastomer flex hoses. The hoses will be visually inspected on a periodic basis

as part of the Fire Protection Program. The staff's evaluation of the Fire Protection Program is

documented in SER Section 3.0.3.2.11.

In LRA Table 3.3.2-14, the applicant identified no aging effects for copper alloy and bronze

spray nozzles and valves exposed to an interior environment of plant indoor air. This line item is

similar to GALL Report, item VIII.I-2, which is for copper alloy piping, piping components, and

piping elements in an external environment of air-indoor uncontrolled. On the basis that the

LRA item is similar to the GALL Report item for that material and environment, the staff finds

that plant indoor air on copper alloy and bronze material will not result in aging that will be of

concern during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

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Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.15 Auxiliary Systems - Summary of Aging Management Evaluation - Emergency Diesel

Engine Fuel Oil Storage and Transfer System - LRA Table 3.3.2-15

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for

the emergency diesel engine fuel oil storage and transfer system component groups.

In LRA Table 3.3.2-15, the applicant proposed to manage loss of pre-load of carbon steel

closure bolting exposed to an exterior environment of atmosphere weather and fuel oil by using

the Bolting Integrity Program. The staff's evaluation of the Bolting Integrity Program is

documented in SER Section 3.0.3.2.7. The staff finds that the Bolting Integrity Program

includes good bolting practices and requirements for proper disassembling, inspecting, and

assembling of connections with threaded fasteners. The staff finds that the program is

consistent with the recommendations of the GALL Report. On the basis of its review of the

applicant's plant-specific and industry operating experience, the staff finds that the aging effect

of loss of pre-load in carbon steel closure bolting exposed to an exterior environment of

atmosphere weather and fuel oil will be adequately managed by using the Bolting Integrity

Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated generically in the

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will

be adequately managed so that the intended function(s) will be maintained consistent with the

CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.16 Auxiliary Systems - Summary of Aging Management Evaluation - Emergency Diesel

Engine System - LRA Table 3.3.2-16

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for

the emergency diesel engine system component groups.

In LRA Table 3.3.2-16, the applicant identified no aging effects for copper alloy valves exposed

to an exterior environment of plant indoor air. The applicant applied notes G and 3 for this line

item. However, in other tables, the applicant referenced a GALL Report, Volume 2, item and

applied note A, which implies that the item is consistent with the GALL Report. The staff

requested that the applicant clarify this discrepancy.

By letter dated August 31, 2007, the applicant amended the LRA to change this line item to

reference note A and GALL Report, item VIII.I-2. The staff finds that the GALL Report line item

applies to copper alloy piping, piping components, and piping elements in an environment of air

indoor uncontrolled with no aging effects and no aging management recommended. On the

basis that the line item is now consistent with the GALL Report, the staff finds the response

acceptable.

In LRA Table 3.3.2-16, the applicant identified no aging effects for ceramic fiber insulation in a

plant indoor air environment. The applicant applied note 2 for this line item; however, note 2

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does not include ceramic fiber insulation. The staff requested that the applicant define this

insulation, explain where it is utilized in the plant, and confirm if note 2 applies.

In its response, the applicant stated that the ceramic fiber insulation is made of Kaowool

ceramic fiber blanket, and used for a DG exhaust line at the penetration of the DG room to

prevent overheat of the surrounding concrete.

By letter dated August 31, 2007, the applicant amended LRA Table 3.3.2-16, note 2, as follows:

NUREG-1 801 does not consider mechanical insulation. The in-scope thermal

insulation is located in areas with non-aggressive environments (meaning the

insulation is not exposed to contaminants). Based on the review of the site

operating experience, it was determined that for stainless steel insulation, closed

cell foam, quilted fiberglass insulation, calcium silicate, ceramic fiber, and

insulation jacketing in non-aggressive environments, there were no aging effects

requiring management.

On the basis of its review of current industry research and operating experience, the staff finds

that plant indoor air is considered a non-aggressive environment on thermal insulation material

and will not result in aging effects that will be of concern during the period of extended

operation.

By letter dated August 31, 2007, the applicant amended the LRA to add the component type of

elastomer material flex connectors exposed to an internal environment of fuel oil and lubricating

oil. The applicant identified no aging effects and applied notes G and 5. The applicant stated

that the elastomer material used is nitrile rubber, which has excellent resistance to fuel oil and

lubricating oil. Nitrile rubber decomposes when exposed to sunlight and ozone. However, these

components are indoor in an environment of lubricating or fuel oil and; therefore, are not

exposed to sunlight or ozone. Furthermore, when ambient temperature is less than 95 OF, nitrile

rubber is highly resistant to thermal exposure which could cause cracking or ultimate

elongation.

On the basis of its review of current industry research and operating experience, the staff finds

that fuel oil or lubricating oil environment on elastomer material will not result in aging effects

that will be of concern during the period of extended operation.

In LRA Table 3.3.2-16, the applicant applied note D for copper alloy heat exchanger

components exposed to an external environment of lube oil; however, a GALL Report item and

a Table 1 item were not referenced. The staff noted that note D implies that this line is

consistent with the GALL Report. Therefore, the staff requested that the applicant identify the

GALL Report and the Table 1 items. The staff stated that if the line is not consistent with the

GALL Report, the applicant should clarify the discrepancy.

In its response, the applicant stated that note D was incorrectly used. The GALL Report does

not consider reduction of heat transfer or fouling in copper alloy heat exchanger tubes exposed

to lubricating oil. Therefore, a separate plant-specific aging evaluation was created.

By letter dated August 31, 2007, the LRA was amended as follows:

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LRA Table 3.3.2-16, Emergency Diesel Engine System, Component Type (Heat

Exchanger Tube Side HX#1 50) is amended to use note H,4 in lieu of note D,4.

Plant-specific note 4 already exists for this row. No changes to the existing

plant-specific note are required.

The staff noted that this line item is now consistent with the GALL Report for plant-specific

evaluation. The staff noted that in the amended LRA Table 3.3.2-16, the applicant proposed to

manage reduction of heat transfer and fouling in copper alloy heat exchanger tubes exposed to

an internal environment of lubricating oil by using the Lubricating Oil Analysis and the One-Time

Inspection Programs. The staff's evaluation of the Lubricating Oil Analysis and the One-Time

Inspection Programs is documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3, respectively.

The staff finds that the Lubricating Oil Analysis Program maintains lubricating oil contaminants

within acceptable limits. Monitoring and trending of lubricating oil analysis results identifies

component aging prior to the loss of the component's intended function. The staff finds that the

One-Time Inspection Program is a new program that, when implemented, will be consistent

with the GALL Report. The staff also confirmed that the emergency diesel engine system is

included within the scope of the One-Time Inspection Program, where enhanced visual (i.e.,

VT-1 or equivalent) and/or volumetric (i.e., RT or UT) inspections are performed to detect loss

of material. On the basis of its review of the applicant's plant-specific and industry operating

experience, the staff finds that the aging effect of reduction of heat transfer and fouling in

copper alloy heat exchanger tubes exposed to an internal environment of lubricating oil will be

adequately managed by using the Lubricating Oil Analysis and the One-Time Inspection

Programs.

In LRA Table 3.3.2-16, the applicant applied note A for stainless steel valves exposed to an

internal environment of wetted gas; however, a GALL Report item and a Table 1 item were not

referenced. Note A implies that this line is consistent with the GALL Report. Therefore, the staff

requested that the applicant identify the GALL Report and the Table 1 items. The staff noted

that if the item is not consistent with the GALL Report, that the applicant should clarify the

discrepancy.

In its response, the applicant stated that note A was incorrectly assigned to this aging

evaluation. By letter dated August 31, 2007, the applicant amended the LRA as follows:

LRA Table 3.3.2-16, Emergency Diesel Engine System, Component Type

"Valve," environment "wetted gas" will be amended to use note G,1 in lieu of

note A,1. Plant-specific note 1 already exists for this row. No changes to the

existing plant-specific note are required.

The staff finds that this line item is now consistent with the GALL Report. The staff noted that in

the amended LRA Table 3.3.2-16, the applicant proposed to manage loss of material of

stainless steel valves exposed to an interior environment of wetted gas using the Inspection of

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff's

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program is documented in SER Section 3.0.3.1.7. The staff finds that the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

performs periodic visual inspections of internal surfaces during periodic maintenance, predictive

maintenance, surveillance testing, and corrective maintenance to detect aging effects that could

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result in a loss of the component's intended function. On the basis of its review of the

applicant's plant-specific and industry operating experience, the staff finds that the aging effect

of loss of material in stainless steel valves exposed to an interior environment of wetted gas will

be adequately managed by using the Inspection of Internal Surfaces in Miscellaneous Piping

and Ducting Components Program.

By letter dated August 31, 2007, the applicant amended the LRA to add the following

component:

Component type: "Flex Connectors"

Material: Elastomer

Environment: Closed Cycle Cooling Water (internal)

Aging Effect: Hardening and loss of strength - elastomer degradation

Aging Management Program: Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components (B2.11.22)

NUREG-1801 Volume 2 No.: None

Table 1 Item: None

Note: G

The staff's evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program is documented in SER Section 3.0.3.1.7. The staff finds that the

Inspection of Internal Surfaces In Miscellaneous Piping And Ducting Components Program

includes periodic visual inspections of internal surfaces during periodic maintenance, predictive

maintenance, surveillance testing, and corrective maintenance to detect aging effects that could

result in a loss of the component's intended function. The staff confirmed that the program

basis document was revised to add elastomers in closed-cycle cooling water to the material and

environment list within the scope of this program. On the basis of its review of the applicant's

plant-specific and industry operating experience, the staff finds that the aging effect of loss of

material in elastomer flex connections exposed to an internal environment of closed cycle

cooling water will be adequately managed by using the Inspection of Internal Surfaces in

Miscellaneous Piping and Ducting Components Program.

On the basis of its review, the staff finds that theapplicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.17 Auxiliary Systems - Summary of Aging Management Evaluation - Floor and

Equipment Drains System - LRA Table 3.3.2-17

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for

the floor and equipment drains system component groups.

In LRA Table 3.3.2-17, the applicant proposed to manage loss of material in stainless steel

piping exposed to an internal environment of wetted gas by using the Inspection of Internal

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff's evaluation of

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

is documented in SER Section 3.0.3.1.7. The staff finds that the Inspection of Internal Surfaces

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in Miscellaneous Piping and Ducting Components Program includes periodic visual inspections

of internal surfaces during periodic maintenance, predictive maintenance, surveillance testing,

and corrective maintenance to detect aging effects that could result in a loss of the

component's intended function. On the basis of its review of the applicant's plant-specific and

industry operating experience, the staff finds that the aging effect of loss of material in stainless

steel piping exposed to an interior environment of wetted gas will be adequately managed by

using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.18 Auxiliary Systems - Summary of Aging Management Evaluation - Oily Waste

System - LRA Table 3.3.2-18

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for

the oily waste system component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.3.2-18 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.19 Auxiliary Systems - Summary of Aging Management Evaluation - Cranes, Hoists,

and Elevator Systems - LRA Table 3.3.2-19

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for

the cranes, hoists, and elevator systems component groups. On the basis of its review, the staff

finds that all AMR results described in LRA Table 3.3.2-19 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.2.3.20 Auxiliary Systems - Summary of Aging Management Evaluation - Turbine Building

HVAC System - LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for

the turbine building HVAC system component groups. On the basis of its review, the staff finds

that all AMR results described in LRA Table 3.3.2-20 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.3.2.3.21 Auxiliary Systems - Summary of Aging Management Evaluation - Miscellaneous

Auxiliary Systems In-Scope only based on Criterion 10 CFR 54.4(a)(2) - LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for

the miscellaneous auxiliary systems in-scope only based on criterion 10 CFR 54.4(a)(2)

component groups.

In LRA Table 3.3.2-21, the applicant proposed to manage loss of pre-load in stainless steel and

copper alloy closure bolting exposed to an external environment of borated water leakage and

plant indoor air by using the Bolting Integrity Program.

The staff's evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.7.

The staff finds that the Bolting Integrity Program includes good bolting practices and

requirements for proper disassembling, inspecting, and assembling of connections with

threaded fasteners. The staff finds that the program is consistent with the recommendations of

the GALL Report. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff finds that the aging effect of loss of pre-load in stainless steel

and copper alloy closure bolting exposed to an external environment of borated water leakage

and plant indoor air will be adequately managed by using the Bolting Integrity Program.

The staff noted that in LRA Table 3.3.2-21, the applicant proposed to manage loss of material

in stainless steel, carbon steel, bronze, copper and copper alloy piping, tubing, and valves

exposed to an internal environment of wetted gas and potable water by using the Inspection of

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The staff's

evaluation of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting

Components Program is documented in SER Section 3.0.3.1.7. The staff finds that the

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

includes periodic visual inspections of internal surfaces during periodic maintenance, predictive

maintenance, surveillance testing, and corrective maintenance to detect aging effects that could

result in a loss of the component's intended function. On the basis of its review of the

applicant's plant-specific and industry operating experience, the staff finds that the aging effect

of loss of material in stainless steel, carbon steel, bronze, copper and copper alloy piping,

tubing, and valves exposed to an internal environment of wetted gas and potable water will be

adequately managed by using the Inspection of Internal Surfaces in Miscellaneous Piping and

Ducting Components Program.

In LRA Table 3.3.2-21, the applicant identified no aging effects for polyvinyl chloride (PVC)

piping and valves exposed externally to an external environment of atmosphere weather and

internally to an internal environment of raw water. PVC is unaffected by water, concentrated

alkalies, nonoxidizing acids, oils, ozone, sunlight, or humidity changes. Unlike metals,

thermoplastics do not display corrosion rates. Rather than depend on an oxide layer for

protection, they depend on chemical resistance to the environments to which they are exposed.

The use of thermoplastics in a water environment is a design-driven criterion. On this basis, the

staff finds that atmosphere weather and raw water environment on PVC materials will not result

in aging effects that will be of concern during the period of extended operation.

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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.3.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the auxiliary systems components within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.4 Aging Management of Steam and Power Conversion System

This section of the SER documents the staff's review of the applicant's AMR results for the

steam and power conversion system components and component groups of:

" main turbine system

" main steam

* feedwater system

" condensate system

* steam generator blowdown system

" auxiliary feedwater system

3.4.1 Summary of Technical Information in the Application

LRA Section 3.4 provides AMR results for the steam and power conversion system components

and component groups. LRA Table 3.4.1, "Summary of Aging Management Evaluations in

Chapter VIII of NUREG-1 801 for Steam and Power Conversion System," is a summary

comparison of the applicant's AMRs with those evaluated in the GALL Report for the steam and

power conversion system components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the steam and power conversion system

components within the scope of license renewal and subject to an AMR will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.4.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.4.2.2.

The staff also conducted a technical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's audit evaluations

are summarized in SER Section 3.4.2.3. The staff's evaluation of the technical review is also

documented in SER Section 3.4.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.4-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.4 and addressed in the GALL Report.

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components in

the GALL Report

.,Component Group Aging Effect/ AMP in GALL Further 'AMP in LRA, Staff-

(GALL Report Mechanism Report iEvaluation Supplements, or Evaluation

Iltem No.)ý -In GALL .' Amendments.

- - ~~~~Report _______

Steel piping, piping cumulative TLAA, evaluated in Yes TLAA Consistent with

components, and fatigue damage accordance with GALL Report

piping elements 10 CFR 54.21 (c) (See SER

exposed to steam or Section 3.4.2.2.

treated water 1)

(3.4.1-1)

Steel piping, piping Loss of material Water Chemistry Yes Water Chemistry Consistent with

components, and due to general, and One-Time ((B2.1.2) and GALL Report

piping elements pitting and Inspection One-Time (See SER

exposed to steam crevice Inspection (B2.1.16) Section 3.4.2.2.

(3.4.1-2) corrosion 2.1)

Steel heat Loss of material Water Chemistry Yes Not applicable Not applicable

exchanger due to general, and One-Time to WCGS

components pitting and Inspection (See SER

exposed to treated crevice Section 3.4.2.2.

water corrosion 2.1)

(3.4.1-3)

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Component Group Aging Effect/ :.AMP in GALL Further AMP in LRA, Staff,.,,

.. (GALL Report! Mechanism' Report Evaluation- Supplements, or Evaluation".-

Item No.) ... :in GALL Amendments

______________ ___________.Report,,,,,_ __ _ _ _ __ _ _

Steel piping, piping Loss of material Water Chemistry Yes Water Chemistry Consistent with

components, and due to general, and One-Time (B2.1.2) and GALL Report

piping elements pitting and Inspection One-Time (See SER

exposed to treated crevice Inspection (B2.1.16) Section 3.4.2.2.

water corrosion 2.1)

(3.4.1-4)

Steel heat Loss of material Water Chemistry Yes Not applicable Not applicable

exchanger due to general, and One-Time . to PWRs

components pitting, crevice, Inspection (See SER

exposed to treated and galvanic Section 3.4.2.2.

water corrosion 9)

(3.4.1-5).

Steel and stainless Loss of material Water Chemistry Yes Water Chemistry Consistent with

steel tanksexposed due to general and One-Time (B2.1.2) and GALL Report

to treated water (steel only) Inspection One-Time (See SER

(3.4.1-6) pitting and Inspection (B2.1.16) Section 3.4.2.2.

crevice. 7.1)

corrosion

Steel piping, piping Loss of material Lubricating Oil Yes- Lubricating Oil Consistent with

components, and due to general, Analysis and Analysis (B2.1.23) . GALL Report

piping elements, pitting and One-Time and One-Time (See SER

exposed to * crevice Inspection Inspection Section 3.4.2.2.

lubricating oil corrosion (3(B2.1.16) 2.2)

(3.4.1-7) .

Steel piping, piping Loss of material Plant-specific Yes Not applicable Not applicable

components, and due to general, to WCGS

piping elements pitting, crevice, (See SER

exposed to raw and micro Section 3.4.2.2.

water biologically-influ 3)

(3.4.1-8) enced

corrosion, and

fouling

Stainless steel and Reduction of Water Chemistry Yes Not applicable Not applicable

copper alloy heat. heat transfer and One-Time to WCGS

exchanger tubes due to fouling Inspection (See SER

exposed to treated Section 3.4.2.2.

water 4.1)

(3.4.1-9)

Steel, stainless Reduction of Lubricating Oil Yes Lubricating Oil Consistent with

steel, and copper heat transfer Analysis and Analysis (B2.1.23) GALL Report.

alloy heat due to fouling One-Time and One-Time (See SER

exchanger tubes Inspection Inspection Section 3.4.2.2.

exposed to (B2.1.16) .4.2)

lubricating oil

(3.4.1-10) 1

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Component Group Aging Effectl AMP in GALL -:Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

_______ _____ ______ _____ ______ ______ Report, _ _ _ _ _ _ __ _ _ _ _ _

Buried steel piping, Loss of material Buried Piping and No Buried Piping and Consistent with

piping components, due to general, Tanks Surveillance Tanks Inspection GALL Report

piping elements, pitting, crevice, (B2.1.18) (See SER

and tanks (with or and micro or Section 3.4.2.2.

without coating or biologically-influ 5.1)

wrapping) exposed enced corrosion Buried Piping and Yes

to soil . Tanks Inspection (3.4.1-11)

Steel heat Loss of material Lubricating Oil Yes Lubricating Oil Consistent with

exchanger, due to general, Analysis and Analysis (B2.1.23) GALL Report

components pitting, crevice, One-Time and One-Time (See SER

exposed to and micro Inspection Inspection Section 3.4.2.2.

lubricating oil biologically-influ (B2.1.16) 5.2)

(3.4.1-12) enced corrosion

Stainless steel Cracking due to Water Chemistry Yes Not applicable Not applicable

piping, piping SCC and One-Time to PWRs

components, piping Inspection (See SER

elements exposed Section 3.4.2.2.

to steam 6)

(3.4.1-13) ,

Stainless steel. Cracking due-to Water Chemistry Yes Water Chemistry Consistent with

piping,.piping., SCC and One-Time (B2.1.2) and GALL Report

components,' piping Inspection One-Time (See SER

elementsitanks, Inspection (B2.1.16) Section 34.2.2.

and heat exchanger 6)

components

exposed to treated

water > 60°C

(> 140°F) .

(3.4.1-14)

Aluminum and Loss of material *Water Chemistry Yes Not applicable * Not applicable

copper al!oy piping, due to pitting and One-Time to WCGS

piping components,, and crevice Inspection (See.SER

and piping elements corrosion Section 3.4.2.2.

exposed to treated 7,1)

water *

(3.4.1-15)

Stainless steel Loss of material Water Chemistry Yes Water Chemistry Consistent with

piping, piping due to pitting and One-Time (82.1.2) and GALL Report

components, and and crevice Inspection One-Time (See SER

piping elements; corrosion Inspection (B2.1.16) Section

tanks, and heat 3.4.2.2.7.1)

exchanger

components

exposed to treated

water

(3.4.1-16)

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Component Group:, Aging Effect/ AMP in GALL Further AMP in LRA, Staff

- (GALL Report. :Mechanism Report Evaluation Supplements, or Evaluation

'It o.)Ns,) in GALL Amendments

-. ________ __________ Report _'A_ _ _ _ _ _ _

Stainless steel Loss of material Plant-specific Yes Not applicable Not applicable

piping, piping due to pitting to WCGS

components, and and crevice (See SER

piping elements corrosion Section 3.4.2.2.

exposed to soil 7.2)

(3.4.1-17) :

Copper alloy piping, Loss of material Lubricating Oil Yes Not applicable Not applicable

piping components, due to pitting Analysis and to WCGS

and piping elements and crevice One-Time (See SER

exposed to corrosion Inspection Section 3.4.2.2.

lubricating oil 7.3)

(3.4.1,18)

Stainless steel Loss of material Lubricating Oil Yes Not applicable Not applicable

piping, piping due to pitting, Analysis and to WCGS

components, piping crevice, and One-Time (See SER

elements, and heat micro Inspection Section 3.4.2.2.

exchanger biologically- 8)

components influenced

exposed to corrosion

lubricating oil

(3.41-19) .

Steel tanks exposed Loss of Aboveground Steel No Not applicable Not applicable

to air - outdoor material, Tanks to WCGS

(external) general, pitting, (See SER

(3.4.1-20) and crevice Section 3.4.2.1.

corrosion 1)

High-strength steel Cracking dueto Bolting Integrity No Not applicable. Not applicable

closure bolting cyclic loading, to WCGS

exposed to air with SCC (See SER

steam or water Section 3.4.2.1.

leakage 1)

(3.4.1-21)

Steel bolting and Loss of material Bolting Integrity No Bolting Integrity Consistent with

closure bolting , due to general, (B2.1.7) GALL Report

exposed to air with pitting and

steam orwater crevice

leakage, air - corrosion; loss

outdoor (external), of preload due

or air - indoor to thermal

uncontrolled effects, gasket

(external); creep, and

(3.4.1-22) self-loosening

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Component Group Aging Effect. AMP in GALL Further AMP in LRA, Staff

S(GALL Report Mechanism Report Evaluation ,Supplements, or Evaluation

Item No.)' nGL Amendments

. ................ ___ ________Report _,_ _ _

Stainless steel, Cracking due to Closed-Cycle No Not applicable Not applicable

piping, piping SCC Cooling Water to WCGS

components, and System (See SER

piping elements Section 3.4.2.1.

exposed to 1)

closed-cycle cooling

water > 60'C

(> 140'F)

(3.4.1-23)

Steel heat Loss of material Closed-Cycle No Not applicable Not applicable

exchanger due to general, Cooling Water to WCGS

components pitting, crevice, System (See SER

exposed to closed- and galvanic Section 3.4.2.1.

cycle cooling water corrosion 1)

(3.4.1-24)

Stainless steel Loss of material Closed-Cycle No Not applicable Not applicable

piping, piping due to pitting Cooling Water to WCGS

components, piping and crevice System See SER

elements, and heat corrosion Section 3.4.2.1.

exchanger 1)

components

exposed to closed

cycle cooling water

(3.4.1-25) _

Copper alloy piping, Loss of material Closed-Cycle No Not applicable Not applicable

piping components, due to pitting, Cooling Water to WCGS

and piping elements crevice, and System See

exposed to closed galvanic Section 3.4.2.1.

cycle cooling water corrosion 1)

(3.4.1-26)

Steel, stainless Reduction of Closed-Cycle No Not applicable Not applicable

steel, and copper heat transfer Cooling Water to WCGS

alloy heat due to fouling System See SER

exchanger tubes Section 3.4.2.1.

exposed to closed 1)

cycle cooling water

(3.4.1-27)

Steel external Loss of material External Surfaces No External Surfaces Consistent with

surfaces exposed to due to general Monitoring Monitoring GALL Report

air - indoor corrosion (B2.1.20)

uncontrolled

(external),

condensation

(external), or air

outdoor. (external)

(3.4.1-28)

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,!Component Group, Aging Effect AMP . in GALL Further- AMP in LRA, Staff.q-

(GALL Report Mechanism - Report Evaluation Supplements, or Evaluation

Itemn No.) , in GALL Amendments'

_____________ ___________ ______________ !Report . .......

Steel piping, piping Wall thinning Flow-Accelerated No Flow-Accelerated Consistent with

components,• and due to Corrosion Corrosion (B2.1.6) GALL Report

piping elements flow-accelerate

exposed to steam or d corrosion

treated water

(3.4.1-29)

Steel piping, piping Loss of material Inspection of No Inspection of Consistent with

components, and due to general, Internal Surfaces in Internal Surfaces in GALL Report

piping elements pitting, and Miscellaneous Miscellaneous

exposed to air crevice Piping and Ducting Piping and Ducting

outdoor (internal) or corrosion Components Components

condensation (B2.1.22)

(internal)

(3.4.1-30)

Steel heat Loss of material Open-Cycle Cooling No Not applicable Not applicable

exchanger due to general, Water System to WCGS

components pitting, crevice, (See SER

exposed to raw galvanic, and Section 3.4.2.1.

water micro 1)

(3.4.1-31) biologically-influ

enced

corrosion, and

_fouling

Stainless steel and Loss of material Open-Cycle Cooling No Not applicable Not applicable

copper alloy piping, due to pitting, Water System to WCGS

piping components, crevice, and (See SER

and piping elements micro Section 3.4.2.1.

exposed to raw biologically-influ . 1)

water enced corrosion

(3.4.1-32)

Stainless steel heat Loss ofmaterial Open-Cycle Cooling No Not applicable Not applicable

exchanger due to pitting, Water System to WCGS

components crevice, and (See SER

exposed to raw. micro Section'3.4.2.1.

water biologically-influ 1)

(3.4.1-33) enced:

corrosion, and

fouling

Steel, stainless Reduction of Open-Cycle Cooling. No Not applicable Not applicable

steel, and copper heat transfer Water System to WCGS

alloy heat due to fouling (See SER

exchanger tubes Section 3.4.2.1.

exposed to raw 1)

water

(314.1-34)

3-316
Component Group Aging Effect/ AMP in GALL Further" AMP in LRA, Staff

(GALL Report 'Mechanism , Report! Evaluation, Supplements, or Evaluation

Item No.). in GALL,; Amendments

_______________i;':•!ii.i;:•!:i~iii ____________l! __ Report _ _ _ __ _ _ _

Copper alloy Loss of material Selective Leaching No Not applicable Not applicable

> 15% Zn piping, due to selective of Materials to WCGS

piping components, leaching (See SER

and piping elements Section 3.4.2.1.

exposed to closed 1)

cycle cooling water,

raw water, or treated

water

(3.4.1-35)

Gray cast iron Loss of material Selective Leaching No Selective Leaching Consistent with

piping, piping due to selective of :Materials of Materials GALL Report.

components, and leaching (B2.1.17) (See SER

piping elements Section 3.4.2.1.

exposed to soil, 1)

treated water, or raw

water

(3.4.1-36)

Steel, stainless Loss of material Water Chemistry No Water Chemistry Consistent with

steel, and due to pitting (B2.1.2) GALL Report

nickel-based alloy and crevice

piping, piping corrosion

components, and

piping elements

exposed to steam

(3.4.1-37)

Steel bolting and Loss of material Boric Acid Corrosion No Not applicable Not applicable

external surfaces due to boric -to WCGS

exposed to air with acid corrosion . (See SER

borated water Section 3.4.2.1.

leakage 1)

(3.4.1-38)

Stainless steel Cracking due to Water Chemistry No Water Chemistry Consistent with

piping,ýpiping SCC- (B2.1.2) GALL Report

components, and

piping elements

exposed to steam

(3.4.1-39).,

Glass piping None None No None Consistent with

elements exposed *GALL Report

to air, lubricating oil,

raw water, and

treated water

(3.4.1-40)

3-317
:Component Group Aging Effectl - AMP in GALL Further AMP in LRA, Staff

-(GALL Report2 . -Mechanism ',Report., :Evaluation Supplements, or Evaluation

Item No.),:ý'& In GALL.. Amendments __.... _____ ________ __________I: .•.i Report- _ _ _ _ _ _

Stainless steel, None None No None Consistent with

copper alloy, and GALL Report

nickel alloy piping,

piping components,

and pipingelements

exposed to air .

indoor uncontrolled

(external)

(3.4.1-41)

Steel piping, piping None None No Not applicable Not applicable

components, and . to WCGS

piping elements *(See SER

expos edto air - . Section 3.4.2.1.

indoor controlled 1)

(external)

(3.4.1-42) .. _

Steel and stainless None None No Not applicable Not applicable

steel piping,.piping to WCGS

components, and (See SER

piping elements in Section 3.4.2.1.

concrete . 1)

(3.4.1-43)

Steel, stainless None None No None Consistent with

steel, aluminum, GALL Report

and copper alloy

piping,piping

components, and

piping elements

exposed to gas

(3.4.1-44)

The staff's review of the steam and power conversion system component groups followed any

one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR

results for components that the applicant indicated are consistent with the GALL Report and

require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed

AMR results for components' that the applicant indicated are consistent with the GALL Report

and for which further evaluation is recommended. A third approach, documented in SER

Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the steam and power conversion system components is

documented in SER Section 3.0.3.

3.4.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the steam and power conversion system components:

Water Chemistry

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* Flow-Accelerated Corrosion

* Bolting Integrity

* One-Time Inspection

* Buried Piping and Tanks Inspection

* External Surfaces Monitoring

* Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

* Lubricating Oil Analysis

LRA Tables 3.4.2-1 through 3.4.2-6 summarize AMRs for the steam and power conversion

system components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

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whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs. The staff's evaluation follows.

3.4.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.4.1, the applicant identified items 20, 21, 23, 24, 25, 26, 27, 31, 32, 33, 34, 35,

36, 38, 40, 42, and 43 as not applicable because the component, material, and environment

combination does not apply to components within the scope of license renewal at WCGS.

However, as a result of the staff's review, by letter dated August 31, 2007, the applicant

amended the LRA to add components within the scope of license renewal that utilize item

numbers 36 and 40. These items are now applicable and have been addressed in this SER. For

each of the remaining items, the staff reviewed the LRA and the applicant's supporting

documents and confirmed the applicant's claim that the component, material, and environment

combination does not exist at WCGS. On the basis that WCGS does not have this combination,

the staff finds that these AMRs are not applicable to WCGS.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the steam and power conversion system components and provides

information concerning how it will manage the following aging effects and related QA:

* cumulative fatigue damage

" loss of material due to general, pitting, and crevice corrosion

* loss of material due to general, pitting, crevice, and MIC, and fouling

* reduction of heat transfer due to fouling

* loss of material due to general, pitting, crevice, and MIC

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* cracking due to SCC

* loss of material due to pitting and crevice corrosion

• loss of material due to pitting, crevice, and MIC

* loss of material due to general, pitting, crevice, and galvanic corrosion

* QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staff's review of the

applicant's further evaluation follows.

3.4.2.2.1 Cumulative Fatigue Damage

LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.3 documents the staff's

review of the applicant's evaluation of this TLAA.

3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.2 against the following criteria in SRP-LR

Section 3.4.2.2.2:

(1) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in steel piping and components, tanks, and heat exchangers exposed to

treated water and steel piping and components exposed to steam. The applicant stated

that the Water Chemistry and the One-Time Inspection Programs will manage this aging

effect in carbon steel components exposed to secondary water. The one-time inspection

will include selected components at susceptible locations where contaminants could

accumulate (e.g., stagnant flow locations and tank bottoms).

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, piping elements, tanks, and

heat exchanger components exposed to treated water and for steel piping, piping

components, and piping elements exposed to steam. The existing AMP monitors and

controls water chemistry to manage the effects of loss of material due to general, pitting,

and crevice corrosion. However, control of water chemistry does not preclude loss of

material due to general, pitting, and crevice corrosion at locations with stagnant flow

conditions; therefore, the effectiveness of water chemistry control programs should be

verified to ensure that corrosion does not occur. The GALL Report recommends further

evaluation of programs to verify the effectiveness of water chemistry control programs.

A one-time inspection of selected components and susceptible locations is an

acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

In LRA Table 3.4.1, items 2 and 4, the applicant addresses loss of material due to

general, pitting, and crevice corrosion in steel piping, piping components, and piping

elements exposed to steam or treated water. During the audit, the staff confirmed that

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the applicant utilizes the Water Chemistry Program to manage these aging effects. The

staff finds that the One-Time Inspection Program will be used to verify the effectiveness

of the water chemistry control. This program performs inspection of selected

components at susceptible locations, as recommended by the GALL Report.

The staff reviewed the One-Time Inspection Program, which is a new program that,

when implemented, will be consistent with the GALL Report. The staff's evaluation of

the Water Chemistry and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to general, pitting, and crevice corrosion in

steel piping, piping components, and piping elements exposed to steam or treated

water.

In LRA Table 3.4.1, item 3, the applicant stated that this item is not applicable. The

applicant states that WCGS has no heat exchangers in the condensate or blowdown

systems within the scope of license renewal; therefore, the applicable GALL Report lines

were not used. The staff reviewed the plant basis documents and interviewed technical

personnel to verify that WCGS does not has these components within the scope of

license renewal. The staff finds that this item is not applicable to WCGS.

(2) LRA Section 3.4.2.2.2 addresses loss of material due to general, pitting, and crevice

corrosion in steel piping and components exposed to lubricating oil. The applicant stated

that the Lubricating Oil Analysis and the One-Time Inspection Programs will manage

this aging effect in carbon steel components exposed to lubricating oil. The one-time

inspection will include selected components at susceptible locations where contaminants

such as water could accumulate.

SRP-LR Section 3.4.2.2.2 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel piping, piping components, and piping elements exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that corrosion does not occur. The

GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of lube oil chemistry control programs. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

In LRA Table 3.4.1, item 07, the applicant addresses loss of material due to general,

pitting, and crevice corrosion in steel piping, piping components, and piping elements

exposed to lubricating oil. The applicant credits the Lubricating Oil Analysis Program to

manage loss of material aging effect. The One-Time Inspection Program is used to

verify the effectiveness of the lube oil chemistry control by performing an inspection of

selected components at susceptible locations, as recommended by the GALL Report.

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The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Lubricating Oil Analysis and the One-Time

Inspection Programs is documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3,

respectively. The staff finds that these programs include activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to general, pitting, and crevice corrosion in steel piping, piping

components, and piping elements exposed to lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion and Fouling

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.

LRA Section 3.4.2.2.3 addresses loss of material due to general, pitting, crevice, and MIC, and

fouling. The applicant stated that this aging effect is not applicable because WCGS does not

have components exposed to raw water in the AFW system that are within the scope of license

renewal.

SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevice

corrosion, and MIC and fouling may occur in steel piping, piping components, and piping

elements exposed to raw water. The GALL Report recommends further evaluation of a

plant-specific AMP to ensure that these aging effects are adequately managed.

In LRA Table 3.4.1, item 8, the applicant stated that this item is not applicable. The applicant

stated that there are no components exposed to raw water in the AFW system that are within

the scope of license renewal; therefore, the applicable GALL Report line was not used. The

staff reviewed the plant basis documents and interviewed the technical personnel to verify that

WCGS does not has these components within the scope of license renewal. The staff finds that

this item is not applicable to WCGS.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.4.2.2.3 criteria. The staff determines that the LRA is consistent with the

GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the. intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.4.2.2.4 Reduction of Heat Transfer Due to Fouling

The staff reviewed LRA Section 3.4.2.2.4 against the following criteria in SRP-LR

Section 3.4.2.2.4:

(1) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in stainless

steel and copper alloy heat exchanger tubes exposed to treated water. The applicant

stated that this aging effect is not applicable because WCGS does not have heat

exchangers in the condensate or blowdown systems, nor heat exchangers with a heat

transfer intended function in the AFW system that are within the scope of license

renewal.

SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur

in stainless steel and copper alloy heat exchanger tubes exposed to treated water. The

existing AMP controls water chemistry to manage reduction of heat transfer due to

fouling. However, control of water chemistry may not always be fully effective in

precluding fouling; therefore, the GALL Report recommends that the effectiveness of

water chemistry control programs should be verified to ensure that reduction of heat

transfer due to fouling does not occur. A one-time inspection is an acceptable method to

ensure that reduction of heat transfer does not occur and that component intended

functions will be maintained during the period of extended operation.

In LRA Table 3.4.1, item 9, the applicant stated that this item is not applicable. The

applicant stated that WCGS has no heat exchangers in the condensate or blowdown

systems, and no heat exchangers with a heat transfer intended function in the AFW

system that are within the scope of license renewal. The staff reviewed plant basis

documents and interviewed the technical personnel to verify that WCGS does not has

these components within the scope of license renewal. The staff finds that this item is

not applicable to WCGS.

(2) LRA Section 3.4.2.2.4 addresses reduction of heat transfer due to fouling in stainless

steel and copper alloy heat exchanger tubes exposed to lubricating oil. The applicant

stated that the Lubricating Oil Analysis and the One-Time Inspection Programs will

manage reduction of heat transfer due to fouling for carbon steel components exposed

to lubricating oil. The one-time inspection will include selected components at

susceptible locations where contaminants such as water could accumulate.

SRP-LR Section 3.4.2.2.4 states that reduction of heat transfer due to fouling may occur

in steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating

oil. The existing AMP monitors and controls lube oil chemistry to mitigate reduction of

heat transfer due to fouling. However, control of lube oil chemistry may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that fouling does not occur. The GALL

Report recommends further evaluation of programs to verify the effectiveness of lube oil

chemistry control programs. A one-time inspection of selected components at

susceptible locations is an acceptable method to determine whether an aging effect is

occurring or is slowly progressing such that the component's intended functions will be

maintained during the period of extended operation.

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In LRA Table 3.4.1, item 10, the applicant addresses reduction of heat transfer due to

fouling in steel, stainless steel, and copper alloy heat exchanger tubes exposed to

lubricating oil. The staff noted that the applicant utilizes the Lubricating Oil Analysis

Program to manage reduction of heat transfer aging effect. The One-Time Inspection

Program is used to verify the effectiveness of the lube oil chemistry control by

performing an inspection of selected components at susceptible locations, as

recommended by the GALL Report.

The staff reviewed the Lubricating Oil Analysis Program and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Lubricating Oil Analysis and the One-Time

Inspection Programs is documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3,

respectively. The staff finds that these programs include activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage reduction

of heat transfer due in fouling for steel, stainless steel, and copper alloy heat exchanger

tubes exposed to lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.4 criteria. For those line items that apply to LRA Section 3.4.2.2.4, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced

Corrosion

The staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR Section 3.4.2.2.5:

(1) LRA Section 3.4.2.2.5 addresses loss of material due to general, pitting, crevice, and

MIC in steel piping and components and tanks exposed to soil. The applicant stated that

the Buried Piping and Tanks Inspection Program will manage this aging effect in carbon

steel external surfaces of buried components. Buried steel piping at WCGS is coated

and/or wrapped in accordance with industry standards. A review of plant-specific

operating history indicated one case of a pin hole leak failure of a buried fire protection

system piping that is within the scope of license renewal. The failure resulted from a loss

of material due to external pitting corrosion underneath a holiday (discontinuity) in the

protective coating, which was subsequently weld repaired. In addition, the applicant

stated that WCGS does not have any documented below grade aggressive environment

conditions, and that although all buried piping within the scope of license renewal is

protected by the cathodic protection system, no credit is taken for this for aging

management. Based on the above, the applicant concluded that application of the

wrapping and/or coating, and the programmatic inspection of their condition will be

adequate to manage loss of material due to external corrosion.

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SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel (with or without coating or wrapping) piping,

piping components, piping elements, and tanks exposed to soil. The buried piping and

tanks inspection program relies on industry practice, frequency of pipe excavation, and

operating experience to manage the effects of loss of material from general, pitting, and

crevice corrosion, and MIC. The effectiveness of the buried piping and tanks inspection

program should be verified to evaluate an applicant's inspection frequency and

operating experience with buried components to ensure that loss of material does not

occur.

In LRA Table 3.4.1, item 11, the applicant addresses loss of material due to general,

pitting, crevice, and microbiologically-influenced corrosion in buried steel piping, piping

components, piping elements, and tanks (i.e., with or without coating or wrapping)

exposed to soil. The staff reviewed the applicant's new Buried Piping and Tanks

Inspection Program and its plant operating experience with buried piping. The staff

noted that all the buried piping that is within the scope of license renewal is coated

and/or wrapped, and protected by the cathodic protection system. The new Buried

Piping and Tanks Inspection Program will be implemented within the 10-year period

before entering the period of extended operation, during which time an opportunistic or

planned inspection will be performed. Upon entering the period of extended operation,

the program will require a planned inspection within ten years unless an opportunistic

inspection has occurred.

The staff's evaluation of the Buried Piping and Tanks Inspection Program is

documented in SER Section 3.0.3.1.4. The staff finds that this program includes

activities that are consistent with the recommendations in the GALL Report, and are

adequate to manage loss of material due to general, pitting, crevice, and

microbiologically-influenced corrosion (MIC) in buried steel piping, piping components,

piping elements, and tanks (with or without coating or wrapping) exposed to soil.

(2) LRA Section 3.4.2.2.5 addresses loss of material due to general, pitting, crevice, and

MIC in steel heat exchanger components exposed to lubricating oil. The applicant stated

that the Lubricating Oil Analysis and the One-Time Inspection Programs will manage

this aging effect in carbon steel components exposed to lubricating oil. The one-time

inspection will include selected components at susceptible locations where contaminants

such as water could accumulate.

SRP-LR Section 3.4.2.2.5 states that loss of material due to general, pitting, and crevice

corrosion, and MIC may occur in steel heat exchanger components exposed to

lubricating oil. The existing AMP periodically samples and analyzes lubricating oil to

maintain contaminants within acceptable limits, thereby preserving an environment not

conducive to corrosion. However, control of lube oil contaminants may not always be

fully effective in precluding corrosion; therefore, the effectiveness of lubricating oil

contaminant control should be verified to ensure that corrosion does not occur. The

GALL Report recommends further evaluation of programs to manage corrosion to verify

the effectiveness of the lube oil chemistry control program. A one-time inspection of

selected components at susceptible locations is an acceptable method to ensure that

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corrosion does not occur and that component intended functions will be maintained

during the period of extended operation.

In LRA Table 3.4.1, item 12, the applicant addresses loss of material due to general,

pitting, crevice, and microbiologically-influenced corrosion in steel heat exchanger

components exposed to lubricating oil. The staff noted that the applicant utilizes the

Lubricating Oil Analysis Program to manage loss of material. The staff finds that the

One-Time Inspection Program will be used to verify the effectiveness of the lube oil

chemistry control by performing an inspection of selected components at susceptible

locations, as recommended by the GALL Report.

The staff reviewed the Lubricating Oil Analysis Program, and finds that it maintains

lubricating oil contaminants within acceptable limits. Monitoring and trending of

lubricating oil analysis results identifies component aging prior to the loss of the

component's intended function. The staff reviewed the One-Time Inspection Program,

which is a new program that, when implemented, will be consistent with the GALL

Report. The staff's evaluation of the Lubricating Oil Analysis and the One-Time

Inspection Programs is documented in SER Sections 3.0.3.2.16 and 3.0.3.1.3,

respectively. The staff finds that these programs include activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage loss of

material due to general, pitting, crevice, and microbiologically-influenced corrosion in

steel heat exchanger components exposed to lubricating oil.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.5 criteria. For those line items that apply to LRA Section 3.4.2.2.5, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6.

LRA Section 3.4.2.2.6 addresses cracking due to SCC. The applicant stated that the Water

Chemistry and the One-Time Inspection Programs will manage this aging effect in stainless

steel components exposed to secondary water. The one-time inspection will include selected

components at susceptible locations where contaminants could accumulate (e.g., stagnant flow

locations).

SRP-LR Section 3.4.2.2.6 states that cracking due to SCC may occur in stainless steel piping,

piping components, piping elements, tanks, and heat exchanger components exposed to

treated water greater than 60 °C (140 OF) and in stainless steel piping, piping components, and

piping elements exposed to steam. The existing AMP monitors and controls water chemistry to

manage the effects of cracking due to SCC. However, high concentrations of impurities in

crevices and with stagnant flow conditions may cause SCC; therefore, the GALL Report

recommends that the effectiveness of water chemistry control programs should be verified to

ensure that SCC does not occur. A one-time inspection of selected components at susceptible

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locations is an acceptable method to ensure that SCC does not occur and that component

intended functions will be maintained during the period of extended operation.

In LRA Table 3.4.1, item 14, the applicant addresses cracking due to SCC in stainless steel

piping, piping components, piping elements, tanks, and heat exchanger components exposed

to treated water with a temperature grater than 140 OF. The staff noted that the applicant

utilizes the Water Chemistry Program to manage SCC. The One-Time Inspection Program will

be used to verify the effectiveness of water chemistry by performing an inspection of selected

components at susceptible locations, as recommended by the GALL Report.

The staff reviewed the One-Time Inspection Program, which is a new program that, when

implemented, will be consistent with the GALL Report. The staff's evaluation of the Water

Chemistry and the One-Time Inspection Programs is documented in SER Sections 3.0.3.2.2

and 3.0.3.1.3, respectively. The staff finds that these programs include activities that are

consistent with the recommendations in the GALL Report, and are adequate to manage

cracking due to SCC in stainless steel piping, piping components, and piping elements; tanks;

and heat exchanger components exposed to treated water with a temperature greater than

140 OF.

In LRA Table 3.4.1, item 13, the applicant stated that this item is not applicable to WCGS

because this item only applies to a BWR. The staff finds that this item applies to BWR systems

and; therefore, is not applicable because WCGS is a PWR. On this basis, the staff finds that

this aging effect is not applicable to this component type.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.6 criteria. For those line items that apply to LRA Section 3.4.2.2.6, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.4.2.2.7 against the criteria in SRP-LR Section 3.4.2.2.7:

(1) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

stainless steel, aluminum, and copper alloy piping and components, and stainless steel

tanks and heat exchangers exposed to treated water.

The applicant stated that the Water Chemistry and the One-Time Inspection Programs

will manage this aging effect in stainless steel components exposed to secondary water.

The one-time inspection will include selected components at susceptible locations where

contaminants could accumulate such as stagnant flow locations and tank bottoms.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion may occur in stainless steel, aluminum, and copper alloy piping, piping

components, and piping elements, and in stainless steel tanks and heat exchanger

components exposed to treated water. The existing AMP monitors and controls water

chemistry to manage the effects of loss of material due to pitting and crevice corrosion.

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However, control of water chemistry may not preclude corrosion at locations with

stagnant flow conditions; therefore, the GALL Report recommends that the

effectiveness of water chemistry programs should be verified to ensure that corrosion

does not occur. A one-time inspection of selected components at susceptible locations

is an acceptable method to ensure that corrosion does not occur and that component

intended functions will be maintained during the period of extended operation.

The staff noted that in LRA Table 3.4.1, item 3.4.1.15, the applicant stated that this item

is not applicable. The applicant stated that WCGS has no aluminum or copper alloy

components in the steam turbine, FW, condensate, blowdown, or AFW systems that are

within the scope of license renewal. The staff reviewed plant basis documents and

interviewed the technical personnel to confirm that WCGS has no aluminum or copper

alloy components in the steam turbine, FW, condensate, blowdown, or AFW systems

within the scope of license renewal. The staff finds that this item is not applicable to

WCGS.

In LRA Table 3.4.1, item 16, the applicant addresses loss of material due to general,

pitting, and crevice corrosion in stainless steel piping, piping components, and piping

elements, and in stainless steel tanks and heat exchanger components exposed to

treated water. The staff noted that the applicant utilizes the Water Chemistry Program to

manage loss of material. The One-Time Inspection Program will be used to verify the

effectiveness of the water chemistry control by performing an inspection of selected

components at susceptible locations, as recommended by the GALL Report.

The staff reviewed the One-Time Inspection Program, which is a new program that,

when implemented, will be consistent with the GALL Report. The staff's evaluation of

the Water Chemistry and the One-Time Inspection Programs is documented in SER

Sections 3.0.3.2.2 and 3.0.3.1.3, respectively. The staff finds that these programs

include activities that are consistent with the recommendations in the GALL Report, and

are adequate to manage loss of material due to general, pitting, and crevice corrosion in

stainless steel piping, piping components, and piping elements, and in stainless steel

tanks and heat exchanger components exposed to treated water.

(2) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

stainless steel piping and components exposed to soil. The applicant stated that this

aging effect is not applicable because WCGS does not have stainless steel components

exposed to soil in the condensate or AFW system that are within the scope of license

renewal.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion could occur for stainless steel piping, piping components, and piping elements

exposed to soil. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that this aging effect is adequately managed.

In LRA Table 3.4.1, item 17, the applicant stated that this item is not applicable. The

applicant stated that WCGS has no stainless steel components exposed to soil in the

condensate or AFW system that are within the scope of license renewal. The staff

reviewed plant basis documents and interviewed the technical personnel to verify that

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WCGS does not has these components within the scope of license renewal. The staff

finds that this item is not applicable to WCGS.

(3) LRA Section 3.4.2.2.7 addresses loss of material due to pitting and crevice corrosion in

copper alloy piping and components exposed to lubricating oil. The applicant stated that

this aging effect is not applicable because WCGS does not have copper alloy

components exposed to lubricating oil in the main steam, main turbine, FW,

condensate, steam generator blowdown, or AFW systems that are within the scope of

license renewal.

SRP-LR Section 3.4.2.2.7 states that loss of material due to pitting and crevice

corrosion may occur in copper alloy piping, piping components, and piping elements

exposed to lubricating oil. The existing AMP relies on the periodic sampling and analysis

of lubricating oil to maintain contaminants within acceptable limits, thereby preserving an

environment that is not conducive to corrosion. However, control of lube oil

contaminants may not always have been adequate to preclude corrosion. Therefore, the

effectiveness of lubricating oil contaminant control should be verified to ensure that

corrosion is not occurring. The GALL Report recommends further evaluation of

programs to verify the effectiveness of the lube oil chemistry control program. A

one-time inspection of selected components at susceptible locations is an acceptable

method to ensure that corrosion does not occur and that the component's intended

function will be maintained during the period of extended operation.

In LRA Table 3.4.1, item 18, the applicant stated that this item is not applicable. The

applicant stated that WCGS has no copper alloy components exposed to lube oil in the

steam turbine, FW, condensate, or AFW systems that are within the scope of license

renewal. The staff reviewed plant basis documents and interviewed the technical

personnel to verify that WCGS does not has these components (copper alloy

components exposed to lube oil in the steam turbine). Therefore, these are not

applicable to be within the scope of license renewal. The staff finds that this item is not

applicable to WCGS.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 3.4.2.2.7, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8.

LRA Section 3.4.2.2.8 addresses loss of material due to pitting, crevice, and MIC. The applicant

stated that this aging effect is not applicable because WCGS does not have stainless steel

components exposed to lube oil in the steam turbine, FW, condensate, or AFW systems that

are within the scope of license renewal.

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SRP-LR Section 3.4.2.2.8 states that loss of material due to pitting and crevice corrosion, and

MIC may occur in stainless steel piping, piping components, piping elements, and heat

exchanger components exposed to lubricating oil.

In LRA Table 3.4.1, item 19, the applicant stated that this line item is not applicable. The

applicant stated that WCGS has no stainless steel components exposed to lubricating oil in the

steam turbine, FW, condensate, or AFW systems that are within the scope of license renewal.

The staff reviewed plant basis documents and interviewed the technical personnel to verify that

WCGS does not has these components within the scope of license renewal. The staff finds that

this item is not applicable to WCGS.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.4.2.2.8 criteria. The staff determines that the LRA is consistent with the

GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion

The staff reviewed LRA Section 3.4.2.2.9 against the criteria in SRP-LR Section 3.4.2.2.9.

LRA Section 3.4.2.2.9 addresses loss of material due to general, pitting, crevice, and galvanic

corrosion. The applicant stated that this aging effect is not applicable because WCGS is a

PWR.

SRP-LR Section 3.4.2.2.9 states that loss of material due to general, pitting, crevice, and

galvanic corrosion may occur in steel heat exchanger components exposed to treated water.

The staff noted that this item applies to BWR systems and; therefore, is not applicable because

WCGS is a PWR. On this basis, the staff finds that this aging effect is not applicable to this

component type.

Based on its review and confirmation above, the staff concludes that the applicant meets

SRP-LR Section 3.4.2.2.9 criteria. The staff determines that the LRA is consistent with the

GALL Report and that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.4.2-1 through 3.4.2-6, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

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In LRA Tables 3.4.2-1 through 3.4.2-6, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.4.2.3.1 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Main Turbine System - LRA Table 3.4.2-1

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the

main turbine system component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.4.2-1 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.2 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Main Steam System - LRA Table 3.4.2-2

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the

main steam system component groups.

In LRA Table 3.4.2-2, the applicant applied Note J for insulation in the main steam system. The

insulation is calcium silicate with aluminum sheathing and is exposed to the indoor air

environment. The applicant did not identify an aging effect requiring management for these

material and environment combinations.

During the audit, the staff requested that the applicant justify why an aging effect requiring

management was not considered for the insulation.

In its response, the applicant stated that the subject insulation is located indoors and is exposed

to a non-aggressive indoor air environment. The staff finds that the GALL Report states that no

agingeffects are applicable to aluminum piping components that are exposed to indoor air

environment. The staff requested that the applicant explain why they did not specify the GALL

Report item for the material and environment combination.

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By letter dated August 31, 2007, the applicant amended the LRA to include GALL Report, item

V.F-2, Table 1 Item 3.2.1.50, and Note C for aluminum jacketing in plant indoor air. The staff

finds that this item is now consistent with the GALL Report; therefore, the applicant's response

is acceptable.

On the basis of its review of the current industry research and operating experience, the staff

concludes that, since the insulation that is within the scope of license renewal is covered by

aluminum sheathing and is not directly exposed to the indoor air, the aging of the insulation will

not be a concern during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.3 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Feedwater System - LRA Table 3.4.2-3

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the

FW system component groups.

In LRA Table 3.4.2-3, the applicant applied Note J for insulation in the FW system. The

insulation is aluminum and calcium silicate and is exposed to the indoor air environment. The

applicant did not identify an aging effect requiring management for these material and

environment combinations. During the site audit, the staff requested that the applicant justify

why an aging effect requiring management was not considered for the insulation.

In its response, the applicant stated that the subject insulation is located indoors and is exposed

to a non-aggressive indoor air environment. The staff finds that the GALL Report states that no

aging effects are applicable to aluminum piping components that are exposed to indoor air

environment. The staff requested that the applicant explain why a GALL Report item for the

material and environment combination was not identified.

By letter dated August 31, 2007, the applicant amended the LRA to include GALL Report item

V.F-2, Table 1 Item 3.2.1.50, and Note C for aluminum jacketing in plant indoor air. Since this

line item is now consistent with the GALL Report, the staff finds it acceptable.

On the basis of its review of the current industry research and operating experience, the staff

concludes that, since the insulation is not directly exposed to the indoor air, the aging will not be

a concern during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

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3.4.2.3.4 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Condensate System - LRA Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the

condensate system component groups.

In LRA Table 3.4.2-4, the applicant applied Note G for the external surface of stainless steel

tank in the condensate system. The tank exterior is exposed to atmosphere weather conditions.

The applicant did not identify an aging effect requiring management for this tank under the

stated environment condition.

During the audit, the staff requested that the applicant clarify if the subject tank is located above

ground or partially buried. The staff also requested that the applicant justify why an aging effect

requiring management was not considered for the tank exterior.

In its response, the applicant clarified that the subject tank is the CST, which is made of

stainless steel and located above ground on a concrete foundation. The applicant also stated

that it applied note G to the tank because the atmosphere weather environment for stainless

steel is not addressed in the GALL Report. The applicant's response also stated that the plant

outdoor environment at WCGS is not subject to industrial air pollution or saline environment and

that the stainless steel tank is not exposed to aggressive chemical species.

The staff noted that alternate wetting and drying resulting from rain has shown a tendency to

wash the exterior surface material rather than concentrate contaminants. The SCC in stainless

steel, which is considered plausible in wetted corrosive environments with a temperature

greater than 140 °F, will not occur in the outside air environment. Also, in the absence of the

corrosive contaminants on the exterior surface, the tank surface should not be susceptible to

loss of material.

The staff also noted that the loss of material in the tank interior exposed to secondary water is

adequately controlled by the Water Chemistry and One-Time Inspection Programs. Based on

its review, the staff concludes that for the exterior surface of the stainless steel tank exposed to

outdoor atmosphere weather, there is no aging effect requiring management because the tank

is neither susceptible to surface corrosion nor to SCC given the absence of corrosive

contaminants and the lack of wetted corrosive environment with temperature greater than

140 OF.

By letter dated August 31, 2007, the applicant amended the LRA to add the stainless steel

rupture disc component in an exterior environment of atmosphere weather with no aging effects

and aging management required. The applicant applied note G to this new line item.

On the basis that this tank has the same material and environment combination, the staff finds

that there is no aging effect requiring management because the rupture disc is neither

susceptible to surface corrosion nor to SCC given the absence of any corrosive contaminants

and the lack of wetted corrosive environment with temperature greater than 140 OF.

In LRA Table 3.4.2-4, the applicant applied note H for steel closure bolting in the condensate

system. This closure bolting is carbon steel and is exposed to outdoor atmosphere weather

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conditions. The applicant proposed to manage loss of preload in these components by using

the Bolting Integrity Program.

During the audit, the staff requested that the applicant explain where this closure bolts are

located.

In its response, the applicant clarified that the examples of such closure bolting are carbon steel

bolts or studs installed on valves and flanges exposed to atmosphere weather. The staff noted

that the GALL Report does not have a loss of preload line item for steel closure bolting exposed

to an atmosphere weather environment. The staff noted that the Bolting Integrity Program

requires that the bolting installation plant procedures control joint assembly and pre-load. This

includes pre-assembly inspection and cleaning requirements, use of specific bolt torque

patterns, use of increased torque application through multiple passes, and verification of the

gasket compression. The staff also noted that post-bolting inspections include verification of

contact between the fastener and flange, and proper flange alignment. Additionally, the same

program is used to manage loss of pre-load for closure bolting exposed to environments

discussed in the GALL Report. The staff's evaluation of the Bolting Integrity Program is

documented in SER Section 3.0.3.2.7.

On the basis of its review of the applicant's plant-specific and industry operating experience, the

staff finds that the aging effect of loss of pre-load in carbon steel closure bolting exposed to an

environment of outdoor atmosphere weather conditions will be adequately managed using the

Bolting Integrity Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.5 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Steam Generator Blowdown System - LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the

steam generator blowdown system component groups.

In LRA Table 3.4.2-5, the applicant applied Note J for insulation in the steam generator

blowdown system. This insulation is calcium silicate or foamglass with aluminum or stainless

steel sheathing and is exposed to an environment of indoor air. In the LRA, the applicant did not

identify an aging effect requiring management for these material and environment

combinations.

During the audit, the staff requested that the applicant justify why an aging effect requiring

management was not considered for the insulation.

In its response, the applicant stated that the subject insulation is located indoors and is exposed

to a non-aggressive indoor air environment. The staff finds that the GALL Report states that no

aging effects are applicable to aluminum or stainless steel piping components that are exposed

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to an indoor air environment. The staff requested that the applicant explain why a GALL Report

item was not specified for this material and environment combination.

By letter dated August 31, 2007, the applicant amended the LRA to add the component type of

aluminum material insulation, referencing GALL Report, item V.F-2, and Note C. By letter dated

October 11, 2007, the applicant amended the LRA to add the component type of insulation

made of stainless steel, referencing GALL Report, item VIII.1-10, and Note C. Since these line

items are now consistent with the GALL Report, the staff finds that the applicant's response is

acceptable.

On the basis of its review of the current industry research and operating experience, the staff

concludes that, because the insulation that is within the scope of license renewal is covered by

aluminum or stainless steel sheathing and is not directly exposed to the indoor air, the aging of

the insulation will not be a concern during the period of extended operation.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.2.3.6 Steam and Power Conversion System - Summary of Aging Management Evaluation -

Auxiliary Feedwater System - LRA Table 3.4.2-6

The staff reviewed LRA Table 3.4.2-6, which summarizes the results of AMR evaluations for the

AFW system component groups. On the basis of its review, the staff finds that all AMR results

described in LRA Table 3.4.2-6 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.4.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the steam and power conversion system components within the scope

of license renewal and subject to an AMR will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation, as

required by 10 CFR 54.21 (a)(3).

3.5 Aging Management of Containments, Structures and Component Supports

This section of the SER documents the staff's review of the applicant's AMR results for the

containments, structures and component supports components and component groups of:

• reactor building

* control building

• diesel generator building

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* turbine building

* auxiliary building

* radwaste building

* emergency fuel oil tank vaults

* essential service water electrical duct banks and manways

* communications corridor

* transmission towers

* essential service water access vaults

* fuel building

* essential service water pumphouse building

• circulating water screenhouse

* ultimate heat sink,

* essential service water discharge structure

* main dam and auxiliary spillway

* essential service water valve house

* refueling water storage tank foundation and valve house

* condensate storage tank foundation and valve house

* concrete support structures for station transformers

* supports

3.5.1 Summary of Technical Information in the Application

LRA Section 3.5 provides AMR results for the containments, structures and component

supports components and component groups. LRA Table 3.5.1, "Summary of Aging

Management Evaluations in Chapters II and III of NUREG-1801 for Containments, Structures,

and Component Supports," is a summary comparison of the applicant's AMRs with those

evaluated in the GALL Report for the containments, structures and component supports

components and component groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the containments, structures and

component supports components within the scope of license renewal and subject to an AMR,

will be adequately managed so that the intended function(s) will be maintained consistent with

the CLB for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

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staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.5.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.5.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.5.2.2.

The staff also conducted a technical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's evaluations are

documented in SER Section 3.5.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.5-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.5 and addressed in the GALL Report.

Table 3.5-1 Staff Evaluation for Containments, Structures and Component Supports in

the GALL Report

C"omponent Group Aging Effect/ AMP in GALL "Further AMP in LRA,_ Saff

;(GALL Report Mechanism Report 'Evaluation Supplements, or' cýEvaluation

hRem No.) in GALL. Amendments

PWRConcrete (Reinforced andPrestressed)anReportdSteelContainment

PWR Concrete (Reinforced and Prestressed) and Steel Containments

Concrete elements:

walls, dome,

basemat, ring

girder, buttresses,

containment

(as applicable).

(3.5.1-1)

Aging of

accessible and

inaccessible

concrete areas

due to

aggressive

chemical

attack, and

corrosion of

embedded steel

ISI (IWL) and for

inaccessible

concrete, an

examination of

representative

samples of

below-grade

concrete, and

periodic monitoring

of groundwater if

environment is

non-aggressive. A

plant-specific

program is to be

evaluated if

environment is

aggressive.

Yes ASME Code

Section X1,

Subsection IWL

(B2.1.28)

Consistent with

GALL Report

(See SER

Section 3.5.2.2.

1.1)

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Component Group, Aging Effect/ AMP in GALL 'Further AMP in LRA, Staff

(GALL Report Mechanism Report 2 Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments ................ ___________ _____________ Reportr • _____________ __ __ __ _

Concrete elements; Cracks and Structures Yes Structures Consistent with

All distortion due to Monitoring Program. Monitoring Program GALL Report

(3.5.1-2) increased If a (B2.1.32) (See SER

stress levels de-watering system Section 3.5.2.2.

from settlement is relied upon for 1.2)

control of

settlement, then the

applicant is to

ensure proper

functioning of the

de-watering system

through the period

of extended

operation.

Concrete elements: Reduction in Structures Yes Not applicable Not applicable

foundation, foundation Monitoring Program to WCGS

subfoundation strength, If a de-watering (See SER

(3.5.1-3) cracking, system is relied Section 3.5.2.2.

differential upon to control 1.2)

settlement due erosion of cement

to erosion of from.porous

porous concrete

concrete subfoundations,

subfoundation then the applicant is

to ensure proper

functioning of the

de-watering. system

* through the period

of extended

operation.

Concrete elements: Reduction of A plant-specific Yes Not applicable Not applicable

dome, wall, * strength and aging management to WCGS

basemat, ring modulus of program is to be (See SER

girder, buttresses,, concrete due to evaluated. Section 3.5.2.2.

containment, elevated 1.3)

concrete fill-in temperature

annulus

(as applicable)

(3.5.1-4) 1

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Component Group. "Aging Effect/ AMP in GALL Further AMP in LRA,' Staff

(GALL Report Mechanism Report 'zEvaluation Supplements, or Evaluation

Item No.) in GALL Amendments

______ _____ ______ _____ ______ ______ Report, _ _ _ _ _ _ _ _ _ _ _ _

Steel elements: Loss of material ISI (IWE) and Yes Not applicable Not applicable

drywell; torus; due to general, 10 CFR Part 50, to PWRs

drywell head; pitting and Appendix J (See SER

embedded shell and crevice Section 3.5.2.2.

sand pocket corrosion 1.4)

regions; drywell - support skirt; torus

ring girder;

downcomers; liner

plate, ECCS suction

header, support

skirt, region

shielded by

diaphragm floor,

suppression

chamber

(as applicable)

(3.5.1-5)

Steel. elements: Loss of material ISI (IWE) and Yes ASME Code Consistent with.

steel liner, liner due to general, 10 CFR Part 50, Section Xl, GALL Report

anchors, integral pitting and Appendix J Subsection IWE (See SER

attachments crevice (B2.1.27) and Section 3.5.2.2.

(3.5.1-6) corrosion 10 CFR 50, 1.4)

Appendix J

_(B2.1.30)

Prestressed Loss of TLAA, evaluated in Yes TLAA Loss of.

containment prestress due accordance with prestress is a

tendons to relaxation, 10 CFR 54.21 (c) TLAA

(3.5.1-7) shrinkage, (See SER

creep, and Section 3.5.2.2.

elevated 1.5)

temperature

Steel and stainless Cumulative TLAA, evaluated in Yes Not applicable Not applicable

steel elements: vent fatigue damage accordance with to PWRs

line, vent header, (CLB fatigue 10 CFR 54.21 (c) (See SER

vent line bellows; analysis exists) Section 3.5.2.2.

downcomers; 1.6)

(3.5.1-8)

Steel, stainless steel Cumulative TLAA, evaluated in Yes Not applicable Not applicable

elements; dissimilar fatigue damage accordance with to PWRs

metal welds: (CLB fatigue 10 CFR 54.21 (c) (See SER

penetration sleeves, analysis exists) Section 3.5.2.2.

penetration bellows; 1.6)

suppression pool

shell, unbraced

downcomers

(3.5.1-9)

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Component Group,, Aging Effect/ 'AMP in GALL Further AMP in LRA, Staff

(GALL tm,:,'Mechanism; Report Report 'Evaluation Supplements, or Evaluation

Item No.): in GALL Amendments .

_____ _____ __ _____ __ __ _____ _____ Report _ _ _ _ _ _ _ _ _ _ _ _

Stainless steel Cracking due to ISI (IWE) and Yes Not applicable Not applicable

penetration sleeves, SCC 10 CFR Part 50, to WCGS

penetration bellows, Appendix J, and (See SER

dissimilar metal additional Section 3.5.2.2.

welds appropriate 1.7)

(3.5.1-10) examinations/

evaluations for

bellows assemblies

and dissimilar metal

welds.

Stainless steel vent Cracking due to ISI (IWE) and Yes Not applicable Not applicable

line bellows, SCC 10 CFR Part 50, to.PWRs

(3.5.1-11) Appendix J, and (See SER

additional Section 3.5.2.2.

appropriate 1.7)

examination/

evaluation for

bellows assemblies

and dissimilar metal

welds.

Steel, stainless steel Cracking due to ISI (IWE) and Yes Not applicable Not applicable

elements, dissimilar cyclic loading 10 CFR Part 50, to WCGS

metal welds: Appendix J, and (See SER

penetration sleeves, supplemented to Section 3.5.2.2.

penetration bellows; detect fine cracks 1.8)

suppression pool

shell, unbraced

downcomers

(3.5.1-12)

Steel, stainless steel Cracking due to ISI (IWE) and Yes Not applicable Not applicable

elements, dissimilar cyclic loading 10 CFR Part 50, to PWRs

metal welds: torus; Appendix J, and (See SER

vent line; vent supplemented to Section 3.5.2.2.

header; vent line detect fine cracks 1.8)

bellows;

downcomers

(3.5.1-13)

Concrete elements: Loss of material ISI (IWL). Yes ASME Code Consistent with

dome, wall, (scaling, Evaluation is Section Xl, GALL Report

basemat ring girder, cracking, and, needed for plants Subsection IWL (See SER

buttresses, spalling) due to that are located in (B2.1.28) Section 3.5.2.2.

containment freeze-thaw moderate to severe 1.9)

(as applicable) weathering

(3.5.1-14) conditions

(weathering

*index > 100

day-inch/yr)

(NUREG-1 557).

3-341
Component Group Aging Effect/ AMP in GALL Further ' AMP in LRA, Staff.

McasmRpRevlti ':::!LLe (GA Ro):i ::. :::ehns :!?::.:••.eport ! ."~alainoGLL ! .Supplements, or? Evauaio

No.) .Ite:i:.::!.: : :.": " :::i:::liiin Report A~ i:!! J!:!iA Amendments!! en m nt ' ,i:

Concrete elements: Cracking due to IS (IWL) for Yes ASME Code Consistent with

walls, dome, expansion and accessible areas. Section Xl, GALL Report

basemat, ring reaction with None for Subsection IWL (See SER

girder, buttresses, aggregate; inaccessible areas if (B2.1.28) Section 3.5.2.2.

containment, increase in concrete was 1.10)

concrete fill-in porosity, constructed in

annulus permeability accordance with the

(as applicable), due to leaching recommendations in

(3.5.1-15) of calcium ACI 201.2R.

hydroxide

Seals, gaskets, and Loss of sealing ISI (IWE) and No ASME Code Consistent with

moisture barriers and leakage 10 CFR Part 50, Section Xl, GALL Report

(3.5.1-16) through Appendix J Subsection IWE

containment (B2.1.27) and

due to 10'CFR Part 50,

deterioration of Appendix J

joint seals, (B2.1.30)

gaskets, and

moisture

barriers

(caulking,

flashing, and

other sealants)

Personnel airlock, Loss of leak 10 CFR Part 50, No 10 CFR Part 50, Consistent with

equipment hatch tightness in Appendix J and Appendix J GALL Report

and CRD hatch• closed position plant Technical (B2.1.30)

locks, hinges, and due to Specifications

closure mechanisms mechanical

(3.5.1-17) wear of locks,

hinges and

closure

mechanisms

Steel penetration Loss of material ISI (IWE) and No ASME Code Consistent with

sleeves and due to general; 10 CFR Part 50, Section Xl, GALL Report

dissimilar metal pitting, and Appendix J Subsection IWE

welds; personnel crevice (B2.1.27) and

airlock, equipment corrosion 10 CFR Part 50,

hatch and CRD Appendix J

hatch (B2.1.30)

(3.5.1-18)

Steel elements: Cracking due to ISI (IWE) and No Not applicable Not applicable

stainless steel SCC 10 CFR Part 50, to PWRs

suppression Appendix J

chamber shell (inner

surface)

(3.5.1-19)

3-342
Component Group Aging Effect/ AMP in GALL .- Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

_____________ ___________ ___________ .,Report _ _ _ _ _ _ _ _ _ _ _ _

Steel elements: Loss of material ISI (IWE) and No Not applicable Not applicable

suppression due to general, 10 CFR Part 50, to PWRs

chamber liner pitting, and Appendix J

(interior surface) crevice

(3.5.1-20) corrosion

Steel elements: Fretting or lock ISI (IWE) No Not applicable Not applicable

drywell head and up due to to PWRs

downcomer pipes mechanical

(3.5.1-21). wear

Prestressed Loss of material ISI (IWL) No ASME Code Consistent with

containment: due to Section Xl, GALL Report

tendons and corrosion Subsection IWL

anchorage (B2.1.28)

components

(3.5.1-22) 1

Safety-Related and Other Structures; and Component Supports

All Groupsexcept Cracking, loss Structures Yes. Structures Consistent with

Group 6: interior of bond, and Monitoring Program Monitoring Program GALL Report

and above grade loss of material (B2.1.32) (See SER

exterior concrete (spalling, Sectionr3.5.2.2.

(3.5.1-23) scaling) due to 2.1)

corrosion of

.. embedded steel

All Groups except Increase in Structures Yes Structures Consistent with

Group 6: interior porosity and Monitoring Program Monitoring Program GALL Report

and above grade permeability, (B2.1.32) (See SER

exterior concrete cracking, loss Section 3.5.2.2.

(3.5.1-24) of material 2.1)

(spalling,

scaling) due to

aggressive

chemical attack

All Groups except Loss of material Structures Yes Structures Consistent with

Group 6: steel due to Monitoring Program. Monitoring Program GALL Report

components: all corrosion If protective (B2.1.32) (See SER

structural steel coatings are relied Section 3.5.2.2.

(3.5.1-25) upon to manage the 2.1)

effects of aging, the

Structures

Monitoring Program

is to include

provisions to

address protective*

coating monitoring

and maintenance.

3-343
Component Group Aging Effectl AMP in GALL F.,,urther AMP in LRA, .Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

,,,.: Report _

All Groups except Loss of material Structures Yes Structures Consistent with

Group 6: accessible (spalling, Monitoring Program. Monitoring Program GALL Report

and inaccessible scaling) and Evaluation is (B2.1.32) (See SER

concrete: foundation cracking due to needed for plants Section 3.5.2.2.

(3.5.1-26) freeze-thaw that are located in 2.1)

moderate to severe

weathering

conditions

(weathering index

> 100 day-inch/yr)

(NUREG-1557).

All Groups except Cracking due to Structures Yes Structures Consistent with

Group 6: accessible expansion due Monitoring Program. Monitoring Program GALL Report

and inaccessible to reaction with None for (B2.1.32) (See SER

interior/exterior aggregates inaccessible areas if Section 3.5.2.2.

concrete concrete was 2.2)

(3.5.1-27) constructed in

accordance with the

recommendations in

ACl 201.2R-77.

Groups 1-3, 5-9: All Cracks'and Structures Yes Structures Consistent with

(3.5.1-28) distortion due to Monitoring Program. Monitoring Program GALL Report

increased If a (B2.1.32) (See SER

stress levels de-watering system Section 3.5.2.2.

from settlement is relied upon for 2.2)

control of

. settlement, then the

applicant is to

ensure proper

functioning of the

de-watering system

through the period

of extended

operation.

Groups 1-3, 5-9:. Reduction in Structures Yes Not applicable Not applicable

foundation foundation Monitoring Program. to WCGS

(3.5.1-29) strength, If a (See SER

cracking, de-watering system Section 3.5.2.2.

differential is relied upon for 2.1)

settlement due control of

to erosion of settlement, then the

porous applicant is to

concrete ensure proper

subfoundation functioning of the

de-watering system

through the period

of extended

operation.

3-344
Component Group Aging Effect/ AMP in GALL 'Further... AMP in LRA, Staff

GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

- - ______________ ~~~Report _ _ _ _ _ _ _ _ _ _ _ _

Group 4: radial Lock-up due to ISl (IWF) or Yes Not applicable Not applicable

beam seats in BWR wear Structures to WCGS

drywell; RPV Monitoring Program (See SER

support shoes for Section 3.5.2.2.

PWR with nozzle 2.1)

supports; steam

generator supports

(3.5.1-30)

Groups 1-3, 5, 7-9: Increase in Structures Yes Structures Consistent with

below-grade porosity and Monitoring Program; Monitoring Program GALL Report

concrete permeability, examination of (B2.1.32) (See SER

components, such cracking, loss• representative Section 3.5.2.2.

as exterior walls of material samples of 2.2)

below grade and (spalling, below-grade

foundation scaling), concrete, and

(3.5.1-31) aggressive periodic monitoring

chemical of groundwater, if

attack; the environment is

cracking, loss non-aggressive. A

of bond, and plant-specific

loss of material program is to be

(spalling, evaluated if

scaling), environment is

corrosion of aggressive.

embedded steel

Groups 1-3, 5, 7-9: Increase in 'Structures Yes Structures Consistent with

exterior above and porosity and Monitoring Program Monitoring Program GALL Report

below grade, permeability, for accessible (B2.1.32) (See SER

reinforced concrete and loss of areas. None for Section 3.5.2.2.

foundations strength due to inaccessible areas if 2.2)

(3.5.1-32) leaching of concrete was

calcium constructed in

hydroxide accordance with the

recommendations in

ACI 201.2R-77.

Groups 1-5: Reduction of A plant-specific Yes Structures Consistent with

concrete strength and aging management Monitoring Program GALL Report

(3.5.1-33). modulus due to program is to be 1(B2.1.32) (See SER

elevated evaluated Section 3.5.2.2.

temperature 2.3)

3-345
Component Group. Aging Effectl 'iAMP in GALL .'Further' AMP in LRA, : ., ,Staff

.:(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

-Item No.) in GALL iAmendments

____ ____ ____ ____ ____ _ -Report

Group 6: Concrete; Increase in Inspection of Yes Regulatory Guide Consistent with

all porosity and Water-Control 1.127, Inspection of GALL Report

(3.5.1-34) permeability, Structures or Water-Control (See SER

cracking, loss FERC/US Army Structures Section 3.5.2.2.

of material due Corps of Engineers Associated with 2.4)

to aggressive dam inspections Nuclear Power

chemical and maintenance Plants (B2.1.33)

attack; programs and for

cracking, loss inaccessible

of bond, loss of concrete, an

material due to examination of

corrosion of representative

embedded steel samples of

below-grade

concrete, and

periodic monitoring

of groundwater, if

the environment is

non-aggressive. A

plant-specific

program is tobe

evaluated if

environment is

aggressive.

Group 6: exterior Loss of material Inspection of Yes Regulatory Guide' Consistent with

above and below (spalling, Water-Control 1.127, Inspection of GALL Report

grade concrete scaling) and Structures or Water-Control (See SER

foundation cracking due to FERC/US Army Structures Section 3.5.2.2.

(3.5.1-35) freeze-thaw Corps of Engineers Associated with 2.4)

dam inspections Nuclear Power

and maintenance Plants (B2.1.33)

programs.

Evaluation is

needed for plants

that are located in

moderate to severe

weathering

conditions

(weathering index

> 100 day-inch/yr)

(NUREG-1557).

3-346
Component Group Aging Effect/ AMP in GALL Further ,AMP in LRA, Staff

.(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments'

I______..............____ ______________ Report _ _ _ _ I _

Group 6: all Cracking due to Accessible areas: Yes Regulatory Guide Consistent with

accessible and expansion/react Inspection of 1.127, Inspection of GALL Report

inaccessible ion with Water-Control Water-Control (See SER

reinforced concrete aggregates Structures or Structures Section 3.5.2.2.

(3.5.1-36) FERC/US Army Associated with 2.4)

Corps of Engineers Nuclear Power

dam inspections Plants (B2.1.33)

and maintenance

programs6 None for

inaccessible areas if

concrete was constructed in

accordance with the

recommendations in

ACI 201.2R-77.

Group 6: exterior Increase in For accessible Yes Regulatory Guide Consistent with

above and below porosity and areas, Inspection of 1.127, Inspection of GALL Report

grade reinforced permeability, Water-Control Water-Control (See SER

concrete foundation loss of strength Structures or Structures Section 3.5.2.2.

interior slab due to leaching FERC/US Army Associated with 2.4)

(3.5.1-37) of calcium Corps of Engineers Nuclear Power

hydroxide dam inspections Plants (B2.1.33)

and maintenance

programs. None for

inaccessible areas if

concrete was

constructed in

accordance with the

recommendations in

ACI 201.2R-77.

Groups 7, 8: tank Cracking due to A plant-specific Yes Not applicable Not applicable

liners stress corrosion aging management to WCGS

(3.5.1-38) cracking; loss program is to be (See SER

of material due evaluated Section 3.5.2.2.

to pitting and 2.5)

crevice

corrosion

Support members; Loss of material Structures Yes Structures Consistent with

welds; bolted due to general Monitoring Program Monitoring Program GALL Report

connections; and pitting (B2.1.32) (See SER

support anchorage corrosion Section 3.5.2.2.

to building structure 2.6)

(3.5.1-39)

3-347
!Component Group Aging Effect/ AMP in GALL Further AMP in LRA,, Staff

(GALL Report Mechanism Report .Evaluation Supplements, or, Evaluation

'Item No.) -in GALL Amendments

____ _ ___ ____ ____ __ ___ ___ ___ Report

Building concrete at Reduction in Structures Yes Structures Consistent with

locations of concrete Monitoring Program Monitoring Program GALL Report

expansion and anchor capacity (B2.11.32) (See SER

grouted anchors; due to local Section 3.5.2.2.

grout pads for concrete 2.6)

support base plates degradation,

(3.5.1-40) service-induced

cracking or

other concrete

aging

mechanisms

Vibration isolation Reduction or Structures Yes Not applicable Not applicable

elements . loss of isolation Monitoring Program to WCGS

(3.5.1-41) function, (See SER

radiation Section 3.5.2.2.

hardening, 2.6)

temperature,

humidity,

sustained

vibratory

loading

Groups B1.1, B1.2, Cumulative TLAA, evaluated in Yes TLAA Consistent with

and B1i.3: support fatigue damage accordance with GALL Report

members: anchor (CLB fatigue 10 CFR 54.21 (c) (See SER

bolts, welds analysis exists) Section 3.5.2.2.

(3.5.1-42) . 2.7)

Groups 1-3,5, 6: all Cracking due to Masonry Wall No Fire Protection Consistent with

masonry block walls restraint Program (B2.1.12) and GALL Report

(3.5.1-43). shrinkage, Masonry Wall (See SER

creep, and Program (B2.1.31) Section 3.5.2.1.

aggressive 2)

environment

Group 6: elastomer Loss of sealing Structures No Structures Consistent with

seals, gaskets, and due to Monitoring Program Monitoring Program GALL Report

moisture barriers deterioration of 1(B2.1.32)

(3.5.1-44) seals, gaskets,

and moisture

barriers

(caulking,

flashing, and

other sealants)

Group 6: exterior Loss of material Inspection of No Regulatory Guide Consistent with

above and below due to Water-Control 1.127, Inspection of GALL Report

grade concrete abrasion, Structures or Water-Control (See SER

foundation; interior cavitation. FERC/US Army Structures Section 3.5.2.1.

slab Corps of Engineers Associated with 4)

(3.5.1-45) dam inspections Nuclear Power

and maintenance Plants (B2.1.33)

3-348
,Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report 'Evaluation Supplements, or Evaluation

'Item No. in GALL 'Amendments

__________ ___ _____ _____ ____ _______ ,.Report _ _ _ _ _ _ _ _ _ _ _ _ _ _

Group 5: fuel pool Cracking due to Water Chemistry No Water Chemistry Consistent with

liners SCC; loss of and monitoring of (B2.1.2) GALL Report

(3.5.1-46) material due to spent fuel pool

• pitting and water level in

crevice accordance with

corrosion technical

specifications and

leakage from the

leak chase

channels.

Group 6: all metal Loss of material Inspection of No Structures Consistent with

structural members due to general Water-Control Monitoring Program GALL Report

(3.5.1-47) (steel only), Structures or (B2.1.32) (See SER

pitting and FERC/US Army Section 3.5.2.1.

crevice Corps of.Engineers 3)

corrosion dam inspections

and maintenance. If

protective coatings

are relied upon to

manage aging,

protective coating

monitoring and

maintenance

provisions should be

included.

Group 6: earthen Loss of Inspection of. No Regulatory Guide Consistent with

water control material, loss of Water-Control 1.127, Inspection of GALL Report

structures - dams, form due to Structures or Water-Control

embankments, erosion, FERC/US Army Structures

reservoirs,, settlement, Corps of Engineers Associated with

channels, canals, sedimentation, dam inspections Nuclear Power

and ponds frost action, and maintenance Plants (B2.1.33)

(3.5.1-48) waves, programs

currents,

surface runoff,

-* seepage

Support members; Loss of material Water Chemistry No Not applicable Not applicable

welds; bolted due to general, and ISI (IWF) to PWRs

connections; * pitting, and

support anchorage 'crevice

to building structure corrosion

(3.5.1-49) *

GroupsB2, andB4: Loss of material Structures No Structures Consistent with

galvanized steel, due to pitting Monitoring Program Monitoring Program GALL Report

aluminum, stainless and crevice (B2.1.32)

steel support. corrosion

members; welds;

bolted connections;

support anchorage

to building structure

(3.5.1-50)

3-349
Component Group Aging Effec AMP in GALL; Further AMP in LRA, ..Staff

(GALL Report Mechanism Report Evaluation Supplements, or, Evaluation

Item No.) in GALL: Amendments

.... .. ..... .... _,.. ......... , , ,, ,:,.," R e p o rt

Group B1.1: high Cracking due to Bolting Integrity No Bolting Integrity Consistent with

strength low-alloy SCC; loss of (B2.1.7) GALL Report.

bolts material due to

(3.5.1-51) general

corrosion

Groups B2, and. 134: Loss of Structures No Structures Consistent with

sliding support mechanical Monitoring Program Monitoring Program GALL Report

bearings and sliding function due to (B2.1.32)

support surfaces corrosion,

(3.5.1-52) distortion, dirt,

overload,

fatigue due to

vibratory and

cyclic thermal

loads

Groups B1.1, B1.2, Loss of material ISI (IWF) No ASME Code Consistent with

and B1.3: support due to general Section Xl, GALL Report

members: welds; and pitting Subsection IWF

bolted connections; corrosion (B2. 1.29)

support anchorage

to building structure

(3.5.1-53)

Groups B13.1, B1.2, Loss of ISI (IWF) No ASME Code Consistent with

and B1.3: constant mechanical Section Xl, GALL Report

and variable load function due to Subsection IWF

spring hangers; corrosion, (B2.1.29)

guides; stops; distortion, dirt,

(3.5.1-54) overload,

fatigue due to

vibratory and

cyclic thermal

loads

Steel, galvanized Loss of material Boric Acid Corrosion No Boric Acid Corrosion. Consistent with

steel, and aluminum due to boric (B2.1.4) GALL Report

support members; acid corrosion

welds; bolted

connections;

support anchorage

to building structure

(3.5.1-55)

Groups B1.1, B1.2, Loss of ISI (IWF) No Not applicable Not applicable

and B1.3: sliding mechanical to WCGS

surfaces function due to

(3.5.1-56) corrosion,

distortion, dirt,

overload,

fatigue due to

vibratory and

cyclic thermal

loads

3-350
Component Group, Aging Effect/ AMP in GALL,- Further AMP in LRA, Staff

(GALL Report -Mechanism Report Evaluation Supplements, or Evaluation

itemn No.) in GALL Amendments _______ ______ ______ ____ _ ______ _____ 'Report _ _ _ _ _ _ _ _ _ _ _ _ _ _

Groups B13.1, B13.2, Reduction or ISI (IWF) No Not applicable Not applicable

and B13.3: vibration loss of isolation to WCGS

isolation elements function,

(3.5.1-57) radiation

hardening,

temperature,

humidity,.

sustained

vibratory

loading

Galvanized steel. None None No None Consistent with

and aluminum GALL Report

support members;

welds; bolted

connections;

support anchorage

to building structure

exposed to air -

indoor uncontrolled

(3.5.1-58)

Stainless steel None None No None Consistent with

support members; GALL Report

welds; bolted,

connections;

support anchorage

to building structure

(3.5.1-59) ... . ................

The staff's review of the containments, structures and component supports component groups

followed any one of several approaches. One approach, documented in SER Section 3.5.2.1,

reviewed AMR results for components that the applicant indicated are consistent with the GALL

Report and require no further evaluation. Another approach, documented in SER

Section 3.5.2.2, reviewed AMR results for components that the applicant indicated are

consistent with the GALL Report and for which further evaluation is recommended. A third

approach, documented in SER Section 3.5.2.3, reviewed AMR results for components that the

applicant indicated are not consistent with or not addressed in the GALL Report. The staff's

review of AMPs credited to manage or monitor aging effects of the containments, structures

and component supports components is documented in SER Section 3.0.3.

3.5.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the containments, structures and component supports

components:

* Water Chemistry

* Boric Acid Corrosion

* Bolting Integrity

3-351
& Fire Protection

* ASME Code Section Xi, Subsection IWE

* ASME Code Section XI, Subsection IWL

0 ASME Code Section XI, Subsection IWF

* 10 CFR 50, Appendix J

* Masonry Wall

0 Structures Monitoring

* RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

LRA Tables 3.5.2-1 through 3.5.2-22 summarize AMRs for the containments, structures and

component supports components and indicate AMRs claimed to be consistent with the GALL

Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

3-352
exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the. aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA, as documented in SER

Section 3.5.2.1. The staff did not repeat its review of the matters described in the GALL Report;

however, the staff did verify that the material presented in the LRA was applicable and that the

applicant identified the appropriate GALL Report AMRs. The staff's evaluation is discussed

below.

3.5.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.5.1, the applicant identified items 3.5.1-56 and 3.5.1-57 as not applicable

because the component, material, and environment combination does not exist at WCGS. The

staff reviewed the LRA and the applicant's supporting documents, and confirmed that this

combination does not exist at WCGS. Because WCGS does not have the component, material,

and environment combination for these items, the staff finds that these AMRs are not

applicable.

3.5.2.1.2 Cracking due to Restraint Shrinkage, Creep, and Aggressive Environment

In LRA Table 3.5.1, item 3.5.1-43, the applicant stated that cracking due to restraint shrinkage,

creep, and aggressive environment is managed by the Fire Protection Program. For this item,

the applicant credited note E to the associated AMR result lines in LRA table 3.5.2. However,

the staff noted that the GALL Report recommends that concrete masonry be inspected by the

Masonry Wall Program.

The staff reviewed the AMR result line items that reference note E and determined that the

component type, material, environment, and aging effect are consistent with the

recommendations in the GALL Report. However, the staff noted that where the GALL Report

recommends AMP XI.S5, "Masonry Wall Program," the applicant has proposed using the Fire

Protection Program.

During the audit, the applicant stated that the AMR result line items that reference LRA table

3.5.1, item 3.5.1-43 are listed only as fire barriers that are within the scope of license renewal

pursuant to 10 CFR 54.4(a)(2), and are not in the masonry wall system and; therefore, the Fire

Protection Program was credited.

The staff noted that the Fire Protection Program performs visual inspections on a periodic basis

to manage cracking due to restraint shrinkage, creep, and aggressive environments. On the

basis that periodic visual inspections are performed, the staff finds the applicant's use of the

Fire Protection Program acceptable.

3-353
On the basis of its review of the applicant's AMR result and the recommendations in the GALL

Report, the staff finds that the applicant addressed the aging effects management adequately,

as recommended by the GALL Report.

3.5.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion

In LRA Table 3.5.1, item 3.5.1-47, the applicant stated that loss of material due to general,

pitting, and crevice corrosion is managed by the Structures Monitoring Program. The applicant

applied note E to the AMR result lines referencing item 3.5.1-47.

The staff reviewed the AMR results lines referencing note E and determined that the

component type, material, environment, and aging effect are consistent with the GALL Report.

However, the staff noted that where the GALL Report recommends AMP XI.S7, "Regulatory

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants,"

the applicant proposed using the Structures Monitoring Program. The staff finds that the AMR

result line items that reference item 3.5.1-47, are metal structural members that are part of the

WCGS water control structure, which are within the scope of the Structures Monitoring Program

and not in the Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with

Nuclear Power Plants Program. The staff finds that the Structures Monitoring Program

performs visual inspections to manage loss of material due to general, pitting, and crevice

corrosion. On the basis that periodic visual inspections are performed, the staff finds the

applicant's use of the Structures Monitoring Program acceptable.

On the basis of its review of the AMR result lines and the recommendations in the GALL

Report, the staff finds that the applicant addressed the aging effect management adequately,

as recommended by the GALL Report.

3.5.2.1.4 Loss of Material Due to Abrasion and Cavitation

In LRA Table 3.5.1, item 3.5.1-45, the applicant stated that loss of material due to abrasion and

cavitation is managed by the Structures Monitoring Program. The applicant applied note E to

the AMR result lines referencing item 3.5.1-45.

The staff requested that the applicant explain why note E was used instead of note A, since

LRA Tables 3.5.1 and 3.5.2 are both crediting the Structures Monitoring Program.

By letter dated August 31, 2007, the applicant amended LRA Table 3.5.1, item 3.5.1-45, to

read:"lnspection of Water-Control Structures(B2.1.33)." This amendment to the LRA will

correctly align with the SRP. The applicant also indicated that WCGS inspects the submerged

portions of the circulating water screen house as part of the Structures Monitoring Program.

Therefore, for this component, the Structures Monitoring Program is credited instead of the

Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power

Plants Program.

The staff reviewed the AMR results for this line item and determined that the component type,

material, environment, and aging effect are consistent with the GALL Report. However, where

the GALL Report recommends AMP XI.S7, Regulatory Guide 1.127, Inspection of

Water-Control Structures Associated with Nuclear Power Plants, the applicant has proposed

using the Structures Monitoring Program because the submerged portions of the circulating

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water screen house is part of the Structures Monitoring Program. The staff finds that the

Structures Monitoring Program performs visual inspections to manage loss of material due to

abrasion and cavitation. On the basis of its review, the staff finds the applicant's use of the

Structures Monitoring Program acceptable.

On the basis of its review of the AMR result line items and recommendations in the GALL

Report, the staff finds that the applicant addressed the aging effect management adequately,

as recommended by the GALL Report.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the containments, structures and component supports components

and provides information concerning how it will manage the following aging effects and related

QA:

(1) PWR containments:

* aging of inaccessible concrete areas

* cracks and distortion due to increased stress levels from settlement; reduction of

foundation strength, cracking, and differential settlement due to erosion of

porous concrete subfoundations if not covered by the Structures Monitoring

Program

reduction of strength and modulus of concrete structures due to elevated

temperature

* loss of material due to general, pitting, and crevice corrosion

• loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

* cumulative fatigue damage

* cracking due to SCC

* cracking due to cyclic loading

" loss of material (scaling, cracking, and spalling) due to freeze-thaw

* cracking due to expansion and reaction with aggregate, and increase in porosity

and permeability due to leaching of calcium hydroxide

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(2) safety-related and other structures and component supports:

* aging of structures not covered by the Structures Monitoring Program

* aging management of inaccessible areas

* reduction of strength and modulus of concrete structures due to elevated

temperature

* aging management of inaccessible areas for Group 6 structures

" cracking due to SCC and loss of material due to pitting and crevice corrosion

* aging of supports not covered by the Structures Monitoring Program

* cumulative fatigue damage due to cyclic loading

(3) QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The staff's review of the

applicant's further evaluation follows.

3.5.2.2.1 PWR Containments

The staff reviewed LRA Section 3.5.2.2.1 against SRP-LR Section 3.5.2.2.1 criteria, which

address several areas of review:

A-qinq of Inaccessible Concrete Areas.

The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.1.1.

LRA Section 3.5.2.2.1.1 addresses aging of inaccessible concrete areas. The applicant stated

that reinforced concrete structures at WCGS were designed, constructed, and inspected in

accordance with applicable ACI and ASTM standards, which provide for a good quality, dense,

well-cured, and low permeability concrete. The mixes were designed with entrained air content

between 3 and 6 percent, and the concrete slumps were controlled throughout the batching,

mixing, and placement processes. The applicant stated that crack control was achieved through

proper sizing, spacing, and distribution of reinforcing steel in accordance with ACI 318-71.

Monthly tests conducted from June 2005 to May 2006 showed that the WCGS groundwater and

soil have pH values between 7.0 and 8.7, which are above the recommended minimum pH

of 5.5. These tests also showed that chloride solutions range from 5.0 to 41.2 ppm, and sulfate

solutions range from 30 to 717 ppm. These results compare favorably to the recommended

limits of less than 500 ppm and less than 1500 ppm, respectively. The applicant stated that

WCGS is located in a geologically and environmentally stable area. In addition, it stated that

groundwater chemistry is not expected to change significantly in the future and that further

evaluation for the effects of corrosion of embedded steel and aggressive chemical attack is not

required.

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SRP-LR Section 3.5.2.2.1.1 states that increases in porosity and permeability, cracking, loss of

material (spalling, scaling) due to aggressive chemical attack, and cracking, loss of bond, and

loss of material (spalling, scaling) due to corrosion of embedded steel may occur in inaccessible

areas of PWR and BWR concrete and steel containments. The existing program relies on

ASME Code Section XI, Subsection IWL to manage these aging effects; however, the GALL

Report recommends further evaluation of plant-specific programs to manage the aging effects

for inaccessible areas in aggressive environments.

The staff noted that the listed possible aging effects apply to concrete elements of PWR

containments and concrete BWR containments. The applicant proposed to manage these aging

effects using the ASME Code Section Xl, Subsection IWL Program. The staff's evaluation of

the ASME Code Section Xl, Subsection IWL Program is documented in SER

Section 3.0.3.2.18. The applicant stated that WCGS is located in a geologically and

environmentally stable area. In addition, it stated that groundwater chemistry is not expected to

change significantly in the future and that further evaluation for the effects of corrosion of

embedded steel and aggressive chemical attack is not required. The staff requested that the

applicant clarify if the Structures Monitoring Program will continue to perform the groundwater

monitoring.

In its letter dated July 26, 2007, the applicant committed (Commitment No. 17) to monitor

groundwater for pH, sulfates, and chlorides. Two samples of groundwater will be tested every

five years.

On the basis that periodic groundwater monitoring will be performed to ensure that the

chemistry has not changed, the staff finds the applicant's response acceptable. The staff finds

that the ASME Code Section XI, Subsection IWL Program includes activities that are consistent

with the recommendations in the GALL Report, and are adequate to manage aging of

accessible and inaccessible areas due to aggressive chemical attack and corrosion of

embedded steel.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.1.1 criteria. For those line items that apply to LRA Section 3.5.2.2.1.1,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Cracks and Distortion Due to Increased Stress Levels from Settlement; Reduction of

Foundation Strength, Cracking, and Differential Settlement Due to Erosion of Porous Concrete

Subfoundations, If Not Covered by the Structures Monitoring Program.

The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2.

LRA Section 3.5.2.2.1.2, addresses cracks and distortion due to increased stress levels from

settlement, reduction of foundation strength, cracking, and differential settlement due to erosion

of porous concrete subfoundations. The applicant stated that competent foundation materials

were found to be present at WCGS for establishing conservative design and construction

criteria for support of the facilities. Major structures are founded on soil, undisturbed and/or

compacted fill, over competent bedrock. USAR Table 2.5-54b shows that settlements of all

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major structures, measured in November 1983, are below the allowable values. The applicant

stated that no permanent de-watering system has been constructed at WCGS and that further

evaluation for the effects of settlement is not required. In addition, it stated that there are no

porous concrete subfoundations in WCGS and that this aging effect is not applicable and

further evaluation is not required.

SRP-LR Section 3.5.2.2.1.2 states that cracks and distortion due to increased stress levels

from settlement may occur in PWR and BWR concrete and steel containments. Also, reduction

of foundation strength, cracking, and differential settlement due to erosion of porous concrete

subfoundations may occur in all types of PWR and BWR containments. The existing program

relies on structures monitoring to manage these aging effects. Some plants may rely on a

de-watering system to lower the site groundwater level. If the plant's CLB credits a de-watering

system, the GALL Report recommends verification of the continued functionality of the

de-watering system during the period of extended operation. The GALL Report recommends no

further evaluation if this activity is within the scope of the applicant's structures monitoring

program.

The staff finds that cracking and distortion due to increased stress levels from settlement,

reduction of foundation strength, cracking, and differential settlement due to erosion of porous

concrete subfoundations (if not covered by the Structures Monitoring Program) are not plausible

aging effects because these aging mechanisms do not exist.

The applicant stated that the aging effects due to settlement in the containment building

foundation are not expected. It clarified that the containment building is founded on sound

bedrock, which prevents significant settlement. In addition, there is no porous concrete

subfoundation of concern below the containment building. However, the applicant

conservatively elected to use the Structural Monitoring Program to monitor the above-grade

exposed containment concrete for the aging effect of cracking due to settlement.

The staff's evaluation of the Structures Monitoring Program is documented in SER

Section 3.0.3.2.21. The staff finds that this program includes activities that are consistent with

the recommendations in the GALL Report, and that are adequate to manage cracks and

distortion due to increased stress levels from settlement, reduction of foundation strength,

cracking, and differential settlement due to erosion of porous concrete subfoundations.

Based on the program identified above, the staff concludes that the applicant's program meets

SRP-LR Section 3.5.2.2.1.2 criteria. For those line items that apply to LRA Section 3.5.2.2.1.2,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature.

The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.

LRA Section 3.5.2.2.1.3 addresses reduction of strength and modulus of concrete structures

due to elevated temperature. The applicant stated that this aging effect is not applicable

because WCGS has no dome, wall, basemat, ring girder, buttresses, containment, or annulus

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concrete exposed to temperature above 150 OF for general areas, or 200 OF for local areas. The

applicant stated that high energy line penetrations have been designed with flued heads to

dissipate the heat from these process pipes, and insulation has been installed to further limit

the exposure of the concrete.

SRP-LR Section 3.5.2.2.1.3 states that reduction of strength and modulus of concrete due to

elevated temperatures may occur in PWR concrete and steel containments. The

implementation of 10 CFR 50.55a and ASME Code Section XI, Subsection IWL would not be

able to identify the reduction of strength and modulus of concrete due to elevated temperature.

Subsection CC-3400 of ASME Code Section III, Division 2, specifies the concrete temperature

limits for normal operation or any other long-term period. The GALL Report recommends further

evaluation of plant-specific AMPs if any portion of the concrete containment components

exceeds specified temperature limits (i.e., general area temperature greater than 60 0C (150 OF)

and local area temperature greater than 93 0C (200 OF)).

The applicant stated that the aging effects due to elevated temperature are not expected at

WCGS because the general area temperatures within the primary containment do not exceed

150 OF and local area temperatures do not exceed 200 °F. The staff finds that the reduction of

strength and modulus for concrete structures due to elevated temperature is not plausible aging

effects because this aging mechanism does not exist.

In addition, the staff finds that because the general area temperatures within the primary

containment do not exceed 150 OF and local area temperatures do not exceed 200 OF, these

aging effects are not applicable at WCGS.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.3

criteria. The staff determines that the LRA is consistent with the GALL Report and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Loss of Material Due to General, Pitting and Crevice Corrosion.

The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4.

LRA Section 3.5.2.2.1.4 addresses loss of material due to general, pitting, and crevice

corrosion. The applicant stated that reinforced concrete structures at WCGS were designed,

constructed, and inspected in accordance with applicable ACI and ASTM standards, which

provide for a good quality, dense, well-cured, and low permeability concrete. Design practices

and procedural controls ensured that the concrete was consistent with the recommendations

and guidance provided by ACI 201.2R. The mixes were designed with entrained air content

between 3 and 6 percent, and the concrete slumps were controlled throughout the batching,

mixing, and placement processes. USAR Section 3.8 discusses the design requirements for

each major structure.

The applicant stated that the Structures Monitoring Program will identify and manage any

cracks in the concrete or degradation of the moisture barrier that could potentially provide a

pathway for water to reach inaccessible portions of the steel containment liner. In addition,

procedural controls will ensure that borated water spills are not common, and that, if detected,

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they will be cleaned up in a timely manner. Therefore, the applicant concluded that further

evaluation for corrosion in inaccessible areas of the steel containment liner is not required.

SRP-LR Section 3.5.2.2.1.4 states that loss of material due to general, pitting, and crevice

corrosion may occur in steel elements of accessible and inaccessible areas for all types of

PWR and BWR containments. The existing program relies on ASME Code Section XI,

Subsection IWE, and 10 CFR Part 50, Appendix J, to manage this aging effect. The GALL

Report recommends further evaluation of plant-specific programs to manage this aging effect

for inaccessible areas if corrosion is significant.

The staff noted that loss of material due to general pitting and crevice corrosion in the steel

elements listed in table 3.5.1, item 3.5.1-5, could only occur in BWRs; therefore, is not

applicable to WCGS. However, the staff noted that for loss of material due to general, pitting,

and crevice corrosion of carbon steel for steel liner, liner anchors, and integral attachments,

described in table 3.5.1, item 3.5.1-6, the applicant is crediting only the ASME Code Section XI,

Subsection IWE Program. The staff's evaluation of the ASME Code Section Xl,

Subsection IWE Program is documented in SER Section 3.0.3.2.17. The applicant's

containment ISI encompasses the ASME Code Section XI, Subsection IWE Program

requirements for managing the loss of material for the primary containment and its integral

attachments.

Because the applicant's containment ISI includes the same requirements for inspection and

detection of loss of material for the primary containment and its integral attachments as the

ASME Code Section XI, Subsection IWE, the staff finds it to be acceptable AMP to manage

loss of material of these components.

The staff noted that table 1, item 3.5.1-6, the LRA states that the Structures Monitoring

Program is used to manage cracking. Item 3.5.1-6 references LRA Section 3.5.2.2.1.4.

However, the discussion column of this item credits the ASME Code Section XI,

Subsection IWE Program. The staff requested that the applicant explain why the Structures

Monitoring Program was not credited.

By letter dated August 31, 2007,-the applicant amended LRA Section 3.5.2.2.1.4 to note that

the WCGS program relies on ASME Code Section XI, Subsection IWE Program, and 10

CFR 50, Appendix J, to manage loss of material. LRA Table 3.5.2-1 was amended to credit the

10 CFR 50, Appendix J Program to manage the component type of liner containment exposed

to an external plant indoor air. The applicant also stated that LRA Section 3.5.2.2.1.4 is

intended to specifically address the conditions given in the GALL Report, item I1.A1 -11. These

conditions, if satisfied, allow the presumption that, for inaccessible areas (i.e., embedded

containment steel shell or liner), loss of material due to corrosion is not significant. Therefore,

further evaluation for corrosion in inaccessible areas of the steel containment liner is not

required. The concrete is monitored to ensure that it is free of penetrating cracks that provide a

path for water seepage to the surface of the containment shell or liner.

The staff finds that the Structures Monitoring Program will identify and manage any cracks in

the concrete (or degradation of the moisture barrier) that could potentially provide a pathway for

water to reach inaccessible portions of the steel containment liner. The staff reviewed the AMR

results for this line item and determines that the component type, material, environment, and

aging effect are consistent with the GALL Report. However, the staff noted that the GALL

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Report recommends AMP XI.S1 "ASME Section Xl, Subsection IWE Program" and AMP XI.S4

"10 CFR 50, Appendix J." The staff also noted that reinforced concrete structures at WCGS

were designed, constructed, and inspected in accordance with applicable ACI and ASTM

standards, which provide for a good quality, dense, well-cured, and low permeability concrete.

Design practices and procedural controls ensured that the concrete was consistent with the

recommendations and guidance provided by ACI 201.2R. The mixes were designed with

entrained air content between 3 and 6 percent, and the concrete slumps were controlled

throughout the batching, mixing, and placement processes. The staff noted that USAR

Section 3.8 discusses the design requirements for each major structure. Therefore, the staff

finds that further evaluation for corrosion in inaccessible areas of the steel containment liner is

not required. The Structures Monitoring Program performs visual inspections to manage loss of

material due to general, pitting and crevice corrosion. On the basis of its review, the staff finds

the applicant's use of the Structures Monitoring Program acceptable.

Based on the program identified above, the staff concludes that the applicant's program meets

SRP-LR Section 3.5.2.2.1.4 criteria. For those line items that apply to LRA Section 3.5.2.2.1.4,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature.

The staff reviewed LRA Section 3.5.2.2.1.5 against the criteria in SRP-LR Section 3.5.2.2.1.5.

LRA Section 3.5.2.2.1.5 states that loss of prestress forces due to relaxation, shrinkage, creep,

and elevated temperature is a TLAA as defined in 10 CFR 54.3. Applicants must evaluate

TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.5 documents the staff's review of

the applicant's evaluation of this TLAA.

Cumulative Fatigue Damage.

The staff reviewed LRA Section 3.5.2.2.1.6 against the criteria in SRP-LR Section 3.5.2.2.1.6

LRA Section 3.5.2.2.1.6 states that fatigue analyses of suppression pool steel shells (including

welded joints) and penetrations (including penetration sleeves, dissimilar metal welds, and

penetration bellows) are not applicable because WCGS does not have containment penetration

sleeves with bellows with dissimilar metal welds.

SRP-LR Section 3.5.2.2.1.6 states that if included in the current licensing basis, fatigue

analyses of suppression pool steel shells (including welded joints) and penetrations (including

penetration sleeves, dissimilar metal welds, and penetration bellows) for all types of PWR and

BWR containments and BWR vent header, vent line bellows, and downcomers are TLAAs as

defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

10 CFR 54.21 (c)(1).

The staff noted that this item applies to containment penetration sleeves with bellows with

dissimilar metal welds that are within the scope of license renewal. The staff finds that WCGS

does not have these components; therefore, this line is not applicable.

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Crackina Due to Stress Corrosion Crackina.

The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7.

LRA Section 3.5.2.2.1.7 addresses cracking due to SCC. The applicant stated that this aging

effect is not applicable because WCGS does not have stainless steel penetration sleeves,

penetration bellows, or dissimilar metal welds subject to SCC that are within the scope of

license renewal. Therefore, the applicable GALL Report line items were not used.

SRP-LR Section 3.5.2.2.1.7 states that cracking due to SCC of stainless steel penetration

sleeves, penetration bellows, and dissimilar metal welds may occur in all types of PWR and

BWR containments. Cracking due to SCC also may occur in stainless steel vent line bellows for

BWR containments. The existing program relies on ASME Code Section XI, Subsection IWE

and 10 CFR Part 50, Appendix J, to manage this aging effect. The GALL Report recommends

further evaluation of additional appropriate examinations/evaluations implemented to detect

these aging effects for stainless steel penetration sleeves, penetration bellows and dissimilar

metal welds, and stainless steel vent line bellows.

The staff noted that this item applies to stainless steel penetration sleeves, penetration bellows,

or dissimilar metal welds subject to SCC that are within the scope of license renewal. The staff

finds that WCGS does not have these components; therefore, this line is not applicable.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.7

criteria. The staff determines that the LRA is consistent with the GALL Report and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Cyclic Loading.

The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR Section 3.5.2.2.1.8.

LRA Section 3.5.2.2.1.8 addresses cracking due to cyclic loading. The applicant stated that this

aging effect is not applicable because WCGS does not have containment penetration sleeves

with bellows with dissimilar metal welds.

SRP-LR Section 3.5.2.2.1.8 states that cracking due to cyclic loading of suppression pool steel

and stainless steel shells (including welded joints) and penetrations (including penetration

sleeves, dissimilar metal welds, and penetration bellows) could occur in all types of PWR and

BWR containments and BWR vent header, vent line bellows, and downcomers. The existing

program relies on ASME Code Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, to

manage this aging effect; however, visual examination (VT-3) may not detect fine cracks. The

GALL Report recommends further evaluation for detection of this aging effect.

The staff noted that this item applies to containment penetration sleeves with bellows with

dissimilar metal welds that are within the scope of license renewal. The staff finds that WCGS

does not have these components; therefore, this line is not applicable.

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Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.1.8

criteria. The staff determines that the LRA is consistent with the GALL Report and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

Loss of Material (Scalinq, Cracking, and Spalling) Due to Freeze-Thaw.

The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9.

LRA Section 3.5.2.2.1.9 addresses loss of material (scaling, cracking, and spalling) due to

freeze-thaw. The applicant stated that, as described in USAR Section 2.3.2.1.1, the average

monthly temperatures at WCGS range from 80 OF in July and August to 29 OF in January, with

extremes recorded as high as 117 OF and as low as -27 OF. Reinforced concrete structures at

WCGS were designed, constructed, and inspected in accordance with ACI and ASTM

standards, which provide for a good quality, dense, well-cured, and low permeability concrete.

The mixes were designed with entrained air content between 3 and 6 percent, and the concrete

slumps were controlled throughout the batching, mixing, and placement processes. Therefore,

the applicant concluded that further evaluation for the effects of freeze-thaw is not required. In

addition, testing and petrographic examination, performed in accordance with ASTM C295, has

demonstrated that the concrete aggregates at WCGS are non-reactive; therefore, further

evaluation for the effects of reaction with aggregates is not required.

SRP-LR Section 3.5.2.2.1.9 states that loss of material (scaling, cracking, and spalling) due to

freeze-thaw may occur in PWR and BWR concrete containments. The existing program relies

on ASME Code Section Xl, Subsection IWL to manage this aging effect. The GALL Report

recommends further evaluation of this aging effect for plants located in moderate to severe

weather conditions.

The staff confirmed that WCGS is located in an area with moderate weathering conditions;

therefore, concrete does not exhibit degradation related to freeze-thaw. The staff's evaluation of

the ASME Code Section XI, Subsection IWL Program is documented in SER

Section 3.0.3.2.18. The staff finds that the ASME Code Section XI, Subsection IWL Program

provides inspection frequencies, sample size, and method of inspection for reinforced concrete

and post-tensioning systems to ensure that the aging effects are adequately managed. The

implementation of this program provides reasonable assurance that the component's intended

functions will be maintained within the CLB during the period of extended operation. The staff

finds that this program includes activities that are consistent with the recommendations in the

GALL Report and is adequate to manage loss of material due to freeze-thaw.

Based its review and confirmation on the program identified above, the staff concludes that the

applicant's program meets SRP-LR Section 3.5.2.2.1.9 criteria. For those line items that apply

to LRA Section 3.5.2.2.1.9, the staff determines that the LRA is consistent with the GALL

Report and that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

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Crackinq Due to Expansion and Reaction with Aggregate and Increase in Porosity and

Permeability Due to Leaching of Calcium Hydroxide.

The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR

Section 3.5.2.2.1.10.

LRA Section 3.5.2.2.1.10 addresses cracking due to expansion and reaction with aggregate

and increase in porosity and permeability due to leaching of calcium hydroxide. The applicant

stated that testing and petrographic examination, performed in accordance with ASTM C295,

has demonstrated that the concrete aggregates at WCGS are non-reactive; therefore, the

applicant concluded that further evaluation for the effects of reaction with aggregates is not

required.

In addition, the applicant stated that reinforced concrete structures at WCGS were designed,

constructed, and inspected in accordance with applicable ACI and ASTM standards, which

provide for a good quality, dense, well-cured, and low permeability concrete. Design practices

and procedural controls ensured that the concrete was consistent with the recommendations

and guidance provided by ACI 201.2R. The mixes were designed with entrained air content

between 3 and 6 percent, and the concrete slumps were controlled throughout the batching,

mixing, and placement processes. Therefore, the applicant concluded that further evaluation for

the effects of leaching of calcium hydroxide is not required.

SRP-LR Section 3.5.2.2.1.10 states that cracking due to expansion and reaction with aggregate

and increase in porosity and permeability due to leaching of calcium hydroxide may occur in

concrete elements of PWR and BWR concrete and steel containments. The existing program

relies on ASME Code Section Xl, Subsection IWL to manage these aging effects. The GALL

Report recommends further evaluation if concrete was not constructed in accordance with

ACI 201.2R-77 recommendations.

During the audit, the applicant indicated that cracking due to expansion and reaction with

aggregate and increase in porosity and permeability due to leaching of calcium hydroxide is not

applicable to the WCGS containment. The staff noted that the GALL Report recommends

programs consistent with GALL AMP XI.S2, "ASME Section XI, Subsection IWL." The staff's

evaluation of the applicant's ASME Code Section XI, Subsection IWL Program is documented

in SER Section 3.0.3.2.18. The staff finds that the ASME Code Section XI, Subsection IWL

imposes requirements for inspection and detection of cracking due to expansion and reaction

with aggregate, and increase in porosity and permeability due to leaching of calcium hydroxide.

Because the applicant's existing ASME Code Section XI, Subsection IWL Program includes the

same requirements for inspection and detection of cracking of material for the containment as

the ASME Code Section XI, Subsection IWL, the staff finds it to be an acceptable AMP to

manage cracking of the above components.

The staff finds that this program includes activities that are consistent with the

recommendations in the GALL Report, and is adequate to manage cracking due to expansion

and reaction with aggregate and increase in porosity and permeability due to leaching of

calcium hydroxide.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.1.10 criteria. For those line items that apply to LRA

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Section 3.5.2.2.1.10, the staff determines that the LRA is consistent with the GALL Report and

that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against SRP-LR Section 3.5.2.2.2 criteria, which

address several areas:

Aging of Structures Not Covered by Structures Monitoring Program.

The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.

LRA Section 3.5.2.2.2.1 addresses aging of structures not covered by the Structures Monitoring

Program. The applicant stated that loss of material due to corrosion does not require further

evaluation because the steel components are evaluated under the Structures Monitoring

Program.

The applicant stated that reinforced concrete structures at WCGS were designed, constructed,

and inspected in accordance with applicable ACI and ASTM standards, which provide for a

good quality, dense, well-cured, and low permeability concrete. Design practices and

procedural controls ensured that the concrete was consistent with the recommendations and

guidance provided by ACI 201.2R. The mixes were designed with entrained air content between

3 and 6 percent, and the concrete slumps were controlled throughout the batching, mixing, and

placement processes. Crack control was achieved through proper sizing, spacing, and

distribution of reinforcing steel in accordance with ACI 318-71. Monthly tests conducted from

June 2005 to May 2006 showed that the groundwater and soil at WCGS have pH values

between 7.0 and 8.7, which are above the recommended minimum pH of 5.5. These tests also

showed that chloride solutions range from 5.0 to 41.2 ppm, and sulfate solutions range from

30 to 717 ppm. These results compare favorably to the recommended limits of less than

500 ppm and less than 1500 ppm, respectively. The applicant stated that WCGS is located in a

geologically and environmentally stable area. In addition, it stated that groundwater chemistry is

not expected to change significantly in the future and that further evaluation for the effects of

corrosion of embedded steel, aggressive chemical attack, and leaching of calcium hydroxide is

not required.

The applicant stated that testing and petrographic examination, performed in accordance with

ASTM C295, demonstrated that the concrete aggregates at WCGS are non-reactive and that

further evaluation for the effects of reaction with aggregates is not required. The applicant also

stated that, as described in USAR Section 2.3.2.1.1, the average monthly temperatures at

WCGS range from 80 OF in July and August to 29 °F in January, with extremes recorded as

high as 117 OF and as low as -27 OF. Reinforced concrete structures at WCGS were designed,

constructed, and inspected in accordance with ACI and ASTM standards. The mixes were

designed with entrained air content between 3 and 6 percent, and the concrete slumps were

controlled throughout the batching, mixing, and placement processes; therefore, further

evaluation for the effects of freeze-thaw is not required.

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The applicant stated that competent foundation materials were found to be present at WCGS

for establishing conservative design and construction criteria for support of the facilities. Major

structures are founded on soil, undisturbed and/or compacted fill, over competent bedrock.

USAR Table 2.5-54b shows that settlements of all major structures, measured in

November 1983, are below the allowable values. The applicant stated that no permanent

de-watering system has been constructed at WCGS; therefore, further evaluation for the effects

of settlement is not required. In addition, it stated that WCGS does not have porous concrete

subfoundations and; therefore, this aging effect is not applicable and further evaluation is not

required.

During normal plant operation, a thermal loading is generated on the primary shield wall around

the reactor cavity in WCGS. An insulation and cooling system is provided on the inside face of

the wall to reduce the severity of this loading by limiting the concrete temperatures to 150 OF

except for the area directly below the seal ring support which is limited to 220 OF. An

engineering evaluation was performed to ensure that this elevated temperature would not be

detrimental to the ability of the concrete to perform its intended functions. High energy line

penetrations have been designed with flued heads to dissipate the heat from these process

pipes, and insulation has been installed to further limit the exposure of the concrete. The

applicant stated that accessible concrete components will be monitored by the Structures

Monitoring Program to identify and manage any visible effects due to elevated temperatures.

SRP-LR Section 3.5.2.2.2.1 states that the GALL Report recommends further evaluation of

certain structure-aging effect combinations not covered by structures monitoring programs,

including: (1) cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion of

embedded steel for Groups 1-5, 7, and 9 structures; (2) increase in porosity and permeability,

cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for

Groups 1-5, 7, and 9 structures; (3) loss of material due to corrosion for Groups 1-5, 7, and 8

structures; (4) loss of material (spalling, scaling) and cracking due to freeze-thaw for

Groups 1-3, 5, and 7-9 structures; (5) cracking due to expansion and reaction with aggregates

for Groups 1-5 and 7-9 structures; (6) cracks and distortion due to increased stress levels from

settlement for Groups 1-3 and 5-9 structures; and (7) reduction in foundation strength, cracking,

and differential settlement due to erosion of porous concrete subfoundation for Groups 1-3 and

5-9 structures. The GALL Report recommends further evaluation only for structure-aging effect

combinations not within structures monitoring programs. In addition, lock-up due to wear may

occur in Lubrite radial beam seats in BWR drywells, RPV support shoes for PWR with nozzle

supports, steam generator supports, and other sliding support bearings and sliding support

surfaces. The existing program relies on structures monitoring or ASME Code Section XI,

Subsection IWF, to manage this aging effect. The GALL Report recommends further evaluation

only for structure-aging effect combinations not within the ISI (IWF) or structures monitoring

programs.

(1) LRA Section 3.5.2.2.2.1 addresses cracking, loss of bond, and loss of material (spalling,

scaling) due to corrosion of embedded steel for groups 1-5, 7, and 9 structures. The

applicant stated that the aging mechanisms associated with cracking, loss of bond, and

loss of material (i.e., spalling, scaling) due to corrosion of embedded steel are applicable

only to below-grade concrete and grout structures. The applicant stated that the

below-grade environment at WCGS is not aggressive, and that the concrete is designed

in accordance with specification ACI 318-71, "Building Code Requirements for

Reinforced Concrete." The use of this specification results in having low permeability

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and resistance to aggressive chemical solutions by providing a high-cement, low

water-to-cement ratio (i.e., 0.50 or less), proper curing, and adequate air content (i.e.,

between 3 and 5 percent). The applicant stated that although specified water-to-cement

ratio's fall outside the established range of 0.35 to 0.45, given all remaining parameters

for durable concrete mix design, WCGS concrete meets the quality requirements of ACI

to ensure acceptable concrete is obtained. Therefore, cracking, loss of bond, and loss of

material (i.e., spalling, scaling) due to corrosion of embedded steel are not aging effects

requiring management for Groups 1-5, 7, and 9 structures.

The staff determines that the cracking, loss of bond, and loss of material (i.e., spalling,

scaling) due to corrosion of embedded steel for Groups 1-5, 7, and 9 structures are not

plausible aging effects because aggressive groundwater does not exist at WCGS.

However, by a letter dated, July 26, 2007, the applicant committed (Commitment

No. 17) to enhance the Structures Monitoring Program to perform periodic engineering

evaluations (i.e., at least once every five years) of two groundwater samples to assess

aggressiveness (i.e., pH less than 5.5, chloride greater than 500 ppm, and sulfate

greater than 1500 ppm) of groundwater to concrete. The staff finds that the concrete at

WCGS, designed in accordance with specification ACI 318-71, has a high-cement, low

water-to-cement ratio, proper curing, and adequate air content between 3 and 6 percent.

However, the applicant conservatively elected to include these aging effects for these

groups within the Structures Monitoring Program.

The staff finds that cracking, spalling, loss of bond, and loss of material due to corrosion

of embedded steel of accessible and inaccessible concrete for Groups 1-5 and 7-9

structures would be adequately managed by using the Structures Monitoring Program.

(2) LRA Section 3.5.2.2.2.1 addresses increase in porosity and permeability, cracking, loss

of material (spalling, scaling) due to aggressive chemical attack for groups 1-5, 7, and 9

structures. The applicant stated that testing and petrographic examinations performed in

accordance with ASTM C295 demonstrated that the concrete aggregates at WCGS are

non-reactive and that further evaluation for the effects of reaction with aggregates is not

required. Resistance to mild acid attack is enhanced by using a dense concrete with low

permeability and low water-to-cement ratio of less than 0.50.

The staff finds that these groups of structures at WCGS use a dense low permeable

concrete with an acceptable water-to-cement ratio, which provides an acceptable

degree of protection against aggressive chemical attack. Water chemical analysis

results confirm that the site groundwater is considered non-aggressive. However, by

letter dated, July 26, 2007, the applicant committed (Commitment No. 17) to enhance

the Structures Monitoring Program to perform periodic engineering evaluations (i.e., at

least once every five years) of two groundwater samples to assess aggressiveness

(i.e., pH less than 5.5, chloride greater than 500 ppm, and sulfate grater than 1500 ppm)

of groundwater to concrete.

*The applicant stated that its concrete is constructed in accordance with the

recommendations in ACI 201.1 R-92 for durability. It also stated that the below-grade

environment is not aggressive. Therefore, increase in porosity and permeability cracking

and loss of material (i.e., spalling, scaling) due to aggressive chemical attack are not

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aging effects requiring management for WCGS Groups 1-5, 7, and 9 concrete

structures.

The staff determined, through discussions with the applicant's technical staff, that the

increase in porosity and permeability, cracking, and loss of material (i.e., spalling,

scaling) due to aggressive chemical attack for Groups 1-5, 7, and 9 structures are not

plausible aging effects at WCGS due to the lack of aggressive groundwater and the

concrete being constructed in accordance with the recommendations in ACI 201.1 R-92.

However, the applicant conservatively elected to include the above aging effects for

these groups within the Structures Monitoring Program. The staff finds that increase in

porosity and permeability cracking and loss of material (i.e., spalling, scaling) due to

aggressive chemical attack will be adequately managed by the Structures Monitoring

Program.

(3) LRA Section 3.5.2.2.2.1 addresses loss of material due to corrosion for groups 1-5, 7,

and 8 structures. The applicant stated that the Structures Monitoring Program will be

used to manage the aging effects requiring management for Groups 1-5, 7, and 8

structures.

The staff's evaluation of the Structures Monitoring Program is documented in SER

Section 3.0.3.2.21. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report and is adequate to manage

loss of material due to corrosion for Groups 1-5, 7, and 8 structures. The staff finds that

loss of material due to corrosion is not a plausible aging effect at WCGS due to the lack

of aggressive groundwater and the concrete being constructed in accordance with the

recommendations in ACI 201.1 R-92. However, the applicant conservatively elected to

include this aging effect for these groups within the Structures Monitoring Program. The

staff finds that loss of material due to corrosion will be adequately managed by the

Structures Monitoring Program.

(4) LRA Section 3.5.2.2.2.1 addresses loss of material (spalling, scaling) and cracking due

to freeze-thaw for groups 1-3, 5, and 7-9 structures. The applicant stated that

aggregates were in accordance with specifications and materials conforming to ACI and

ASTM standards.

The staff noted that the WCGS' structures are constructed of a dense, durable mixture

of sound coarse aggregate, fine aggregate, cement, water, and admixture.

Water-to-cement ratios are within the limits provided in ACI 318-71, and air entrainment

percentages were within the range prescribed in the GALL Report. Therefore, loss of

material (i.e., spalling, scaling) and cracking due to freeze-thaw are not aging effects

requiring management for Groups 1-3, 5, and 7-9 structures.

The staff determines that the loss of material (i.e., spalling, scaling) and cracking due to

freeze-thaw for Groups 1-3, 5, and 7-9 structures are not plausible aging effects at

WCGS because the concrete was constructed in accordance with ACI and ASTM

standards. However, the applicant conservatively elected to use the Structures

Monitoring Program to monitor concrete for the aging effect of loss of material (i.e.,

spalling, scaling) and cracking due to freeze-thaw. The staff's evaluation of the

Structures Monitoring Program is documented in SER Section 3.0.3.2.21. The staff finds

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that this program includes activities that are consistent with the recommendations in the

GALL Report, and is adequate to manage loss of material (i.e., spalling, scaling) and

cracking due to freeze-thaw for Groups 1-3, 5, and 7-9 structures.

(5) LRA Section 3.5.2.2.2.1 addresses cracking due to expansion and reaction with

aggregates for groups 1-5 and 7-9 structures. The applicant stated that testing and

petrographic examination, performed in accordance with ASTM C295, demonstrated

that the concrete aggregates at WCGS are non-reactive and that further evaluation for

the effects of reaction with aggregates is not required.

The staff determines that cracking due to expansion and reaction with aggregates for

Groups 1-5 and 7-9 structures are not plausible aging effects at WCGS because the

concrete was constructed in accordance with ACI and ASTM standards with a

high-cement, low-water-to-cement ratio. However, the applicant conservatively elected

to include these aging effects for these groups within the Structures Monitoring

Program.

(6) LRA Section 3.5.2.2.2.1 addresses cracks and distortion due to increased stress levels

from settlement for groups 1-3 and 5-9 Structures. The applicant stated that settlement

is not a credible event for Groups 1-3 and 5-9 structures at WCGS because they are

founded on bedrock. The applicant clarified that no permanent de-watering system has

been constructed at WCGS. Therefore, further evaluation for the effects of settlement is

not required.

The staff noted that in LRA Table 3.5.1, item 3.5.1-28, the applicant stated that cracks

and distortion due to increased stress levels from settlement for the ESW discharge

structure is managed by the Inspection of Water Control Structures Program. The

applicant was asked to explain why the Inspection of Water Control Structures Program

was indicated instead of the Structures Monitoring Program as recommended by the

GALL Report. The applicant stated that the ESW discharge structure is normally

submerged and is inspected by divers under a program that is based on RG 1.127.

By letter dated August 31, 2007, the applicant amended LRA Table 3.5.2.16 for

concrete elements component that references Table 1, item 3.5.1-28, to credit the

Structures Monitoring Program and to apply note A instead of note E. The applicant also

deleted note 1 for the table.

The staff reviewed the AMR results for this line item and determines that the component

type, material, environment, and aging effect are consistent with the recommendations

of the GALL Report. The staff finds the applicant's use of the Structures Monitoring

Program acceptable.

On the basis of its review of the applicant's response, the staff finds that the applicant

appropriately addressed the aging effect management as recommended by the GALL

Report.

The staff also determines that the cracks and distortion due to increased stress levels

from settlement for Groups 1-3 and 5-9 structures are not plausible aging effects these

aging mechanisms do not exist at WCGS. The applicant stated that the aging effects

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due to settlement are not expected at WCGS for Groups 1-3 and 5-9, Class 1,

structures. The applicant clarified that the WCGS Class 1 structures are founded on

sound bedrock or supported by steel pilings which prevent significant settlement.

However, the applicant conservatively elected to use its Structures Monitoring Program

to monitor the above-grade exposed concrete of Groups 1-3, 5, and 7-9 structures for

the aging effect of cracking due to settlement.

(7) LRA Section 3.5.2.2.2.1 addresses reduction in foundation strength, cracking, and

differential settlement due to erosion of porous concrete subfoundation for groups 1-3

and 5-9 structures. The applicant stated that the WCGS concrete was provided in

accordance with ACI 318-71 requirements resulting in dense, well-cured, high-strength

concrete with low-permeability. Structures are supported on bedrock and erosion of the

subfoundation is not credible since the subfoundation also eliminates the possibility of

loss of soil resulting in voids below the subgrade. The applicant stated that fluid leakage

across the subfoundation is captured by circumferential drains and inspected for any

material loss. Operating history has not identified any losses to date and; therefore,

reduction in foundation strength, cracking, and differential settlement due to erosion of

porous concrete subfoundation are not aging effects requiring management for Groups

1-3 and 5-9 structures.

The staff determines that reduction in foundation strength, cracking, and differential

settlement due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9

structures are not plausible aging effects because these aging mechanisms do not exist.

The applicant stated that the aging effects of reduction in foundation strength, cracking,

and differential settlement due to erosion of porous concrete subfoundation for Groups

1-3 and 5-9 structures are not applicable to WCGS because there are no porous

concrete subfoundations of concern below these structures.

On the basis that WCGS does not have porous concrete subfoundations below these

structures, the staff finds that these aging effects are not applicable to Groups 1-3 and

5-9 structures.

The staff determines that the applicant has included the above seven structures and

aging effect combinations in its Structures Monitoring Program, and no further

evaluation is required, in accordance with the GALL Report.

The staff's evaluation of the Structures Monitoring Program is documented in SER

Section 3.0.3.2.21. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report, and that it is adequate to

manage the aging effects as identified in items 1 through 7 above.

(8) LRA Section 3.5.2.2.2.1 addresses lockup due to wear for LubriteO radial beam seats in

BWR drywell and other sliding support surfaces. In LRA Table 3.5.1, item 3.5.1-30, the

applicant stated that WCGS does not use sliding support surfaces for their equipment

and piping supports. Therefore, wear-resistant material, the low frequency of movement,

and the slow movement between sliding surfaces lockup due to wear is not an aging

effect requiring management.

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The staff determines that the lockup due to wear for sliding support surfaces is not a

plausible aging effect due to wear-resistant material, the low frequency of movement,

and the slow movement between sliding surfaces. On the basis that WCGS does not

have sliding support surfaces for their equipment and piping supports that are within the

scope of license renewal, the staff agrees that this line is not applicable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.2.1 criteria. For those line items that apply to LRA Section 3.5.2.2.2.1,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Aging Management of Inaccessible Areas.

The staff reviewed LRA Section 3.5.2.2.2.2 against the following criteria in SRP-LR

Section 3.5.2.2.2.2:

(1) LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas:

freeze-thaw. The applicant stated that, as described in USAR Section 2.3.2.1.1, the

average monthly temperatures at WCGS range from 80 OF in July and August to 29 OF

in January, with extremes recorded as high as 117 OF and as low as -27 OF. Reinforced

concrete structures at WCGS were designed, constructed, and inspected in accordance

with applicable ACI and ASTM standards, which provide for a good quality, dense,

well-cured, and low permeability concrete. The mixes were designed with entrained air

content between 3 and 6 percent, and the concrete slumps were controlled throughout

the batching, mixing, and placement processes; therefore, further evaluation for the

effects of freeze-thaw is not required.

SRP-LR Section 3.5.2.2.2.2 states that loss of material (spalling, scaling) and cracking

due to freeze-thaw may occur in below-grade inaccessible concrete areas of

Groups 1-3, 5, and 7-9 structures. The GALL Report recommends further evaluation of

this aging effect for inaccessible areas of these groups of structures for plants located in

moderate to severe weather conditions.

The staff determines that the loss of material (i.e., spalling, scaling) and cracking due to

freeze-thaw for Groups 1-3, 5, and 7-9 structures are not plausible aging effects at

WCGS because the concrete was constructed in accordance with ACI and ASTM

standards, which provide for a good quality, dense, well-cured, and low permeability

concrete. The mixes were designed with entrained air content between 3 and 6 percent,

and the concrete slumps were controlled throughout the batching, mixing, and

placement processes. The staff finds that further evaluation for the effects of

freeze-thaw is not required.

(2) LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas: reaction

with aggregates. The applicant stated that testing and petrographic examination,

performed in accordance with ASTM C295, demonstrated that the concrete aggregates

at WCGS are non-reactive; therefore, further evaluation for the effects of reaction with

aggregates is not required.

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SRP-LR Section 3.5.2.2.2.2 states that cracking due to expansion and reaction with

aggregates may occur in below-grade inaccessible concrete areas for Groups 1-5 and

7-9 structures. The GALL Report recommends further evaluation of inaccessible areas

of these groups of structures if concrete was not constructed in accordance with

ACI 201.2R-77 recommendations.

The staff determines that the cracking due to expansion and reaction with aggregates

for Groups 1-5 and 7-9 structures are not plausible aging effects at WCGS because the

concrete was constructed in accordance with ACI and ASTM standards, which provide

for a high-cement, low water-to-cement ratio. On this basis, the staff finds that further

evaluation for the effects of reaction with aggregates is not required.

(3) LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas: settlement

and settlement due to erosion of porous concrete subfoundations. The applicant stated

that competent foundation materials were found to be present at WCGS for establishing

conservative design and construction criteria for support of the facilities. Major

structures are founded on soil, undisturbed and/or compacted fill, over competent

bedrock. USAR Table 2.5-54b shows that settlements of all major structures, measured

in November 1983, are below the allowable values. The applicant stated that no

permanent de-watering system has been constructed at WCGS; therefore, further

evaluation for the effects of settlement is not required. In addition, it stated that there are

no porous concrete subfoundations at WCGS; therefore, this aging effect is not

applicable and further evaluation not required.

SRP-LR Section 3.5.2.2.2.2 states that cracks and distortion due to increased stress

levels from settlement and reduction of foundation strength, cracking, and differential

settlement due to erosion of porous concrete subfoundations may occur in below-grade

inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures. The existing program

relies on structures monitoring to manage these aging effects. Some plants may rely on

de-watering systems to lower site groundwater level. If the plant's CLB credits a

de-watering system, the GALL Report recommends verification of the system's

continued functionality during the period of extended operation. The GALL Report

recommends no further evaluation if this activity is included in the scope of the

applicant's structures monitoring program.

The staff determines that reduction in foundation strength, cracking, and differential

settlement due to erosion of porous concrete subfoundation for Groups 1-3, 5, and 7-9

structures are not plausible aging effects because these aging mechanisms do not exist.

The applicant stated that the aging effects of reduction in foundation strength, cracking,

and differential settlement due to erosion of porous concrete subfoundation for Groups

1-3 and 5-9 structures are not applicable to WCGS because there are no porous

concrete subfoundations of concern below these structures. The staff finds that, for

reduction in foundation strength, cracking, and differential settlement due to erosion of

porous concrete subfoundation for Groups 1-3, 5, and 7-9 structures, further evaluation

is not required.

(4) LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas:

aggressive chemical attack and corrosion of embedded steel. The applicant stated that

reinforced concrete structures at WCGS were designed, constructed, and inspected in

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accordance with applicable ACI and ASTM standards, which provide for a good quality,

dense, well-cured, and low permeability concrete. The mixes were designed with

entrained air content between 3 and 6 percent, and the concrete slumps were controlled

throughout the batching, mixing, and placement processes. The applicant stated that

crack control was achieved through proper sizing, spacing, and distribution of reinforcing

steel in accordance with ACI 318-71. Monthly tests conducted from June 2005 to

May 2006 showed that the groundwater and soil at WCGS have pH values between 7.0

and 8.7, which are above the recommended minimum pH of 5.5. These tests also

showed that chloride solutions range from 5.0 to 41.2 ppm, and sulfate solutions range

from 30 to 717 ppm. These results compare favorably to the recommended limits of less

than 500 ppm and less than 1500 ppm, respectively. The applicant stated that WCGS is

located in a geologically and environmentally stable area. It also stated that groundwater

chemistry is not expected to change significantly in the future; therefore, further

evaluation for the effects of aggressive chemical attack and corrosion of embedded

steel is not required.

SRP-LR Section 3.5.2.2.2.2 states that increase in porosity and permeability, cracking,

and loss of material (spalling, scaling) due to aggressive chemical attack and cracking,

loss of bond, and loss of material (spalling, scaling) due to corrosion of embedded steel

may occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9

structures. The GALL Report recommends further evaluation of plant-specific programs

to manage these aging effects in inaccessible areas of these groups of structures in

aggressive environments.

The staff determines that the cracking, loss of bond, and loss of material (i.e., spalling,

scaling) due to corrosion of embedded steel for Groups 1-3, 5, and 7-9 structures are

not plausible aging effects at WCGS due to the lack of aggressive groundwater.

However, in the letter dated July 26, 2007 the applicant committed (Commitment

No. 17) to monitor groundwater for pH, sulfates, and chlorides. Two samples of

groundwater will be tested every five years. WCGS' concrete is designed in accordance

with specification ACI 318-71 with a high-cement, low water-to-cement ratio, proper

curing, and adequate air content between 3 and 6 percent. On the basis that periodic

groundwater monitoring will be performed to ensure that the chemistry has not changed,

the staff finds that for cracking, loss of bond, and loss of material (i.e., spalling, scaling)

due to corrosion of embedded steel for Groups 1-3, 5, and 7-9 structures, further

evaluation is not required.

(5) LRA Section 3.5.2.2.2.2 addresses aging management of inaccessible areas: leaching

of calcium hydroxide. The applicant stated that reinforced concrete structures at WCGS

were designed, constructed, and inspected in accordance with applicable ACI and

ASTM standards, which provide for a good quality, dense, well-cured, and low

permeability concrete. Design practices and procedural controls ensured that the

concrete was consistent with the recommendations and guidance provided by

ACI 201.2R. The mixes were designed with entrained air content between 3 and 6

percent, and the concrete slumps were controlled throughout the batching, mixing, and

placement processes; therefore, further evaluation for the effects of leaching of calcium

hydroxide is not required.

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SRP-LR Section 3.5.2.2.2.2 states that increases in porosity and permeability and loss

of strength due to leaching of calcium hydroxide may occur in below-grade inaccessible

concrete areas of Groups 1-3, 5, and 7-9 structures. The GALL Report recommends

further evaluation of this aging effect for inaccessible areas of these groups of

structures for concrete not constructed in accordance with ACI 201.2R-77

recommendations.

The staff determines that the loss of strength due to leaching of calcium hydroxide for

Groups 1-3, 5, and 7-9 structures is are not plausible aging effects at WCGS because

the concrete was constructed in accordance with ACI and ASTM standards, which

provide for a good quality, dense, well-cured, and low permeability concrete. The mixes

were designed with entrained air content between 3 and 6 percent, and the concrete

slumps were controlled throughout the batching, mixing, and placement processes;

therefore, further evaluation for the loss of strength due to leaching of calcium hydroxide

is not required. On this basis, the staff finds this acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.2.2 criteria. For those line items that apply to LRA Section 3.5.2.2.2.2,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21(a)(3).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature.

The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3.

LRA Section 3.5.2.2.2.3 addresses reduction of strength and modulus of concrete structures

due to elevated temperature. The applicant stated that at WCGS, during normal plant

operation, a thermal loading is generated on the primary shield wall around the reactor cavity.

An insulation and cooling system is provided on the inside face of the wall to reduce the severity

of this loading by limiting the concrete temperatures to 150 OF except for the area directly below

the seal ring support which is limited to 220 OF. An engineering evaluation was performed to

ensure that this elevated temperature would not be detrimental to the ability of the concrete to

perform its intended functions. High energy line penetrations have been designed with flued

heads to dissipate the heat from these process pipes, and insulation has been installed to

further limit the exposure of the concrete. The applicant stated that accessible concrete

components will be monitored by the Structures Monitoring Program to identify and manage

any visible effects due to elevated temperatures.

SRP-LR Section 3.5.2.2.2.3 states that reduction of strength and modulus of concrete due to

elevated temperatures may occur in PWR and BWR Groups 1-5 concrete structures. For

concrete elements that exceed specified temperature limits, further evaluations are

recommended. Appendix A to ACI 349-85 specifies the concrete temperature limits for normal

operation or any other long-term period. Temperatures shall not exceed 150 OF except for local

areas allowed to have temperatures not to exceed 200 OF. The GALL Report recommends

further evaluation of a plant-specific program if any portion of the safety-related and other

concrete structures exceeds specified temperature limits (i.e., general area temperature greater

than 66°C (150 OF) and local area temperature greater than 93 0C (200 'F)).

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During the audit, the staff requested that the applicant provides the maximum temperatures that

concrete experiences in Groups 1-5 structures.

In its response, the applicant stated that, for normal plant operation, the primary shield wall

concrete temperatures are limited to 150 OF except for the area directly below the seal ring

support which is limited to 220 °F. The applicant stated that the WCGS' technical specifications

require that containment average air temperature be less than or equal to 120 OF. The

containment cooling system provides cooling to ensure temperature limits are not exceeded.

The highest concrete temperature in the area directly below the seal ring support is not load

bearing.

On the basis of its review, the staff determines that the reduction of strength and modulus of

concrete structures due to elevated temperatures is not a plausible aging effect because these

aging mechanisms do not exist. The applicant stated that the aging effects due to elevated

temperature are not expected at WCGS for the concrete associated with Groups 1 through 5

structures because the general area temperatures within the primary containment do not

exceed 150 °F, except for the area directly below the seal ring support which is limited to

220 OF, and local area temperatures do not exceed 200 OF.

On the basis of its review, the staff finds that the applicant's response that accessible concrete

components will be monitored by the Structures Monitoring Program to identify and manage

any visible effects due to elevated temperatures to the Groups 1 through 5 structures concrete

is acceptable. The staff's evaluation of the Structures Monitoring Program is documented in

SER Section 3.0.3.2.21. The staff finds that this program includes activities that are consistent

with the recommendations in the GALL Report, and is adequate for managing reduction of

strength and modulus of concrete structures due to elevated temperatures.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.2.3 criteria. For those line items that apply to LRA Section 3.5.2.2.2.3,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Aging Management of Inaccessible Areas for Group 6 Structures.

The staff reviewed LRA Section 3.5.2.2.2.4 against the following criteria in SRP-LR

Section 3.5.2.2.2.4:

(1) LRA Section 3.5.2.2.2.4 addresses aging management of inaccessible areas for

Group 6 structures: aggressive chemical attack and corrosion of embedded steel. The

applicant stated that reinforced concrete structures at WCGS were designed,

constructed, and inspected in accordance with applicable ACI and ASTM standards,

which provide for a good quality, dense, well-cured, and low permeability concrete. The

mixes were designed with entrained air content between 3 and 6 percent, and the

concrete slumps were controlled throughout the batching, mixing, and placement

processes. The applicant stated that crack control was achieved through proper sizing,

spacing, and distribution of reinforcing steel in accordance with ACI 318-71. Monthly

tests conducted from June 2005 to May 2006 showed that the groundwater and soil at

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WCGS have pH values between 7.0 and 8.7, which are above the recommended

minimum pH of 5.5. These tests also show that chloride solutions range from 5.0 to

41.2 ppm, and sulfate solutions range from 30 to 717 ppm. These results compare

favorably to the recommended limits of less than 500 ppm and less than 1500 ppm,

respectively. The applicant stated that WCGS is located in a geologically and

environmentally stable area. It also stated that groundwater chemistry is not expected to

change significantly in the future; therefore, further evaluation for the effects of

aggressive chemical attack and corrosion of embedded steel is not required.

SRP-LR Section 3.5.2.2.2.4 states that increase in porosity and permeability, cracking,

loss of material (spalling, scaling), aggressive chemical attack and cracking, loss of

bond, and loss of material (spalling, scaling), corrosion of embedded steel may occur in

below-grade inaccessible concrete areas of Group 6 structures. The GALL Report

recommends further evaluation of plant-specific programs to manage these aging

effects in inaccessible areas in aggressive environments.

On the basis of its review, the staff determines that the increase in porosity and

permeability, cracking, loss of material (i.e., spalling, scaling), and aggressive chemical

attack, along with cracking, loss of bond, and loss of material (i.e., spalling, scaling), and

corrosion of embedded steel in below-grade inaccessible concrete areas of Group 6

structures are not significant aging effects at WCGS due to the lack of aggressive

groundwater and the concrete being constructed in accordance with the

recommendations in ACI 201.1 R-92.

The applicant credited the Inspection of Water Control Structures Program to manage

these aging effects. The staff's evaluation of the Inspection of Water Control Structures

Program is documented in SER Section 3.0.3.2.22. Furthermore, by letter dated

July 26, 2007 the applicant committed (Commitment No. 17) to monitor groundwater for

pH, sulfates, and chlorides. Two samples of groundwater will be tested every five years.

Therefore, further evaluation of the effects of aggressive groundwater chemistry is not

required.

The staff finds that this program includes activities that are consistent with the

recommendations in the GALL Report and are adequate to manage an increase in

porosity and permeability, cracking, loss of material (i.e., spalling, scaling), and

aggressive chemical attack, along with cracking, loss of bond, and loss of material (i.e.,

spalling, scaling), and corrosion of embedded steel in below-grade inaccessible

concrete areas of Group 6 structures.

(2) LRA Section 3.5.2.2.2.4 addresses aging management of inaccessible areas for

Group 6 structures: freeze-thaw. The applicant stated that, as described in USAR

Section 2.3.2.1.1, the average monthly temperatures at WCGS range from 80 OF in

July and August to 29 OF in January, with extremes recorded as high as 117 OF and as

low as -27 °F. Reinforced concrete structures at WCGS were designed, constructed,

and inspected in accordance with ACI and ASTM standards, which provide for a good

quality, dense, well-cured, and low permeability concrete. The mixes were designed with

entrained air content between 3 and 6 percent, and the concrete slumps were controlled

throughout the batching, mixing, and placement processes; therefore, further evaluation

for the effects of freeze-thaw is not required.

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SRP-LR Section 3.5.2.2.2.4 states that loss of material (spalling, scaling) and cracking

due to freeze-thaw may occur in below-grade inaccessible concrete areas of Group 6

structures. The GALL Report recommends further evaluation of this aging effect for

inaccessible areas for plants located in moderate to severe weather conditions.

On the basis of its review, the staff determines that the loss of material (i.e., spalling,

scaling) and cracking due to freeze-thaw in below grade inaccessible concrete areas of

Group 6 structures are not aging effects at WCGS because the concrete was

constructed in accordance with ACI and ASTM standards with a high-cement, low

water-to-cement ratio. Therefore, the staff finds that further evaluation of the effects of

freeze-thaw is not required. The applicant credited the Inspection of Water Control

Structures Program to manage these aging effects. The staff's evaluation of the

Inspection of Water Control Structures Program is documented in SER

Section 3.0.3.2.22. The staff finds that this program includes activities that are

consistent with the recommendations in the GALL Report and is adequate to manage

loss of material (i.e., spalling, scaling) and cracking due to freeze-thaw in below-grade

inaccessible concrete areas of Group 6 structures.

(3) LRA Section 3.5.2.2.2.4 addresses aging management of inaccessible areas for

Group 6 structures: reaction with aggregates and leaching of calcium hydroxide. The

applicant stated that testing and petrographic examination, performed in accordance

with ASTM C295, demonstrated that the concrete aggregates at WCGS are

non-reactive. Therefore, further evaluation for the effects of reaction with aggregates is

not required.

Reinforced concrete structures at WCGS were designed, constructed, and inspected in

accordance with applicable ACI and ASTM standards, which provide for a good quality,

dense, well-cured, and low permeability concrete. Design practices and procedural

controls ensured that the concrete was consistent with the recommendations and

guidance provided by ACI 201.2R. The mixes were designed with entrained air content

between 3 and 6 percent, and the concrete slumps were controlled throughout the

batching, mixing, and placement processes; therefore, further evaluation for the effects

of leaching of calcium hydroxide is not required.

SRP-LR Section 3.5.2.2.2.4 states that cracking due to expansion and reaction with

aggregates and increased porosity and permeability and loss of strength due to leaching

of calcium hydroxide may occur in below-grade inaccessible reinforced concrete areas

of Group 6 structures. The GALL Report recommends further evaluation of inaccessible

areas for concrete not constructed in accordance within ACI 201.2R-77

recommendations.

On the basis of its review, the staff determines that cracking due to expansion and

reaction with aggregates, increase in porosity and permeability, and loss of strength due

to leaching of calcium hydroxide in below-grade inaccessible concrete areas of Group 6

structures are not aging effects at WCGS because the concrete was constructed in

accordance with ACI and ASTM standards. The staff finds that the concrete was

constructed with a high-cement, low water-to-cement ratio and the below-grade

environment is nonaggressive. Therefore, further evaluation of the effects of reaction

with aggregates and leaching of calcium hydroxide is not required. However, the

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applicant credited the Inspection of Water Control Structures Program to manage these

aging effects. The staff's evaluation of the Inspection of Water Control Structures

Program is documented in SER Section 3.0.3.2.22. The staff finds that this program

includes activities that are consistent with the recommendations in the GALL Report and

is adequate to manage cracking due to expansion and reaction with aggregates and the

increase in porosity and permeability due to leaching of calcium hydroxide in

below-grade, inaccessible concrete areas of Group 6 structures.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.2.4 criteria. For those line items that apply to LRA Section 3.5.2.2.2.4,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and Crevice

Corrosion.

The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 3.5.2.2.2.5.

LRA Section 3.5.2.2.2.5 addresses cracking due to SCC and loss of material due to pitting and

crevice corrosion. The applicant stated that this aging effect is not applicable because WCGS

does not have stainless steel tank liners exposed to water-standing within the scope of license

renewal. Therefore, the applicable GALL Report line items were not used.

SRP-LR Section 3.5.2.2.2.5 states that cracking due to SCC and loss of material due to pitting

and crevice corrosion may occur in Groups 7 and 8 stainless steel tank liners exposed to

standing water. The GALL Report recommends further evaluation of plant-specific programs to

manage these aging effects.

The staff noted that this item is applicable to stainless steel tank liners exposed to standing

water. On the basis that WCGS does not have stainless steel tank liners exposed to

standing-water that are within the scope of license renewal, the staff finds that this line is not

applicable.

Based on the above, the staff concludes that the applicant meets SRP-LR Section 3.5.2.2.2.5

criteria. The staff determines that the LRA is consistent with the GALL Report and that the

applicant has demonstrated that the effects of aging will be adequately managed so that the

intended function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

Aging of Supports Not Covered by the Structures Monitoring Program.

The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6.

LRA Section 3.5.2.2.2.6 addresses aging of supports not covered by the Structures Monitoring

Program. The applicant stated that building concrete, HVAC duct supports, instrument

supports, non-ASME mechanical equipment supports, non-ASME supports, and electrical

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panels and enclosures are inspected by the Structures Monitoring Program; therefore, no

further evaluation is required.

SRP-LR Section 3.5.2.2.2.6 states that the GALL Report recommends further evaluation of

certain component support-aging effect combinations not covered by structures monitoring

programs, including (1) loss of material due to general and pitting corrosion for Groups B2-B5

supports, (2) reduction in concrete anchor capacity due to degradation of the surrounding

concrete for Groups B1-B5 supports, and (3) reduction/loss of isolation function due to

degradation of vibration isolation elements for Group B4 supports. Further evaluation is

necessary only for structure-aging effect combinations not covered by the applicant's structures

monitoring program.

The staff noted that loss of material due to general and pitting corrosion for Groups B2 through

B5 supports components is an aging effect that requires management. The applicant credits

the Structures Monitoring Program to manage this aging effect.

The staff noted that concrete anchors and surrounding concrete for Groups 61 through B5 are

included in the Structures Monitoring Program. Also it noted that the applicant did not identify

any component support structure and aging effect combination that corresponds to the GALL

Report, Volume 2, Item III.B4.2-a, that addressed reduction and loss of isolation function due to

degradation of vibration isolation elements for Group B4 supports.

The staff noted that WCGS does not have vibration isolation elements for Group B4 supports

that are within the scope of license renewal; therefore, the staff finds that this line is not

applicable.

On the basis of its review, the staff finds that the applicant included the aging effect and

material combinations discussed in the SRP-LR within the scope of its Structures Monitoring

Program, and finds that no further evaluation is required. The staff's evaluation of the

Structures Monitoring Program is documented in SER Section 3.0.3.2.21. The staff finds that

this program includes activities that are consistent with the recommendations in the GALL

Report and that is adequate to manage the aging effects of loss of material due to general and

pitting corrosion for Groups B2 through B5 supports and reduction in concrete anchor capacity

due to degradation of the surrounding concrete for Groups B1 through B5 supports.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.5.2.2.2.6 criteria. For those line items that apply to LRA Section 3.5.2.2.2.6,

the staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

Cumulative Fatigue Damage Due to Cyclic Loading.

LRA Section 3.5.2.2.2.7 states that fatigue of component support members, anchor bolts, and

welds for Groups B1.1, B1.2, and B1.3 component supports is a TLAA, as defined in

10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER

Section 4.3 documents the staff's review of the applicant's evaluation of this TLAA.

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3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.5.2-1 through 3.5.2-22, the staff reviewed additional details of the AMR results

for material, environment, AERM, and AMP combinations not consistent with or not addressed

in the GALL Report.

In LRA Tables 3.5.2-1 through 3.5.2-22, the applicant indicated, via notes F through J, that the

combination of component type, material, environment, and AERM does not correspond to a

line item in the GALL Report. The applicant provided further information about how it will

manage the aging effects. Specifically, note F indicates that the material for the AMR line item

component is not evaluated in the GALL Report. Note G indicates that the environment for the

AMR line item component and material is not evaluated in the GALL Report. Note H indicates

that the aging effect for the AMR line item component, material, and environment combination

is not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL

Report for the line item component, material, and environment combination is not applicable.

Note J indicates that neither the component nor the material and environment combination for

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.5.2.3.1 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Reactor Building - LRA Table 3.5.2-1

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the

reactor building component groups.

In LRA Table 3.5.2-1 the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) by using the Fire

Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps, and fire barrier (i.e., ceramic fiber) material is

effectively managed by using the Fire Protection Program.

In LRA Table 3.5.2-1, the applicant stated that fatigue is a TLAA for carbon steel penetration

component, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with

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10 CFR 54.21 (c)(1). SER Section 4.6.2 documents the staff's review of the applicant's

evaluation of this TLAA.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.2 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Control Building - LRA Table 3.5.2-2

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the

control building component groups.

In LRA Table 3.5.2-2, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps component, and fire barrier (i.e., ceramic fiber) material by using the

Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps component, fire barrier (i.e., ceramic fiber) material is

effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.3 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Diesel Generator Building - LRA Table 3.5.2-3

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the

DG building component groups.

In LRA Table 3.5.2-3, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

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effect of fire barrier coatings and wraps component, fire barrier (i.e., ceramic fiber) material is

effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.4 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Turbine Building - LRA Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for the

turbine building component groups.

In LRA Table 3.5.2-4, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber)

material is effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.5 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Auxiliary Building - LRA Table 3.5.2-5

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the

auxiliary building component groups.

In LRA Table 3.5.2-5, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

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effect of fire barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber)

material is effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.6 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Radwaste Building - LRA Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the

radwaste building component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.5.2-6 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.7 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Emergency Fuel Oil Tank Vaults - LRA Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the

emergency fuel oil tank vaults component groups. On the basis of its review, the staff finds that

all AMR results described in LRA Table 3.5.2-7 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.8 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Essential Service Water Electrical Duct Banks and Manways -

LRA Table 3.5.2-8

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the

essential service water electrical duct banks and manways component groups. On the basis of

its review, the staff finds that all AMR results described in LRA Table 3.5.2-8 are consistent with

the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.9 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Communications Corridor - LRA Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the

communications corridor component groups.

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In LRA Table 3.5.2-9, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber)

material is effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.10 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Transmission Towers - LRA Table 3.5.2-10

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for

the transmission towers component groups.

In LRA Table 3.5.2-10, the applicant proposed to manage loss of material in treated wood

material by using the Structures Monitoring Program.

The staff's evaluation of the Structures Monitoring Program is documented in SER

Section 3.0.3.2.21. The staff finds that the Structures Monitoring Program manages the

cracking, loss of material, and change in material properties by monitoring the condition of

structures and structures supports that are in within the scope of license renewal. The staff

finds that the program will be enhanced to add inspection parameters for treated wood. On the

basis of its review of the applicant's plant-specific and industry operating experience, the staff

finds that, since these components will be visually inspected, the aging effect of treated wood

material is effectively managed by using the Structures Monitoring Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.11 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Essential Service Water Access Vaults - LRA Table 3.5.2-11

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for

the essential service water access vaults component groups. On the basis of its review, the

staff finds that all AMR results described in LRA Table 3.5.2-11 are consistent with the GALL

Report.

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The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.12 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Fuel Building - LRA Table 3.5.2-12

The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations for

the fuel building component groups.

In LRA Table 3.5.2-12, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber)

material is effectively managed by using the Fire Protection Program.

In LRA Table 3.5.2-12, the applicant stated that fatigue is a TLAA for stainless steel liner spent

fuel pool component, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in

accordance with 10 CFR 54.21 (c)(1). SER Section 4.3.6 documents the staff's review of the

applicant's evaluation of this TLAA.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.13 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Essential Service Water Pumphouse Building - LRA Table 3.5.2-13

The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations for

the essential service water pumphouse building component groups. On the basis of its review,

the staff finds that all AMR results described in LRA Table 3.5.2-13 are consistent with the

GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.14 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Circulating Water Screenhouse - LRA Table 3.5.2-14

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The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations for

the circulating water screenhouse component groups.

In LRA Table 3.5.2-14, the applicant proposed to manage loss of material and cracking in fire

barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber) material by using

the Fire Protection Program.

The staff's evaluation of the Fire Protection Program is documented in SER Section 3.0.3.2.11.

The staff finds that the Fire Protection Program will visually inspect 10 percent of each type of

electrical and mechanical penetration seal at least once every 18 months. On the basis of its

review of the applicant's plant-specific and industry operating experience, the staff finds that,

since these components will be visually inspected at least once every 18 months, the aging

effect of fire barrier coatings and wraps components, and fire barrier (i.e., ceramic fiber)

material is effectively managed by using the Fire Protection Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.15 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Ultimate Heat Sink - LRA Table 3.5.2-15

The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations for

the ultimate heat sink component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.5.2-15 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.16 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Essential Service Water Discharge Structure - LRA Table 3.5.2-16

The staff reviewed LRA Table 3.5.2-16, which summarizes the results of AMR evaluations for

the essential service water discharge structure component groups. On the basis of its review,

the staff finds that all AMR results described in LRA Table 3.5.2-16 are consistent with the

GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.17 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Main Dam and Auxiliary Spillway - LRA Table 3.5.2-17

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The staff reviewed LRA Table 3.5.2-17, which summarizes the results of AMR evaluations for

the main dam and auxiliary spillway component groups. On the basis of its review, the staff

finds that all AMR results described in LRA Table 3.5.2-17 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.18 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Essential Service Water Valve House - LRA Table 3.5.2-18

The staff reviewed LRA Table 3.5.2-18, which summarizes the results of AMR evaluations for

the essential service water valve house component groups. On the basis of its review, the staff

finds that all AMR results described in LRA Table 3.5.2-18 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.19 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Refueling Water Storage Tank Foundation and Valve House -

LRA Table 3.5.2-19

The staff reviewed LRA Table 3.5.2-19, which summarizes the results of AMR evaluations for

the refueling water storage tank foundation and valve house component groups. On the basis

of its review, the staff finds that all AMR results described in LRA Table 3.5.2-19 are consistent

with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.20 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Condensate Storage Tank Foundation and Valve House -

LRA Table 3.5.2-20

The staff reviewed LRA Table 3.5.2-20, which summarizes the results of AMR evaluations for

the CST foundation and valve house component groups. On the basis of its review, the staff

finds that all AMR results described in LRA Table 3.5.2-20 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.21 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Concrete Support Structures for Station Transformers -

LRA Table 3.5.2-21

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The staff reviewed LRA Table 3.5.2-21, which summarizes the results of AMR evaluations for

the concrete support structures for station transformers component groups. On the basis of its

review, the staff finds that all AMR results described in LRA Table 3.5.2-21 are consistent with

the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.2.3.22 Containments, Structures, and Component Supports - Summary of Aging

Management Evaluation - Supports - LRA Table 3.5.2-22

The staff reviewed LRA Table 3.5.2-22, which summarizes the results of AMR evaluations for

the supports component groups.

In LRA Table 3.5.2-22, the applicant stated that fatigue is a TLAA for carbon steel support

fittings 1 E cable tray, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in

accordance with 10 CFR 54.21 (c)(1). SER Sebtion 4.3.7 documents the staff's review of the

applicant's evaluation of this TLAA.

The staff noted that in LRA Table 3.5.2-22, for carbon steel ASME 2 and 3 supports, the

applicant stated that no fatigue or cycle design analysis exist for these supports at WCGS.

Therefore, there is no TLAA performed for these supports. Also, the staff noted that the

applicant proposed to manage loss of material in carbon steel support mechanical equipments

Class 2 and 3 using the ASME Code Section XI, Subsection IWF.

The staff's evaluation of the ASME Code Section XI, Subsection IWF Program is documented

in SER Section 3.0.3.2.19. The staff finds that the ASME Code Section XI, Subsection IWF

Program will perform visual examination of supports based on sampling of the total support

population. Degradation that potentially compromises support function or load capacity is

identified for evaluation. On the basis of its review of the applicant's plant-specific and industry

operating experience, the staff finds that, since these components will be visually inspected

based on sampling of the total support population, the aging effect is effectively managed by

using the ASME Code Section XI, Subsection IWF Program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR

results of material, environment, AERM, and AMP combinations not evaluated in the GALL

Report. The staff finds that the applicant has demonstrated that the effects of aging will be

adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.5.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the containments, structures and component supports components

within the scope of license renewal and subject to an AMR will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

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3.6 Aging Management of Electrical and Instrumentation and Controls

This section of the SER documents the staff's review of the applicant's AMR results for the

electrical and I&C components and component groups of:

* cable connections (metallic parts)

* connectors

• high-voltage insulators

• insulated cables and connections

" penetrations electrical

" switchyard bus and connections

* terminal blocks

" transmission conductors and connections

0 electrical equipment subject to 10 CFR 50.49 environmental qualification (EQ)

requirements

3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides AMR results for the electrical and I&C components and component

groups. LRA Table 3.6.1, "Summary of Aging Management Evaluations in Chapter VI of

NUREG-1 801 for Electrical Components," is a summary comparison of the applicant's AMRs

with those evaluated in the GALL Report for the electrical and I&C components and component

groups.

The applicant's AMRs evaluated and incorporated applicable plant-specific and industry

operating experience in the determination of AERMs. The plant-specific evaluation included

condition reports and discussions with appropriate site personnel to identify AERMs. The

applicant's review of industry operating experience included a review of the GALL Report and

operating experience issues identified since the issuance of the GALL Report.

3.6.2 Staff Evaluation

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient

information to demonstrate that the effects of aging for the electrical and I&C components

within the scope of license renewal and subject to an AMR, will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB for the period of extended

operation, as required by 10 CFR 54.21 (a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant's claim that certain AMRs

were consistent with the GALL Report. The staff did not repeat its review of the matters

described in the GALL Report; however, the staff did verify that the material presented in the

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The

staff's evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff's

audit evaluation are documented in SER Section 3.6.2.1.

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In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which

further evaluation is recommended. The staff confirmed that the applicant's further evaluations

were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff's audit

evaluations are documented in SER Section 3.6.2.2.

The staff also conducted a technical review of the remaining AMRs that were not consistent

with, or not addressed in, the GALL Report. The technical review evaluated whether all

plausible aging effects have been identified and whether the aging effects listed were

appropriate for the material-environment combinations specified. The staff's evaluations are

documented in SER Section 3.6.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management,

the staff reviewed the AMR line items and the plant's operating experience to verify the

applicant's claims.

Table 3.6-1 summarizes the staff's evaluation of components, aging effects or mechanisms,

and AMPs listed in LRA Section 3.6 and addressed in the GALL Report.

Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls in the GALL

Report

Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

Report

Electrical equipment Degradation Environmental Yes TLAA Consistent with

subject to due to various Qualification of Environmental GALL Report

10 CFR 50.49 aging Electric Qualification of (See SER

environmental mechanisms Components Electrical Section 3.6.2.2.

qualification (EQ) Components (B3.2) 1)

requirements

(3.6.1-1)

Electrical cables, Reduced Electrical Cables No Electrical Cables Consistent with

connections and insulation and Connections and Connections GALL Report

fuse holders resistance and Not Subject to Not Subject to

(insulation) not electrical failure 10 CFR 50.49 10 CFR 50.49

subject to due to various EQ Requirements Environmental

10 CFR 50.49 physical, Qualification

EQ requirements thermal, Requirements

(3.6.1-2) radiolytic, (B2.1.24)

photolytic, and

chemical

mechanisms

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Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

Report

Conductor insulation Reduced Electrical Cables No Electrical Cables Consistent with

for electrical cables insulation And Connections and Connections GALL Report

and connections resistance and Used In Not Subject to

used in electrical failure Instrumentation 10 CFR 50.49

instrumentation due to various Circuits Not Subject Environmental

circuits not subject physical, to 10 CFR 50.49 Qualification

to 10 CFR 50.49 thermal, EQ Requirements Requirements Used

EQ requirements radiolytic, in Instrumentation

that are sensitive to photolytic, and Circuits (B2.1.25)

reduction in chemical

conductor insulation mechanisms

resistance

(3.6.1-3)

Conductor insulation Localized Inaccessible No Inaccessible Consistent with

for inaccessible damage and Medium Voltage Medium-Voltage GALL Report

medium voltage breakdown of Cables Not Subject Cables Not Subject

(2 kV to 35 kV) insulation to 10 CFR 50.49 to 10 CFR 50.49

cables leading to EQ Requirements Environmental

(e.g., installed in electrical failure Qualification

conduit or direct due to moisture Requirements

buried) not subject intrusion, water (B2.1.26)

to 10 CFR 50.49 trees

EQ requirements

(3.6.1-4)

Connector contacts Corrosion of Boric Acid Corrosion No Boric Acid Corrosion Consistent with

for electrical connector (B2.1.4) GALL Report

connectors exposed contact

to borated water surfaces due to

leakage intrusion of

(3.6.1-5) borated water

Fuse Holders Fatigue due to Fuse Holders No Not applicable Not applicable

(Not Part of a Larger ohmic heating, to WCGS (See

Assembly): Fuse thermal cycling, SER

holders - metallic electrical Section 3.6.2.1.

clamp transients, 1)

(3.6.1-6) frequent

manipulation,

vibration,

chemical

contamination,

corrosion, and

oxidation

Metal enclosed Loosening of Metal Enclosed Bus No Not applicable Not applicable

bus - bus, bolted to WCGS (See

connections connections SER

(3.6.1-7) due to thermal Section 3.6.2.1.

cycling and 1)

ohmic heating

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Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

Report

Metal enclosed Reduced Metal Enclosed Bus No Not applicable Not applicable

bus - insulation, insulation to WCGS (See

insulators resistance and SER

(3.6.1-8) electrical failure Section 3.6.2.1.

due to various 1)

physical,

thermal,

radiolytic,

photolytic, and

chemical

mechanisms

Metal enclosed Loss of material Structures No Not applicable Not applicable

bus - enclosure due to general Monitoring Program to WCGS (See

assemblies corrosion SER

(3.6.1-9) Section 3.6.2.1.

1)

Metal enclosed Hardening and Structures No Not applicable Not applicable

bus - enclosure loss of strength Monitoring Program to WCGS (See

assemblies due to SER

(3.6.1-10) elastomers Section 3.6.2.1.

degradation 1 )

High-voltage Degradation of A plant-specific Yes None Consistent with

insulators insulation aging management GALL Report

(3.6.1-11) quality due to program is to be (See SER

presence of any evaluated Section 3.6.2.2.

salt deposits 2)

and surface

contamination;

loss of material

caused by

mechanical

wear due to

wind blowing on

transmission

conductors

Transmission Loss of material A plant-specific Yes None Consistent with

conductors and due to wind aging management GALL Report

connections; induced program is to be (See SER

switchyard bus and abrasion and evaluated Section 3.6.2.2.

connections fatigue; loss of 3)

(3.6.1-12) conductor

strength due to

corrosion;

increased

resistance of

connection due

to oxidation or

loss of preload

3-392
Component Group Aging Effect/ AMP in GALL Further AMP in LRA, Staff

(GALL Report Mechanism Report Evaluation Supplements, or Evaluation

Item No.) in GALL Amendments

Report

Cable Connections - Loosening of Electrical Cable No Electrical Cable Consistent with

metallic parts bolted Connections Not Connections Not GALL Report

(3.6.1-13) connections Subject to Subject to (See SER

due to thermal 10 CFR 50.49 10 CFR 50.49 Section 3.6.2.1.

cycling, ohmic Environmental Environmental 2)

heating, Qualification Qualification

electrical Requirements Requirements

transients, (B2.1.36)

vibration,

chemical

contamination,

corrosion, and

oxidation

Fuse Holders None None No Not applicable Not applicable

(Not Part of a Larger to WCGS

Assembly) - (See SER

insulation material Section 3.6.2.1.

,(3.6.1-14) .1)

The staff's review of the electrical and I&C component groups followed any one of several

approaches. One approach, documented in SER Section 3.6.2.1, reviewed AMR results for

components that the applicant indicated are consistent with the GALL Report and require no

further evaluation. Another approach, documented in SER Section 3.6.2.2, reviewed AMR

results for components that the applicant indicated are consistent with the GALL Report and for

which further evaluation is recommended. A third approach, documented in SER

Section 3.6.2.3, reviewed AMR results for components that the applicant indicated are not

consistent with or not addressed in the GALL Report. The staff's review of AMPs credited to

manage or monitor aging effects of the electrical and I&C components is documented in SER

Section 3.0.3.

3.6.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.6.2.1 identifies the materials, environments, AERMs, and the following programs

that manage aging effects for the electrical and I&C components:

* Boric Acid Corrosion

* Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

" Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuits

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification

Requirements

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LRA Table 3.6.2-1 summarizes AMRs for the electrical and instrumentation and controls (I&C)

components and indicates AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed

consistency with the report and for which the GALL Report does not recommend further

evaluation, the staff's audit and review determined whether the plant-specific components of

these GALL Report component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the

information in the GALL Report. The staff audited those AMRs with notes A through E

indicating how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP.

The staff audited these line items to verify consistency with the GALL Report and validity of the

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component,

material, environment, and aging effect. In addition, the AMP takes some exceptions to the

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted.

The staff also determined whether the applicant's AMP was consistent with the GALL AMP and

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP is consistent with the GALL AMP. This note indicates that the applicant was unable to find

a listing of some system components in the GALL Report; however, the applicant identified in

the GALL Report a different component with the same material, environment, aging effect, and

AMP as the component under review. The staff audited these line items to verify consistency

with the GALL Report. The staff also determined whether the AMR line item of the different

component was applicable to the component under review and whether the AMR was valid for

the site-specific conditions.

Note D indicates that the component for the AMR line item, although different from, is

consistent with the GALL Report for material, environment, and aging effect. In addition, the

AMP takes some exceptions to the GALL AMP. The staff audited these line items to verify

consistency with the GALL Report. The staff verified whether the AMR line item of the different

component was applicable to the component under review and verified whether the identified

exceptions to the GALL AMPs have been reviewed and accepted. The staff also determined

whether the applicant's AMP was consistent with the GALL AMP and whether the AMR was

valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material,

environment, and aging effect, but credits a different AMP. The staff audited these line items to

verify consistency with the GALL Report. The staff also determined whether the credited

AMP would manage the aging effect consistently with the GALL AMP and whether the AMR

was valid for the site-specific conditions.

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The staff audited and reviewed the information in the LRA. The staff did not repeat its review of

the matters described in the GALL Report; however, the staff did verify that the material

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs.

The staff reviewed the LRA to confirm that the applicant: (a) provided a brief description of the

system, components, materials, and environments; (b) stated that the applicable aging effects

were reviewed and evaluated in the GALL Report; and (c) identified those aging effects for the

electrical and I&C components that are subject to an AMR. On the basis of its audit and review,

the staff determines that, for AMRs not requiring further evaluation, as identified in LRA

Table 3.6.1, the applicant's references to the GALL Report are acceptable and no further staff

review is required.

3.6.2.1.1 AMR Results Identified as Not Applicable

The staff reviewed LRA Table 3.6.1, which summarizes the results of AMR evaluations in the

GALL Report for the electrical and I&C component groups.

In LRA Table 3.6.1, items 6 and 14, the applicant stated that fatigue due to ohmic heating,

thermal cycling, electrical transients, frequent manipulation, vibration, chemical contamination,

corrosion, and oxidation of fuse holders (not part of a larger assembly) metallic clamp, and that

the aging effect or mechanism of fuse holder insulation are not applicable. The applicant stated

that all fuse holders, including the fuses installed for electrical penetration protection, are part of

larger assemblies.

The staff noted that in Interim Staff Guidance-5, "Identification and Treatment of Electrical Fuse

Holders for License Renewal," the staff provided examples of typical fuse holders that require

an AMR. These are fuses that are installed separately in fuse holder panels which are used as

protective devices to ensure the integrity of containment penetration or that are used as

isolation devices between Class 1 E and non-Class 1 E electrical circuits.

During the audit, the staff requested that the applicant explain why the fuse holders installed in

an electrical containment protection assembly are considered part of a larger active assembly

that do not require an AMR.

In its response, the applicant stated that the electrical containment penetration assemblies at

WCGS do not incorporate self-fusing characteristics and must be protected externally. The

fuses that are used to protect the electrical containment penetration are installed in larger

assemblies (i.e., motor control center cubicles, main control boards, distribution panels, etc.).

The staff noted that in accordance to Interim Staff Guidance-5 and 10 CFR 50.54, fuse holders

installed in an active assembly are part of an active assembly and an AMR need not be

performed. Therefore, the staff finds the applicant's response acceptable.

During the audit, the staff also requested that the applicant identify fuse holders installed

separately as isolation devices between Class 1 E and non-Class 1 E electrical circuits and

explain why these fuses do not require an AMR.

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In its response, the applicant stated that the WCGS controlled fuse list does not identify which

of the 2500 fuses are used as isolation devices between Class 1 E and non-Class 1 E electrical

circuits. The fuse list does identify the locations for all of the fuses. A review of this list

determined that there are no fuses within the scope of license renewal that are not installed as

part of larger assemblies. The aging of the components including the fuse holders within these

assemblies is managed as part of the active component. The applicant clarified that WCGS did

not install fuses in standalone fuse panels or cabinets.

The staff finds the applicant's response acceptable because only the fuses that are installed in

fuse panels or cabinets need to have an AMR performed. The staff finds that these fuse

holders are part of an active assembly and; therefore, an AMR is not required.

In LRA Table 3.6.1, items 7, 8, 9, and 10, the applicant stated that WCGS has no metal

enclosed bus within the scope of license renewal.

During the audit, the staff verified that WCGS has no metal enclosed bus within the scope of

license renewal and; therefore, these GALL Report line items are not applicable.

3.6.2.1.2 Loosening of Bolted Connections Due to Thermal Cycling, Ohmic Heating, Electrical

Transients, Vibration, Chemical Contamination, Corrosion, and Oxidation

The staff noted that GALL Report, Chapter VI, Item VI.A-1, for cable connections (metallic

parts), lists an environment of air indoor and air outdoor. LRA Table 3.6.2-1 lists an

environment of air indoor; however, it does not include outdoor air.

During the audit, the staff requested that the applicant justify why oxidation of cable

connections is not an aging effect for cable connections in an outdoor environment.

In its response, the applicant stated that it would amend LRA Table 3.6.271 to include electrical

cable connections exposed to outdoor air. By letter dated August 31, 2007, the applicant

revised LRA Table 3.6.2-1 to include an outdoor air environment for cable connections.

The staff finds the applicant's response acceptable because oxidation of cable connections is a

potential aging mechanism in an environment of outdoor air. The staff finds that this

environment is now consistent with the recommendations in the GALL Report.

The staff evaluated the applicant's claim of consistency with the GALL Report. The staff also

reviewed information pertaining to the applicant's consideration of recent operating experience

and proposals for managing aging effects. On the basis of its review, the staff concludes that

the AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated

that the effects of aging for these components will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

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3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is

Recommended

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended

by the GALL Report, for the electrical and I&C components and provides information

concerning how it will manage the following aging effects and related QA:

° electrical equipment subject to EQ

° degradation of insulator quality due to salt deposits or surface contamination, loss of

material due to mechanical wear

loss of material due to wind induced abrasion and fatigue, loss of conductor strength

due to corrosion, and increased resistance of connection due to oxidation or loss of

pre-load

QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed

consistency with the report and for which the GALL Report recommends further evaluation, the

staff audited and reviewed the applicant's evaluation to determine whether it adequately

addressed the issues further evaluated. In addition, the staff reviewed the applicant's further

evaluations against the criteria contained in SRP-LR Section 3.6.2.2. The staff's review of the

applicant's further evaluation follows.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

LRA Section 3.6.2.2.1 states that EQ is a TLAA, as defined in 10 CFR 54.3. Applicants must

evaluate TLAAs in accordance with 10 CFR 54.21 (c)(1). SER Section 4.4 documents the staff's

review of the applicant's evaluation of this TLAA.

3.6.2.2.2 Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, Loss

of Material Due to Mechanical Wear

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2.

LRA Section 3.6.2.2.2 addresses degradation of insulator quality due to presence of any salt

deposits and surface contamination, and loss of material due to mechanical wear. The applicant

stated that WCGS is located in an area with moderate rainfall and where the outdoor

environment is not subject to industry air pollution or salt spray. Contamination buildup on the

high-voltage insulators is not a problem due to rainfall periodically washing the insulators.

Additionally, there is no salt spray at the plant since the plant is not located near the ocean. The

applicant stated that degradation of insulator quality in the absence of salt deposits and surface

contamination is not an aging effect requiring management. Industry experience has shown that

transmission conductors are designed and installed not to swing significantly and cause wear,

due to wind-induced abrasion and fatigue. The WCGS transmission conductors are designed

and installed not to swing significantly and cause wear due to wind induced abrasion and

fatigue. Therefore, loss of material due to wind induced abrasion and fatigue is not an

applicable aging effect requiring management.

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SRP-LR Section 3.6.2.2.2 states that degradation of insulator quality due to salt deposits or

surface contamination may occur in high-voltage insulators. The GALL Report recommends

further evaluation of plant-specific AMPs for plants at locations of potential salt deposits or

surface contamination (e.g., in the vicinity of salt water bodies or industrial pollution). Loss of

material due to mechanical wear caused by wind on transmission conductors may occur in

high-voltage insulators. The GALL Report recommends further evaluation of a plant-specific

AMP to ensure that these aging effects are adequately managed.

The staff noted that various airborne materials such as dust, salt, and industrial effluent can

contaminate insulator surface. The buildup of surface contamination is gradual and in most

areas washed away by rain. The glazed insulator surface aids this contamination removal. A

large buildup of contamination enables the conductor voltage to track along the surface more

easily and can lead to insulator flashover. Surface contamination can be a problem in areas

where there are greater concentrations of airborne particles such as near facilities that

discharge soot or near the sea coast where salt spray is prevalent. Since WCGS is not located

near facilities that discharge soot or near the sea coast, the staff finds that surface

contamination is not an applicable aging effect requiring management for high-voltage

insulators at WCGS.

The staff also noted that mechanical wear could be an aging effect for strain and suspension

insulators if they are subject to movement. Movement of the insulators can be caused by wind

blowing the supported transmission conductor, causing it to swing from side to side. If this

swinging is frequent enough, it could cause wear in the metal contact points of the insulator

string and between an insulator and supporting hardware. Although this is possible, industry

experience has shown transmission conductors do not normally swing and that when they do,

due to substantial wind, they do not continue to swing for very long once the wind has subsided.

The staff finds that the applicant considered wind loading that could cause a transmission line

and insulator to vibrate in its design and installation. In addition, the applicant confirmed that

none of the industry operating experience has shown that transmission conductors swing

significantly and cause wear. Therefore, the staff finds that loss of material of insulator caused

by transmission conductor vibration or sway is not a significant aging effect requiring

management at WCGS.

Based on the programs identified above, the staff concludes that theapplicant's programs meet

SRP-LR Section 3.6.2.2.2 criteria. For those line items that apply to LRA Section 3.6.2.2.2, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of Conductor

Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss

of Pre-Load

The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3.

LRA Section 3.6.2.2.3 addresses loss of material due to wind induced abrasion and fatigue,

loss of conductor strength due to corrosion, and increased resistance of connection due to

oxidation or loss of pre-load. The applicant stated that industry experience has shown that

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transmission conductors are designed and installed not to swing significantly and cause wear

due to wind induced abrasion and fatigue. Therefore, loss of material due to wind induced

abrasion and fatigue is not an applicable aging effect requiring management. The applicant

stated that the most prevalent mechanism contributing to loss of conductor strength of an

Aluminum Conductor Steel Reinforced (ACSR) transmission conductor is corrosion, which

includes corrosion of the steel core and aluminum strand pitting. ACSR conductor degradation

begins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on

air quality, which involves suspended particles in the air, sulphur dioxide concentration, rain, fog

chemistry, and other weather conditions. The WCGS outdoor environment is not subject to

industry air pollution or saline environment that would cause significant corrosion of the

transmission conductors.

The applicant stated that the National Electrical Safety Code (NESC) requires that tension on

installed conductors be a maximum of 60 percent of the ultimate conductor strength. The NESC

also sets the maximum tension a conductor must be designed to withstand under heavy load

requirements, which includes consideration of ice, wind, and temperature. At WCGS the ACSR

transmission conductors with a core of 7 steel strands have ultimate conductor strength of

42,200 lbs. The WCGS ACSR transmission conductors within the scope of license renewal are

installed so that conductor tension does not exceed 9,900 lbs at the NESC heavy loading

condition (23 percent of the ultimate conductor strength). Tests performed by Ontario

Hydroelectric on ACSR transmission conductors showed a 30 percent loss of ultimate

conductor strength due to corrosion. Assuming a 30 percent loss of ultimate conductor strength

(12,660 Ibs) due to corrosion over 60 years, the WCGS ACSR transmission conductors have

adequate design margin to offset the loss of strength due to corrosion and still meet the NESC

requirement of not exceeding 60 percent of the ultimate conductor strength (17,724 Ibs). The

Ontario Hydroelectric test envelops the conductors at WCGS, and based on the conservatism

in strength margin, demonstrates that the material loss on the WCGS ACSR transmission

conductors is acceptable for the period of extended operation. Therefore, corrosion is not a

credible aging effect that requires management for the period of extended operation.

The applicant stated that transmission conductor connections at the time of installation are

treated with corrosion inhibitors to avoid connection oxidation and torqued to avoid loss of

pre-load. Based on temperature data described in USAR Section 2.3, the transmission

connections do not experience thermal cycling. The transmission connections are subject to

average monthly temperatures ranging from 80 OF in July and August to 29 OF in January with

minimal ohmic heating. Therefore, increased resistance of connections due to oxidation or loss

of pre-load is not an aging effect requiring management. In addition, the applicant stated that

the outdoor environment at WCGS is not subject to industry air pollution or saline environment.

Aluminum bus material, galvanized steel support hardware, and stainless steel connection

material do not experience any appreciable aging effects in this environment. The design

incorporates the use of stainless steel "Belleville" washers on the switchyard bus bolted

electrical connections of dissimilar metals to compensate for temperature changes, to maintain

the proper torque and prevent loss of pre-load.

SRP-LR Section 3.6.2.2.3 states that loss of material due to wind-induced abrasion and fatigue,

loss of conductor strength due to corrosion, and increased resistance of connection due to

oxidation or loss of pre-load may occur in transmission conductors and connections and in

switchyard bus and connections. The GALL Report recommends further evaluation of a

plant-specific AMP to ensure that these aging effects are adequately managed.

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The staff finds that the transmission conductors at WCGS are designed and installed not to

swing significantly and cause wear; therefore, mechanical wear is not an applicable aging effect

that can cause a loss of intended function of the transmission conductors.

The staff also finds that corrosion of an ACSR conductor is a very slow acting mechanism, and

test data from Ontario Hydroelectric, which is bounded by the types of conductors at WCGS,

illustrates that transmission conductors will have ample strength through the period of extended

operation. Based on this information, the staff concludes that loss of conductor strength is not a

significant aging effect requiring management at WCGS.

In LRA Table 3.6.1, item 12, the applicant stated that for transmission conductors and

connections and switchyard bus and connections, the aging effect in the GALL Report for this

material and environment combination is not applicable.

The staff noted that SRP-LR Section 3.6.2.2.3 states that increased resistance of connections

due to oxidation or loss of pre-load could occur in transmission conductor connections and in

switchyard bus connections. Further, EPRI document TR-1 04213, "Bolted Joint Maintenance &

Application Guide," states that increased temperature difference in electrical bolted joints is due

to high circuit rating or increased current duration. The temperature of an electrical bolted joint

will rise and stress will increase with increasing current duration. If this temperature increase is

not taken into consideration, loose or failure joint will result.

During the audit, the staff requested that the applicant explain why torque relaxation for bolted

connections of switchyard bus and transmission conductors is not a concern at WCGS. The

staff also requested that the applicant explain why increased resistance of bolted connections

due to oxidation is not a concern for switchyard bus and transmission conductor connections.

In its response, the applicant stated that torque relaxation for bolted connections of switchyard

bus and transmission conductors is not a concern because it uses stainless steel bolts with

stainless steel washers to maintain the proper torque and prevent loss of pre-load. The bolted

transmission connections that are within the scope of license renewal are at the startup

transformer XMR01 and disconnect 345-163. These connections are periodically evaluated with

thermography as part of the preventive maintenance activities performed on the startup

transformer and disconnect. Based on temperature data provided in USAR Chapter 2.3, the

transmission connections do not experience thermal cycling. The transmission connections are

subject to average monthly temperatures ranging from 80 OF in July and August to 29 OF in

January, with minimal ohmic heating.

The applicant also stated that the corrosion inhibitors compound (i.e., a grease-type sealant) is

a consumable which is used for initial assembly of bolted connections and is replaced as

required when connections are taken apart and reassembled (e.g., during routine

maintenance). The compound is weather resistant and adheres to the connection to ensure low

contact resistance. Based on operating experience, this method of installation has been shown

to provide a corrosion-resistant low electrical resistance connection. Also, the applicant clarified

that the plant outdoor environment is not subject to industry air pollution or saline environment.

The connection does not experience any appreciable aging effects in this environment.

Therefore, the applicant concluded that general corrosion resulting in the oxidation of

transmission connection surface metals is not an aging effect requiring management at WCGS.

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Further, the applicant stated that periodic thermography will continue during the period of

extended operation. The applicant also provided a copy of a thermography report for the startup

transformer dated October 23, 2003, along with a copy of the work order history. The

thermography results showed that based on the transmission line capacity versus the

connected load, these connections experience minimal to no ohmic heating. These electrical

bolted joints do not experience high circuit rating or increased current duration, as discussed in

EPRI document TR-1 04213. By letter dated August 31, 2007, the applicant amended LRA

Section 3.6.2.2.3 to state:

The WCGS outdoor environment is not subject to industry air pollution or saline

environment. Aluminum bus material, galvanized steel support hardware, and

stainless steel connection material do not experience any appreciable aging

effects in this environment. These connections are periodically evaluated via

thermography as part of the preventive maintenance activities performed on the

startup transformer and disconnect. The periodic thermography will continue into

the period of extended operation.

The staff reviewed the infrared thermography report data and verified that the startup

transformer connections experienced minimal ohmic heating. Based on the data, the staff

determines that these electrical bolted connections do not experience high temperature as a

result of ohmic heating. Anti-oxidant compound is used in bolted connections to prevent the

formation of oxides on the metal surface and to prevent moisture entering the connections,

thus, reducing the chances of corrosion. Therefore, the staff finds that increased resistance of

bolted connections due to oxidation is not an aging effect requiring management at WCGS.

The staff finds that because the startup transformer connections experienced minimal ohmic

heating, bolt loosening due to ohmic heating is not an aging effect requiring management at

WCGS. In addition, a periodic infrared thermography inspection on the startup transformer and

disconnect is performed as part of preventive maintenance activities to maintain the integrity of

switchyard connections that are within the scope of license renewal. The staff finds that this

inspection will continue during the period of extended operation. On the basis of its review, the

staff finds the applicant's response acceptable.

Based on the programs identified above, the staff concludes that the applicant's programs meet

SRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the

staff determines that the LRA is consistent with the GALL Report and that the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB during the period of extended operation,

as required by 10 CFR 54.21 (a)(3).

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff's evaluation of the applicant's QA program.

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3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material,

environment, AERM, and AMP combinations not consistent with or not addressed in the GALL

Report.

In LRA Table 3.6.2-1, the applicant indicated, via notes F through J, that the combination of

component type, material, environment, and AERM does not correspond to a line item in the

GALL Report. The applicant provided further information about how it will manage the aging

effects. Specifically, note F indicates that the material for the AMR line item component is not

evaluated in the GALL Report. Note G indicates that the environment for the AMR line item

component and material is not evaluated in the GALL Report. Note H indicates that the aging

effect for the AMR line item component, material, and environment combination is not evaluated

in the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the

line item component, material, and environment combination is not applicable. Note J indicates

that neither the component nor the material and environment combination for the line item is

evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL

Report, the staff reviewed the applicant's evaluation to determine whether the applicant has

demonstrated that the effects of aging will be adequately managed so that the intended

function(s) will be maintained consistent with the CLB for the period of extended operation. The

staff's evaluation is documented in the following sections.

3.6.2.3.1 Summary of Aging Management Evaluation Electrical Components -

LRA Table 3.6.2-1

The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the

electrical and I&C component groups. On the basis of its review, the staff finds that all AMR

results described in LRA Table 3.6.2-1 are consistent with the GALL Report.

The staff finds that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB for the

period of extended operation, as required by 10 CFR 54.21 (a)(3).

3.6.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that

the effects of aging for the electrical and I&C components within the scope of license renewal

and subject to an AMR will be adequately managed so that the intended function(s) will be

maintained consistent with the CLB for the period of extended operation, as required by

10 CFR 54.21(a)(3).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, "Aging Management Review Results," and

LRA Appendix B, "Aging Management Programs." On the basis of its review of the AMR results

and AMPs, the staff concludes that the applicant has demonstrated that the aging effects will be

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adequately managed so that the intended function(s) will be maintained consistent with the CLB

for the period of extended operation, as required by 10 CFR 54.21 (a)(3). The staff also

reviewed the applicable USAR supplement program summaries and concludes that the

supplement adequately describes the AMPs credited for managing aging, as required by

10 CFR 54.21(d).

With regard to these matters, the staff concludes that there is reasonable assurance that the

applicant will continue to conduct the activities authorized by the renewed license will continue

to be conducted in accordance with the CLB, and any changes made to the CLB, in order to

comply with 10 CFR 54.21 (a)(3), the Atomic Energy Act of 1954 (as amended), and NRC

regulations.

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SECTION 4

TIME-LIMITED AGING ANALYSES

4.1 Identification of Time-Limited Aging Analyses

This section of the safety evaluation report (SER) addresses the identification of time-limited

aging analyses (TLAAs). In license renewal application (LRA) Sections 4.2 through 4.7, Wolf

Creek Nuclear Operating Corporation (WCNOC or the applicant) addressed the TLAAs for Wolf

Creek Generating Station (WCGS), Unit 1. SER Sections 4.2 through 4.8 document the review

of the TLAAs conducted by the staff of the United States (US) Nuclear Regulatory Commission

(NRC) (the staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined

by the current operating term. Pursuant to Title 10, Section 54.21 (c)(1), of the Code of Federal

Regulations (10 CFR 54.21 (c)(1)), applicants must list TLAAs as defined in 10 CFR 54.3.

In addition, pursuant to 10 CFR 54.21 (c)(2), applicants must list plant-specific exemptions

granted under 10 CFR 50.12 based on TLAAs. For any such exemptions, the applicant must

evaluate and justify the continuation of the exemptions for the period of extended operation.

4.1.1 Summary of Technical Information in the Application

To identify the TLAAs, the applicant evaluated calculations for WCGS against the six criteria

specified in 10 CFR 54.3. The applicant indicated that it has identified the calculations that met

the six criteria by searching the current licensing basis (CLB). The CLB includes the updated

safety analysis report (USAR), engineering calculations, technical reports, engineering work

requests, licensing correspondence, and applicable vendor reports. LRA Table 4.1-1, "List of

TLAAs," lists applicable TLAAs:

* reactor vessel neutron embrittlement

" metal fatigue

" environmental qualification of electrical equipment

* concrete containment tendon prestress

* containment liner plate, polar crane bracket, and penetration load cycles

* containment polar crane, fuel building cask handling crane, spent fuel pool bridge crane,

and fuel handling machine CMAA-70 load cycle limits

* absence of a TLAA for reactor vessel underclad cracking analyses

* absence of a TLAA in a reactor coolant pump flywheel fatigue crack growth analysis

4-1
Pursuant to 10 CFR 54.21 (c)(2), the applicant identified an exemption granted under

10 CFR 50.12 based on a TLAA as defined in 10 CFR 54.3. The applicant listed the following

exemption associated with TLAAs in LRA Section 4.3.2.11, "Fatigue Crack Growth Assessment

in Support of a Fracture Mechanics Analysis for the Leak-Before-Break (LBB) Elimination of

Dynamic Effects of Primary Loop Piping Failures.'!

As stated in LRA Section 4.3.2.11, an LBB analysis eliminated the large breaks in the main

reactor coolant loops, permitting omission of evaluations of their jet and pipe whip effects and of

large jet barriers and whip restraints. The containment pressurization and equipment

qualification analyses retained the large-break assumptions. The dynamic effects from

postulated pipe breaks have been eliminated from the structural design basis of the reactor

coolant system primary loop piping as allowed by General Design Criterion (GDC) 4 (as

amended). The elimination of these breaks is the result of the application of LBB technology

approved by the NRC. The final licensing basis LBB submission is the proprietary

Westinghouse Commercial Atomic Power (WCAP)-1 0691, "Technical Basis for Eliminating

Large Primary Loop Pipe Rupture as a Structural Design Basis for Callaway and Wolf Creek

Plants." The NRC approval of this LBB use was granted with the SER for the original license as

a 10 CFR 50.12 exemption from parts of GDC 4 and documented in NUREG-0881 (SER

Section 3.6.1.1; Supplement 5).

4.1.2 Staff Evaluation

LRA Section 4.1 lists the WCGS TLAAs; the applicant also discussed an exemption

(documented in Section 4.1.1) based on these TLAAs. The staff reviewed the information to

determine whether the applicant has provided sufficient information pursuant to

10 CFR 54.21 (c)(1) and 10 CFR 54.21 (c)(2).

As defined in 10 CFR 54.3, TLAAs meet the following six criteria:

(1) involve systems, structures, and components within the scope of license renewal, as

described in 10 CFR 54.4(a)

(2) consider the effects of aging

(3) involve time-limited assumptions defined by the current operating term (40 years)

(4) are determined to be relevant by the applicant in making a safety determination

(5) involve conclusions, or provide the basis for conclusions, related to the capability of the

system, structure, and component to perform its intended functions as described in

10 CFR 54.4(b)

(6) are contained or incorporated by reference in the CLB

The applicant reviewed the list of common TLAAs in NUREG-1800, Revision 1, "Standard

Review Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

dated September 2005. The applicant listed TLAAs applicable to WCGS in LRA Table 4.1-1.

Pursuant to 10 CFR 54.21 (c)(2), the applicant must list all exemptions granted under

10 CFR 50.12, based on a TLAA, and evaluated and justified for continuation through the

period of extended operation. The LRA states that each active exemption was reviewed to

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determine whether it was based on a TLAA. The applicant identified one TLAA-based

exemption. Based on the information provided by the applicant regarding the process used to

identify the exemption and its result, the staff concludes, in accordance with

10 CFR 54.21 (c)(2), that there is one TLAA-based exemption that is justified for continuation

through the period of extended operation.

4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable list

of TLAAs, as required by 10 CFR 54.21 (c)(1). The staff confirmed, as required by

10 CFR 54.21 (c)(2), that the applicant has provided an evaluation, as discussed in LRA

Section 4.3.2.11, that justifies the continuation of the exemption(s) pursuant to 10 CFR 50.12

for the period of extended operation.

4.2 Reactor Vessel Neutron Embrittlement Analysis

Reactor vessel materials are subject to embrittlement, primarily due to exposure to neutron

radiation. Absorbed energy increases with temperature up to a maximum (the Charpy impact

test "upper-shelf energy" (USE)). Neutron embrittlement decreases USE. Nil-ductility transition

reference temperature (RTNDT), is determined for vessel materials before irradiation and

indicates temperatures above which impact tests will demonstrate an acceptable USE. Neutron

embrittlement raises this transition temperature. This increase (ARTNDT) means that higher

temperatures are required for the material to continue to act in a ductile fashion. The

pressure-temperature (P-T) curves are determined by the limiting adjusted reference

temperatures (ARTs) or, if at end-of-life, (EOL ARTs). Low-temperature overpressure

protection (LTOP) is provided by a cold overpressurization mitigation system (COMS), one of

whose setpoints is determined by the calculation of the P-T limit curves. Concerns for the

possibility of thermal shock to the vessel while at high pressure have required evaluation of a

ductile-brittle transition temperature screening parameter for pressurized water reactor (PWR)

vessel material susceptibility to pressurized thermal shock, (PTS), similar to evaluations of EOL

ART. These limits and effects depend on lifetime neutron fluence, are part of the licensing

basis, and support safety determinations and Technical Specification operating limits. Their

calculations are therefore TLAAs. The supporting calculation of expected EOL vessel neutron

fluence is similarly a TLAA. At WCGS, limiting-material coupons have been tested at exposures

comparable to those expected at the end of the period of extended operation. The tests

demonstrate EOL USE values with considerable margins above the 50 foot-pound acceptance

criterion, and special methods were therefore unnecessary. The same tests demonstrate low

values of EOL ART and therefore permit generous operating margins to P-T curve limits to the

end of the period of extended operation. The same coupon tests similarly demonstrate

considerable margins between the reference temperatures for pressurized thermal shock

(RTPTS) for the vessel materials at the EOL fluence, and their acceptance criteria.

4.2.1 Neutron Fluence, Upper-Shelf Energy, and Adjusted Reference Temperature

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 summarizes the evaluation of neutron fluence, USE, and ART for the period

of extended operation. The WCGS surveillance program is consistent with 10 CFR Part 50,

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Appendix H. The coupons are actual samples from the materials in the vessel. However, the

weld material test specimens were not taken from excess material from the beltline region, for

which an exemption is granted in NUREG-0881, SER, Section 5.3.3. WCGS coupon capsules

are lettered U, V, W, X, Y, and Z. The U, Y, V, and X coupons have been withdrawn and

examined (in that order), and the last W and Z capsules have been placed in storage. The W

and Z capsules were removed to the spent fuel pool during the 2005 refueling outage at about

16.5 effective full-power years (EFPY). These capsules had a lead factor of 4.11 and therefore

reached a fluence equivalent to about 54 EFPY at the vessel surface at 13.83 EFPY, and would

have reached two times this fluence at 26.8 EFPY. This withdrawal therefore meets the

American Society for Testing and Materials (ASTM) El 85-82 criterion that states that capsules

may be removed when the capsule neutron fluence is between one and two times the limiting

fluence calculated for the reactor vessel at the end of expected life. This removal and the

change to the withdrawal schedule have been reviewed and approved as required by

10 CFR Part 50, Appendix H. Vessel neutron fluence is now confirmed by ex-vessel dosimetry.

The WCAP-1 6028 X-Capsule examination report projected neutron fluences to 54 EFPY,

including effects of power rerate from 3411 to 3565 megawatt thermal (MWt), by methods

consistent with Regulatory Guide (RG) 1.190, Revision 0, "Calculational and Dosimetry

Methods for Determining Pressure Vessel Neutron Fluence." WCAP-1 6028 validated these

projections by comparison of the measured Capsule X dosimetry reaction rates with expected

rates from the calculated exposures and evaluated the uncertainties in these projections as

recommended by RG 1.190. WCAP-16028 Section 6.0 and Appendix A also projected the

displacement per atom (dpa) alternative measure of neutron embrittlement (energy-dependent

displacements per iron atom) to 54 EFPY, using methods consistent with ASTM E853 and

E693, in support of RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials,"

embrittlement assessment methods using dpa. The measured exposure of these coupons is

3.49 x 1019 neutrons/cm2 , nearly equal to the 3.51 x 1019 now predicted for 54 EFPY (i.e., for a

60-year life, including rerate). This 54 EFPY, 60-year projection of 3.51 x 1019 neutrons/cm 2 is

only 12 percent more than the original design-basis 32 EFPY estimate of 3.14 x 1019

neutrons/cm 2.

The applicant evaluated the X coupon set in 2003. The WCAP-1 6028 analysis of the X vessel

material coupons and the staff evaluation indicate more than adequate EOL USE and indicate

that ART for the limiting material will remain modest and will permit adequate operating margins

to P-T limits until the end of a 60-year period of extended operation, projecting evaluation of the

acceptability of these parameters to the end of the period of extended operation with

considerable margin. Aging management for fluence, USE, and ART therefore now consists of

ex-vessel dosimetry and available reserve coupons stored in the spent fuel pool with exposures

in excess of those expected for the vessel at the end of the period of extended operation if

additional coupon tests are required. Additional vessel material is available if new coupons are

needed. The validity of these parameters for the analyses that depend upon them therefore will

be maintained and confirmed to the end of the period of extended operation.

4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.2.1 to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected for the period of extended operation and, pursuant to

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10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

The staff finds that the Reactor Vessel Surveillance Program is designed to monitor material

property changes due to neutron irradiation. The surveillance program is also required pursuant

to 10 CFR Part 50, Appendix H.

The staff noted that six surveillance capsules, named U, V, W, X, Y and Z, were placed in the

WCGS reactor vessel. The U, Y, V, and X capsules were then removed and analyzed, in that

specific order. Capsules W and Z were removed also and placed in storage in the spent fuel

pool for possible use at a later time. Exposure of the capsules satisfies the ASTM E -185

requirements for the current license as well as during the period of extended operation.

Analysis of the capsule dosimetry and conversion into projected vessel fluence values is

performed in accordance with NRC-approved codes that in general adhere to staff guidance

provided in RG 1.190. The staff finds that the calculation for the peak fluence at 60 years of

operation takes into account a power uprate from 3411 MWt to 3565 MWt. The staff noted that

conservatively, the period of extended operation was calculated at 90 percent load factor to

54 EFPYs of operation even though for the initial fuel cycles, the load factor was much lower

than 90 percent. Surveillance capsule analysis and projection of vessel fluence to the end of the

period of extended operation have been performed by Westinghouse Electric Company using

staff-approved methodologies. Its topical report WCAP-1 6028, Revision 0, "Analysis of Capsule

X from Wolf Creek Nuclear Operating Corporation, Wolf Creek Reactor Vessel Radiation

Surveillance Program," dated March, 2003, includes the results of the dosimetry analysis,

comparison of calculated to measured dosimeter activation for Capsule X, and the projected

values of the peak vessel fluence to the end of license renewal (i.e., 60 years of operation).

Based on its review of this topical report, the staff finds that:

" Dosimetry indicated excellent agreement between calculated and measured values from

surveillance Capsule X.

" The estimated (i.e., through the lead factor) measured value for the peak fluence is

3.49 x 1019 n/cm2 (i.e., E greater than 1 MeV) compared to 3.51 x 1019 n/cm2 from the

calculation. This close agreement provides an additional assurance for the calculated

value.

" The accepted value of the peak vessel fluence is 3.51 x 10'" n/cm2.

The staff finds that by using RG 1.99, Revision 2, position 2.1, the maximum value for the

limiting plate is 109 OF (270 0 F limit per 10 CFR 50.61). This is indicative of a large margin and

the low state of embrittlement of the reactor vessel.

The staff's review of LRA Section 4.2.1 identified an area in which additional information was

necessary to complete the review of the applicant's TLAA evaluation. The applicant responded

to the staff's request for additional information (RAI) as discussed below.

In RAI 4.2.1-1 dated April 9, 2007, the staff requested that the applicant submits a table of the

60-year EOL USE values for each beltline material. In addition, the staff requested that the

applicant discusses how surveillance results were evaluated in determining the USE values.

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In its response dated May 9, 2007, the applicant provided discussion of the USE values for all

the reactor pressure vessel beltline materials as a part of providing its evaluation in determining

the USE values (documented in the applicant response to RAI 4.2.1-1). Based on its review, the

staff finds that the applicant has demonstrated that all are above the 50 ft-lb acceptance

criterion.

The staff finds the applicant's response to RAI 4.2.1-1 acceptable. The staff also noted that the

vessel, primarily due to its chemical composition (i.e., low copper and nickel content), sustained

very little embrittlement; consequently, it has generous operating margins to P-T curve limits for

PTS and LTOP. Therefore, the staff's concern described in RAI 4.2.1-1 is resolved.

On the basis of its review, the staff finds that the analyses have been projected to the end of

the period of extended operation and that the aging effects will be adequately managed.

4.2.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

neutron fluence, upper-shelf energy and adjusted reference temperature in LRA Section A3.1.1.

On the basis of its review of the USAR supplement, the staff concludes that the summary

description of the applicant's actions to address neutron fluence, upper-shelf energy and

adjusted reference temperature is adequate.

4.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(ii), that for neutron fluence, upper-shelf energy and adjusted reference

temperature, the analyses have been projected to the end of the period of extended operation

and, pursuant to 10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will

be adequately managed for the period of extended operation. The staff also concludes that the

USAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21 (d).

4.2.2 Pressurized Thermal Shock

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2 summarizes the evaluation of PTS for the period of extended operation.

Section 54.4(a)(3) of the 10 CFR requires the applicant to evaluate all structures, systems, and

components (SSCs) relied on in safety analyses or plant evaluations to perform functions for

compliance with 10 CFR 50.61. If the RTpTS for each heat of material of the reactor pressure

vessel does not exceed 270 OF for plates, forgings, and axial welds or 300 OF for circumferential

welds (the PTS screening criteria), only the reactor pressure vessel is "relied on to demonstrate

compliance" with 10 CFR 50.61. The reactor pressure vessel meets the PTS screening criteria,

will continue to meet them for the period of extended operation, and is therefore the only

component relied upon to demonstrate compliance with 10 CFR 50.61. Section 50.61 (b)(1) of

10 CFR requires a re-evaluation of RTPTS whenever there is a significant change in projected

RTPTS values or upon a request for a change in the expiration date for operation of the facility.

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License renewal therefore requires RTPTs re-evaluation even if the expected change is not

significant. The applicant will revise the P-T limits report (PTLR) for the period of extended

operation and incorporate the RTPTs projections reported in WCAP-16030 and summarized

here, in accordance with 10 CFR 50.61 (b)(1). The evaluation of the PTS screening parameter

will be projected to the end of the period of extended operation.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2 to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The staff finds that 10 CFR 50.61 provides the fracture toughness requirements protecting

reactor pressure vessels against the consequences of PTS, and the screening criteria against

which the calculated values are to be evaluated. Reactor pressure vessel beltline base-metal

materials (i.e., forging or plate materials) and longitudinal (i.e., axial) weld materials are

considered to provide adequate protection against PTS events if the calculated RTPTs values

are less than or equal to 270 OF. Reactor pressure vessel beltline circumferential weld materials

are considered to provide adequate protection against PTS events if the calculated RTPTS

values are less than or equal to 300 OF. The regulations also provide an expanded discussion

regarding how the calculations of RTPTS values should be performed and describe two methods

for determining RTPTs values for reactor vessel beltline materials, depending on whether or not

a given reactor vessel beltline material is represented in the plant's surveillance program.

The staff noted that LRA Table 4.2-3 lists RTPTS values for only the limiting reactor pressure

vessel material.

The staff's review of LRA Section 4.2.2 identified an area in which additional information was

necessary to complete the review of the applicant's TLAA evaluation. The applicant responded

to the staff's RAI as discussed below.

In RAI 4.2.2-1 dated April 9, 2007, the staff requested that the applicant submit a table of the

60-year EOL RTPTS values for each beltline material. In addition, the staff requested that the

applicant discuss how surveillance capsule results were applied in the determination of the

RTPTs values.

In its response dated May 9, 2007, as a part of providing its discussion of evaluation in

determining the RTPTS values, the applicant provided the heat numbers, material ID, copper and

nickel content, chemistry factor, initial RTNDT, margin, 60-year peak fluence, fluence factor,

ARTPTS, and 60-year RTPTS values for all materials included in the WCGS surveillance program.

Based on its review, the staff finds that the applicant has calculated the PTS values for these

materials in accordance with 10 CFR 50.61 for the period of extended operation.

The staff finds the applicant's response to RAI 4.2.2-1 acceptable. The staff finds that the

applicant performed evaluations of all materials subject to the provision of 10 CFR Part 50,

Appendix H, and that the limiting material specified in the LRA is bounding. Therefore, the

staff's concern described in RAI 4.2.2-1 is resolved.

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The staff verified the applicant's limiting 54 EFPY RTpTs values and confirmed that the limiting

material for PTS, lower shell plate R2508-3, has a predicted value of 109 OF using surveillance

data. The staff notes that this value is less than the screening criteria of 270 OF for plates.

Therefore, the staff concludes that the reactor vessel will meet the requirements of

10 CFR 50.61 during the period of extended operation and that the aging effects will be

adequately managed.

4.2.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of PTS

in LRA Section A3.1.2. On the basis of its review of the USAR supplement, the staff concludes

that the summary description of the applicant's actions to address PTS is adequate.

4.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(ii), that for PTS, the analyses have been projected to the end of the period.

of extended operation. The staff also concludes that the USAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.2.3 Pressure-Temperature Limits

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 summarizes the evaluation of P-T limits for the period of extended operation.

P-T limit curves are operating limits, conditions of the operating license, and are included in the

PTLR, as required by Technical Specifications. They are valid up to a stated vessel fluence limit

and must be revised prior to operating beyond that limit. The currently-applicable PTLR is valid

up to only 20 EFPY and is not based on the evaluation of the most recently withdrawn

X-Coupon set. The analysis of the X vessel coupons indicates that the ART for the limiting

material will remain modest and will permit adequate operating margins to P-T limits until the

end of a 60-year period of extended operation. The applicant will revise the PTLR before

reaching 20 EFPY and will project appropriate P-T limits to the end of the 60-year period.

4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.2.3 to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected to the end of the period of extended operation.

The staff finds that 10 CFR 50.60 and 10 CFR Part 50, Appendix G establish the requirements

and criteria for generating the P-T limits for commercial U.S. light-water reactors. The P-T limit

curves that apply for the current operating conditions are included in the facility's PTLR. The

P-T limit curves will continue to be updated as required by 10 CFR Part 50, Appendix G, or by

operational needs. The staff finds that this will assure that the operational limits remain valid

during the period of extended operation. Therefore, based on its review, the staff finds that the

applicant's evaluation of P-T limits for the period of extended operation is acceptable pursuant

to 10 CFR 54.21 (c)(1)(ii).

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The staff finds that the applicant's current PTLR is valid for up to 20 EFPY. The data from the

analysis of surveillance Capsule X is not included in the current PTLR. The staff noted that by

letter dated April 8, 2003, the applicant submitted its reactor pressure vessel surveillance

capsule report for Capsule X. By letter dated December 13, 2003, the staff concluded that there

will be no significant impact on P-T operating limits due to the Capsule X results.

In addition (additional measure of assurance), the applicant committed to revise the PTLR

before reaching 20 EFPY and will, at that time, project appropriate P-T limits to the end of the

period of extended operation. Therefore, the staff concludes that the applicant will continue to

meet the requirements of 10 CFR 50.61 during the period of extended operation and that the

aging effects will be adequately managed.

4.2.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of P-T

limits in LRA Section A3.1.3. On the basis of its review of the USAR supplement, the staff

concludes that the summary description of the applicant's actions to address P-T limits is

adequate.

4.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(ii), that for P-T limits, the analyses have been projected to the end of the

period of extended operation. The staff also concludes that the USAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.2.4 Low Temperature Overpressure Protection

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the evaluation of LTOP for the period of extended operation.

LTOP is required by Technical Specifications (Limited Condition for Operation 3.4.12) and

provided (in part) by the COMS, which opens the power-operated relief valves at a setpoint

determined by current P-T limits analysis. The calculation of the P-T limit curves depends on

assumed neutron fluence at the end of the period to which the limits apply and is therefore a

TLAA; however, once the P-T curves have been calculated, the subsequent calculation of the

COMS setpoint is time-dependent only because it depends on the P-T limits. Other COMS

setpoints and features are not time-dependent. The COMS setpoint is established in the PTLR,

which will be revised for the period of extended operation.

4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.2.4 to verify pursuant to 10 CFR 54.21 (c)(1 )(ii), that the

analyses have been projected to the end of the period of extended operation.

The staff noted that LTOP limits are considered as part of the calculation of the P-T curves. The

current P-T analyses are valid up to 20 EFPY. The P-T limit curves that apply for the current

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operating license are included in the PTLR for each plant. The P-T limit curves will be updated

continuously as required by 10 CFR Part 50, Appendix G, or by operational needs. The staff

finds that this updating will assure that the operational limits remain valid through the period of

extended operation.

The staff noted that the data from the analysis of surveillance Capsule X is not included in the

current PTLR. The staff noted that by letter dated April 8, 2003, the applicant submitted its

reactor pressure vessel surveillance capsule report for Capsule X. By letter dated

December 13, 2003, the NRC concluded that there will be no significant impact on P-T

operating limits due to the Capsule X results. In addition (additional measure of assurance), the

applicant committed (documented in Appendix A) to revise the PTLR before reaching 20 EFPY

and will also, at that time, project appropriate P-T limits to the end of the period of extended

operation.

On the basis of its review, the staff concludes that the applicant has a process for updating the

plant's P-T curves and LTOP power-operated relief valve setpoints for the period of extended

operation. Therefore, the staff finds that, the applicant's evaluation of LTOP for the period of

extended operation satisfies the requirements of 10 CFR 54.21 (c)(1)(ii) and 10 CFR Part 50,

Appendices G and H.

4.2.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

LTOP in LRA Section A3.1.4. On the basis of its review of the USAR supplement, the staff

concludes that the summary description of the applicant's actions to address LTOP is

adequate.

4.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1 )(ii), that for LTOP, the analyses have been projected to the end of the

period of extended operation. The staff also concludes that the USAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3 Metal Fatigue Analysis

By letters dated June 1, August 9, and October 17, 2007, the applicant revised LRA

Section 4.3. In these amendments, the applicant stated that the fatigue analyses are required

for piping, vessels, and heat exchangers designed to American Society of Mechanical

Engineers (ASME) "Boiler and Pressure Vessel Code, Section III, Rules for Construction of

Nuclear Power Plant Components," Division 1, "Metal Components," Subsection NB,

"Requirements for Class 1 Components" (ASME Code Section III Class 1). Fatigue analyses

may also be invoked for Class 1 pump and valve pressure boundaries. The design of piping

and vessels to certain other codes and code sections, including ASME Code Section III Class 2

and 3, ANSI-ASME B31.1, and ASME Code Section VIII Division 2, may assume a stated

number of full-range thermal and displacement cycles. Westinghouse license renewal topical

report WCAP-14575-A, "Aging Management Evaluation for Class 1 Piping and Associated

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Pressure Boundary Components," and the related NRC staff evaluation catalog aging effects

and the Class 1 components affected by them, and propose dispositions for the period of

extended operation that are consistent with the requirements of 10 CFR 54. This

section supplies additional WCGS-specific information necessary for disposition of these

TLAAs and describes fatigue analyses and evaluations of a limited number of other non-Class 1

components.

The applicant stated that ASME Code Section III Class 1 design specifications define a set of

static and transient load conditions for which components are to be designed. Although original

design specifications commonly state that the transient conditions are for a 40-year design life,

the fatigue analyses themselves are based on the specified number of occurrences of each

transient rather than on this lifetime. The number of occurrences of each transient for the

WCGS fatigue analyses was specified to be somewhat larger than the number of occurrences

expected during the 40-year license life of the plant, based on engineering experience and

judgement. This provides a margin of safety and an allowance for future changes in design or

operation that may affect system design transients. The applicant stated that operating

experience at WCGS and at other similar units has demonstrated that the assumed frequencies

of design transients, and therefore the number of transient cycles assumed for a 40-year life,

were conservative.

4.3.1 Fatigue Management Program

LRA Section 4.3.1 states that in accordance with the Technical Specifications, the existing

Metal Fatigue of Reactor Coolant Pressure Boundary Program uses cycle counting and usage

factor tracking to ensure that actual plant experience remains bounded by design assumptions

and calculations reflected in the USAR. It was customized, verified, and validated pursuant to a

10 CFR 50, Appendix B, quality assurance (QA) program for plant-specific implementation at

WCGS. The applicant indicates that the program will be enhanced and augmented in order to

support safe plant operation for the period of extended operation. The enhanced Metal Fatigue

of Reactor Coolant Pressure Boundary Program will monitor plant transients and cumulative

usage factors (CUrs) for a subset of ASME Code Section III Class 1 reactor coolant pressure

boundary vessel and piping locations, to ensure that licensing basis limits on fatigue effects, in

all locations, are not exceeded without being identified, and without appropriate corrective

measures.

4.3.1.1 Present WCGS Fatigue Monitoring Program

4.3.1.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1.1 summarizes the evaluation of the existing Metal Fatigue of Reactor

Coolant Pressure Boundary Program for the period of extended operation. The fatigue analyses

incorporate several conservative assumptions and methods, described below, to ensure that

usage factors predicted by the design calculation will exceed (or "bound") the usage factors

actually accumulated by the components.

Fatigue Desiqn Curve with Margin for Uncertainties and Moderate Environmental

Effects. The ASME Code Section III fatigue cyclical stress and cycles to failure curves

(i.e., S-N curves) are based on regression analysis of a large number of fatigue data

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points for samples strain-cycled in air. The curves include adjustments for the elastic

modulus and for departure from zero mean stress; and a margin for uncertainties,

including modest environmental effects.

* Bounding Parameters for Transients. Fatigue analyses assume a given number of

cycles of each transient of a set of transient events, where each event is defined by

limiting pressure and temperature transients and other load conditions. Since actual

event cycles are seldom as severe as those considered in the analysis, the resulting

stress ranges are lower. Therefore, the contributions to cumulative usage factor are also

lower.

* Actual Number of Event Cycles. The analytic limit for a fatigue analysis is a CUF of 1.0

at any location. The CUF is calculated as the sum of all contributing partial usage

factors for the design basis number of each of the design basis cyclic loading events.

Even if the analysis showed a calculated usage factor at the 1.0 limit for a location, and

even if the design basis number of events were reached for one or more events of a set,

but not for the remainder of the assumed events, some margin will remain to the 1.0

limit because not as many design basis events will have occurred as assumed by the

analysis. Therefore they will not have contributed as much to the usage factor as the

analysis assumed.

4.3.1.1.2 Staff Evaluation

LRA Section 4.3.1 describes the current fatigue monitoring program at WCGS and

demonstrates how this program will continue to manage fatigue during the period of extended

operation. During the audit, the staff requested that the applicant explain how the aging

management program (AMP) tracks usage factors.

In its response, the applicant stated that the program uses both design basis cycle-based and

stress-based monitoring. However, the applicant clarified that stress-based results are only

used if they are required to demonstrate acceptable fatigue usage; otherwise, the cycle-based

results are used. The staff also reviewed the applicant's basis documents which tracks current

transient cycles. The staff's evaluation of the Metal Fatigue of Reactor Coolant Pressure

Boundary Program is documented in SER Section 3.0.3.2.24.

On the basis that the applicant is committed (Commitment No. 21) to perform cycle monitoring

and stress-based evaluations at selected locations, the staff finds the applicant's fatigue

monitoring acceptable.

4.3.1.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of the

Metal Fatigue of Reactor Coolant Pressure Boundary Program in LRA Section A3.2. On the

basis of its review of the USAR supplement, the staff concludes that the summary description of

the applicant's actions to address the existing Metal Fatigue of Reactor Coolant Pressure

Boundary Program is adequate.

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4.3.1.1.4 Conclusion

On the basis of its review, the staff concludes that the Fatigue Monitoring Program provides an

acceptable method to track the fatigue usage of selected reactor coolant system (RCS)

components. The staff also concludes that the USAR supplement contains an appropriate

summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.1.2 Present Status of Monitored Locations

4.3.1.2.1 Summary of Technical Information in the Application

LRA Section 4.3.1.2 summarizes the evaluation of present status of monitored locations for the

period of extended operation. The applicant stated that the Metal Fatigue of Reactor Coolant

Pressure Boundary Program was implemented in 1997. The usage factors calculated by the

program include the effects of cycles incurred before the program was installed. The cycle

count input to the program was accumulated from two periods. Effects were counted or

estimated from the WCGS operating history for the period between initial cold hydro in

February 1982 to the installation of the automated transient data acquisition system in

March 1992. Data from the data acquisition system and from operating records were used

thereafter, up to the implementation of the Metal Fatigue of Reactor Coolant Pressure

Boundary program.

The applicant stated that the cycle accumulations indicate that the original design basis number

of events should not be reached in a 60-year operating life, nor should the cumulative usage

factor limit of 1.0 be exceeded. WCGS operating changes have successfully mitigated surge

line and pressurizer thermal stratification and insurge-outsurge transient effects, limiting the

remaining causes of fatigue usage to counted transients. Cycle counting is therefore an

effective means of determining the contribution of these effects to fatigue usage in these

locations.

With the exception of one location that has been validated for a 60-year life, the Metal Fatigue

of Reactor Coolant Pressure Boundary Program monitors all of the NUREG/CR-6260,

"Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear power Plant

Components," sample locations to be addressed at WCGS. The applicant stated that these

locations were chosen to represent limiting usage factor locations in the Class 1 components

and piping systems.

4.3.1.2.2 Staff Evaluation

During the audit, the staff reviewed the limiting locations tracked by the Metal Fatigue of

Reactor Coolant Pressure Boundary Program as indicated in LRA Table 4.3-2. On the basis

that the program monitors a sample of critical components, which include all of the locations

identified in NUREG/CR-6260, the staff finds that the fatigue monitored locations are consistent

with the recommendations provided in the SRP-LR.

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4.3.1.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

present status of monitored locations in LRA Section A3.2. On the basis of its review of the

USAR supplement, the staff concludes that the summary description of the applicant's actions

to address present status of monitored locations is adequate.

4.3.1.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant's monitored locations are

consistent with recommendations in the SRP-LR. The staff concludes that these monitored

locations are acceptable. The staff also concludes that the USAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.1.3 Program Enhancements for the Period of Extended Operation

4.3.1.3.1 Summary of Technical Information in the Application

LRA Section 4.3.1.3 summarizes the evaluation of program enhancements for the period of

extended operation. The Metal Fatigue of Reactor Coolant Pressure Boundary Program will be

enhanced by including additional components to be monitored and by incorporating additional

action limits and corrective action administrative controls. Corrective actions of the Metal

Fatigue of Reactor Coolant Pressure Boundary Program will be enhanced to ensure that on

approach to an action limit, an evaluation determines whether the scope of the program must

be enlarged to include additional affected reactor coolant pressure boundary locations; to

ensure that other locations do not approach the code limit without an appropriate action, and

that the bases of the LBB and high-energy line break (HELB) analyses are maintained.

These enhancements will be required to address fatigue TLAAs in the period of extended

operation. The applicant therefore will complete these program enhancements before the end

of the current licensed operating period. Changes in available monitoring technology or in the

analyses themselves by that time may permit different action limits and action statements or

may re-define the program features and actions required to address the fatigue TLAAs.

4.3.1.3.2 Staff Evaluation

During the audit, the staff reviewed the enhanced corrective action limits described in LRA

Section 4.3.1.3. The staff requested that the applicant explain if there will be sufficient time to

take appropriate and timely corrective actions if the periodic evaluation prescribed by the Metal

Fatigue of Reactor Coolant Pressure Boundary Program indicates that the CUF limit might be

exceeded in the next operating cycle. The staff also asked that the applicant clarify what are the

definitions of the CUF limits for initiating corrective actions.

In its response, the applicant noted that allowing sufficient time for corrective action is a

criterion for these action limits. The applicant stated that the action limits are under

development for the period of extended operation, and that the time constraints and their bases

cannot be described in detail in advance of these action limits. The applicant further stated that

LRA Section 4.3.1.3 has been amended to describe the basis for these action limits, including

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time constraints. The Metal Fatigue of Reactor Coolant Pressure Boundary Program provides

for periodic evaluation (i.e., once per operating cycle) of fatigue usage and cycle count tracking

of critical thermal and pressure transients to verify that the ASME Code CUF limit of 1.0 and

other CUF design limits (i.e., the HELB criteria of CUF less than 1.0) will not be exceeded. The

applicant also stated that the program will be enhanced to specify acceptable corrective actions

to be implemented to ensure that design limits are not exceeded. These enhancements will

include action limits for accrued transient cycles or CUF that require initiation of corrective

actions, allowing sufficient time to effectively address the issues.

By letter dated June 1, 2007, the applicant amended LRA Section 4.3.1.3 to include these

changes. In addition, by letter dated August 20, 2007, the applicant committed (Commitment

No. 21) to address the enhancement of the Metal Fatigue of Reactor Coolant Pressure

Boundary Program. This commitment was subsequently modified by letter dated

October 3, 2007, to state:

Prior to the period of extended operation, the Metal Fatigue of Reactor Coolant

Pressure Boundary Program will be enhanced to include:

(1) Cycle-Count Action Limit and Corrective Actions. An action limit will be

established that requires corrective action when the cycle count for any of

the critical thermal and pressure transients is projected to reach a high

percentage (e.g., 90%) of the design specified number of cycles before

the end of the next fuel cycle. If this action limit is reached, acceptable

corrective actions include:

(a) Review of fatigue usage calculations:

I. to determine whether the transient in question contributes

significantly to CUF,

ii. to identify the components and analyses affected by the

transient in question, and

iii. to ensure that the analytical bases of the

leak-before-break (LBB) fatigue crack propagation

analysis and of the high-energy line break (HELB)

locations are maintained.

(b) Evaluation of remaining margins on CUF based on cycle-based or

stress-based CUF calculations using the WCGS fatigue

management program software.

(c) Redefinition of the specified number of cycles (e.g., by reducing

specified numbers of cycles for other transients and using the

margin to increase the allowed number of cycles for the transient

that is approaching its specified number of cycles).

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(2) Cumulative Fatigue Usage Action Limit and Corrective Actions. An action

limit will be established that requires corrective action when calculated

CUF (from cycle based or stress based monitoring) for any monitored

location is projected to reach 1.0 within the next 2 or 3 fuel cycles. If this

action limit is reached, acceptable corrective actions include:

(a) Determine whether the scope of the monitoring program must be

enlarged to include additional affected reactor coolant pressure

boundary locations. This determination will ensure that other

locations do not approach design limits without an appropriate

action.

(b) Enhance fatigue monitoring to confirm continued conformance to

the code limit

(c) Repair the component

(d) Replace the component

(e) Perform a more rigorous analysis of the component to

demonstrate that the design code limit will not be exceeded

(f) Modify plant operating practices to reduce the fatigue usage

accumulation rate

(g) Perform a flaw tolerance evaluation and impose

component-specific inspections, under ASME Code Section Xl

Appendices A or C (or their successors), and obtain required

approvals by the NRC.

Corrective action limits for cumulative fatigue usage will be

established to assure that sufficient margin is maintained to allow

one cycle of the highest fatigue usage per cycle transient to occur

without exceeding CUF = 1.0. (This includes consideration of

environmental effects for NUREG/CR-6260 locations.) This may

require that corrective action is taken more than 2 or 3 fuel cycles

before CUF is projected to exceed 1.0. This is because the

projections will be based on historical experience, which is not

expected to include many of the low probability design transients.

The low probability design transients to be used in the evaluation

will include:

auxiliary spray actuation, spray water diff. greater than

320 "F

* excessive feedwater flow

* reactor trip - cooldown with no SI

* COMS

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* reactor trip - no inadvertent cooldown with turbine

over-speed

* reactor trip - cooldown with SI

* inadvertent RCS depressurization

* accumulator safety injection

* operating basis earthquake

(3) 10 CFR 50, Appendix B, procedural and record requirements. Prior to the

period of extended operation, changes in available monitoring technology

or in the analyses themselves may permit different action limits and

action statements, or may re-define the program features and actions

required to address fatigue time-limited aging analyses (TLAAs).

The staff reviewed the applicant's commitment and finds that it addresses all the concerns

raised by the staff. Based on its review, the staff concludes that the Metal Fatigue of Reactor

Coolant Pressure Boundary Program is an acceptable program to manage the fatigue usage of

the monitored components during the period of extended operation in accordance with the

requirements of 10 CFR 54.21 (c)(1)(iii).

.4.3.1.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

program enhancements as described in Commitment No. 21, for the period of extended

operation in LRA Section A3.2. On the basis of its review of the USAR supplement, the staff

concludes that the summary description of the applicant's actions to address program

enhancements for the period of extended operation is adequate.

4.3.1.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant demonstrated that the Metal

Fatigue of Reactor Coolant Pressure Boundary Program will adequately manage the effects of

fatigue. The staff also concludes that the USAR supplement contains an appropriate summary

description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.2 ASME Code Section III Class 1 Fatigue Analysis of Vessels, Piping, and

Components

Fatigue analyses are performed for ASME Code Section III, Division 1, Class 1 piping, vessels,

heat exchangers, pumps, and valves; and if applicable, their supports. The reactor vessel

internals are not designed to ASME Code Section III Class 1 but are analyzed to ASME

Code Section III Subsection NG.

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4.3.2.1 Reactor Pressure Vessel, Nozzles, Head, and Studs

4.3.2.1.1 Summary of Technical Information in the Application

LRA Section 4.3.2.1 summarizes the evaluation of reactor pressure vessel, nozzles, head, and

studs for the period of extended operation. The reactor pressure vessel is designed to the

ASME Code Section III, Subsection NB (Class 1), 1971 Edition with Addenda through Winter

1972. Pressure-retaining and support components of the reactor pressure vessel are subject to

an ASME Boiler and Pressure Vessel Code, Division 1, Section III, fatigue analysis which has

been updated to incorporate redefinitions of loads and design-basis events (DBEs), operating

changes, power rerate, and minor modifications. The currently applicable fatigue analyses of

these components are TLAAs.

The limiting components for fatigue in the reactor pressure vessel pressure boundary and its

supports are the bottom-mounted instrument tubes and the inlet and outlet nozzles. The

design-basis CUFs in these components do not exceed 0.4. Other components of the reactor

pressure vessel pressure boundary and its supports are affected by similar loads and

transients. The closure flanges, studs, and nuts are also subject to bolt-up cycles; however, the

maximum 40-year usage factor in the head and flanges is only about 0.08, including the COMS

transient allowance. The maximum 40-year usage factor in the studs, including effects of an

increased elongation tolerance and the conservative COMS transient allowance, is 0.672. The

reactor vessel primary coolant inlet and outlet nozzles and lower head-to-shell juncture are

evaluated consistently with NUREG/CR-6260, for effects of the reactor coolant environment on

fatigue behavior of these materials.

The applicant stated that fatigue usage factors in the reactor vessel pressure boundary depend

not on effects time-dependent at steady-state conditions, but only on effects of operational,

abnormal, and upset transient events, principally on startup and shutdown transients and on

head flange bolt-up. The existing reactor vessel fatigue analyses therefore will remain valid for

the period of extended operation. The Metal Fatigue of Reactor Coolant Pressure Boundary

Program will ensure that the fatigue analyses remain valid or that appropriate reevaluation or

other corrective measures maintain the design and licensing basis. The applicant stated that

fatigue effects in the reactor pressure vessel pressure boundary and its supports will be so

managed for the period of extended operation.

4.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.1 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

During the audit, the staff reviewed the reactor pressure vessel report, including its CUF results,

and confirmed that the maximum design CUF for the reactor pressure vessel studs is 0.672.

The staff also reviewed LRA Table 4.3-1 that lists the design transient cycles and transient

cycles for the last 20 years of operation. The 60-year transient cycles could be conservatively

determined by adding the design transient cycles and transient cycles up to the end of 2005.

The staff determined that a conservative factor of 1.3 could be used to multiply by the current

maximum design CUF of 0.672 to get a value of 0.874.

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On the basis of the above evaluation, the staff concludes that the CUFs will remain below 1.0

during the period of extended operation. In addition, as required by 10 CFR 54.21 (c)(1)(iii), the

applicant will manage the effects of fatigue in the reactor pressure vessel pressure boundary

components and studs during the period of extended operation. The staff's evaluation of the

Metal Fatigue of Reactor Coolant Pressure Boundary Program is documented in SER

Section 3.0.3.2.24. On this basis, the staff concludes that the applicant's aging management is

consistent with the recommendations of the SRP-LR.

4.3.2.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA aging

management of reactor pressure vessel, nozzles, head, and studs in LRA Section A3.2.1. On

the basis of its review of the USAR supplement, the staff concludes that the summary

description of the applicant's actions to address reactor pressure vessel, nozzles, head, and

studs is adequate.

4.3.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for reactor pressure vessel, nozzles, head, and studs, the effects of

aging on the intended function(s) will be adequately managed for the period of extended

operation. The staff also concludes that the USAR supplement contains an appropriate

summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.2.2 Control Rod Drive Mechanism Pressure Housings, Adapter Plugs, and Canopy

Seals

4.3.2.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2.2 summarizes the evaluation of control rod drive mechanism (CRDM)

pressure housings, adapter plugs, and canopy seals for the period of extended operation. The

applicant stated that the CRDM housings are designed to the ASME Code Section 11,

Subsection NB (Class 1), 1974 Edition with Addenda through Winter 1974. The CRDM pressure

housings, adapter plugs, and the added canopy seal clamp assemblies are ASME

Code Section III Class 1 components with a Class 1 fatigue analysis. The analysis was

reexamined for the power rerate and Thot reduction modification, for 10 percent of steam

generator tubes plugging, and for addition of canopy seal clamp assemblies. The maximum

calculated usage factor in the CRDM pressure housings indicates design adequacy for nine

times the number of specified design transient events. The evaluation of fatigue effects in the

CRDM pressure housings will therefore remain valid for the period of extended operation.

4.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.2 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

During the audit, the staff reviewed the ASME Code analysis and confirmed that the maximum

usage factor at the worst-case CRDM housing-to-head weld is 0.1093. The staff agrees that the

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maximum usage factor of 0.1093 indicates that the design is adequate for nine times the number

of specified design transient events.

Based on its review, the staff concludes that the fatigue effects in the CRDM housing will remain

below 1.0 during the period of extended operation, in accordance with 10 CFR 54.21 (c)(1)(i).

4.3.2.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

CRDM pressure housings, adapter plugs, and canopy seals in LRA Section A3.2.1. On the basis

of its review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address CRDM pressure housings, adapter plugs, and canopy seals is

adequate.

4.3.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for CRDM pressure housings, adapter plugs, and canopy seals, the

analyses remain valid for the period of extended operation. The staff also concludes that the

USAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21 (d).

4.3.2.3 Reactor Coolant Pump Pressure Boundary Components

4.3.2.3.1 Summary of Technical Information in the Application

LRA Section 4.3.2.3 summarizes the evaluation of reactor coolant pump (RCP) pressure

boundary components for the period of extended operation. The applicant stated that the pump

pressure boundary was designed to ASME Code Section III, 1972 Edition with Addenda through

Summer 1973. It stated that conservative, simplified fatigue analyses for a number of

components and subsequent load definition changes eventually resulted in fatigue waivers or

analyses in a number of additional locations in the pump pressure boundary. These fatigue and

fatigue waiver analyses have been updated to redefine loads and DBEs, operating changes,

power rerate, and minor modifications. The fatigue analyses are TLAAs. The fatigue waiver

analyses are also TLAAs because they depend in part on the assumed numbers of design-basis

normal and upset transient cycles.

The applicant stated that fatigue usage factors in the RCPs do not depend on time-dependent

effects at steady-state conditions, but depend only on effects of operational, abnormal, and

upset transient events, principally on startup and shutdown transients. The Metal Fatigue of

Reactor Coolant Pressure Boundary Program will track events to ensure either that the code

design values remain valid or that appropriate reevaluation or other corrective action is taken if a

design-basis number of events is exceeded or if usage factors approach the limit of 1.0. Effects

of fatigue in the RCP boundaries will be so managed for the period of extended operation.

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4.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.3 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in RCP

pressure boundary components during the period of extended operation. The applicant indicated

that the original evaluation of the pump pressure boundary demonstrated that the ASME

Code fatigue exemption rules were satisfied. The applicant also indicated that fatigue analyses

were performed for several pump components. The Metal Fatigue of Reactor Coolant Pressure

Boundary Program will track events used for these evaluations to ensure: (1) that the operating

cycles of the events remains within the cycles of design allowable events, or (2) that appropriate

reevaluation or other corrective action is taken if a design-basis number of events is exceeded or

if usage factors approach the limit of 1.0. The staff's evaluation of the applicant's Metal Fatigue

of Reactor Coolant Pressure Boundary Program is documented in SER Section 3.0.3.2.24. The

staff concludes that the applicant's aging management is consistent with the recommendations

in the SRP-LR.

4.3.2.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA aging

management of RCP pressure boundary components in LRA Section A3.2.1. On the basis of its

review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address RCP pressure boundary components is adequate.

4.3.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for RCP pressure boundary components, the effects of aging on the

intended function(s) will be adequately managed for the period of extended operation. The staff

also concludes that the USAR supplement contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.2.4 Pressurizer and Pressurizer Nozzles

4.3.2.4.1 Summary of Technical Information in the Application

LRA Section 4.3.2.4 summarizes the evaluation of pressurizer and pressurizer nozzles for the

period of extended operation. The applicant stated that pressure-retaining and support

components of the pressurizer are subject to an ASME Code, Division 1, Section III, fatigue

analysis. This analysis has been updated from time to time to incorporate redefinitions of loads

and DBEs, operating changes, power rerate, and minor modifications; including the effects of

thermal stratification and insurge-outsurge transients which were not included in the original

analyses.

The LRA states that with the design basis set of transients, including the power rerate and Tot

modifications, the worst-case fatigue usage factors for the present design exceed 0.9 at three

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pressurizer locations. Although the pressurizer surge nozzle, spray nozzle, and lower head are

subject to significant operating thermal cycles from thermal stratification and insurge-outsurge

transients not considered in the original code analysis, operating procedure changes have

minimized these transients. Updated analyses confirm that fatigue usage factors in the affected

pressurizer components will be within acceptable limits for the originally-specified design

transient events, plus the number of these additional transient events expected for an operating

life of 60 years.

The LRA states that the Metal Fatigue of Reactor Coolant Pressure Boundary Program will track

events to ensure either that the number of assumed events are sufficient and the usage factors

are not exceeded, or that appropriate reevaluation or other corrective measures maintain the

design and licensing basis. The pressurizer surge nozzle, spray nozzle, and lower head may be

subject to significant operating thermal stress cycles due to thermal stratification and

insurge-outsurge cycles and therefore are expected to be the limiting pressurizer components

for fatigue. The fatigue usage factors of these locations therefore are specifically monitored. The

applicant stated that the effects of fatigue in the pressurizer Class 1 pressure boundary and

supports will thereby be managed for the period of extended operation.

4.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.4 to verify pursuant to 10 CFR 54.21 (c)(1 )(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

During the audit, the staff requested that the applicant discuss the fatigue impact on the

pressurizer nozzles due to the application of weld overlays in 2006.

In its response dated July 26, 2007, the applicant stated:

A weld overlay was installed over the surge-nozzle-to-safe-end weld, safe end,

and safe-end-to-pipe weld during Refuel 15. The overlay extends beyond the

nozzle-to-safe-end weld toward the pressurizer until it blends into the tapered

thickness transition of the nozzle. The overlay extends beyond the

safe-end-to-pipe weld onto the pipe for a distance of several pipe wall

thicknesses. Therefore, the ends of the overlay are sufficiently far from the

original welds to be unaffected by the stress intensification of the weld. The

fatigue usage factors of the nozzle-to-safe-end and safe-end-to-pipe welds are no

longer the basis of a safety determination, because the reliability of these welds

will be verified by periodic inspections and by flaw propagation analyses that are

not TLAAs.

The maximum fatigue usage in the surge nozzle is at a location inside the nozzle

inner radius. The overlay did not require a revision to the fatigue analysis at this

location. The fatigue analysis of this location remains a TLAA, and fatigue in this

location will continue to be monitored.

The staff finds that the above evaluations for fatigue analysis are not adequate. During the audit,

the staff requested that the applicant explain why this analysis is not considered a TLAA. The

staff requested that the applicant provides its regulatory basis.

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In its response dated October 17, 2007, the applicant stated:

The basis for the determination that the flaw propagation analyses are not TLAAs

is that these analyses do not meet the definition of a TLAA in 10 CFR 54.3.

Specifically, these analyses do not "involve time-limited assumptions defined by

the current operating term, for example 40 years." The weld overlays are

examined as part of the in-service inspection program. The flaw propagation

analyses are performed to support in-service inspection frequencies and are

based on the terms between inspections, not on the reactor operating life.

On the basis that these analyses are not time-limited, the staff finds the applicant's response

acceptable. The staff agrees with the applicant that this is not a TLAA.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in pressurizer

Class 1 pressure boundary components during the period of extended operation. The Metal

Fatigue of Reactor Coolant Pressure Boundary Program will track events to ensure (1) that the

operating cycles of the events remains within the cycles of design allowable events, or (2) that

appropriate reevaluation or other corrective action is taken if a design-basis number of events is

exceeded, or if usage factors approach the limit of 1.0. The staff's evaluation of the applicant's

Metal Fatigue of Reactor Coolant Pressure Boundary Program is documented in SER

Section 3.0.3.2.24. The staff concludes that the applicant's aging management is consistent with

the recommendations of the SRP-LR.

4.3.2.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA aging

management of pressurizer and pressurizer nozzles in LRA Section A3.2.1. On the basis of its

review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address pressurizer and pressurizer nozzles is adequate.

4.3.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for pressurizer and pressurizer nozzles, the effects of aging on the

intended function(s) will be adequately managed for the period of extended operation. The staff

also concludes that the USAR supplement contains an appropriate summary description of the

TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.2.5 Steam Generator ASME Code Section III Class 1, Class 2 Secondary Side, and

Feedwater Nozzle Fatigue Analyses

4.3.2.5.1 Summary of Technical Information in the Application

LRA Section 4.3.2.5 summarizes the evaluation of steam generator ASME Code Section III

Class 1, Class 2 secondary side, and feedwater nozzle fatigue analyses for the period of

extended operation. The steam generators are designed to the ASME Code Section III,

Subsection NB (Class 1) and Subsection NC (Class 2), 1971 Edition with Addenda through

Summer 1973. Pressure-retaining and support components of the primary coolant side of the

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steam generators are subject to an ASME Boiler and Pressure Vessel Code, Division 1,

Section III fatigue analysis. Although the secondary side is Class 2, pressure-retaining parts of

the steam generator satisfy the Class 1 criteria, including the Class 2 secondary side

boundaries. These analyses have been updated to redefine loads and DBEs, operating

changes, power rerate, primary loop Thot reduction, and minor modifications.

The LRA states that fatigue usage factors in other steam generator pressure boundary and

Class 1 support components and qualification of the primary manway studs by test do not

depend on time-dependent effects at steady-state conditions, but depend only on effects of

operational, abnormal, and upset transient events. Appropriate corrective measures, which may

include requalification or replacement, will ensure that the design basis of the bolting is

maintained if fatigue monitoring indicates that the numbers of load cycles assumed by the

qualification by test may be exceeded. The Metal Fatigue of Reactor Coolant Pressure Boundary

Program will track events to ensure that appropriate reevaluation or other corrective action is

taken if a design-basis number of events is exceeded. This program will maintain a record of

CUF for each monitored location. The applicant stated that effects of fatigue in the steam

generator pressure boundaries and their supports will be so managed for the period of extended

operation.

4.3.2.5.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.5 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

The steam generator tube degradation mechanisms related to aging effects were not anticipated

in the original design. The steam generator tube integrity now depends on managing aging

effects by using the Steam Generator Tube Integrity Program. The staff's evaluation of this

program is documented in SER Section 3.0.3.2.8.

LRA Table 4.3-2 states that the steam generator feedwater nozzles are tracked with

stress-based monitoring. During the audit, the staff reviewed basis documents that indicate that

actual plant transient data was used for the fatigue usage factor calculation for Period 2 (i.e.,

from 1996 through 2005), and that these CUF values were used to derive backward projected

initial CUFs for Period 1 (i.e., from 1984 through 1995). During the audit, the staff requested the

applicant to justify its backward-projected methodology.

In its response the applicant stated that fatigue usage for steam generator feedwater nozzles is

principally accumulated during heatup and cooldown. The applicant concluded that fatigue

usage for the initial period can be reasonably estimated by multiplying the usage accumulated

during the monitored period by the ratio of heatup and cooldown events for these two periods.

The staff reviewed the applicant's response and requested the applicant to provide additional

information.

In RAI 4.3-3 dated July 24, 2007, the staff requested that the applicant further justify the validity

of these CUF backward-projections using the ratio of heatup and cooldown cycles. The staff

noted that the projections were based solely on the ratio of heatup and cooldown cycles for most

4-24
locations; however, it did not consider other significant transients. For example, the transient

tracking report indicated that seven loss of offsite power cycles and two loss of load cycles

occurred between 1984 and March 1992, and that these transients did not occur between

March 1992 and December 2005.

In its response dated August 20, 2007, the applicant stated that it considered its original

backward projected methodology are still valid. The staff reviewed the applicant's response and

determined that additional information was necessary.

By letter dated September 4, 2007, the staff noted that a loss of offsite power and loss of load

transient may cause the feedwater temperature to drop significantly. On this basis, the staff

believes that the validity of the feedwater nozzles CUFs backward projections using the ratio of

heatup and cooldown events may not be conservative. The staff requested that the applicant

address this issue.

In its response dated October 3, 2007, the applicant stated:

The RAI identifies two transients that are not accounted for when using the

back-projection approach. The transient tracking report indicates that seven loss

of offsite power cycles and two loss of load cycles occurred between 1984 and

March 1992, and that these two transients did not occur again between

March 1992 and December 2005. While those events are present in the cycle

counts in LRA Table 4.3-1, the transients that actually occurred were not as

severe as the design transients as specified in the Westinghouse Systems

Standard Design Criteria 1.3F. Review of operator logs has verified that none of

those transients need have been counted.

The counted events did not include any auxiliary feedwater actuation, therefore these

events were no more serious than a normal reactor trip. (Note that all 3 events, which

included a reactor trip, were also counted as Reactor Trips.)

The staff reviewed the Westinghouse System Standard Design Criteria 1.3F, which defines the

design transients, to confirm if loss of load and loss of power conservatively assumed auxiliary

feedwater initiation could cause the feedwater temperature to drop approximately 400 OF. On the

basis that actual auxiliary feedwater actuation has not occurred for those events during plant

operation, the staff concludes that the fatigue evaluation does not have to address the original

design conservatism based on the assumption specified in the Design Criteria 1.3F. The staff's

concern related to the feedwater nozzles CUFs backward projections is resolved.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in steam

generator pressure boundary components, other than steam generator tubes, during the period

of extended operation. The staff's evaluation of the applicant's Metal Fatigue of Reactor Coolant

Pressure Boundary Program is documented in SER Section 3.0.3.2.24. The staff concludes that

the applicant's aging management is consistent with the recommendations in the SRP-LR.

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4.3.2.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA aging

management of steam generator ASME Code Section III Class 1, Class 2 secondary side, and

feedwater nozzle fatigue analyses in LRA Section A3.2.1. On the basis of its review of the USAR

supplement, the staff concludes that the summary description of the applicant's actions to

address steam generator ASME Code Section III Class 1, Class 2 secondary side, and

feedwater nozzle fatigue analyses is adequate.

4.3.2.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for steam generator ASME Code Section III Class 1, Class 2

Secondary side, and feedwater nozzle fatigue analyses, the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation. The staff also

concludes that the USAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21 (d).

4.3.2.6 ASME Code Section III Class 1 Valves

4.3.2.6.1 Summary of Technical Information in the Application

LRA Section 4.3.2.6 summarizes the evaluation of ASME Code Section III Class 1 valves for the

period of extended operation. Class 1 valves are designed to the ASME Code Section III,

Subsection NB, 1974 Edition and later addenda.

The LRA states that the calculated worst-case usage factors for Class 1 pressurizer safety

valves and for 6 inch swing check valves indicate that the designs have large margins and

therefore that the pressure boundaries would withstand fatigue effects for at least two of the

original design lifetimes. The design of these valves for fatigue effects is therefore valid for the

period of extended operation.

The LRA states that the calculated worst-case usage factors for the Class 1 residual heat

removal (RHR) 12 inch suction gate valves and the 10 inch check valves exceed 0.4; however,

fatigue usage factors in these valves do not depend on time-dependent effects at steady-state

conditions, but depend only on effects of operational, abnormal, and upset transient events. The

applicant stated that the 40-year design-basis number of events should be sufficient for 60 years

of operation of Class 1 piping containing valves. The Metal Fatigue of Reactor Coolant Pressure

Boundary Program will ensure that calculated usage factors will not be exceeded, or that

appropriate corrective action is taken if a design-basis number of events is exceeded. Effects of

fatigue in Class 1 valve pressure boundaries will thereby be managed for the period of extended

operation.

4.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.6 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation and, pursuant to

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10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

During the audit, the staff reviewed the applicant's basis documents which include

Westinghouse valve design specifications, stress report for Westinghouse ASME Code Class 1

6-inch and larger swing check valves, and stress report for pressurizer safety valves. On the

basis of its review, the staff finds that the designs have large margins to cover more than twice

of the original design lifetime for the pressurizer safety valves and Class 1, 6-inch swing check

valves. Therefore, the staff finds the design of these valves for fatigue effects is valid for the

period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue for Class 1,

12-inch RHR suction gate valves and Class 1, 10-inch gate valves during the period of extended

operation. The staff's evaluation of the applicant's Metal Fatigue of Reactor Coolant Pressure

Boundary Program is documented in SER Section 3.0.3.2.24. The staff concludes that the

applicant's aging management is consistent with the recommendations of the SRP-LR.

4.3.2.6.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

ASME Code Section III Class 1 valves in LRA Section A3.2.1. On the basis of its review of the

USAR supplement, the staff concludes that the summary description of the applicant's actions to

address ASME Code Section III Class 1 valves is adequate.

4.3.2.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for ASME Code Section III Class 1 valves, the analyses remain valid

for the period of extended operation. The applicant also has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation. The staff also concludes that the USAR

supplement contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21 (d).

4.3.2.7 ASME Code Section III Class 1 Piping and Piping Nozzles

4.3.2.7.1 Summary of Technical Information in the Application

LRA Section 4.3.2.7 summarizes the evaluation of ASME Code Section III Class 1 piping and

piping nozzles for the period of extended operation. Class 1 reactor coolant main-loop piping

was supplied by Westinghouse, which designed it to the ASME Code Section III, Subsection NB,

1974 Edition with Addenda through Winter 1975. The main loop piping fatigue analysis was

performed to the 1974 Edition with Addenda through Winter 1975. The fatigue analyses of piping

outside the main loop used code Addenda through Summer 1979. These analyses have been

updated from time to time to redefine loads and DBEs, operating changes, power rerate, and

minor modifications. The currently applicable fatigue analyses of these components are TLAAs.

4-27
The LRA states that with the exception of the thermowells, surge line nozzles, and the

pressurizer surge line, usage factors in Class 1 piping pressure boundaries do not depend on

time-dependent effects at steady-state conditions, but depend only on effects of operational,

abnormal, and upset transient events. The Metal Fatigue of Reactor Coolant Pressure Boundary

Program will ensure either that the original design basis number of events or usage factor is not

exceeded or that appropriate reevaluation or other corrective action is taken. Effects of fatigue in

the Class 1 piping pressure boundary will thereby be managed for the period of extended

operation.

4.3.2.7.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.7 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation or, pursuant to

10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

During the audit, the staff reviewed the applicant's stress analysis design report for the RCS

thermowells and crossover leg nozzle cap to confirm that the maximum usage factor is 0.025.

The staff agrees with the applicant's assessment that the thermowells cumulative fatigue usage

factor for 60 years will remain negligible (10 CFR 54.21 (c)(1)(i)).

As discussed in SER Section 4.3.2.5.2, during the audit, the staff requested that the applicant

justify the methodology used for estimating fatigue usage prior to the implementation of the

monitoring program. The applicant responded that the severities of the transients during the

monitored period are typical of the period before monitoring was implemented. The staff

reviewed the response and requested the applicant to provide additional information.

During the audit, the staff reviewed a surge line stratification evaluation report that indicates

there are 26,000 piping insurge and outsurge cycles for 200 heatups and cooldowns that should

be considered, if a modified operating procedure (relative to NRC bulletin 88-11 documented in

SER Section 4.3.2.8) is not implemented. In RAI 4.3-3 dated July 24, 2007, the staff requested

that the applicant further justify the validity of these CUF backward-projections using the ratio of

heatup and cooldown cycles. During the audit, the applicant stated that WCGS had implemented

a modified operating procedure prior to 1995 to mitigate piping insurge and outsurge transients.

However, the staff reviewed the CUF calculation in the basis document supporting the LRA and

found that the analyses that used actual transient data for Period 2 does not consider significant

piping insurge and outsurge cycles from Period 1 to support the validity of the backward

projections.

In its response to RAI 4.3-3 dated August 20, 2007, the applicant stated, in part:

For the Group 2 pressurizer locations, the current backward projection to

establish baseline fatigue usage may not be conservative. Following a review of

the method used to develop backward projection of accumulated fatigue usage

during plant operation in Period 1, it is concluded that data collected for transients

affecting the hot leg surge line nozzle (HL surge nozzle) during Period 2 may not

be bounding for transients experienced by this nozzle during Period 1. Therefore,

the baseline Period 1 fatigue usage for HL surge nozzle calculated by using the

ratio of Period 1 heatup/cooldown events to Period 2 heatup/cooldown events

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times the fatigue usage for Period 2 determined by the stress based monitoring

program may not be conservative.

A conservative baseline fatigue usage for Period 1 will be calculated using the

method of cycle based fatigue usage calculations. Fatigue usage by this method

is calculated from the actual plant transients counted during the period of interest

and the design basis transient severity assumption. For the HL surge nozzle, the

design basis transient severity is defined in WCAP-1 2893, "Structural Evaluation

of the Wolf Creek and Callaway Pressurizer Surge Lines, Considering the effects of

Thermal Stratification."

WCAP-12893 postulates that each heatup and cooldown evolution includes a

large number of sub-transients (from insurge/outsurge). The fatigue usage for a

heatup/cooldown is a summation of the usage from the postulated

insurge/outsurge sub-transients combined with the fatigue usage from the system

temperature and pressure changes.

The baseline fatigue usage for the HL surge nozzle accumulated prior to

implementation of the stress based fatigue monitoring data acquisition system will

be recalculated using the conservative assumption that the transients that

occurred during the un-monitored period (Period 1) were as severe as the design

basis assumptions. The same methodology will be used for other pressurizer

locations tracked by stress based monitoring unless there is a basis for assuming

that the monitored period (Period 2) is typical of the un-monitored period (Period

1) for a specific locations.

In its response dated August 20, 2007, the applicant also stated that the charging and alternate

charging nozzles are locations in the stress-based fatigue monitoring program that are evaluated

for environmental effects in accordance with NUREG/CR-6260. It also stated that the Period 2

transients for these components are typical of the Period 1 transients.

The staff reviewed the applicant's response and determined that additional information was

necessary.

As documented in the teleconference summary dated September 4, 2007, the staff noted that

the applicant's backward projection ignored severity of transients by using only the cycles ratio.

For example, a loss of charging water will cause three different types of transients. The loss of

charging and prompt return to service does not contribute to a significant temperature change

(around 50 OF). However, the loss of charging and delayed return to service has a significant

temperature step change (about 500 OF). The staff stated that it does not agree with the

applicant's method of combining different types of transients and using that ratio to determine

the baseline usage factor. The staff finds that the validity of charging and alternate charging

nozzles CUFs backward projections using the ratio of heatup and cooldown events may not be

conservative. The staff requested that the applicant address this issue.

In its response dated October 3, 2007, the applicant committed (Commitment No. 38) to address

backward projections for the surge line hot leg nozzle, charging nozzle and alternate charging

nozzle. The applicant committed to calculate an updated baseline fatigue usage factor that

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adequately bounds transients experienced before the monitoring of CUFs was started. The

applicant stated that the existing baseline CUF for all monitored locations will be increased to

bound the potential CUF contribution from the transients that were under-represented in the

existing baseline CUF.

The staff requested that the applicant submit this reanalysis to the staff for review by

January 31, 2008. This was identified as open item (01) 4.3-3.

By letter dated January 25, 2008, the applicant provided its first response to 01 4.3-3. The staff

reviewed the applicant's methodology on the CUF reanalyses for the pressurizer spray nozzle,

pressurizer lower head and heater penetration, pressurizer surge nozzle, surge line piping,

steam generator feedwater nozzles, surge line hot leg nozzle, charging nozzles, and alternate

charging nozzles. In its response, the applicant stated that its methodology will include

identifying the transients count for Period 1 by incorporating a review of transient records to

account for any improperly counted events being assumed and then computing a bounding CUF

increment with the information gathered to update the baseline analysis. The staff found the

methodology and process for performing a revised CUF analysis of pressurizer spray nozzle,

pressurizer lower head and heater penetration, pressurizer surge nozzle, surge line piping and

steam generator feedwater nozzles to be acceptable because: (a) the applicant's methodology

and process will appropriately account for transients that occurred in Period 1 (i.e., revising the

counted events being assumed, as appropriate, including those transients that were not

accounted for and those transients whose cycles were improperly counted) and (b) the applicant

appropriately computed the revised baseline CUFs for these components based on the updated

transient information. In addition, in LRA Section 4.3.2.7, the applicant states that the impacts of

metal fatigue on the intended functions of the Class 1 reactor coolant pressure boundary will be

managed for the period of extended operation (i.e., the Metal Fatigue of the Reactor Coolant

Pressure Boundary Program will ensure the number of cycles for design basis transients will be

tracked and monitored against their allowable values). Based on this review, the staff concludes

that the aging management of metal fatigue of the pressurizer spray nozzle, pressurizer lower

head and heater penetration, pressurizer surge nozzle, surge line piping and steam generator

feedwater nozzles is acceptable because the applicant will manage the effects of aging in

accordance with the requirement in 10 CFR 54.21 (c)(1)(iii). For the same reason, the staff also

considers Commitment No. 38 to be fulfilled with respect to the CUF analyses for pressurizer

spray nozzle, pressurizer lower head and heater penetration, pressurizer surge nozzle, surge

line piping and steam generator feedwater nozzles.

The staff determined it needed additional information on the applicant's reanalyses for the surge

line hot leg nozzle and charging nozzles because in its reassessment, the applicant did not

account for: (a) the additional insurge/outsurge cycles from the pre-MOP environment and (b)

the differential contribution from each category of charging events. The staff issued a follow-up

RAI in a letter dated February 28, 2008, requesting that the applicant provides the information

described above in order for the staff to complete its review.

By letter dated May 15, 2008, the applicant provided its second response to 01 4.3-3. The staff

determined that the applicant's response did not provide the updated baseline CUF calculation

for surge line hot leg nozzle and charging nozzles which were to account for the pre-MOP

conditions and the differential contribution of fatigue for each charging event. The applicant

supplemented this second response by letter dated June 9, 2008 and committed (Commitment

No.41) as part of its Metal Fatigue of the Reactor Coolant Pressure Boundary Program, to

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prepare an updated baseline calculation for the surge line hot leg surge nozzle based on the

actual pre-MOP environment for the nozzle and an updated baseline calculation for the charging

nozzles based on the consideration for the differential contribution from each category of

charging events. The applicant indicated that Commitment No. 41 closes and replaces

Commitment No. 38 with respect to the reanalyses for the surge line hot leg nozzles and the

charging nozzles. The staff finds this to be an acceptable basis for managing the impacts of

metal fatigue on the pressure boundary function of the charging nozzles and surge line hot leg

nozzle because: (a) for performance of periodic CUF updates, the applicant's commitment to do

the updated baseline CUF calculations for these components and (b) the applicant has brought

Commitment No. 41 within the scope of its existing Metal Fatigue of Reactor Coolant Pressure

Boundary AMP to manage the aging effect on the components. Based on this review, the staff

finds that the applicant has provided an acceptable basis for accepting the aging management

of metal fatigue of the charging nozzles and surge line hot leg nozzle in accordance with the

requirement in 10 CFR 54.21( c)(1)(iii).

Relative to the closure of commitment No. 38, in its review of this TLAA as it relates to the

assessment of the charging nozzles, the staff noted that the applicant's current CUF analyses

for the charging nozzles are based on the assumption that the charging nozzles are designed

with thermal sleeves, which are used to mitigate the consequences of thermal cycling on the

nozzles. The staff noted that in the applicant's response letter of May 15, 2008, the applicant

indicated that it could not currently perform a revised baseline analysis for charging nozzles due

to "conflicting and inconclusive" documentation on whether the charging nozzle were designed

with thermal sleeves. To address this issue, the applicant supplemented its response letter of

May 15, 2008, with a letter dated June 9, 2008. In the letter of June 9, 2008, the applicant

committed to (Commitment No. 40): (a) confirm that either the design of the charging nozzles

includes thermal sleeves or if not, (b) account for the lack of thermal sleeves in the reanalysis of

the charging nozzles. The applicant indicated that Commitment No. 40 is folded within the scope

of the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary Program and also

closes and replaces Commitment No. 38 with respect to the reanalyses for the charging nozzles.

The staff verified that the applicant incorporated Commitment Nos. 40 and 41 within the scope of

LRA FSAR Supplement No. A.2.1, which provided the summary description for the applicant's

Fatigue of the Reactor Coolant Pressure Boundary Program (Commitment Nos. 40 and 41). This

replaces Commitment No. 38 for the portions related to the surge line hot leg nozzle and

charging nozzles; thus, Commitment No. 38 is considered to be completed. The staff finds the

applicant's response in the supplemental letter acceptable because the commitment to update

the baseline CUF calculations for surge line hot leg nozzle and charging nozzles is consistent

with the "detection of aging effects" program element of GALL AMP XI.M1, "Metal Fatigue of the

Reactor Coolant Pressure Boundary" for performance of "periodic update of the fatigue usage

calculations." Based on this determination, that staff concludes that Commitment Nos. 40 and 41

provide an acceptable basis for accepting the aging management of metal fatigue of the

charging nozzles and surge line hot leg nozzle in accordance with 10 CFR 54.21 (c)(1)(iii)

because the applicant will use the existing Metal Fatigue of the Reactor Coolant Pressure

Boundary AMP to manage the effects of metal fatigue (i.e., identified as cracking-fatigue in the

relevant AMRs) during the period of extended operation. Open Item 4.3-3 is resolved.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in Class 1

piping and piping nozzles during the period of extended operation. The staff's evaluation of the

applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program is documented in SER

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Section 3.0.3.2.24. The applicant's aging management is consistent with the recommendations

of the SRP-LR.

4.3.2.7.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

ASME Code Section III Class 1 piping and piping nozzles in LRA Section A3.2.1. The staff

reviewed the amended LRA Section A2.1 provided by the applicant in supplemental letter dated

June 9, 2008 and verified that the applicant incorporated the commitments that are provided in

LRA Commitment No. 40 and Commitment No.41. The staff determines that the USAR

Supplement summary description in LRA Section A2.1 and A3.2.11: (a) adequately summarizes

the options relied on for TLAA acceptance and Commitment Nos. 40 and 41 and (b)

appropriately applies to the assessment in LRA Section 4.3.2.7 and to the USAR Supplement

summary description in LRA Section A2.1 and A3.2.1. On the basis of its review of the USAR

supplement, the staff concludes that the summary description of the applicant's actions to

address ASME Code Section III Class 1 piping and piping nozzles is adequate.

4.3.2.7.4 Conclusion

On the basis of its review of the thermowells, the staff concludes that the applicant has

demonstrated pursuant to 10 CFR 54.21 (c)(1)(i) and for ASME Code Section III Class 1 piping

and piping nozzles, the analyses for thermowells remains valid for the period of extended

operation. For the remaining Class 1 piping pressure boundary items, the applicant has

demonstrated that pursuant to 10 CFR 54.21 (c)(1)(iii), the effects of aging on the intended

function will be adequately managed for the period of extended operation. The staff also

concludes that the USAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21 (d).

4.3.2.8 Bulletin 88-11 Revised Fatigue Analysis of the Pressurizer Surge Line for Thermal

Cycling and Stratification

4.3.2.8.1 Summary of Technical Information in the Application

LRA Section 4.3.2.8 summarizes the evaluation of NRC Bulletin 88-11 revised fatigue analysis of

the pressurizer surge line for thermal cycling and stratification for the period of extended

operation. The original surge line fatigue analysis used ASME Code Addenda through

Summer 1979. In response to the NRC Bulletin 88-11 thermal stratification concerns, the surge

line design was reanalyzed to the 1986 ASME Code. This analysis later was re-evaluated for

effects of snubber removals. These reevaluation results are incorporated into the piping and

main-loop nozzle code design reports. Winter 1982 and later ASME Code addenda state stress

limits for high-cycle fatigue of Class 1 supports under Subarticle NF-3330; however, the

reevaluation of the surge line for NRC Bulletin 88-11 did not retroactively impose these

requirements and therefore no TLAA arises for design of the supports.

The surge line is subject to fatigue monitoring. The Metal Fatigue of Reactor Coolant Pressure

Boundary Program will ensure either that the usage factor remains valid for the period of

extended operation or that appropriate corrective measures maintain the design and licensing

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basis. Effects of fatigue in the Class 1 surge line will thereby be managed for the period of

extended operation.

4.3.2.8.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.8 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

During the audit, the staff reviewed a basis document that describes thermal stratification in the

pressurizer surge lines. The staff noted that the maximum calculated CUF at any location in the

surge line, under the current analysis of record, including thermal stratification effects, is less

than 1.0. The staff also confirmed that the fatigue usage of the nozzle-to-safe-end and

safe-end-to-pipe welds are no longer the basis of a safety determination because a crack was

discovered in 2006 and a weld overlay was applied in these areas (verified by the staff). The

staff finds that maintaining fatigue usage below 1.0 would prevent crack initiation. If a crack has

initiated, there is no need for a fatigue usage evaluation. The staff agrees that the reliability of

the weld overlay area will be verified by periodic inspections and by flaw propagation analyses,

which are not considered as TLAAs. The staff's evaluation of these flaw propagation analyses is

documented in SER Section 4.3.2.4.2.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in the

pressurizer surge line during the period of extended operation. The staff's evaluation of the

applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program is documented in SER

Section 3.0.3.2.24. The staff concludes that the applicant's aging management is consistent with

the recommendations of the SRP-LR.

4.3.2.8.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of NRC

Bulletin 88-11 revised fatigue analysis of the pressurizer surge line for thermal cycling and

stratification in LRA Section A3.2.1. On the basis of its review of the USAR supplement, the staff

concludes that the summary description of the applicant's actions to address bulletin 88-11

revised fatigue analysis of the pressurizer surge line for thermal cycling and stratification is

adequate.

4.3.2.8.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for NRC Bulletin 88-11 revised fatigue analysis of the pressurizer

surge line for thermal cycling and stratification, the effects of aging on the intended function(s)

will be adequately managed for the period of extended operation. The staff also concludes that

the USAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21 (d).

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4.3.2.9 Primary Coolant System Heatup Expansion Noise Events

4.3.2.9.1 Summary of Technical Information in the Application

LRA Section 4.3.2.9 summarizes the evaluation of primary coolant system heatup expansion

noise events for the period of extended operation. Since 1990, there have been abrupt audible

events heard inside containment, toward the end of primary system heatups. These audible

events have been attributed to an abrupt release of differential expansion energy originally

believed to be at the crossover piping supporting saddle shims, later found to occur probably

also between the reactor vessel support pads and shoes under the vessel main loop nozzles.

The evaluation of these effects on the vessel, piping, nozzle, and component fatigue analyses is

a TLAA, as is the projection of shakedown effects in a reactor vessel support element.

The LRA states that the evaluation found that the effect of these events on the reactor pressure

vessel, reactor coolant loop and support fatigue analyses, and the reactor coolant loop LBB

analysis is zero or insignificant for the period of extended operation. The effect of these events

has been projected to the end of the period of extended operation. The effect of this event on

vessel supports is within normal and upset allowables, with the exception of a local region of the

reactor vessel support cooling box. This region is shaking down or has shaken down to a stable

response to these events and therefore will be suitable for the period of extended operation. The

effects of these events on the steam generator primary nozzles have been projected to the end

of the period of extended operation.

4.3.2.9.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.9 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

During the audit, the staff reviewed the applicant's assumption that 11 noise events per refueling

cycle could occur and the comparison with the quasi-dynamic monitoring data. The staff finds

that the fatigue analysis, which assumed that 330 noise events would occur in a 60-year design

life is still valid. In addition, the staff finds that the applicant verifies this by monitoring the noise

occurrence. On this basis, the staff concludes that the applicant's analysis assumption is valid in

accordance with the requirements of 10 CFR 54.21 (c)(1)(i).

4.3.2.9.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

primary coolant system heatup expansion noise events in LRA Section A3.2.1. On the basis of

its review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address primary coolant system heatup expansion noise events is

adequate.

4.3.2.9.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for primary coolant system heatup expansion noise events, the

analyses remain valid for the period of extended operation. The staff also concludes that the

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USAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21 (d).

4.3.2.10 High Energy Line Break Postulation Based on Fatigue Cumulative Usage Factor

4.3.2.10.1 Summary of Technical Information in the Application

LRA Section 4.3.2.10 summarizes the evaluation of HELB postulation, based on fatigue CUF for

the period of extended operation. Selection of pipe failure locations for evaluation of the

consequences on nearby essential SSCs, except for the reactor coolant loop, is in accordance

with RG 1.46 and Branch Technical Positions ASB 3-1 and MEB 3-1. A revised stress analysis

also permitted omission of the surge line intermediate breaks. An LBB analysis eliminated large

breaks in the main reactor coolant loops.

The LRA states that break locations which depend on usage factor and their absence in the

surge line will remain valid as long as the calculated usage factors are not exceeded. The Metal

Fatigue of Reactor Coolant Pressure Boundary Program will ensure that the calculated fatigue

usage factors upon which the HELB break locations are based, and the HELB locations, will

remain valid for the period of extended operation or that appropriate corrective measures will

maintain the design and licensing basis.

4.3.2.10.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.10 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

The staff noted that the HELB locations generally occur at high stress and fatigue locations.

These HELB locations are identified based on a limiting stress criterion and on a CUF criterion

as specified in NUREG-0800, Revision 1, "Standard Review Plan for the Review of Safety

Analysis Report of Nuclear Power Plants," Section 3.6.2, Branch Technical Position 3-1, dated

July 1981. In addition, a pipe break is postulated for any intermediate point where stress

exceeds 2.4 allowable design stress intensity (i.e., Sm) and usage factor exceeds 0.1.

During the audit, the staff confirmed that the applicant eliminates pipe breaks in the main reactor

coolant loops based on NRC approved LBB analyses and in accordance with 10 CFR Part 50,

Appendix A, GDC 4. The evaluation of the LBB analysis is discussed in SER Section 4.3.2.11.

During the audit, the staff reviewed the basis documents and confirmed that all the fatigue

usages of surge line intermediate points are less than 0.1 and the stresses are less than 2.4 Sm.

The staff also reviewed the applicant's CLB and confirmed that surge line intermediate break

locations were eliminated from the design basis. On the basis that surge line intermediate

breaks locations postulation is no longer required, the staff finds the applicant's omission of the

surge line intermediate breaks in the revised stress analysis acceptable.

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The staff agrees that there are no postulated break locations based on fatigue usage for the

reactor coolant loop and that the Metal Fatigue of Reactor Coolant Pressure Boundary Program

will track the transient cycles applicable to the surge lines to ensure that design limit will not be

reached during the period of extended operation or to provide corrective actions if this happens.

The staff's evaluation of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary

Program is documented in SER Section 3.0.3.2.24. The staff concludes that the applicant's

aging management is consistent with the recommendations of the SRP-LR.

4.3.2.10.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of high

energy line break postulation based on fatigue cumulative usage factor in LRA Section A3.2.1.

On the basis of its review of the USAR supplement, the staff concludes that the summary

description of the applicant's actions to address high energy line break postulation based on

fatigue cumulative usage factor is adequate.

4.3.2.10.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for high energy line break postulation based on fatigue cumulative

usage factor, the effects of aging on the intended function(s) will be adequately managed for the

period of extended operation. The staff also concludes that the USAR supplement contains an

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.2.11 Fatigue Crack Growth Assessment in Support of a Fracture Mechanics Analysis

for the Leak-Before-Break Elimination of Dynamic Effects of Primary Loop Piping Failures

4.3.2.11.1 Summary of Technical Information in the Application

LRA Section 4.3.2.11 summarizes the evaluation of fatigue crack growth assessment in support

of a fracture mechanics analysis for the LBB elimination of dynamic effects of primary loop

piping failures for the period of extended operation. An LBB analysis eliminated the large breaks

in the main reactor coolant loops and permitted omission of evaluations of their jet and pipe whip

effects and consequent omission of large jet barriers and whip restraints. The containment

pressurization and equipment qualification analyses retained the large-break assumptions. The

dynamic effects from postulated pipe breaks have been eliminated from the structural design

basis of the reactor coolant system primary loop piping as allowed by GDC 4. The elimination of

these breaks is the result of the application of LBB technology approved for WCGS by the NRC.

The applicant's final licensing basis LBB submission is the proprietary WCAP-10691, "Technical

Basis for Eliminating Large Primary Loop Pipe Rupture as a Structural Design Basis for

Callaway and Wolf Creek Plants." The NRC approval of this use of LBB was granted with

NUREG-0881, the SER for the original license, as a 10 CFR 50.12 exemption from parts of

GDC 4. The fracture mechanics analysis is not time-dependent and; therefore, not a TLAA.

However, the final LBB submission is also supported by a fatigue crack growth assessment for a

40-year design life, which is a TLAA. There is no licensing basis evaluation of embrittlement of

the cast reactor coolant piping or other cast austenitic stainless steel apart from the LBB

question.

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The LRA states that the LBB analysis found that fatigue crack growth effects will be negligible.

The basis for evaluation of fatigue crack growth effects in the LBB analysis will remain

unchanged if the number of occurrences of each transient remains below the number assumed

for the existing analysis of fatigue crack growth effects. The Metal Fatigue of Reactor Coolant

Pressure Boundary Program will ensure (1) that the number of occurrences of each transient

cycle in the primary loop piping remains below the number specified by the design specifications

during the period of extended operation; and therefore, below the number assumed for the

existing analysis of fatigue crack growth effects; or (2) that appropriate corrective measures

maintain the design and licensing basis. Therefore, the effects will be managed for the period of

extended operation.

4.3.2.11.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2.11 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

During the audit, the staff reviewed the final licensing basis for LBB and confirmed that saturated

material fracture toughness was used in the LBB evaluation. On the basis that saturated material

fracture toughness is not time-dependent, the staff concludes that the fracture mechanics

analysis is not a TLAA.

The fatigue crack growth evaluation of the LBB used 40-year design events with various initial

crack sizes from 10 to 15 percent of the wall thickness. The staff reviewed the results and

indicated that the crack growth for 40-year design events is very small (i.e., the worst case is

approximately 10 percent of the initial crack size). ASME Code Section Xl, Tables IWB-3514-1

and IWB-3514-2 identify that the allowable crack depth for the pre-service examination is.

approximately 9 percent of the wall thickness for the primary RCS piping. The applicant's fatigue

crack growth evaluation demonstrates that the 10 percent wall thickness initial crack depth will

grow to around 11 percent, and that the 15 percent wall thickness initial crack depth will grow to

around 16.5 percent. On the basis of this fatigue crack growth result, the staff can project that

an initial 9 percent wall thickness crack depth will grow to approximately 11 percent wall

thickness crack depth in a 60-year design life. The flaw growth evaluation due to PWSCC was

not considered. However, the applicant is monitoring PWSCC and will address this aging effect

issue under its current licensing requirements. On this basis, the staff concludes that this is

acceptable.

The staff finds that the applicant's proposed AMP to manage the effects of fatigue to justify the

fatigue crack growth evaluation remains valid. The applicant's Metal Fatigue of Reactor Coolant

Pressure Boundary Program will track events to ensure (1) that the operating cycles of the

events remains within the cycles of analyzed design allowable events, or (2) that appropriate

reevaluation or other corrective action is taken if a design-basis number of events is exceeded.

The staff's evaluation of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary

Program is documented in SER Section 3.0.3.2.24. The staff concludes that the applicant's

aging management is consistent with the recommendations in the SRP-LR.

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4.3.2.11.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue crack growth assessment in support of a fracture mechanics analysis for the LBB

elimination of dynamic effects of primary loop piping failures in LRA Section A3.2.1. On the basis

of its review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address fatigue crack growth assessment in support of a fracture

mechanics analysis for the LBB elimination of dynamic effects of primary loop piping failures is

adequate.

4.3.2.11.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for fatigue crack growth assessment in support of a fracture

mechanics analysis for the LBB elimination of dynamic effects of primary loop piping failures, the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation. The staff also concludes that the USAR supplement contains an appropriate

summary description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.3 ASME Code Section III Subsection NG Fatigue Analysis of Reactor Pressure Vessel

Internals

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3 summarizes the evaluation of ASME Code Section III, Subsection NG, fatigue

analysis reactor pressure vessel internals for the period of extended operation. The reactor

vessel internals were designed after the incorporation of Subsection NG into the 1974 Edition of

the ASME Code, Section III. The design meets the intent of paragraph NG-3311 (c); that is,

design and construction of core support structures meet Subsection NG in full, and other

internals are designed and constructed for their effects on the core support structures to remain

within the core support structure code limits. As fatigue usage factor depends strongly not on

flow-induced vibration or other high-cycle time-dependent effects at steady-state conditions but

on effects of operational, upset, and emergency transient events, the increase in operating life to

60 years should not have a significant effect on fatigue usage factor, as long as the number of

design-basis transient cycles remains within the number assumed by the original analysis.

The LRA states that the applicant will obtain a design report amendment either to quantify the

increase in high-cycle fatigue effects or to confirm that the increase will be negligible. The

applicant will complete this action before the end of the current licensed operating period. The

analysis of these fatigue effects in reactor internals will thereby be revised for the period of

extended operation.

The LRA states that transient cycle counting under the Metal Fatigue of Reactor Coolant

Pressure Boundary Program will ensure that the design basis fatigue usage factor limit of 1.0 will

not be exceeded in any analyzed location in the reactor internals without being identified and

evaluated, which includes taking any necessary mitigating actions. The effects of fatigue and

other mechanisms in the barrel-to-former and baffle-to-former will be managed with the Reactor

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Coolant System Supplement AMP. Therefore, fatigue in the reactor vessel internals will be

adequately managed for the period of extended operation.

4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.3 to verify pursuant to 10 CFR 54.21 (c)(1)(ii), that the

analyses have been projected for the period of extended operation or, pursuant to

10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation.

The staff found that for locations with reported usage factors that are less than 0.66, fatigue in

the reactor vessel internals has been projected to the end of the period of extended operation in

accordance with 10 CFR 54.21 (c)(1)(ii); and for locations with reported usage factors that are

greater than 0.66, fatigue in the reactor vessel internals will be managed for the period of

extended operation in accordance with 10 CFR 54.21 (c)(1)(iii).

In the LRA, the applicant stated that some part of the fatigue usage in the reactor pressure

vessel internals is due to high-cycle effects. Therefore, it depends on steady-state operating

time rather than on the number of transient events. Hence, high-cycle fatigue must be evaluated

separately in order to extend the conclusion of the supplementary design report to the end of the

60-year operating period. In LRA Section 4.3.3, the applicant stated that the analysis of

high-cycle fatigue effects in reactor internals will be revised for the period of extended operation,

in accordance with 10 CFR 54.21 (c)(1)(ii).

However, 10 CFR 54.21 (c)(1)(ii) states that the applicant shall demonstrate that the analyses

have been projected to the end of the period of extended operation. The analyses has not been

completed for the staff's review. Therefore, the applicant did not satisfy the requirement

described in 10 CFR 54.21 (c)(1)(ii).

By letter dated November 30, 2007, the applicant provided its assessment of the impact of

high-cycle fatigue to the total fatigue usage factor for the reactor pressure vessel internals. In its

review of the letter of November 30, 2007, the staff noted that the projected CUFs for the reactor

vessel internals will not exceed 1.0. There were two conclusions regarding the applicant's metal

fatigue analysis for the reactor vessel internals that were of concern to the staff on the validity of

the conclusion. These were: (1) the vibratory stresses for the reactor vessel internals are very

small when compared to the thermal transient stresses, and (2) the usage from high-cycle

effects is negligible. To address this issue, the applicant amended the LRA to include

Commitment No. 24. In this commitment, the applicant stated that it would either obtain a design

report amendment to quantify the increase in high-cycle fatigue effects, or else confirm that the

increase in the CUFs for the reactor vessel internals will be negligible. The staff informed the

applicant that it might need to verify the validity of the applicant's assessment by performing an

audit of the plant basis documents in early 2008. The staff identified this issue as 01 4.3.

The staff audited the applicant's calculation BB-S-029 Revision 0, titled "ASME Code Design

Stress Report for Wolf Creek Generating Station Reactor Vessel Internals" and validation letter

W LTR SAP 07-28. The staff's audit verified that, for some locations (representative), fatigue

usage from high-cycle loadings (e.g., flow-induced vibrations) was calculated and found to be

negligible. This indicates that vibratory stresses were very small compared to thermal transient

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stresses and do not have a contributing effect in the fatigue CUF calculation. For the remainder

of the locations high-cycle fatigue due to vibration was not calculated because the vibratory

stresses were thought to be very small compared to thermal transient stresses. The staff finds

the applicant's approach acceptable and concludes that the part of 01 4.3 which refers to the

vessel internals (Section 4.3.3) is resolved, and that the applicant has fulfilled LRA Commitment

No. 24.

The staff noted that, with the exception of the baffle former and baffle former bolts, the applicant

also credited transient cycle counting under the Metal Fatigue of Reactor Coolant Pressure

Boundary Program to manage the effects of fatigue in the reactor vessel internals in accordance

with the requirements of 10 CFR 54.21 (c)(1)(iii). The applicant's Metal Fatigue of Reactor

Coolant Pressure Boundary Program is designed and credited to track the events occurring at

the plant in order to ensure that: (a) the accumulated number of operating cycles for the

transients analyzed for in the CUF calculations will remain within the number of cycles that were

analyzed and allowed for in the design basis CUF calculations or (b) appropriate reevaluation or

other corrective actions, if the allowable number of cycles is projected to be exceeded. The

staff's evaluation of the applicant's Metal Fatigue of Reactor Coolant Pressure Boundary

Program is documented in SER Section 3.0.3.2.24. This evaluation, which includes the staff's

basis for acceptance, is also valid for evaluation and acceptance of the aging management of

the metal fatigue in the reactor vessel internals in accordance with the requirements of

10 CFR 54.21 (c)(1)(iii). Based on this review, the staff concludes that the applicant's aging

management is consistent with the recommendations in the SRP-LR.

The staff noted that the applicant, based on industrial operating experience, has indicated that

cracking of the reactor internal baffle-to-former bolts may be induced by either metal fatigue or

by stress corrosion cracking, including irradiated-assisted stress corrosion cracking. Because of

this, the applicant has credited: (a) its Reactor Coolant System Supplement Program to provide

aging management of metal fatigue of the baffle/former bolts in accordance with

10 CFR 54.21 (c)(1)(iii) and (b) to manage the effects of cracking, regardless of the mechanism

(i.e., metal fatigue or stress corrosion cracking/irradiated-assisted stress corrosion cracking) that

may potentially induce cracking in the components. The staff's evaluation of the Reactor Coolant

System Supplement Program is documented in SER Section 3.0.3.3.2. This evaluation, which

includes the staff's basis for acceptance, is also valid for the staff's evaluation and acceptance

that the program will be capable of managing cracking in the baffle-to-former bolts caused by

metal fatigue. Based on this review, the staff concludes that the applicant may use the Reactor

Coolant System Supplement Program to manage the effects of metal fatigue-induced cracking

in these bolting components, in accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

4.3.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

ASME Code Section III subsection NG fatigue analysis for the reactor pressure vessel internals

in LRA Section A3.2.2. On the basis of its review of the USAR supplement and resolution of the

reactor vessel internals portion of 01 4.3, the staff concludes that the summary description of the

applicant's actions to address ASME Code Section III subsection NG fatigue analysis, reactor

pressure vessel internals is adequate.

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4.3.3.4 Conclusion

On the basis of its review as discussed above, the portion of 01 4.3 which refers to the impact of

high-cycle fatigue to the CUF for the reactor vessel internals has been resolved. The staff

concludes that the applicant has demonstrated for ASME Code Section III subsection NG fatigue

analysis of reactor pressure vessel internals, the analyses have been projected to the end of the

period of extended operation in accordance with 10 CFR 54.21 (c)(1)(ii) and the effects of aging

on the intended function(s) will be adequately managed for the period of extended operation in

accordance with 10 CFR 54.21 (c)(1)(iii). The staff also concludes that the USAR supplement

contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21 (d).

4.3.4 Effects of the Reactor Coolant System Environment on Fatigue Life of Piping and

Components (Generic Safety Issue 190)

4.3.4.1 Summary of Technical Information in the Application

LRA Section 4.3.4 summarizes the evaluation of effects of the reactor coolant system

environment on fatigue life of piping and components (Generic Safety Issue (GSI) 190) for the

period of extended operation. The fatigue data for the ASME Code Section III fatigue curves are

the results of tests in air at room temperature and constant strain rate. Concerns over possible

effects of elevated temperature, reactor coolant chemistry environments, and different strain

rates prompted NRC-sponsored research to assess them in NUREG/CR-5999, "Interim Fatigue

Design Curves for Carbon, Low-Alloy, and Austenitic Stainless Steels in LWR Environments."

Subsequent research and studies, including NUREG/CR-6260, "Application of NUREG/CR-5999

Interim fatigue Curves to Selected Nuclear Power Plant Components," refined the methods. The

NRC concluded that effects of the reactor coolant environment perhaps should be included in

the calculated fatigue life of components and opened three GSIs to address this question; all

finally closed to a single issue, GSI 190. Although GSI 190 has been closed for plants with

40-year initial licenses, NUREG-1 800 states that, "the applicant's consideration of the effects of

coolant environment on component fatigue life for license renewal is an area of review," noting

the staff recommendation "...that the samples in NUREG/CR-6260 should be evaluated

considering environmental effects for license renewal."

NUREG/CR-6260 identifies seven sample locations for newer Westinghouse plants like WCGS:

* reactor vessel lower head to shell juncture

* reactor vessel primary coolant inlet nozzles

* reactor vessel primary coolant outlet nozzle

• surge line hot leg nozzle

• charging nozzles

* safety injection nozzles

* residual heat removal line inlet transition

WCGS performed plant-specific calculations for the seven locations and evaluated effects of the

reactor coolant environment on fatigue calculations using the appropriate FEN factors from

NUREG/CR-6583 and NUREG/CR-5704. At the first location, the vessel lower head to shell

juncture, the expected 60-year fatigue usage factor was determined by multiplying the design

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basis 40-year usage factor times 1.5. All others were projected from historical and current rates

of accumulation of transient cycles and usage factors, using either the cycle-based method or

the stress-based method of the Metal Fatigue Program of Reactor Coolant Pressure Boundary

Program. The inlet, outlet, safety injection, and accumulator-RHR nozzle predictions used the

cycle-based method. The remaining hot leg and charging nozzle predictions used the

stress-based method.

The LRA states that the analysis showed that the fatigue usage factors in the NUREG/CR-6260

sample locations should remain less than 1.0 for the period of extended operation (including the

effects of the reactor coolant environment); and, that the safety determination supported by the

code fatigue analyses should therefore remain valid. The Metal Fatigue of Reactor Coolant

Pressure Boundary Program will include appropriate usage factor action limits to ensure that the

usage factor at the remainder of these locations, including FEN, does not exceed 1.0 before an

evaluation is completed and appropriate actions have been identified. The effects of the reactor

coolant environment on fatigue usage factors in these locations will be managed for the period

of extended operation.

4.3.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.4 to verify, pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation or pursuant to 10 CFR 54.21 (c)(1)(iii),

that the effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

During the audit, the staff reviewed LRA Section 4.3.4 against the guidance provided in SRP-LR

Section 4.3.3.2. The SRP-LR recommends that license renewal applicants address the effect of

the reactor coolant environment. To assess the impact of the reactor coolant environment on a

sample of critical components, the SRP-LR states that the applicant should address the

recommendations as follows:

* *the critical components include, as a minimum, those selected in NUREG/CR-6260

* the sample of critical components has been evaluated by applying environmental

correction factors to the existing ASME Code fatigue analyses

formulas for calculating the environmental life correction factors are those contained in

NUREG/CR-6583 for carbon and low-alloy steels, and in NUREG/CR-5704 for austenitic

stainless steels, or an approved technical equivalent

LRA Table 4.3-5 provides the CUFs for a sample of critical components, which are calculated by

applying environmental correction factors to the existing ASME Code fatigue analysis. The staff

confirmed that the critical components include those selected in NUREG/CR-6260 for the newer

vintage Westinghouse plants. The applicant stated that environmental life correction factors are

calculated in accordance with the formulas contained in NUREG/CR-6583 for carbon and

low-alloy steels, and in NUREG/CR-5704 for austenitic stainless steels. Therefore, the staff finds

that WCGS has followed the staff's recommendation to assess the impact of the reactor coolant

environment.

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During the audit, the staff reviewed the applicant's existing fatigue analysis and requested that

the applicant resolve three issues related to the CUFs calculation.

(1) numbers of transient cycles used in the fatigue evaluation:

The staff reviewed LRA Table 4.3-1 which lists estimated numbers of transient cycles for

60 years. The staff finds that the estimated 60-year cycles assume that some design

transients will never occur. However, those design transients have occurred in other

similar design nuclear power plants. For example, the LRA for the Shearon Harris

Nuclear Power Plant states that it has experienced the following design transients within

the first 18 years of operation:

* inadvertent reactor coolant system depressurization

" reactor trip cooldown with safety injection

* reactor cooldown without safety injection

* inadvertent safety injection

* excessive feedwater flow

LRA Table 4.3-1 also shows a reduction in the number of design transients. For example,

WCGS experienced 55 reactor trips during the past 20 years and projected 44 reactor

trips for the next 40 years. During the audit, the staff requested that the applicant explain

the projection methodology which is used to develop estimated cycles to the end of the

period of extended operation.

In its response dated June 7, 2007, the applicanf stated that the algorithm used to predict

future rates of accumulation weighs recent history more heavily than the experience

obtained from the plant startup and early years of operation. The applicant clarified that

the cycle reduction in the projection did not refer to reduction in the number of design

transients. These projections are used for estimating probable usage factor and these are

not the basis for the disposition of these fatigue TLAAs.

On the basis that the Metal Fatigue of Reactor Coolant Pressure Boundary Program is

used to manage the effects of fatigue for the NUREG/CR-6260 sample locations, except

the reactor vessel lower head and shell junction, the staff finds that this position is

consistent with the recommendations in the SRP-LR and in accordance with the

requirements of 10 CFR 54.21 (c)(1)(iii). The Metal Fatigue of Reactor Coolant Pressure

Boundary Program will track events to ensure (1) that the operating cycles of the events

remains within the cycles of analyzed design allowable events or, (2) that appropriate

reevaluation or other corrective action is taken if an analyzed number of events is

exceeded.

By letter dated August 20, 2007, the applicant committed (Commitment No. 21) to

address the metal fatigue in the reactor pressure boundary. The Metal Fatigue of Reactor

Coolant Pressure Boundary Program will establish an action limit and corrective actions

prior to the period of extend operation.

On the basis that the corrective actions and action limits will address future transients, the

staff finds Commitment No. 21 acceptable.

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LRA Section 4.3.4 states that all the NUREG/CR-6260 sample locations will be age

managed except the reactor vessel lower head-to-shell junction. The reactor vessel lower

head-to-shell junction permits a projection of the usage for a 60-year life, equal to 1.5

times the design basis usage factor and times a conservative environmental fatigue life

correction factor for carbon steel. The results include a considerable margin to the ASME

Code allowance of 1.0.

On the basis that the fatigue usage factor for this location has been successfully validated

and will remain below the code allowable limit of 1.0, the staff finds that the fatigue TLAA

for the reactor vessel lower head-to-shell junction remains valid for the period of extended

operation in accordance with 10 CFR 54.21 (c)(1)(i).

(2) methodology used in the fatigue evaluation:

LRA Section 4.3.1.3 states that cycle-based monitoring assumes that the alternating

stress range of every cycle of a transient is equal to that of the design basis, worst-case

events assumed by the ASME Code fatigue analysis.

The staff's review of LRA Section 4.3.1.3 identified an area in which additional information

was necessary to complete the review of the applicant's TLAA evaluation. The applicant

responded to the staff's RAI as discussed below.

In RAI 4.3-3 dated July 24, 2007, the staff requested that the applicant clarify the

methodology used to calculate the usage factors for the cycle-based monitoring locations.

The staff requested that the applicant demonstrate the validity of the baseline fatigue

usage factors.

In its response dated August 20, 2007, the applicant stated, in part:

For the cycle-based locations (line numbers 1-4 in LRA Table 4.3-2), the

Wolf Creek Generating Station (WCGS) fatigue management program

uses (1) actual plant cycle count data and (2) the design basis fatigue

effect of each cycle transient pair. Because all of the cycles contributing to

fatigue that occurred before implementation of the fatigue monitoring

program were reconstructed from reviews of historical records, all transient

cycles have been accounted for since the beginning of plant life (starting

from February 1984). The fatigue effect of each cycle is defined by design

calculations. Thus, there are no unknown parameters needed to calculate

CUF using cycle based methodology. Therefore, CUF results from cycle

based monitoring represent the accurate baseline usage to date for these

locations. No back-projection was necessary.

On the basis that the actual plant cycle count data and design transient defined by design

calculation were used to evaluate CUFs for cycle-based locations, the staff finds this

method acceptable and conservative compared with using actual transient data.

As stated in SER Section 4.3.2.7.2, the staff questioned the applicant's methodology used

to calculate the baseline fatigue usage factors for the surge line hot leg nozzle, charging

nozzle, and alternate charging nozzle locations.

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In its response dated October 3, 2007, the applicant committed (Commitment No. 38) to

address the backward projection for the surge line hot leg nozzle, charging nozzles, and

alternate charging nozzles. The applicant committed to calculate an updated baseline

fatigue usage factor that adequately bounds transients experienced before the monitoring

of CUFs was started. The existing baseline CUF for all monitored locations will be

increased to bound the potential CUF contribution from the transients that were

under-represented in the existing baseline.

The staff found that the applicant would submit this reanalysis to the staff for review by

January 31, 2008. This was identified as open item (01) 4.3-3.

By letter dated January 25, 2008, the applicant provided its response to 01 4.3-3. The staff

reviewed the applicant's methodology on the backward projection for the surge line hot leg

nozzle, charging nozzles, and alternate charging nozzles. In its response, the applicant states its

methodology would include identifying the unaccounted transients for Period 1, a review of

transient records to account for any improperly counted events, and then computing a bounding

CUF increment with the information gathered to update the baseline. The staff finds this

acceptable because the applicant is appropriately accounting for transients that occurred in

Period 1, and accounting for any transients that were not properly counted by reviewing transient

records. The staff also finds it acceptable that the applicant is computing the CUF increment as a

sum of the CUF from the unaccounted transients and the improperly accounted transients.

However, the staff determined that additional information was necessary because the applicant

did not provide the analysis results for CUF accumulated in Period 1. For this reason, the staff

issued a follow-up RAI in letter dated February 28, 2008. Based on its review, the staff concludes

that the response letter submitted by the applicant dated January 25, 2008 closed Commitment

No. 38, except those portions related to the pressurizer hot leg surge nozzle and charging nozzle.

By letter dated May 15, 2008, the applicant provided its response letter to 01 4.3-3. The staff

determined that the applicant's response did not provide the updated baseline CUF calculation for

surge line hot leg nozzle and charging nozzles which were to account for the pre-MOP conditions

and the differential contribution of fatigue for each charging event. The applicant supplemented

this response by letter dated June 9, 2008 and committed (Commitment No.41) as part of its

Metal Fatigue of the Reactor Coolant Pressure Boundary Program, to prepare an updated

baseline calculation for the surge line hot leg surge nozzle based on the actual pre-MOP

environment for the nozzle and an updated baseline calculation for the charging nozzles based

on the consideration for the differential contribution from each category of charging events. The

applicant indicated that Commitment No. 41 closes and replaces Commitment No. 38 with

respect to the reanalyses for the surge line hot leg nozzle and the charging nozzles. The staff

verified that the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary Program

includes an enhancement, as given in LRA Commitment No. 21, to adjust the CUF values for the

NUREG/CR-6260 locations (which include the charging nozzles and surge line hot leg nozzle) by

the environmental Fn factors for the components. The staff finds this to be an acceptable basis

for managing the impacts of environmentally-assisted metal fatigue on the pressure boundary

function of the charging nozzles and surge line hot leg nozzle because: (a) the commitment to do

the updated baseline CUF calculations for these components is consistent with the recommended

criterion in the "detection of aging effects" program element in the GALL Report for performance

of periodic CUF updates, (b) the applicant has committed in LRA Commitment No. 21 to adjust

the CUF values for the NUREG/CR-6260 locations (which include the charging nozzles and surge

line hot leg nozzle) by the environmental Fen factors for the components, and (c) the applicant has

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brought Commitment No. 41 within the scope of its existing Metal Fatigue of Reactor Coolant

Pressure Boundary AMP to manage the aging effect on the components. Based on this review,

the staff finds that the applicant has provided an acceptable basis for aging management of

environmentally-assisted metal fatigue of the charging nozzles and surge line hot leg nozzle in

accordance with 10 CFR 54.21 (c)(1)(iii), because the applicant will manage the effects of

environmentally-assisted metal fatigue on the pressure boundary function of the nozzles during

the period of extended operation. The staff concludes that Commitment 38 regarding

environmentally-assisted metal fatigue assessment for these nozzle components is resolved and

completed. Based on its review, the staff concludes that 01 4.3-3 is resolved.

(3) fatigue evaluation using the FatiguePro software:

During the audit, the staff reviewed the applicant's FatiguePro stress calculations. The

calculations indicate that FatiguePro only tracks one stress component for each location

monitored, while a stress vector consists of 6 stress components. The staff requested that

the applicant address the following items:

(a) Explain why the stress function contains only one value and what is the meaning of

this stress value and justify how one stress component could be used to evaluate

fatigue CUF.

(b) The report defines stress transfer function as stress intensity. Explain how stress

intensity value could be used as an input for the transfer function methodology.

(c) Is the same methodology, using only one component of stress intensity vector to

calculate the fatigue usage value, applied to all reactor coolant pressure boundary

locations?

(d) Describe how the stress transfer functions were benchmarked for the components

of WCGS.

(e) Explain how to determine the stress transfer function for S(pr), S(momxz),

S(momy). Demonstrate S(pr)= 3.71, S(momyz)=9.40, S(momy)=0.0.

During the audit, the applicant explained that this one stress component is a one

dimensional (1 D) virtual peak stress. This stress value is obtained by summing the

absolute value of the individual stress components. The applicant also indicated that

Structural Integrity Associates, the consulting firm that owns FatiguePro, did not perform a

benchmark of FatiguePro transfer functions to an independent standard.

The staff reviewed the applicant's response and determined that additional information

was necessary to resolve the staff's concerns on the adequacy and basis for using 1 D

virtual peak stress, the lack of verification of the accuracy of these transfer functions, and

the lack of independent benchmark.

The staff issued two RAIs. In RAI 4.3-1 (first RAI) dated June 22, 2007, the staff noted

that the applicant's response to audit question TLAAA025, states that the transfer function

report defines a 1 D virtual stress value that is designed to bound the actual stress

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intensity ranges for all fatigue significant transients and this type of stress value does not

have a name in the professional literature.

(a) Since it cannot be found in the professional literature, the staff requested that the

applicant describe in detail how the 1 D virtual stress was derived.

(b) The staff requested that the applicant demonstrate how the virtual stress bounds

the actual stress intensity ranges for any thermal transient. The staff requested

that the applicant show that the stress difference between any two thermal

transients is also conservative since the fatigue evaluation is based on the stress

difference of two events.

In its response dated July 26, 2007, the applicant provided calculations, figures, and case

studies. The staff reviewed the applicant's response and determined that additional

information was necessary. As documented in the teleconference summary dated

September 4, 2007, the staff requested that the applicant:

(a) Clearly define 1 D thermal (virtual) stresses for different locations on the

component (nozzle, nozzle inner radius) and thermal conditions (stratification). In

addition, explain how the 1 D thermal stress is derived for the surge line hot leg

nozzle under stratification.

(b) Explain what is the limitation of 1 D virtual stress methodology and describe what

kind of conditions cannot be mathematically proven to be conservative.

(c) Provide a justification that demonstrates ASME Code compliance using the 1 D

thermal (virtual) stress methodology.

In RAI 4.3-2 (second RAI) dated June 22, 2007, the staff requested the applicant to

demonstrate that 1 D virtual stresses for pressure, bending, and torsion can be

benchmarked with close form solutions and that the stresses are within a reasonable

percentage of deviation.

In its response dated July 26, 2007, the applicant provided a detailed analysis and

calculations. The staff reviewed the applicant's response and determined that additional

information was necessary.

As documented in the teleconference summary dated September 4, 2007, the staff noted

that the applicant evaluated the fatigue CUF at the top of the pipe for all stratification

cases. The top of the pipe may not be the most critical stress location for either bending or

stratification. For bending, the maximum stress location is at an angle from the top of the

pipe. Also, the maximum stratification stress is right above or below the temperature

discontinuity.

The staff requested that the applicant justify why these two critical locations were not

evaluated. The current evaluation eliminates one of the bending moment components and

may not be in compliance with the ASME Code.

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In a letter dated October 3, 2007, the applicant provided its response to address 1 D virtual

stress related issues. In the response, the applicant stated that FatiguePro 1 D stress

analysis is demonstrably conservative for all load pairs that include significant transients.

However, the staff noted that FatiguePro was used in another plant, which has

demonstrated that 1 D virtual stress method has its limitation, and may generate

unconservative stress results. Therefore, the staff determined that the applicant did not

provide sufficient information to address the concerns raised in the staff's follow-up

questions to RAI 4.3-1. On this basis, the staff determined that this item remained open.

This was identified as 01 4.3-1.

On May 1, 2008, a public meeting was held to discuss 01 4.3-1. During this meeting, the

applicant presented its methodology for the confirmatory analyses of the charging nozzle and the

surge line hot leg nozzle. During this meeting, the staff asked the applicant to verify the absence

or presence of thermal sleeves for the charging nozzles.

By letter dated May 15, 2008, the applicant provided its response to 01 4.3-1. The staff reviewed

the applicant's response and determined that it is inadequate because the confirmatory analysis

was performed assuming a thermal sleeve was present in the charging nozzles, and the applicant

is unsure of this assumption. The applicant also provided the results of a confirmatory analysis of

the hot leg surge line nozzle. The results of the confirmatory analysis indicated that the baseline

fatigue evaluations are conservative. As discussed previously, the applicant committed to update

the baseline calculation to address the pre-MOP conditions (Commitment No. 41). The staff

chose not to review this confirmatory analyses at this time because the applicant committed to

update the calculations and verify the existence of the charging nozzle thermal sleeves. As a

consequence, the fatigue calculations and supporting confirmatory analyses may be superseded.

The applicant supplemented its response by letter dated June 9, 2008 and committed

(Commitment No.40) to validate the presence or absence of a charging nozzle thermal sleeve,

and to perform a new analysis if a thermal sleeve is not present, which will be incorporated into

the Fatigue Monitoring Program. The applicant indicated that Commitment No. 40 is incorporated

within the scope of the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary

Program and also closes and replaces Commitment No. 38 with respect to the reanalyses for the

charging nozzles. The staff find's the supplemental letter response acceptable because the

applicant has committed to performing updated baseline CUF analyses for the charging nozzle as

part of Fatigue Monitoring Program, pending confirmation on the presence or absence of thermal

sleeve.

The staff verified that the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary

Program includes an enhancement, as given in LRA Commitment No. 21, to adjust the CUF

values for the NUREG/CR-6260 locations (which include the charging nozzles) by the

environmental Fen factors for the components. The staff finds this to be an additional acceptable

basis for managing the impacts of environmentally-assisted metal fatigue on the pressure

boundary function of the charging nozzles because: (a) the applicant has brought Commitment

No. 40 within the scope of its Metal Fatigue of the Reactor Coolant Pressure Boundary Program,

(b) the commitment to do the updated baseline CUF calculations for these components is

consistent with the recommended criterion in the "detection of aging effects" program element in

the GALL Report for performance of periodic CUF updates, and (c) the applicant has committed

in LRA Commitment No. 21 to adjust the CUF values for the NUREG/CR-6260 locations (which

include the charging nozzles and surge line hot leg nozzle) by the environmental Fen factors for

the components. Based on this determination, the staff concludes that the aging management of

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environmentally-assisted metal fatigue for the charging nozzles is acceptable in accordance with

10 CFR 54.21 (c)(1)(iii) because the applicant will manage the impacts of

environmentally-assisted metal fatigue on the intended pressure boundary function of the nozzles

in accordance with its Metal Fatigue of the Reactor Coolant Pressure Boundary Program, during

the period of extended operation. Therefore, the staff concludes that 01 4.3-1 is resolved.

The staff also inquired about the critical fatigue location. In its response to the critical fatigue

location questions dated October 3, 2007, the applicant explained that for newer vintage

Westinghouse plants, the critical fatigue location on the pressurizer surge line is the reactor

coolant system hot leg surge line nozzle. The applicant also stated that the surge line pipe

location is not a location for which environmental effects of the reactor coolant require evaluation.

The staff finds the applicant's response to RAI 4.3-2 acceptable because for newer vintage

Westinghouse plant, like WCGS, the critical fatigue location on the pressurizer surge line is the

hot leg surge line nozzle. In addition, as a result of RAI 4.3-3, the applicant committed

(Commitment No. 38) to recalculate the baseline usage factor for the surge line hot leg nozzle.

The staff's concern described in RAI 4.3-2 is resolved.

Pursuant to 10 CFR 54.21 (c)(1)(iii), the applicant will manage the effects of fatigue in Class 1

piping and piping nozzles during the period of extended operation. The staff's evaluation of the

applicant's Metal Fatigue of Reactor Coolant Pressure Boundary Program is documented in SER

Section 3.0.3.2.24. The staff concludes that the applicant's aging management is consistent with

the recommendations in the SRP-LR.

4.3.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

effects of the reactor coolant system environment on fatigue life of piping and components

(GSI 190) in LRA Section A3.2.3. The staff determined that the USAR Supplement summary

description in LRA Section A3.2.3 adequately summarizes the options relied on for TLAA

acceptance and that Commitment No. 21, 40 and 41, as amended in the applicant's supplemental

response letter dated June 9, 2008, appropriately applies to the assessment in LRA Section 4.3.4

and to the USAR Supplement summary description in LRA Section A3.2.3 and A2.1. On the basis

of its review of the USAR supplement, the staff concludes that the summary description of the

applicant's actions to address effects of the reactor coolant system environment on fatigue life of

piping and components (GSI 190) is adequate.

4.3.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated: (a) pursuant

to 10 CFR 54.21 (c)(1)(i), the analyses remain valid for the period of extended operation or (b)

pursuant to 10 CFR 54.21 (c)(1)(iii) and for the effects of the reactor coolant system environment

on fatigue life of piping and components (GSI 190), the effects of aging on the intended

function(s) will be adequately managed for the period of extended operation. The staff also

concludes that the USAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21(d).

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4.3.5 Assumed Thermal Cycle Count for Allowable Secondary Stress Range Reduction

Factor in B31.1 and ASME Code Section III Class 2 and 3 Piping

4.3.5.1 Summary of Technical Information in the Application

LRA Section 4.3.5 summarizes the evaluation of assumed thermal cycle count for allowable

secondary stress range reduction factor in ASME Code B31.1 and ASME Code Section III

Classes 2 and 3 piping for the period of extended operation. Piping within the scope of license

renewal designed to ASME Code B31.1 or Section III Class 2 and 3 requires application of a

stress range reduction factor to the allowable stress range for secondary stresses to account for

thermal cyclic conditions.

If the number of equivalent full-temperature thermal cycles is less than 7,000, the stress

reduction factor is 1. Therefore, if the number of cycles remains below this number for a 60-year

life, the stress reduction factor remains at 1 and the stress range reduction factor used in the

piping analysis will not be affected by extending the operation period to 60 years.

4.3.5.2 Staff Evaluation

The staff reviewed LRA Section 4.3.5 to verify that the ASME Code B31.1 and Section III, Class 2

and 3, piping analyses remain valid for the period of extended operation pursuant to

10 CFR 54.21 (c)(1)(i), and that the sample lines analyses have been projected to the end of the

period of extended operation, pursuant to 10 CFR 54.21 (c)(1)(ii).

The staff agrees with the applicant that the plant does not operate in a cycling mode that would

expose the piping to more than three thermal cycles per week (i.e., to more than 7,000 cycles in

60 years), with the exception of the reactor coolant sampling lines. On the basis that the

projected 60-year value would not exceed the design cycle limit of 7,000 cycles, the staff

concludes that, with the exception of the reactor coolant sample lines, the ASME Code B31.1 and

Section III, Class 2 and 3, piping analyses remain valid in accordance with 10 CFR 54.21 (c)(1)(i).

LRA Section 4.3.5 indicates that the piping analyses for the reactor coolant sample lines will be

revised in accordance with 10 CFR 54.21 (c)(1)(ii), for the duration of the period of extended

operation.

However, 10 CFR 54.21 (c)(1)(ii) states that the applicant shall demonstrate that the analyses

have been projected to the end of the period of extended operation. The analyses have not been

completed for the staff's review and; therefore, do not satisfy the requirements described in

10 CFR 54.21 (c)(1)(ii).

By letter dated November 30,2007, the applicant addressed its assumed thermal cycle count for

allowable secondary stress range reduction factor in B31.1 and ASME III Class 2 and 3 piping. In

addition, the applicant also made a commitment to complete the reanalysis of the reactor coolant

sample lines and any additional corrective actions or modifications as appropriate, in accordance

with 10 CFR 54.21 (c)(1)(i). This is documented as Commitment No. 25. The staff planned to

verify the validity of the applicant's assumptions by performing an audit of the plant basis

documents. This was identified as 01 4.3 which includes two parts; the first part of 01 4.3 has

been discussed and resolved in SER Section 4.3.3.

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In the letter dated November 30, 2007, the applicant claimed that based on further review of the

original stress calculations for the reactor coolant sample lines (submitted as supplemental

information), the calculations and related assumptions are valid for the period of extended

operation in accordance with 10 CFR 54.21 (c)(1)(i). In addition, the applicant claimed that survey

of all plant piping systems found that some of the reactor coolant sample lines may be subject to

more than 7,000 cycles but less than 11,000 full temperature cycles in 60 years, requiring a

Stress Range Reduction Factor (SRRF) of 0.9 times the allowable stress value in accordance

with NC-3611.2. The applicant identified three evaluations that required further review. Further

review of existing calculations by the applicant revealed that the original calculations of these

three reactor coolant sample lines were performed utilizing a SRRF of 0.9. Based on SRP-LR

Table 4.3-1, a SRRF of 0.9 is required for piping experiencing full temperature cycles between

7,000 and 14,000. During the audit of calculations (J-SJ16-3 and J-SJ16-4, "Stress Analysis of

Instrument Lines, System SJ - Post Accident Sampling System, Auxiliary and Reactor Building"

and J-SJ03-1, "Tube Support Loads and Locations for System SJ - Nuclear Sampling System -

Auxiliary Building"), the staff verified conclusively that a SRRF of 0.9 was incorporated into the

analyses. Based on the staff's review as described above, the staff concludes that the second

part of 01 4.3 is also resolved. Similarly, the staff concludes that the applicant has fulfilled

Commitment No. 25 because it is no longer needed.

4.3.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

assumed thermal cycle count for allowable secondary stress range reduction factor in ASME

Code B31.1 and Section III Class 2 and 3 piping in LRA Section A3.2.4. On the basis of its review

of the USAR supplement and the resolution of the stress range reduction factor for thermal

expansion stress portion of 01 4.3, the staff concludes that the summary description of the

applicant's actions to address assumed thermal cycle count for allowable secondary stress range

reduction factor in ASME Code B31.1 and Section III Class 2 and 3 piping is adequate.

4.3.5.4 Conclusion

On the basis of its review as discussed above, the portion of 01 4.3 which refers to the stress

range reduction factor for the thermal expansion stresses in B31.1 and ASME III Class 2 and 3

piping has been resolved and the staff concludes that the applicant has demonstrated, pursuant

to 10 CFR 54.21 (c)(1)(i), the ASME Code B31.1 and Section III, Class 2 and 3, piping analyses

remain valid for the period of extended operation, which include the reactor coolant sample lines

analyses. The staff also concludes that the USAR supplement contains an appropriate summary

description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.3.6 Fatigue Design of Spent Fuel Pool Liner and Racks for Seismic Events

4.3.6.1 Summary of Technical Information in the Application

LRA Section 4.3.6 summarizes the evaluation of fatigue design of spent fuel pool liner and racks

for seismic events for the period of extended operation. The spent fuel pool racks were replaced

to accommodate a larger inventory. The design of the replacement racks included a fatigue analysis of the racks and of high-stress locations in the pool liner. Operating-basis and

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safe-shutdown earthquakes (OBE and SSE) are the only DBEs for cyclic loading on the fuel pool

liner and racks. No detectable seismic events have occurred in the 20-year operating history of

the plant to date; therefore, the design basis number of events remains sufficient for the

remainder of the original license operating period, plus the 20-year licensed operating period

extension. The replacement racks are presently qualified for the number of these events now

expected for the remainder of a 60-year life.

The analysis for both the racks and liner depend only on the assumed number of OBE and SSE

events. Although an ASME Code Section III Class 1 pressure boundary fatigue analysis would

omit the faulted SSE loads, this analysis included them because spent fuel storage must continue

to function following these events. The analysis remains valid for any period for which the number

of OBE events has not been and is not expected to be exceeded, assuming an additional SSE

event might occur. As the remaining plant life from the present to the end of the period of

extended operation (2006 to 2045) is less than that of the original license to which the numbers of

OBE and SSE events apply and as no SSE or significant OBE has occurred, these analyses

remain valid for the period of extended operation.

4.3.6.2 Staff Evaluation

The staff reviewed LRA Section 4.3.6 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

During the audit, the staff asked the applicant to clarify what is meant by the term "significant

OBE."

In its response, the applicant stated that a significant earthquake would be one producing

sufficient ground acceleration to trigger the free field strong motion accelerometer, which can be

adjusted over a minimum'range of 0.01 to 0.03. To date, no actuation of the strong motion

accelerometer trigger has been attributable to an earthquake.

On the basis that no seismic events have occurred in the 20-year operating history of the plant,

the staff concludes that the design basis number of events remains sufficient for the period of

extended operation. Therefore, the staff concludes that the applicant has adequately

demonstrated that the analyses remain valid for the period of extended operation in accordance

with the requirements of 10 CFR 54.21 (c)(1)(i).

4.3.6.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue design of spent fuel pool liner and racks for seismic events in LRA Section A3.2.5. On the

basis of its review of the USAR supplement, the staff concludes that the summary description of

the applicant's actions to address fatigue design of spent fuel pool liner and racks for seismic

events is adequate.

4.3.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for fatigue design of spent fuel pool liner and racks for seismic events,

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the analyses remain valid for the period of extended operation. The staff also concludes that the

USAR supplement contains an appropriate summary description of the TLAA evaluation, as

required by 10 CFR 54.21 (d).

4.3.7 Fatigue Design and Analysis of Class IE Electrical Raceway Support Angle Fittings

for Seismic Events

4.3.7.1 Summary of Technical Information in the Application

LRA Section 4.3.7 summarizes the evaluation of fatigue design and analysis of Class IE electrical

raceway support angle fittings for seismic events for the period of extended operation. The design

of the Class IE electrical raceway included a fatigue evaluation of the effects of OBE and SSE

loads on angle fittings at the connections of strut hangers to overhead supports or at interhanger

locations. The seismic fatigue analysis of Class IE electrical support angle fittings was

conservative, assuming 1000 allowable cycles for a deflection, considerably less than the

endurance limit. OBEs and SSEs are the only DBEs for cyclic loading on these support angle

fittings. Furthermore, no detectable seismic events have occurred in the 20-year operating history

of the plant to date. Thus, the design basis number of events remains sufficient for the remainder

of the original licensed operating period, plus the period of extended operation. Therefore, the

analysis is valid for the period of extended operation.

4.3.7.2 Staff Evaluation

The staff reviewed LRA Section 4.3.7 to verify, pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

The staff finds that the only cyclic loads applied to these support angle fittings will occur during an

OBE or SSE. Based on recommendations in Institute of Electrical and Electronics Engineers

344-1975, "Recommended Practices for Seismic Qualification of Class 1 E Equipment for Nuclear

Power Generating Stations," the components were designed to survive five OBE and one SSE

events over the lifetime of the plant. Since no seismic events have induced cyclic loads on the

components during the 20-year operating history of the plant, the design-basis assumption

remains valid for the period of extended operation. This assumption results in a total of 900

maximum-deflection cycles. This value was compared to an allowable value of 1000 which was

much less than the indicated endurance limit on the fatigue curve.

On the basis of its review, the staff concludes that the applicant's evaluation provides a

reasonable upper limit estimate on the number of maximum-deflection cycles. The staff

concludes that the applicant has adequately demonstrated that the analyses remain valid for the

period of extended operation in accordance with the requirements of 10 CFR 54.21 (c)(11)(i).

4.3.7.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

fatigue design and analysis of Class IE electrical raceway support angle fittings for seismic

events in LRA Section A3.2.6. On the basis of its review of the USAR supplement, the staff

concludes that the summary description of the applicant's actions to address fatigue design and

analysis of Class IE electrical raceway support angle fittings for seismic events is adequate.

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4.3.7.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for fatigue design and analysis of Class IE electrical raceway support

angle fittings for seismic events, the analyses remain valid for the period of extended operation.

The staff also concludes that the USAR supplement contains an appropriate summary description

of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.4 Environmental Qualification of Electrical Equipment

The 10 CFR 50.49 EQ program is a TLAA for purposes of license renewal. The TLAA of the

environmental qualification (EQ) of electrical components includes all long-lived, passive, and

active electrical and I&C components that are important to safety and are located in a harsh

environment. The harsh environments of the plant are those areas subject to environmental

effects by loss-of-coolant accidents or high-energy line breaks. EQ equipment comprises

safety-related and Q-list equipment, nonsafety-related equipment the failure of which could

prevent satisfactory accomplishment of any safety-related function, and necessary post-accident

monitoring equipment.

Pursuant to 10 CFR 54.21 (c)(1), the applicant must provide a list of EQ TLAAs in the LRA. The

applicant shall demonstrate that for each type of EQ equipment, one of the following is true:

(1) the analyses remain valid for the period of extended operation, (2) the analyses have been

projected to the end of the period of extended operation, or (3) the effects of aging on the

intended function(s) will be adequately managed for the period of extended operation.

4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 summarizes the evaluation of EQ of electrical equipment for the period of

extended operation. Section 50.49(e)(5) of 10 CFR requires consideration of all significant types

of aging degradation that can affect component functional capability and component replacement

or maintenance prior to the end of designated life unless additional life is established through

ongoing qualification. Additionally, it permits different qualification criteria based on plant vintage.

Supplemental EQ regulatory guidance for compliance with these different qualification criteria is

stated in the RG 1.89, Revision 1, "Environmental Qualification of Certain Electric Equipment

Important to Safety for Nuclear Power Plants," and NUREG-0588, "Interim Staff Position on

Environmental Qualification of Safety-Related Electrical Equipment." The applicant stated that its

EQ program is consistent with 10 CFR 50.49 and NUREG-0588. Qualified components and their

service requirements and environments are identified in a controlled equipment qualification

summary document with a program description, a master list of affected equipment, replacement

and maintenance information, and local environment descriptions. The qualification evaluation

records for specific component types are maintained in equipment qualification work packages.

The existing Environmental Qualification of Electrical Components Program manages the aging

effects so EQ components will continue to perform their intended functions for the period of

extended operation. Aging effects addressed by this program will thereby be managed for the

period of extended operation.

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4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4 to verify pursuant to 10 CFR 54.21 (c)(1)(iii), that the effects

of aging on the intended function(s) will be adequately managed for the period of extended

operation.

During the audit, the staff reviewed LRA Sections 4.4 and B3.2, and plant basis documents to

determine whether the applicant provided adequate information to meet the requirements of

10 CFR 54.21 (c)(1)(iii). As documented in SER Section 3.0.3.2.25, the staff finds that the EQ

Program is consistent with the GALL Report. The staff finds that the qualified life of those

components within the scope of the EQ Program will be maintained. The continued

implementation of the EQ Program provides reasonable assurance that the aging effects will be

managed and that components within the scope of the EQ Program will continue to perform their

intended functions for the period of extended operation.

4.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

environmental qualification of electrical equipment in LRA Section A3.3. On the basis of its review

of the USAR supplement, the staff concludes that the summary description of the applicant's

acticins to address environmental qualification of electrical equipment is adequate.

4.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that for environmental qualification of electrical equipment, the effects of

aging on the intended function(s) will be adequately managed for the period of extended

operation. The staff also concludes that the USAR supplement contains an appropriate summary

description of the TLAA evaluation, as required by 10 CFR 54.21 (d).

4.5 Concrete Containment Tendon Prestress

4.5.1 Summary of Technical Information in the.Application

LRA Section 4.5 summarizes the evaluation of concrete containment tendon prestress for the

period of extended operation. The containment is a prestressed concrete, hemispherical

dome-on-a-cylinder structure with a steel membrane liner. Post-tensioned tendons compress the

concrete and permit the structure to withstand design-basis accident internal pressures. The steel

tendons, in tension, relax and the concrete structure, which the tendons hold in compression,

both creeps and shrinks with time; therefore, to ensure the integrity of the containment pressure

boundary under design-basis accident loads, an inspection program confirms whether the tendon

prestress remains within design limits throughout the life of the plant. The original design

predictions of loss of prestress and the regression analyses of surveillance data that predict the

future performance of the post-tensioning system to the end of design life are TLAAs.

The post-tensioning system consists of two tendon groups: (1) vertical, inverted-U-shaped

tendons and (2) horizontal circumferential tendons. The vertical inverted-U tendons are anchored

through the bottom of the conventionally-reinforced concrete basemat. The horizontal hoop

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tendons are anchored at three exterior buttresses 120 degrees apart. Each hoop tendon extends

240 degrees around the containment building, passing under an intervening buttress. The

tendons are not bonded to the concrete but inserted in tendon ducts, after concrete cure, and

tensioned in the prescribed sequence. Each tendon consists of up to 170 1/1⁄4-inch high-strength

steel wires with cold-formed button heads on each end bearing on stressing washers. The total

tendon load is carried by a shim stack to steel bearing plates embedded in the structure.

The condition of the containment prestressing system meets the following criteria for validation

for the period of extended operation as described in NUREG-1800, Section 4.5.3.1.1: (1) The

recent surveillance data for individual tendons have all fallen above the predicted force and (2)

the regression analysis of surveillance lift-off data has extended the trend lines for both the

vertical and horizontal cylinder tendons to 60 years. Both trend lines remain well above minimum

required values for at least 60 years. The lift-off trend lines are calculated by regression of

individual tendon lift-off data, including results of the most recent 2005 20-year surveillance.

These calculations are therefore consistent with NRC IN 99-10, Attachment 3. The surveillance

data regression analysis trend lines are above the surveillance program predicted force lines. The

current regression analysis of the vertical and horizontal cylinder tendons is therefore valid for the

period of extended operation. The existing Concrete Containment Tendon Prestress Program

ensures that the average tendon prestress in each of the vertical and hoop tendon groups will be

maintained above its design-basis minimum required value for the period of extended operation.

4.5.2 Staff Evaluation

The staff reviewed LRA Section 4.5 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the analyses

remain valid for the period of extended operation and, pursuant to 10 CFR 54.21 (c)(1)(iii), that the

effects of aging on the intended function(s) will be adequately managed for the period of

extended operation.

The staff's review of LRA Section 4.5 identified areas in which additional information was

necessary to complete the review of the applicant's TLAA. The applicant responded to the staff's

RAIs as discussed below.

In RAI 4.5-1 dated April 10, 2007, the staff noted that LRA Table 4.5-2 indicates that two tendon

types, dome hoop and cylinder hoop, are combined into one horizontal hoop group. The total

number of examined tendons for these two types was seven for the first, third, and fifth-year

surveillance, and three for the tenth, fifteenth, and twentieth-year surveillance. Two dome hoop

tendons were inspected at the first and third-year surveillance; however, no dome hoop tendon

was inspected after the third-year surveillance. The staff found that ASME Code Section XI,

Subsection IWL-2520, "Examination of Unbonded Post-Tensioning Systems," states that tendons

on dome and cylinder shall be characterized into two different tendon types because of their

geometry and position in the containment. It also states that the minimum number of surveillance

tendons is four for each type of tendons for the first, third, and fifth-year surveillance, and three

for the tenth, fifteenth, and twentieth-year surveillance. The staff requested that the applicant

justify this deviation from the ASME Code requirements.

In its response dated May 9, 2007, the applicant stated that the use of a single horizontal hoop

tendon surveillance group is part of the original licensing basis for this surveillance program. The

WCGS tendon program was originally developed using RG 1.35, proposed Revision 3,

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dated 1979. The applicant stated that the program was modified to conform to the WCGS

technical specification Amendment No. 152, Section 5.5.6, "Containment Tendon Surveillance

Program and Containment Leakage Rate Testing Program," as a commitment to ASME

Code Section XI, Subsection IWL. It also stated that a review of the program plan and

specification confirmed that the present program is consistent with ASME Code Section XI,

Subsection IWL, dated 1998, and with RG 1.35, Revision 3, dated 1990. Therefore, the applicant

concluded that the hoop samples sizes meet the minimum limits specified by ASME

Code Table IWL-2521 -1.

Based on its review, the staff finds the applicant's response to RAI 4.5-1 acceptable because it

clarified that the use of a single horizontal hoop tendon surveillance group is consistent with the

plant's original licensing basis, with ASME Code Section XI, Subsection IWL, dated 1998, and the

staff guidance provided in RG 1.35. The staff's concern described in RAI 4.5-1 is resolved.

In RAI 4.5-2 dated April 10, 2007, the staff noted that LRA Table 4.5-2 states that the seven

horizontal tendons forces at the first year surveillance were 1358.0 kips, 1359.0 kips, 1381.0 kips,

1409.0 kips, 1348.0 kips, 1422.0 kips, and 1387.0 kips. The staff finds that the average value of

these seven tendons force is 1380.6 kips, which is different from the value of 1416 kips shown on

LRA Figure 4.5-1. The staff requested that the applicant explain this discrepancy.

In its response dated May 9, 2007, the applicant explained that it used a lifetime log-linear

regression analysis for all lift-off data to-date, which may differ from the mean value of early-life

data.

Based on its review, the staff finds the applicant's response to RAI 4.5-2 acceptable as it provides

one reasonable way to present this data. In addition, WCGS reconfirmed the log-linear regression

analysis and provided revised plots that include scatter graphs of the lift-off data. The staff's

concern described in RAI 4.5-2 is resolved.

In RAI 4.5-3 dated April 10, 2007, the staff noted that LRA Figure 4.5-1, note 4, states:

The surveillance program predicted force lines were calculated per wire. The

values plotted here assume 170 wires per tendon. Some tendons have fewer

[wires] due to failure to meet acceptance criteria at installation, or due to removal

for surveillance testing.

The staff finds that the predicted magnitude of force of that tendon, based on the assumption of

170 wires, would be higher than it should have been if the numbers of wires in a tendon is less

than 170 due to failure during installation, or due to removal for surveillance testing. The staff

requested that the applicant provides its basis for using the assumed 170 wires per tendon

instead of using the actual numbers of wires to calculate the tendon force.

In its response dated May 9, 2007, the applicant stated that this note applied only to the IWL

predicated force lines. The applicant also stated that the trend lines were calculated from the

actual tendon lift-off forces, regardless of the number of effective wires per tendon.

Based on its review, the staff finds the applicant's response to RAI 4.5-3 acceptable because it

clarified that the trend lines were adequately calculated from the actual tendon lift-off forces. The

staff's concern described in RAI 4.5-3 is resolved.

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In RAI 4.5-4 dated April 10, 2007, the staff requested that the applicant establish a new trend line

for LRA Figure 4.5-1 with actual pre-stressed tendon force.

In its response dated May 9, 2007, the applicant stated that the trend lines were calculated from

the actual tendon lift-off forces, although the IWL predicted forces lines were not. The applicant

provided scatter graphs of the lift-off data with actual prestressed tendon force, and reconfirmed

the adequacy of the log-linear regression analysis lift-off data (i.e., the trend line).

Based on its review, the staff finds the applicant's response to RAI 4.5-3 acceptable because it

clarified that the trend lines were calculated from the actual tendon lift-off forces. In addition, the

scatter graphs provided by the applicant reconfirmed the adequacy of the regression analysis.

The staff's concern described in RAI 4.5-4 is resolved.

4.5.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

concrete containment tendon prestress in LRA Section A3.4. On the basis of its review of the

USAR supplement, the staff concludes that the summary description of the applicant's actions to

address concrete containment tendon prestress is adequate.

4.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1 )(i), that for concrete containment tendon prestress, the analyses remain valid

for the period of extended operation. The applicant also has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(iii), that the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation. The staff also concludes that the USAR

supplement contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21 (d).

4.6 Containment Liner Plate, Polar Crane Bracket, and Penetration Load Cycles

The WCGS post-tensioned concrete containment vessel is designed to Bechtel Topical Report

(BC-TOP)-5A Revision 3. It is poured against a steel membrane liner designed to BC-TOP-1,

Revision 1, "Containment Building Liner Plate Design Report." No credit is taken for the liner for

the pressure design of the containment vessel, but the liner and penetrations ensure the vessel is

leak-tight, and its electrical, process, personnel access, and equipment hatch penetrations are

part of the containment pressure boundary.

4.6.1 Absence of a TLAA for Containment Liner Plate, Polar Crane Bracket, and

Containment Penetration Design (Except Main Steam Penetrations)

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 summarizes the evaluation of absence of a TLAA for containment liner plate,

polar crane bracket, and containment penetration design (except main steam penetrations) for

the period of extended operation. The liner plate is a gas-tight barrier to prevent uncontrolled

release of fission products from the reactor building during operation and also in the unlikely

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event of an accident. SRP-LR Section 4.6.1 notes that in some designs, "fatigue of the liner

plates or metal containments may be considered in the design based on an assumed number of

loading cycles for the current operating term"; however, with the exception of the main steam

penetrations, the containment liner and penetrations were designed to stress limit criteria

independent of the number of load cycles and with no fatigue analyses. The liner plate design

considers creep and shrinkage, prestress combined with concrete creep and shrinkage; and

deadload, earthquake, wind, tornado, hydrostatic, vacuum, pressure, and thermal loads. The

applicant's containment design specification invokes Bechtel containment design topical report

BC-TOP-5A. Neither of these documents nor the ASME Code editions and addenda invoked by

them impose an analysis for cyclic loading to other than quasi-static stress criteria. Although the

containment design specification includes cyclic loads, it does not specify their number nor supply

fatigue or other time-dependent design criteria. The BC-TOP-1 design report for the liner plate

reports no fatigue analysis nor any other design for a stated number of cyclic loads or events for

the liner or for its anchors or embedments. BC-TOP-1, Part II, does include cyclic design of the

main steam penetrations.

The polar crane is supported on a system of girders supported by a series of brackets supported

by the containment structure. BC-TOP-1, Revision 1, reviews the design of these brackets but

reports no fatigue analysis nor any other design for a stated number of crane lifts, cyclic loads, or

other events for the polar crane brackets. A thorough search of the licensing basis and review of

the design documents for the containment liner and polar crane brackets found no evidence of

any TLAAs applicable'to penetrations except for the main steam penetration design. The

containment penetrations include no bellows or expansion joints with TLAA-supported design.

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6 to evaluate the absence of a TLAA for the containment liner

plate, polar crane bracket, and containment penetration design. The containment at WCGS was

designed by Bechtel according to topical reports BC-TOP-5A and BC-TOP-I. The staff agrees

with the applicant that neither of these documents, nor the ASME Code editions and addenda

invoked by them, impose an analysis for cyclic loading to other than the quasi-static stress

criteria. Although the containment design specification includes cyclic loads, it does not specify

their number nor supply fatigue or other time-dependent design criteria. The BC-TOP-1 design

report does not contain fatigue analysis for the liner plate nor any other design report for a stated

number of cyclic loads or events for the liner, or for its anchors or embedments.

4.6.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

absence of a TLAA for containment liner plate, polar crane bracket, and containment penetration

design (except main steam penetrations) in LRA Section A3.5. On the basis of its review of the

USAR supplement, the staff concludes that the summary description of the applicant's actions to

address absence of a TLAA for containment liner plate, polar crane bracket, and containment

penetration design (except main steam penetrations) is adequate.

4-59
4.6.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant's evaluation of the absence of a

TLAA for the containment liner plate, polar crane bracket, and containment penetration design

(except main steam penetrations) for the period of extended operation is adequate. The staff also

concludes that the USAR supplement contains an appropriate summary description of the TLAA

evaluation, as required by 10 CFR 54.21 (d).

4.6.2 Design Cycles for the Main Steam Line Penetrations

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 summarizes the evaluation of design cycles for the main steam line

penetrations for the period of extended operation. The main steam penetrations are designed for

cyclic loads. BC-TOP-1 includes 100 lifetime steady state operating-thermal-gradient-plusnormal-operating-cyclic loads (i.e., Loading Condition V) and 10 steady state operating-thermalgradient-plus-steam-pipe-rupture-cyclic loads (i.e., Loading Condition IV). The BC-TOP-1

analysis of effects of Loading Condition IV and V cyclic loads does not calculate a usage factor

but uses a simplified ASME Code Section III, Subparagraph NB-3228.3, elastic-plastic analysis to

compare the maximum allowed alternating stress range to the calculated maximum alternating

stress intensity.

The LRA states that the original number of thermal cycles assumed for the main steam line

penetrations is adequate for the period of extended operation and there is more than sufficient

margin in the design for any possible increase in operating cycles above the original estimate.

The design of the main steam penetrations is therefore valid for the period of extended

operation.

4.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.6.2 to verify pursuant to 10 CFR 54.21 (c)(11)(i), that the

analyses remain valid for the period of extended operation.

During an audit, the staff noted that LRA Section 4.6 states that LRA Table 4.3-1, item 1, shows

only 27 startup cycles in the 19 years through 2004, and projects about 62 in 60 years. The staff

requested that the applicant provide its technical justification for this statement provided under

the Loading Condition V discussion.

In its response, the applicant indicated that its LRA amendment dated June 1, 2007, removed the

60-year projection column from LRA Table 4.3-1. The applicant stated that LRA Section 4.6.2 will

be amended to provide the following estimate and analysis.

The BC-TOP-1 "Containment Building Liner Plate Design Report" addresses cycle

loading of the main steam penetrations. BC-TOP-1 Loading condition V is directly

dependent on startup-shutdown cycles, which, from experience, are a constant

multiplier of two per refueling cycle. WCGS currently refuels on 18-month cycles,

and expects about 42 refuelings before the end of the extended period of

operation, or about 85 startup-shutdowns cycles at two per refueling. In the 19

4-60
years of operation through 2004, WCGS has 27 startup cycles, which also

indicates that about 85 might occur in a 60-year operating life. Therefore, the

design basis assumption of 100 full-range thermal cycles (BC-TOP-1 Condition V

events) should be adequate.

The number of assumed BC-TOP-1 condition IV events does not change with

licensed life. The design basis equivalent usage factor for the 10 assumed

condition IV events is 0.270. The design basis equivalent usage factor for the 100

assumed Condition V events is 0.028. Up to 2500 Condition V events would then

result in an equivalent usage factor of only 0.270 + 25.0 x 0.028 = 0.970 < 1.000.

The staff reviewed the applicant's response and finds that the analysis showed a calculated

usage factor near the 1.0 limit. However, the staff finds that some margin will be available even if

the design basis number of events were reached for some events of a set. This is justified

because the analysis assumes a higher number of DBEs.

In addition, by letter dated August 9, 2007, the applicant amended the LRA to incorporate these

changes. The staff finds that the calculations will remain valid during the period of extended

operation in accordance with 10 CFR 54.21 (c)(i).

4.6.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

design cycles for the main steam line penetrations in LRA Section A3.5. On the basis of its review

of the USAR supplement, the staff concludes that the summary description of the applicant's

actions to address design cycles for the main steam line penetrations is adequate.

4.6.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for design cycles for the main steam line penetrations, the analyses

remain valid for the period of extended operation. The staff also concludes that the USAR

supplement contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21 (d).

4.7 Plant-Specific Time-Limited Aging Analyses

LRA Section 4.7 summarizes the evaluation of the following plant-specific TLAAs:

" containment polar crane, fuel building cask handling crane, spent fuel pool bridge crane,

and fuel handling machine Crane Manufacturers Association of America Specification

No. 70 (CMAA-70) load cycle limits

* absence of a TLAA for reactor vessel underclad cracking analyses

* absence of a TLAA in a reactor coolant pump flywheel fatigue crack growth analysis

4-61
4.7.1 Containment Polar Crane, Fuel Building Cask Handling Crane, Spent Fuel Pool

Bridge Crane, and Fuel Handling Machine CMAA-70 Load Cycle Limits

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 summarizes the evaluation of containment polar crane, fuel building cask

handling crane, spent fuel pool bridge crane, and fuel handling machine CMAA-70 load cycle

limits for the period of extended operation. USAR Section 9.1.4 and licensing correspondence

describe design of these lifting machines to CMAA-70. The CMAA-70 crane service classification

for each machine depends in part on the assumption that the number of stress cycles at or near

the maximum allowable stress will not exceed the number assumed for that design class. In

operation, this assumption means the number of lifts which approach or equal the design load

(significant lifts) will not exceed the number of stress cycles assumed for that design class. The

design of cranes for these standard numbers of lifts for the plant lifetime is therefore a TLAA. The

design standard number of full-capacity lifts far exceeds the number expected of each machine

for a the period of extended operation. The lifting machine designs therefore remain valid for the

period of extended operation.

4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.1 to verify pursuant to 10 CFR 54.21 (c)(1)(i), that the

analyses remain valid for the period of extended operation.

The staff finds that CMAA-70 Class A and B cranes are designed for 20,000 to 100,000

full-capacity lifts in a design life, and Class C cranes for 100,000 to 500,000 lifts. LRA Table 4.7-1

shows that 487 is the estimate of significant lifts for the polar crane lifetime. The polar crane is a

CMAA-70 Class C crane which is rated for 500,000 lifetime heavy lifts.

The staff reviewed the polar crane overload evaluation which identified that there was one single

overload event performed during Refueling Outage 13. The overload evaluation determined that

stresses were well within the elastic range of all critical elements. On the basis that the design

lifts far exceeds the number of expected lifts and that one single overload event had no significant

effect on the margin of safety of the polar crane, the staff finds that the applicant has

demonstrated that the polar crane design remains valid for the period of extended operation, in

accordance with 10 CFR 54.21 (c)(1)(i).

The applicant estimated that the gate movements in the fuel storage pool and the 16,800 fuel

handling lifts per fuel handling machine add about 100 lifetime lifts to the spent fuel bridge crane.

On the basis that these machines will experience only a fraction of its rate lifetime number of lifts,

as identified in CMAA-70, the staff finds that the applicant has demonstrated that the fuel

handling machine design remains valid for the period of extended operation, in accordance with

10 CFR 54.21 (c)(1)(i).

4.7.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of

containment polar crane, fuel building cask handling crane, spent fuel pool bridge crane, and fuel

handling machine CMAA-70 load cycle limits in LRA Section A3.6.1. On the basis of its review of

4-62
the USAR supplement, the staff concludes that the summary description of the applicant's actions

to address containment polar crane, fuel building cask handling crane, spent fuel pool bridge

crane, and fuel handling machine CMAA-70 load cycle limits is adequate.

4.7.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to

10 CFR 54.21 (c)(1)(i), that for containment polar crane, fuel building cask handling crane, spent

fuel pool bridge crane, and fuel handling machine CMAA-70 load cycle limits, the analyses

remain valid for the period of extended operation. The staff also concludes that the USAR

supplement contains an appropriate summary description of the TLAA evaluation, as required by

10 CFR 54.21(d).

4.7.2 Absence of a TLAA for Reactor Vessel Underclad Cracking Analyses

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 summarizes the evaluation of absence of a TLAA for reactor vessel underclad

cracking analyses for the period of extended operation. WCAP-1 5338-A reports a generic

60-year flaw growth analysis which assumes 1.5 times the number of 40-year design basis cycles

and finds the maximum flaw predicted by the crack growth analysis less than the ASME

Code Section XI allowable flaw size, demonstrating that these effects are acceptable for the

period of extended operation. The NRC safety evaluation of this topical report determined that it

may be incorporated by reference in an LRA if the analysis applies to the applicant's plant.

WCAP-1 5338-A applies to WCGS. The cyclic and transient load assumptions of this topical

report bound those expected in the vessel for the period of extended operation. If invoked,

WCAP-1 5338-A therefore would be valid for the period of extended operation. As these analyses

qualify vessels for the extended 60-year rather than the current 40-year operating term, they are

not TLAAs based on 10 CFR 54.3(a) criterion 3. The Metal Fatigue of Reactor Coolant Pressure

Boundary Program will ensure either that the assumed number of cyclic and transient events is

not exceeded or that appropriate reevaluation or other corrective action is taken if a design-basis

number of events is exceeded. Cyclic and transient loadings that might affect growth of underclad

cracking in the vessel will thereby be managed for the period of extended operation.

4.7.2.2 Staff Evaluation

The staff reviewed WCAP-15338-A. On the basis that the cyclic and transient load assumptions

of this topical report bound those expected in the vessel and vessel geometry of a typical

Westinghouse 4-loop vessel design, the staff concludes that WCAP-1 5338-A is applicable to

WCGS. The staff confirms that WCAP-15338-A reports a generic 60-year flaw growth analyses

and demonstrates the aging effects are acceptable. On the basis that these analyses qualify for

the 60-year rather than the current 40-year operating term, the staff agrees that these analyses

would not be TLAAs as described in 10 CFR 54.3(a)(3). The staff agrees that the existing

analyses are validated for the period of extended operation.

4-63
4.7.2.3 USAR Supplement

On the basis of its review, the staff determines that the reactor vessel underclad cracking

analyses is not a TLAA; therefore, an USAR supplement is not required.

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that the reactor vessel underclad cracking analyses

is not a TLAA. In addition, the staff determines that an USAR supplement is not required.

4.7.3 Absence of a TLAA in a Reactor Coolant Pump Flywheel Fatigue Crack Growth

Analysis

4.7.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3 summarizes the evaluation of absence of a TLAA in a reactor coolant pump

flywheel fatigue crack growth analysis for the period of extended operation. Based on the

definition of TLAA in 10 CFR 54.3(a), neither the risk assessment nor the supporting crack

growth analysis is a TLAA because (1) these analyses support a 20-year inspection interval

rather than a qualified design life and (2) the fatigue crack growth analysis is for a 60-year period

rather than for the term of the current operating license. WCGS License Amendment 153

extended the surveillance interval for the flywheels to 20 years based on Westinghouse Topical

Report WCAP-1 5666, "Extension of Reactor Coolant Pump Motor Flywheel Examination," which

is based on RG 1.174 risk assessment methods. The staff accepted WCAP-15666 for use in

license applications for technical specification improvements. The supporting WCAP-15666,

Section 2, fatigue crack growth analysis assumes an initial flaw from a flywheel bore keyway

equal to 10 percent of the keyway-to-outer-radius dimension and demonstrates that 6000

start-stop cycles (over an assumed 60-year life) produce only about an 80-mil extension of the

crack. As this evaluation was based on the extended rather than the current licensed operating

period, it is not a TLAA. Though not a TLAA, the 60-year crack growth analysis supported this

licensing amendment permitting a 20-year surveillance interval during the current 40-year

licensed operating period. The question remains whether the assumptions of this analysis for a

60- year licensed operating period are valid at WCGS. The applicant stated that the answer

depends only on a demonstration that pumps will experience fewer than 6000 start-stop cycles

during the period of extended operation.

The applicant now refuels on 18-month cycles. Refueling Outage 14 was performed in mid-2005.

The applicant therefore expects about 41 or 42 refueling outages in 60 years. The forced outage

history through early 2005 (20 years of operation) includes 70 events, of which only about 50

required a pump restart. Recent capacity factors have exceeded 90 percent. A conservative

estimate therefore would require no more than about three pump stop-start cycles per year for

forced outages plus about two per refueling outage or about 165 in a 60-year life. As many as 10

per fuel cycle would require only about 400 in a 60-year life. Furthermore, pumps usually are

rebuilt at least every 15 to 20 years, and the present 20-year inspection interval and inspection

methods ensure detection of any incipient flaws long before they might reach critical size.

4-64
4.7.3.2 Staff Evaluation

The staff reviewed WCAP-1 5666 and confirmed that 6000 cycles of RCP starts and stops were

assumed for a 60-year plant life in the fatigue crack growth evaluation. The staff also reviewed

WCGS operating history and determined that 6000 design cycles of RCP starts and stops far

exceeds the actual operating cycles of RCP starts and stops. On the basis that the fatigue crack

growth evaluation qualify for the 60-year rather than the current 40-year operating term, the staff

agrees that the fatigue crack growth evaluation would not be TLAAs as described in

10 CFR 54.3(a)(3). The staff determines that the existing analysis is valid for the period of

extended operation.

4.7.3.3 USAR Supplement

On the basis of its review, the staff determines that the RCP flywheel fatigue crack growth

analysis is not a TLAA; therefore, an USAR supplement is not required.

4.7.3.4 Conclusion

On the basis of its review, the staff concludes that the RCP flywheel fatigue crack growth analysis

is not a TLAA. In addition, the staff determines that an USAR supplement is not required.

4.8 Conclusion for Time-Limited Aging Analyses

The staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On the basis

of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, as

required by 10 CFR 54.3 and that the applicant has demonstrated that: (1) the TLAAs will remain

valid for the period of extended operation, as required by 10 CFR 54.21 (c)(1)(i); (2) the TLAAs

have been projected to the end of the period of extended operation, as required by

10 CFR 54.21 (c)(1)(ii); or (3) the effects of aging on the intended function(s) will be adequately

managed for the period of extended operation, as required by 10 CFR 54.21 (c)(1)(iii). The staff

also reviewed the USAR supplement for the TLAAs and finds that the supplement contains

descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21 (d). In addition,

the staff concludes, as required by 10 CFR 54.21 (c)(2), that no additional plant-specific,

TLAA-based exemptions beyond what is described in the LRA are in effect.

With regard to these matters, the staff concludes that there is reasonable assurance that the

activities authorized by the renewed license will continue to be conducted in accordance with the

CLB, and that any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are in

accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

4-65

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

In accordance with Title 10, Part 54, of the Code of Federal Regulations, the Advisory Committee

on Reactor Safeguards (ACRS) has reviewed the license renewal application (LRA) for Wolf

Creek Generating Station (WCGS).

On March 5, 2008, the applicant presented its LRA, and the NRC staff, including Region IV

personnel, presented its review findings, as contained in the safety evaluation report (SER) with

open items dated February 1, 2008, to the ACRS Plant License Renewal Subcommittee.

On September 4, 2008, the applicant presented its LRA, and the NRC staff, including Region IV

personnel, presented its review findings, as contained in the final SER dated July 29, 2008, to

the ACRS Plant License Renewal Full Committee.

During the 5 5 5th meeting of the ACRS on September 4-5, 2008, the ACRS completed its review

of the WCGS LRA and the staff SER. The ACRS documented its findings in a letter to the

Commission dated September 17, 2008. A copy of this letter is provided on the following pages of

this SER Section.

5-1
UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

WASHINGTON, DC 20555 - 0001

September 17, 2008

The Honorable Dale E. Klein

Chairman

U. S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL

APPLICATION FOR THE WOLF CREEK GENERATING STATION, UNIT 1

Dear Chairman Klein:

During the 555th meeting of the Advisory Committee on Reactor Safeguards (ACRS),

September 4-5, 2008, we completed our review of the license renewal application for the Wolf

Creek Generating Station (WCGS), Unit I, and the final Safety Evaluation Report (SER)

prepared by the NRC staff- Our Plant License Renewal Subcommittee also reviewed this

matter during its meeting on March 5, 2008. During these reviews, we had the benefit of

discussions with the NRC staff and the applicant, Wolf Creek Nuclear Operating Corporation

(WCNOC). We also had the benefit of the documents referenced. This report fulfills the

requirement of 10 CFR 54.25 that the ACRS review and report on all license renewal

applications.

CONCLUSION AND RECOMMENDATION

The programs established and committed to by the applicant to manage age-related

degradation provide reasonable assurance that WCGS can be operated in

accordance with its current licensing basis for the period of extended operation

without undue risk to the health and safety of the public.

The WCNOC application for renewal of the operating license for WCGS should be

approved.

BACKGROUND AND DISCUSSION

WCGS is a Westinghouse 4-loop pressurized water reactor with a large dry containment located

approximately 3.5 miles northeast of Burlington, Kansas. The current licensed power rating of

WCGS is 3565 megawatts thermal with a gross electrical output of approximately 1228

megawatts. WCNOC requested renewal of the WCGS operating license for 20 years beyond

the current license term, which expires on March 11, 2025.

5-2
-2-

In the final SER, the staff documented its review of the license renewal application and other

information submitted by the applicant or obtained from the staff audits and an inspection at the

plant site. The staff reviewed the completeness of the applicant's identification of the

Structures, Systems, and Components (SSCs) that are within the scope of license renewal; the

integrated plant assessment process; the applicant's identification of the plausible aging

mechanisms associated with passive, long-lived components; the adequacy of the applicant's

Aging Management Programs (AMPs); and identification and assessment of Time-Limited Aging

Analyses (TLAAs) requiring review.

In the WCGS license renewal application, WCNOC identified the SSCs that fall within the scope

of license renewal. Based on this review, the applicant will implement 39 AMPs for license

renewal comprised of 32 existing programs, 13 of which have been enhanced, and 7 new

programs.

The WCGS application either demonstrates consistency with the Generic Aging Lessons

Learned (GALL) Report or documents deviations to the specified approaches in this Report.

The WCGS application includes 15 exceptions to the GALL Report. We reviewed these

exceptions and agree with the staff that they are acceptable. Other recent license renewal

applications have contained a number of exceptions to the GALL Report, which, upon review,

have been found acceptable. The staff agrees that future updates of the GALL Report should

incorporate alternative approaches which are used by the industry and have been previously

approved by the staff. These proposed efforts will reduce the number of exceptions to the

GALL Report in future applications and will facilitate the staff's review.

The staff conducted license renewal audits and an inspection at WCGS. The audits verified the

appropriateness of the scoping and screening methodology, AMPs, aging management review,

and TLAAs. The site inspection verified that the license renewal requirements are appropriately

implemented. Based on the audits and inspection, the staff concludes in the SER that the

proposed activities will manage the effects of aging of SSCs identified in the application and that

the intended functions of these SSCs will be maintained during the period of extended

operation. We agree with this conclusion.

As a result of the staff's review of the WCGS and other recent license renewal applications, the

staff issued draft Regulatory Information Summary (RIS), 2008-xx, "Fatigue Analysis of Nuclear

Power Plant Components," for public comment. This draft RIS identifies instances where a

simplified fatigue analysis methodology can lead to a non-conservative result. This simplified

methodology is not consistent with the methodology described in the American Society of

Mechanical Engineers (ASME) Code, Section III, Subarticle NB-3200. In response to the staff's

Requests for Additional Information (RAls), the applicant performed confirmatory analyses for

the hot leg surge line nozzle and charging nozzles.

The results of the confirmatory analyses indicated that the calculated Cumulative Usage Factors

(CUFs) for these components, based on the simplified methodology, are conservative as

compared to results based on the ASME NB-3200 methodology. However, there are two issues

not currently fully analyzed, both relate to thermally induced cyclic metal fatigue. To resolve the

first metal fatigue issue, the applicant has committed to update the count of thermal cycles for

5-3
-3-

the early years of plant operation, during which thermal cycle counts were not collected in a

systematic and rigorous manner. Regarding the second issue, the applicant has recently

determined that a thermal sleeve is not present in the charging nozzle as assumed in a

previously submitted analysis. The applicant is in the process of performing a reanalysis, which

is consistent with the commitment documented in the final SER. Through these license renewal

commitments, the applicant will perform the required fatigue analyses in a conservative manner

and in sufficient time to permit thorough staff review and approval of these analyses prior to the

start of the extended period of operation.

The applicant identified the systems and components requiring TLAAs and reevaluated them for

the period of extended operation. The staff concluded that the applicant has provided an

adequate list of TLAAs. Further, the staff has concluded that, in all cases, the applicant has met

the requirements of the License Renewal Rule by demonstrating that the TLAAs will remain

valid for the period of extended operation, or that the TLAAs have been projected to the end of

the period of extended operation, or that the aging effects will be adequately managed for the

period of extended operation. We concur with the staff's conclusion that WCGS TLAAs have

been properly identified and that the required criteria will be met for the period of extended

operation.

We agree with the staff that there are no issues related to the matters described in 10 CFR

54-29(a)(1) and (a)(2) that preclude renewal of the operating license for WCGS. The programs

established and committed to by WCNOC provide reasonable assurance that the WCGS can be

operated in accordance with its current licensing basis for the period of extended operation

without undue risk to the health and safety of the public. The WCNOC application for renewal of

the operating license for WCGS should be approved.

Sincerely,

IRA/

William J. Shack

Chairman

References

1. Letter dated September 27, 2006, from Terry J. Garrett, WCNOC to U.S. Nuclear Regulatory

Commission, transmitting the Application to Renew the Operating License of Wolf Creek

Generating Station, Unit 1, (ML062770308).

2. U.S- Nuclear Regulatory Commission, "Safety Evaluation Report, Related to the License

Renewal of Wolf Creek Generating Station," dated July 31, 2008, (ML082180210).

3. NRC Staff Audit Summary Report, dated February 14, 2008, (ML073310013).

4. NRC License Renewal Inspection Report 05000482/2007007, Wolf Creek Generating

Station, dated December 5, 2007, (ML073390687).

5-4
-4-

5. NRC Draft Regulatory Issue Summary, 2008-xx, "Fatigue Analysis of Nuclear Power Plant

Components," dated April 11, 2008, (ML080950235).

6- U.S. Nuclear Regulatory Commission, NUREG-1801, Volumes 1 & 2, Rev 1, "Generic Aging

Lessons Learned Report," September 2005.

5-5

SECTION 6

CONCLUSION

The staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff) reviewed

the license renewal application (LRA) for Wolf Creek Generating Station, Unit 1, in accordance

with NRC regulations and NUREG-1800, Revision 1, "Standard Review Plan for Review of

License Renewal Applications for Nuclear Power Plants," dated September 2005. Title 10,

Section 54.29, of the Code of Federal Regulations (10 CFR 54.29) sets the standards for

issuance of a renewed license.

On the basis of its review of the LRA, the staff concludes that the requirements of

10 CFR 54.29(a) have been met.

The staff noted that any requirements of 10 CFR Part 51, Subpart A, are documented in

NUREG-1437, "Generic Environmental Impact Statement for License Renewal of Nuclear Plants

(GELS)" and Supplement 32, "Generic Environmental Impact Statement for License Renewal

Plants Regarding Wolf Creek Generating Station," dated May 2008.

6-1

APPENDIX A

WCGS UNIT 1 LICENSE RENEWAL COMMITMENTS

During the review of the Wolf Creek Generating Station (WCGS), Unit 1, license renewal

application (LRA) by the staff of the United States (US) Nuclear Regulatory Commission (NRC)

(the staff), Wolf Creek Nuclear Operating Corporation (WCNOC or the applicant) made

commitments related to aging management programs (AMPs) to manage aging effects for

structures and components. The following table lists these commitments along with the

implementation schedules and sources for each commitment.

A-1
_____ APrP04 1XýA, W,-UGSý UNIT fVLI CENSE, REN EWAL.0 M AITANS M 

ltem~Nurnber, Conimit~me'it &upI.AR nhanemen ortý Source,

(1) Prior to the period of extended operation, procedures A1.4 March 11, 2025 ET 06-0038

will be enhanced to state that susceptible components

adjacent to potential leakage sources will include

electrical components and connectors.

(2) Prior to the period of extended operation, procedures A1.5 March 11, 2025 ET 06-0038

will be enhanced to indicate that detection of leakage or

evidence of cracking in the vessel-head penetration

nozzles or associated welds will cause an immediate

reclassification to the

"High" susceptibility ranking,

commencing from the same outage in

which the leakage or cracking is -

detected.

(3) Prior to the period of extended operation, a new periodic Al.10 March 11, 2025 ET 06-0038

preventive maintenance activity will be developed to ET 07-0020

specify performing inspections of the internal surfaces of

valve bodies and accessible piping while the valves are

disassembled for operational readiness inspections to

detect loss of material and fouling. The acceptance

criteria will be specified in this Preventive Maintenance

activity.

A-2
I1 APPENIX A W.CGS UNIT 1 LICENSE RENEWAL G""MIWI-ENTS

Corm PARn Ejih M~t r Source -S-" umpp tetIn :Irped Mo emIo ___ __ __ __ ___ __ __ __ __ __ __ LRA SponSchedule_ _ _ _ _

(4) Prior to the period of extended operation, procedures

will be enhanced to: (1) identify industry standards or

Wolf Creek Generating Station (WCGS) specifications

that are applicable to the component, and (2)

specifically inspect for loss of material due to corrosion

or rail wear.

A1.11 March 11, 2025 ET 06-0038

4 + I

(5) Prior to the period of extended operation: (1) fire

damper inspection and drop test procedures will be

enhanced to inspect damper housing for signs of

corrosion, (2) fire barrier and fire door inspection

procedures will be enhanced to specify fire barriers and

doors described in USAR Appendix 9.5A, 'WVCGS Fire

Protection Comparison to APCSB 9.5-1 Appendix A,"

and WCGS Fire Hazards Analysis, (3) training for

technicians performing the fire door and fire damper

visual inspection will be enhanced to include fire

protection inspection requirements and training

documentation, and (4) halon fire suppression system

inspection procedures will be enhanced to include visual

inspection of halon tank flexible hoses (that

do not have scheduled periodic replacement intervals)

for hardening - loss of strength.

A1.12 March 11, 2025 ET 06-0038

ET 07-0038

I

A-3
APPENDIX A: WCGS UNIT 1 LICENSE RENEWAL COMMITMENTS_____________

Itiam Numrber' Commitment USAR: Enhancement or Source

Suippleme'ntSec'tio6I Implementation

(6) Prior to the period of extended operation: (1) the A1.14 March 11, 2025 ET 06-0038

emergency fuel oil day tanks will be added to the ET 07-0020

ten-year drain, clean, and internal inspection program,

and (2) procedures will be enhanced to provide for

supplemental ultrasonic thickness measurements if

there are indications of reduced cross sectional.

thickness found during the visual inspection of the

emergency fuel oil storage tanks. A one time ultrasonic

(UT) or pulsed eddy current (PEC) thickness

examination on the external surface of engine driven fire

pump fuel oil tank (1 DO002T) will be performed to

detect corrosion related wall thinning. If UT is used, the

examination will be on a 4 inch grid. The examination

will be performed once between 10 and 2 years prior to

the period of extended operation.

(7) The One-Time Inspection program conducts one-time A1.16 March 11, 2025 ET 06-0038

inspections of plant system piping and components,

to verify the effectiveness of the Water Chemistry

program (A1.2), Fuel Oil Chemistry program (A1.14),

and Lubricating Oil Analysis program (Al.23).This new

program will be implemented and completed within

the ten-year period prior to the period of extended

operation.

(8) The Selective Leaching of Materials program is a new A1.17 March 11, 2025 ET 06-0038

program that will be implemented prior to the period of

extended operation.

A-4
APPENDIX* A.WCGS UNIT 1 LICENSE RENEWAL'COMMITMVENTS____________

IteM'.Number. Commitment USAR Enhancement or Source

_________ - .Supplement Section/ Implemen~taion

(9) The Buried Piping and Tranks Inspection program-is a1 A1.1 8 March 11, 2025 ET 06-0038

new program that will be implemented prior to the period and once within

of extended, operation. Within the ten-yea~r period prior 1 0-years of

to entering the period 'of extended operation, an entering period

opportunistic or planned inspection will be performed. of extended

.Upon enterin'g the period of extended operation a operation planned inspection within ten years will be required

unless an opportunistic inspection has occurred

within this ten-year period. ________________

(10) The fourth interval of the ISI program at WOGS will Al1.19 March 11, 2025 ET 06-0038

provide the results for the one-time-inspection of ASME

Code Class 1. small-bore piping. _________ _____

(11) The Inspection of Internal Surfaces in Miscellaneous Al .22 March 11, 2025 ET 06-0038

Piping and Ducting Components program is a new

program that will be implemented prior to the period of

extended operation. For those systemns or components

where inspections of opportunity are insufficient, an

inspection will be conducted prior to the period of

extended operation to provide reasonable, assurance

that the intended functions are maintained.

(12) The Electrical Cables and Connections Not Subject to Al1.24 March 11, 2025 ET 06-0038

10 CFR5O.49 Environmental Qualification Requirements

program is a new program that will be implemented prior

to the period of extended operation.________________________

A-5
__________ " . -' APPENDIX A:; WCGS UNIT 1 LICENSE RENEWAL COMMITMENTS _'_....."

Item Number Commitment USAR Enhancement or Sourde

Supplement Section/ Implementation

(13) A review of the calibration surveillance test results will A1.25 March 11, 2025 ET 06-0038

be completed before the period of extended operation and every 10

and every 10 years thereafter. years thereafter

(14) The Inaccessible Medium Voltage Cables Not Subject to A1.26 March 11, 2025 ET 06-0038

10 CFR 50.49 Environmental Qualification

Requirements program is a new program that will be

implemented prior to the period of extended operation.

(15) Prior to the period of extended operation, procedures A1.28 March 11, 2025 ET 06-0038

will be enhanced to include two new provisions ET 07-0020

regarding inspection of repair/replacement activities.

The 2001 Edition with 2002 and 2003 addenda of ASME

Code Section XI, Subsection IWL, Article IWL-2000,

includes two provisions that are not required by the

1998 edition. IWL-2410(d) specifies additional

inspections for concrete surface areas affected by a

repair/replacement activity, and IWL-2521.2 specifies

additional inspections for tendons affected by a

repair/replacement activity. In accordance with

10 CFR 50.55a, WCGS will revise their CISI program

prior to the next inspection interval to incorporate the

ASME Code edition and addenda incorporated into

10 CFR 50.55a at that time.

(16) Prior to the period of extended operation, procedures A1.31 March 11, 2025 ET 06-0038

will be enhanced to identify un-reinforced masonry in

the Radwaste Building within the scope of license

renewal that requires aging management.

A-6
__._ /•APPENDIX A::WCGSUNIT1 LICENSE RENEWAL COMMMITENTS

IeNubrCommitment USAR Enihancemnent or. Source

Supplement-Section/I 'mplementation

(17) Prior to the period of extended operation, procedures A1.32 March 11, 2025 ET 06-0038

will be enhanced to add inspection parameters for ET 07-0020

treated wood and to monitor groundwater for pH,

sulfates, and chlorides. Two samples of groundwater will

be tested every five years.

(18) Prior to the period of extended operation, procedures A1.33 March 11, 2025 ET 06-0038

will be enhanced: (1) so that the main dam service

spillway and the auxiliary spillway will be inspected in

accordance with the same specification, (2) to clarify the

scope of inspections for the spillways, (3) to add the

5-year inspection 'frequency for the main dam service

spillway, and (4) to add cavitation to the list of concrete

aging effects for surfaces other than spillways.

(19) WCNOC will: A1.35 March 11, 2023 ET 06-0038

A. Reactor Coolant System Nickel Alloy Pressure ET 07-0033

Boundary Components. Implement applicable (1) NRC WM 08-

Orders, Bulletins and Generic Letters associated with 0019

nickel alloys and (2) staff-accepted industry guidelines,

(3) participate in the industry initiatives, such as owners

group programs and the EPRI Materials Reliability

Program, for managing aging effects associated with

nickel alloys, (4) upon completion of these programs,

but not less than 24 months before entering the period

of extended operation, WCNOC will submit an

inspection plan for reactor coolant system nickel alloy

_ _ pressure boundary components to the NRC for review

A-7
__________ ~APPENDIX; A. WC S UNIT LIUCENSE RENEWALC&OIMITME!4T$ ______ ____

Item Number 2 6rmsitment S ,.S _nncAin••...... USAR .... or. o

. upplpemnt S66to'ln/ "Impýerntatlon

and approval, and

B. Reactor Vessel Internals (1) Participate in the

industry programs for investigating and managing aging

effects on reactor internals; (2) evaluate and implement

the results of the industry programs as applicable to the

reactor internals; and (3) upon completion of these

programs, but not less than 24 months before entering

the period of extended operation, WCNOC will submit

an inspection plan for reactor internals to the NRC for

review and approval.

(20) Prior to the period of extended operation: A1.36 March 11, 2025 ET 06-0038

(1) the infrared thermography testing ET 07-0038

procedure will be enhanced to require an

engineering evaluation when test

acceptance criteria are not met. This

engineering evaluation will include

identifying the extent of condition, the

potential root cause for not meeting the test

acceptance, and the likelihood of

recurrence, and (2) A one-time inspection of

a representative sample of low voltage, low

current, or low load connections will be

performed.

A-8
__________ APOPEN=I A.:W'CGS UNIT ILICENSE RENEWAL CQMMITMENTS____________

Item, Number .Commitment U SAR E nhtinceibbt or,-ore

SU'ppIemeniectloW;, enatb ..... _. ___. . _-_ ....._.__.______.____.-_._•_-_ _-..-_ _._ _-"_ LRA.Me0t0otji ______________ ... __.. .

" " " " ' " • " ' N " .,| ' | .. • l '..... lJi'l• : • ="•~ •= _• ' I " l• ,l••"•" +.' | l li =' " ~ ~ l • • I i ill N . ' ' •• •"• > • + ' " '• ": • : •• : : / ' •' ' •" •

(21) Prior to the period of extended operation, the Metal

Fatigue of Reactor Coolant Pressure Boundary program

will be enhanced to include:

1) Cycle Count Action Limit and Corrective Actions.

An action limit will be established that requires

corrective action when .the cycle count for any of the

critical thermal and pressure transients is projected to

reach a high percentage (e.g., 90%) of the design

specified number of cycles before the end of the next

fuel cycle. If this action limit is reached, acceptable

corrective actions include:

1. Review of fatigue usage calculations:

* To determine whether the transient in question

contributes significantly to CUF

* To identify the components and analyses

affected by the transient in question

* To ensure that the analytical bases of the

leak-before-break (LBB) fatigue crack

propagation analysis and of the high-energy

line break (HELB) locations are maintained

2. Evaluation of remaining margins on CUF based on

cycle-based or stress-based CUF calculations using the

WCGS fatigue management program software.

3. Redefinition of the specified number of cycles (e.g.,

by reducing. specified numbers of cycles.for other

transients and using the margin to increase the allowed

number of.cycles for the transient that is approaching its

specified number of cycles).

A2.1 March 11,2025 ET 06-0038

ET 07-0031

ET 07-0037

ET 07-0046

A-9
APPENDIX A: WCGS UNIT 1 LICENSE ýRENEWAL COMMITMVENTS____________

ItmNubrCommitment IJSAR Enharncement or Sourcet

SupplemOn~~Ln Inplemehit~tion •_ • _ ,_~_ ,_,__ .-. __ __ .. "___ .,:_____ .__ r____ "__,.___ ,__ ,',_;_• t• ;ip " -S : '" l: , :__.• _": 

2) Cumulative Fatigue Usage Action Limit and

Corrective Actions.

An. action limit will be established that requires

correctiVe action when calculated CUF (from cycle

based or stress basedimonitoring) for any monitored

location is projectedt0o reach 1.0 within the next 2 or 3

fuel cycles. If this'action limit is reached, acceptable

corrective actions include:

1. Determine whether the scope of the monitoring

program must be enlarged to include additional affected

reactor coolant pressure boundary locations. This

determination Will ensure that other

locations do not approach design limits without an

appropriate action.

2. Enhance fatigue monitoring to confirm continued

conformance to the code limit.

3. Repair the component.

4. Replace the component.

5. Perform a more rigorous analysis of the component to

demonstrate that the design code limit will not be

exceeded.

6. Modify plant operating practices to reduce the fatigue

usage accumulation rate.

7. Perform a flaw tolerance evaluation and impose

component-specific inspections, under ASME Code

Section Xl Appendices A or C (or their successors), and

obtain required approvals by the NRC. Corrective

action limits for cumulative fatigue usage will be I

A-10
__________ t

~APPENDIX A: WCG% UNIT 1 LICENSE RENEWAL.COMMITMENTS, . ____

iItem Number Commitment USAR Enhancement or Source ISupplement'SectlonI ImplemeritatIon.

assure that sufficient margin is maintained to allow one

cycle of the highest -fatigue usage per cycle transient to

occur without exceeding CUF = 1.0. (This includes.

consideration of environmental effects for

NUREG/CR6260 locations). This may require that

corrective action is taken more than 2 or 3 fuel cycles

before CUF is projected to exceed 1 .0.

This is because the projections will be based on

historical experience, which is not expected to include

many of the low probability design transients. The low

probability design transients to be used in the evaluation

will include:

* Aux. Spray Actuation, Spray Water Diff.>320F

* Excessive Feedwater Flow

* Reactor Trip - Cooldown with no SI

* COMS

* Reactor Trip - No Inadvertent Cooldown with Turbine

Over-speed

* Reactor Trip - Cooldown with SI

* Inadvertent RCS Depressurization

* Accumulator Safety Injection

* Operating Basis Earthquake

3) 10 CFR 50 Appendix B procedural and record

requirements.

[Prior to the period of extended operation, changes in

available monitoring technology or in the analyses

themselves may permit different action limits. and action

statements, or may re-define the program features and

A-11
APPENDIXA: WOGS UNIT 1 LICENSE RENEWAL COMMITMVENTS _______

'Item, Number C.ormmitment- USAR: Enhancement or. Sourco

Suppleiment Sectlon/ lmpleineritatlon

actions required to address fatigue time-limited aging

analyses. (TLAAs)]

(22) DELETED DELETED DELETED ET 06-0038

ET 07-0020

(23) Prior to the period of extended operation, procedures A2.3 March 11, 2025 ET 06-0038

will be revised to: (1) extend the list of surveillance

tendons to include random samples

for the year 40, 45, 50, and 55-year surveillances, (2)

explicitly require a regression analysis for each tendon

group after every surveillance, (3) invoke and describe

regression analysis methods used to construct

the lift-off trend lines, (4) extend surveillance program

predicted force lines for the vertical and hoop tendon

groups to 60 years, and (5) conform procedure

descriptions of acceptance criteria action levels to the

ASME Code, Subsection IWL 3221 descriptions.

(24) WCNOC will obtain a design report amendment to either A3.2.2 COMPLETED ET 06-0038

quantify the increase in high-cycle fatigue effects,

or to confirm that the increase will be negligible.

WCNOC will complete this action before the end of the

current licensed operating period.

(25) WCNOC will complete the reanalysis of the reactor A3.2.4 COMPLETED ET 06-0038

coolant sample lines and any additional corrective

actions or modifications indicated by them, before the

end of the current licensed operating period.

A-12
APPEN •IXA: CGýSOUNIT 1 LICENSERENEWAL COMMITMENTS __________r__

Item Number Commitment ,JSA•,• hancei-t or Source

Supptmteton imlementation

kLft ',tlp Schedule. _____

(26) Following issuance of the renewed operating license in AO USAR update. ET 06-0038

accordance with 10 CFR 50.71 (e), WCNOC will following ET 07-0020

incorporate the USAR supplement into the WCGS issuance of the

USAR as required by 54.21 (d). renewed

operating license

in accordance

with

10 CFR50.71 (e).

(27) WCNOC will revise the Pressure and Temperature A3.1.3 March 11, 2025 ET 06-0038

Limits Report for a 60-year licensed operating life.

(28) Implementation of new programs may. require additional March 11, 2025 ET 06-0038

action items. not included in this list. WCGS is

committed to including new program elements in the

corrective action program.

(29) License Renewal Application changes discussed in this COMPLETED ET 07-0011

document ET 07-0011 will be submitted in an ET 07-0025

amendment to the application. ET 07-0038

(30) The WCNOC Nickel Alloy Aging Management Program A1.34 March 11, 2023 ET 07-0016

will be supplemented with implementation of applicable ET 07-0042

(1) NRC Orders, Bulletins and Generic Letters WM

associated with nickel alloys and (2) staff-accepted 07-0077

industry guidelines, (3) participate in the industry

initiatives, such as owrers group programs and the

EPRI Materials Reliability Program, for managing aging

effects associated with nickel alloys, (4) upon

A-13
* . . ~~~~APPENDIX A: WCGS UNIT .1 LIPENSE--RE~gWA COMM ITM ENT! ____________

Item'Number .. U$AR ~ -Enhanorrint qr. Source

Comiten . ppem 6. ctiortI Iprio.llri~tntlon

completion of these programs, but not less than 24

months before entering the period of extended

operation, WCNOC will submit an inspection plan for

reactor coolant system nickel alloy pressure boundary

components to the NRC for review and approval.

(31) License Renewal Application changes discussed in ET COMPLETED ET 07-0020

07-0020 and ET 07-0031, Enclosure 1, will be submitted ET 07-0031

in an amendment to the Application. ET 07-0038

(32) WCNOC Procedure QCP-20-518, "Visual March 11, 2025 ET 07-0020

System Examination of Heat Exchangers and

(RCMS 2007-253) Piping Components," will be revised

to define cracking, provide additional guidance

for detection of cracking and specific acceptance criteria

relating to "as found" cracking.

(33) License Renewal Application changes discussed in WM COMPLETED WM

07-0050 will be submitted in an amendment to the 07-0050

application. ET 07-0038

(34) License Renewal Application changes discussed in WM COMPLETED WM

07-0051 will be submitted in an amendment to the 07-0051

application. WM

07-0077

(35) License Renewal Application changes discussed in ET COMPLETED ET 07-0028

07-0028 will be submitted in an amendment to the ET 07-0038

It_ application.

A-14
APEDXA: WCGS UNIT 1 LICENSE, RENEWAL COMMITMETI_______ ____

Item Number Corntmnt usAR Enhancervientor Source

Supi. en.......ti o / mi .... tati .....n

(36) License Renewal Application changes discussed in ET COMPLETED ET 07-0031

07-0031, Enclosure 2, will be submitted in an WM

amendment to the Application. 07-0077

(37) License Renewal Application changes discussed in COMPLETED ET 07-0033

RAI 2.1-2 Followup Response will be included in an ET 07-0038

amendment to the Application if determined to have

LRA impact.

(38) Backward projection of CUF was. used for COMPLETED ET 07-0046

NUREG/CR-6260 locations (Surge Line Hot ET 07-0037

Leg Nozzle, Charging Nozzles), and for several WM

locations not covered by NUREG/CR -6260 locations 07-0077

(Pressurizer Lower Head, Pressurizer Spray Nozzle,

Pressurizer Surge Nozzle, Pressurizer Surge Line, S/G

Feedwater Nozzles). While the ratios used for

back-projection do incorporate accumulated fatigue

effects from all transients that occurred during

PERIOD 2, it does not account for transients

which occurred more frequently in PERIOD 1 than

during PERIOD 2. Therefore, Wolf Creek -will prepare an

updated baseline that adequately bounds

transients experienced prior to the start of CUF

monitoring. The existing baseline CUF for all monitored

locations will be increased to bound the potential CUF

contribution from the transients that were

I under-represented in the existing baseline.

A-15
* APPENDIX A: WCGS UNIT 1 LICENSE RENEWAL COMMITMENTS

itemNumber CommitmentUSAR Enhancement or SourceSupplement Section/ Implementto

(39) Pursuant to 10 CFR 54.21 (b), Wolf Creek Nuclear COMPLETED ET 07-0044

Operating Corporation (WCNOC) has completed the WM

annual review and is in the process of evaluating two 07-0077

changes to the Wolf Creek Generating Station (WCGS) ET 07-0048

current licensing basis (CLB) that may materially affect

the content of the WCGS License Renewal Application

(LRA), including the Updated Safety Analysis Report

(USAR) supplement. WCNOC expects to complete this

evaluation and if necessary submit any changes to the

WCGS LRA.

(40) Validate the presence or absence of charging nozzle A2.1 March 11, 2023 ET 08-0030

thermal sleeves. If WCNOC determines that the sleeves ET 08-0036

are not present, the analyses will be re-performed and

the new analyses will be incorporated into the WCGS

I fatigue monitoring program.

A-16
APPENDIX A: WCGS UNIT. 1. LICENSE-,RENEWAL COMMITMENTS

Item Number Commitment USAR Enhancement or Source

Supplement Section/ ImplementatIon-

(41) Backward projection of CUF was used in the WCGS A2.1 March 11, 2023 ET 08-0030

fatigue monitoring program for NUREG/CR-6260 ET 08-0036

Locations (Surge Line Hot Leg Nozzle, and Charging

Nozzles). While the ratios used for back-projection do

incorporate accumulated fatigue effects from all

transients that occurred during Period 2, it does not

account for transients, which occurred more frequently

in Period 1 than Period 2. Therefore, WCNOC will

prepare a fatigue monitoring program updated baseline

for the pressurizer hot leg surge nozzle based on the

additional insurge/outsurge cycles accumulated in a

pre-MOP environment. Additionally, WCNOC will update

the fatigue monitoring program baseline for the charging

nozzles with consideration for the differential

contribution of fatigue for each category of charging

event.

A-17

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the routine licensing correspondence between the staff of the

United States (US) Nuclear Regulatory Commission (NRC) (the staff) and Wolf Creek Nuclear

Operating Corporation (WCNOC). This appendix also lists other correspondence on the staff's

review of the Wolf Creek Generating Station (WCGS), Unit 1 license renewal application (LRA)

(under Docket No. 50-482).

APPE-ND:IX BI: CHRO-NOLOGY

Dot, ý>S~ubjeq!

September 27, 2006 Transmittal of WCGS LRA (ADAMS Accession No. ML062770301)

September 27, 2006 WCGS LRA (ADAMS Accession No. ML062770308)

September 27, 2006 WCGS LRA Drawings (ADAMS Accession No. ML062770307)

September 27, 2006 WCGS LRA Environmental Report (ADAMS Accession

No. ML062770305)

October 10, 2006 Press Release 06-127: NRC Announces Availability of LRA for WCGS,

Unit 1 (ADAMS Accession No. ML062830270)

October 12, 2006 Receipt and Availability of the LRA for the WCGS, Unit 1 (ADAMS

Accession No. ML062840512)

October 20, 2006 Summary of Meeting Held on September 20, 2006, Between The U.S.

Nuclear Regulatory Commission (NRC) Staff and Strategic Teaming

and Resource Sharing (STARS) Representatives to Discuss the WCGS

LRA (ADAMS Accession No. ML062760407)

November 3, 2006 LRA for the WCGS, Unit 1 - Supplemental Information (ADAMS

Accession No. ML063070581)

November 17, 2006 WCGS Supplementary Environmental Information to Support the LRA

(ADAMS Accession No. ML063260283)

November 30, 2006 Determination of Acceptability and Sufficiency for Docketing, Proposed

Review Schedule, and Opportunity for a Hearing Regarding the

Application from WCNOC, for Renewal of the Operating License for

WCGS (ADAMS Accession No. ML063240216)

November 30, 2006 Notice of Acceptance for Docketing of the Application, Notice of

Opportunity for Hearing, and Notice of Intent to Prepare an

Environmental Impact Statement and Conduct Scoping Process for

WCGS (ADAMS Accession No. ML063240237)

B-1
'APPENDIX'B: CHRONOLOGY

Date , Subject

November 30, 2006 Forthcoming Public Meeting to Discuss the License Renewal Process

and Environmental Scoping for WCGS, Unit 1, LRA Review (ADAMS

Accession No. ML063240053)

December 5, 2006 Press Release 06-148: NRC Announces. Opportunity to Request a

Hearing on for the WCGS LRA (ADAMS Accession No. ML063390067)

December 12, 2006 Revised Forthcoming Meeting to Discuss the License Renewal Process

and Environmental Scoping for WCGS, Unit 1, LRA Review (ADAMS

Accession No. ML063460165)

December 12, 2006 Request for Additional Information (RAI) For the Review of The WCGS,

Unit 1, LRA (ADAMS Accession No. ML063420403)

December 13, 2006 Press•Release IV-06-027: NRC Staff To Hold Two Public Meetings To

Discuss License Renewal Process For WCGS, Unit 1 (ADAMS

Accession No. ML063470208)

January 11, 2007 WCNOC Response to RAI Regarding the Review of the LRA (ADAMS

Accession No. ML070180367)

January 19, 2007 Summary of Public Meetings Held on December 19, 2007, Related to

the Review of the WCGS LRA (ADAMS Accession No. ML070220041)

February 2, 2007 Summary of Conference Call Held on January 4, 2007, Between the - NRC and WCNOC, Concerning the Upcoming Scoping and Screening

Methodology Audit (ADAMS Accession No. ML070330525)

February 6,2007 Audit and Review Plan for Plant Aging Management Reviews and

Programs, WCGS (ADAMS Accession No. ML070230166)

April 3, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070710027)

April 3, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070930559)

April 4, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070710050)

April 9, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070930695)

April 9, 2007 Revision of Schedule for the Review of the WCGS, Unit 1, LRA

(ADAMS Accession No. ML070930175)

April 10, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

I No. ML070930685)

B-2
APPIENDIX: B: 'CHRONOLOGY

Date Subject

April 11, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070800176)

April 11, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML070930659)

April 18, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML071000259)

May 2, 2007 WCGS, Response to RAI Related to LRA (ADAMS Accession

No. ML071290058)

May 6, 2007 Summary of Telephone Conference Call Held on April 06, 2007

Between the NRC and WCNOC, Concerning Draft RAIs Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071220339)

May 6, 2007 Summary of Telephone Conference Call Held on March 06, 2007,

Between the NRC and WCNOC, Concerning Draft RAIs Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071220212)

May 6, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML0711220180)

May 7, 2007 Summary of Telephone Conference Call Held on March 07, 2007,

Between the NRC and WCNOC, Concerning Draft RAts Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071 220191)

May 8, 2007 Summary of Telephone Conference Calls Held on March 20 and

April 06, 2007, Between the NRC and WCNOC, Concerning Draft RAIs

Pertaining to the WCGS, Unit 1, LRA (ADAMS Accession

No. ML071220293)

May 8, 2007 Summary of Telephone Conference Call Held on April 10, 2007,

Between the NRC and WCNOC, Concerning Draft RAIs Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071220365)

May 8, 2007, Summary of Telephone Conference Call Held on April 11, 2007,

Between the NRC and WCNOC, Concerning Draft RAIs Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071240153)

May 9, 2007 WCNOC Response to RAI Related to the WCGS LRA (ADAMS

Accession No. ML071360100)

May 10, 2007 WCNOC Response to RAI Related to the WCGS LRA (ADAMS

Accession No. ML071380454)

B-3
APPENDIX B: CHRONOLOGY

Date Subject

May 16, 2007 Summary of Telephone Conference Call Held on March 7, 2007,

Between the NRC and WCNOC, Concerning Draft RAI Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071240214)

May 20, 2007 Summary of Telephone Conference Call Held on May 02, 2007

Between the NRC and WCNOC, Concerning Draft RAI Pertaining to

the WCGS, Unit 1, LRA (ADAMS Accession No. ML071240286)

May 22, 2007 Summary of Conference Call Held on March 7, 2007, Between the

NRC and WCNOC, Concerning the Upcoming Safety Audit (ADAMS

Accession No. ML071240256)

May 22, 2007 Summary of Telephone Conference Call Held on March 20, 2007,

Between the NRC and WCNOC, Concerning Draft RAI Pertaining to

the. WCGS, Unit 1, LRA (ADAMS Accession No. ML071240269)

May 25, 2007 WCNOC Response to RAI Related to the WCGS LRA (ADAMS

Accession No. ML071500565)

June 1, 2007 WCNOC Response to RAI Related to the WCGS LRA (ADAMS

Accession No. ML071580194)

June 1, 2007• WCGS LRA Amendment 1 (ADAMS Accession No. ML071580237)

,June 7, 2007 WCNOC Time-Limited Aging Analysis Questions and Responses

Related to WCGS LRA(ADAMS Accession No. ML071!640384)

June 15, 2007 Summary, of Telephone Conference Call Held on June 8, 2007,

Between the NRC and WCNOC Concerning RAI Pertaining to the

•_ WCGS, Unit 1, LRA (ADAMS Accession No. ML071640024)

June 22, 2007 RAI For The Review of The WCGS, Unit 1, LRA (ADAMS Accession

No. ML071730352)

June 25, 2007 Summary of Telephone Conference Call Held On June 14, 2007,

Between the NRC and WCNOC, Concerning RAI Pertaining to the

WCGS, Unit 1, LRA (ADAMS Accession No. ML071690318)

June 25, 2007 Revision of Schedule for The Review of The WCGS, Unit 1, LRA

(ADAMS Accession No. ML071710372)

June 27, 2007 WCNOC Revision to WCGS LRA Commitment Due Date (ADAMS

Accession No. ML071840191)

June 27, 2007 Summary of Telephone Conference Call Held on May 15, 2007,

Between the NRC and WCNOC Concerning RAI Pertaining to the

WCGS, Unit 1, LRA (ADAMS Accession No. ML071730415)

B-4
APPENDIX ýB: CHRONOLOGY

Date Subject

June 28, 2007 Summary of Telephone Conference Call Held on June 21, 2007,

Between the NRC and WCNOC Concerning RAI Pertaining to the

WCGS, Unit 1, LRA (ADAMS Accession No. MLO71780545)

July 9, 2007 Summary of Telephone Conference Call Held on June 13, 2007

Between the NRC and WCNOC Concerning RAI Pertaining to the

WCGS, Unit 1, LRA (ADAMS Accession No. ML071780563)

July 11, 2007 WCNOC Followup Response to RAI Related to WCGS LRA (ADAMS

Accession No. ML071990100)

July 18, 2007 WCNOC Revision to the RAI Response Due Date for the WCGS LRA

(ADAMS Accession No. ML072050323)

July 24, 2007 RAI For The Review of The WCGS, Unit 1, LRA(ADAMS Accession

No. ML072000324)

July 26, 2007 Commitment Extension Related to the WCGS, Unit 1, LRA (ADAMS

Accession No. ML072000330)

July 26, 2007 WCNOC Followup Response to RAI Related to WCGS LRA (ADAMS

Accession No. ML072150232)

July 26, 2007 WCNOC Response to RAI Related to WCGS LRA (ADAMS Accession

No. ML072150241)

July 26, 2007 WCNOC Revision to the Aging Management Program, and

Time-Limited Aging Analysis Questions and Responses Related to

WCGS LRA (ADAMS Accession No. ML072180225)

August 8, 2007 WCNOC Followup Response to RAI Related to WCGS LRA (ADAMS

Accession No. ML072280073)

August 9, 2007 WCGS LRA Amendment 2 (ADAMS Accession No. ML072280068)

August 20, 2007 WCNOC Response to RAI Related to WCGS LRA (ADAMS Accession

No. ML072400403)

August 28, 2007 Summary of Telephone Conference Call Held on August 17, 2007,

Between the NRC and WCNOC, Concerning RAI Pertaining to the

WCGS, Unit 1, LRA (ADAMS Accession No. ML072320452)

August 31, 2007 WCGS LRA Amendment 3 (ADAMS Accession No. ML072490301)

September 4, 2007 Summary of Telephone Conference Call Held on August 17, and

August 31, 2007, Between the NRC and WCNOC, Concerning RAI

Pertaining to the WCGS, Unit 1, LRA (ADAMS Accession

No. ML072320487)

B-5
APPENDIX. B: CHRONOLOGY

Date Subject

September 19, 2007 Press Release IV-07-036: NRC to Hold Public Meetings on Draft

Environmental Impact Statement for WCGS LRA (ADAMS Accession

No. ML072620531)

September 26, 2007 Summary of Telephone Conference Call Held on September 26, 2007,

Between the NRC and WCNOC, Concerning Draft RAI Pertaining to

the.WCGS, Unit 1, LRA (ADAMS Accession No. ML072700054)

September 27, 2007 RAI for the Review of the WCGS, Unit 1, LRA (ADAMS Accession

No. ML072680037)

September 27, 2007 WCNOC Followup Response to RAI Related to WCGS LRA (ADAMS

Accession No. ML072770010)

September 27, 2007 WCGS LRA Annual Update Information (ADAMS Accession

No. ML072770009)

September 30, 2007 NUREG-1437, Supplement 32, Generic Environmental Impact

Statement for the License Renewal of Nuclear Plants: Regarding Wolf

Creek Generating Station, Draft for Comment. (ADAMS Accession

No. ML072540026)

October 3, 2007 WCNOC Followup Response to RAI Related to WCGS LRA (ADAMS

Accession No. ML072840051)

October 11, 2007 WCGS LRA Amendment 4 (ADAMS Accession No. ML072900637)

October 17, 2007 WCGS LRA Time-Limited Aging Analyses Supplemental Information

(ADAMS Accession No. ML072970530)

October 17, 2007 WCNOC Response to RAI and Supplement to the WCGS LRA

(ADAMS Accession No. ML072980026)

November 16, 2007 WCGS LRA Amendment 5 (ADAMS Accession No. ML073300457)

November 30, 2007 WCNOC Time-Limiting Aging Analysis Supplemental Information

WCGS LRA (ADAMS Accession No. ML073460041

December 5, 2007 Wolf Creek Generating Station - NRC License Renewal Inspection

Report 05000482/2007007 (ADAMS Accession No. ML073390687)

January 25, 2008 Wolf Creek - Followup Response to NRC Requests for Additional

Information Related to License Renewal Application Time-Limited

Aging Analysis (ADAMS Accession No. ML080350012)

February 14, 2008 Audit summary (ADAMS Accession No. ML073310013)

B-6
APPENDIX B:-CHRONOLOGY

Date Subject

February 28, 2008 Request for Additional Information for the Review of the Wolf Creek

Generating Station (WCGS), License Renewal Application (ADAMS

Accession No. ML080530067)

March 26, 2008 Revision to the Response Due Date for a Request for Additional

Information for Wolf Creek Generating Station License Renewal

Application Metal Fatigue Analysis (ADAMS Accession

No. ML080930156)

March 29, 2008 Wolf Creek - License Renewal Application, Amendment 6 (ADAMS

Accession No. ML081000123)

March 29, 2008 Wolf Creek, Response to Open Items Associated with the NRC Draft

Safety Evaluation for the Application for License Renewal (ADAMS

Accession No. ML081000124)

.March 31, 2008 Schedule for Completion of Wolf Creek License Renewal Review

(ADAMS Accession No. ML080840288)

April 1, 2008 Wolf Creek Generating Station - License Renewal Application Update

Provided in Accordance with 10 CFR 54.21 (b) (ADAMS Accession

No. ML081000122)

April 17,,2008 Wolf Creek- Correction to Summary of License Renewal Application,

Amendment 6 (ADAMS Accession No. ML081 150508)

May 15, 2008 Docket No. 50-482: Response to NRC Requests for Additional

Information Related to Wolf Creek Generating Station License

Renewal Application.- Closure of the Metal Fatigue Analysis Open

Items (ADAMS Accession No. ML081440051)

May 23, 2008 Docket No. 50-482: Correction to Response to NRC Requests for

Additional Information Related to Wolf Creek Generating Station

License Renewal Application - Closure of the Metal Fatigue Analysis

Open Items (ADAMS Accession No. ML081540472)

June 9, 2008ý Docket No. 50-482: Supplement to Response to NRC Requests

for Additional Information Related to Wolf Creek Generating

Station License Renewal Application - Closure of the Metal

Fatigue Analysis Open Items (ADAMS Accession No. ML081700279)

August 1, 2008 Docket No. 50-482: Documentation of Telephone Calls Associated

to the Wolf Creek Generating Station License Renewal Application

(ADAMS.Accession No. ML082200317)

September 17, 2008 Report on the Safety Aspects of the License Renewal Application for

the Wolf Creek Generating Station, Unit 1 (ADAMS Accession No.

ML082540142)

B-7

.APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this safety evaluation report

(SER) and their areas of responsibility.

APPENDIX C: PRINCIPAL.CONTRIBUtORS

Name Reponibility.

S. Arora GALL Report Audit

H. Ashar Structural Engineering

R. Auluck Management Oversight

T. Chan Management Oversight

K. Chang Management Oversight

G. Cranston Management Oversight

J. Davis GALL Report Audit

B. Dennig Management Oversight

J. Fair Mechanical Engineering

C. Fairbanks Materials Engineering

R. Franovich Management Oversight

G. Galletti Scoping and Screening Methodology Audit

Q. Gan GALL Report Audit

K. Green Scoping and Screening Methodology Audit

V. Goel Electrical Engineering

H. Hamzehee Management Oversight

D. Harrison Management Oversight

R. Hernandez Plant Systems

D. Hoang GALL Report Audit

R. Hsu TLAA Audit

N. lqbal Fire Protection

C-1
APPENDIX C: PRINCIPAL CONTRIBUTORSI.

Name Res ponsibillit'y

A. Klein Management Oversight

W. Koo Materials Engineering

P. T. Kuo Management Oversight

L. Lois Materials Engineering

L. Lund Management Oversight

K. Manoly Management Oversight

J. Medoff GALL Report Audit

S. Miranda System Engineering

M. Mitchell Management Oversight

D. Nguyen GALL Report Audit

D. Nold Containment System

D. Oudinot Fire Protection

J. Raval Ventilation System

S. Ray Electrical Engineering

D. Reddy Scoping and Screening Methodology Audit

V. Rodriguez Project Management

B. Rogers Scoping and Screening Methodology Audit

J. Segala Management Oversight

T. Tran Project Management

A. Tsirigotis GALL Report Audit

S. Weerakkody Management Oversight

P. Wen GALL Report Audit

G. Wilson Management Oversight

Z. Xi Structural Engineering

0. Yee GALL Report Audit

C-2
CONTRACTORS

APPENDIX C: PRINCIPAL CONTRIBUTORS

Advanced Technologies and Laboratories GALL Report Audit

International, Inc.

Information System Laboratories Plant Systems

Legin Group, Inc. SER Support

C-3
i
APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report (SER) for review

of the license renewal application (LRA) for Wolf Creek Generating Station (WCGS), Unit 1.

APPENDIX-D: REFERENCES

hem.. .. 7ji Reference

1 NUREG-1800, Revision 1, "Standard Review Plan for Review of License Renewal

Applications for :Nuclear Power Plants," September 2005.

2 NUREG-1801, Revision 1, "Generic Aging Lessons Learned (GALL) Report,"

September 2005.

3 NEI 95-10, Revision 6, "Industry Guideline for Implementing the Requirements of

10 CFR Part 54 - The License Renewal Rule," June 2005.

4 NUREG-0800, Revision 1, "Standard Review Plan for the Review of Safety Analysis

Report of Nuclear Power Plants," Section 3.6.2 Branch Technical Position 3-1,

July 1981.

5 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities."

6 10 CFR Part 52 "Early Site Permits; Standard Design Certifications; And Combined

Licenses For Nuclear Power Plants."

7 10 CFR Part 54, "Requirements for Renewal of Operating Licenses For Nuclear

Power Plants."

8 10 CFR Part 100, "Reactor Site Criteria."

9 NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves to

Selected Nuclear Power Plant Components."

10 NUREG-0881, "Safety Evaluation Report related to the Operation of Wolf Creek

Generating Station, Unit 1," April 1982.

11 NUREG/CR-57604 ."Effects of LWR Coolant Environments on Fatigue Design

Curves of Austenitic Stainless Steels."

12 NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design

Curves of Carbon and Low-Alloy Steels."

13 Institute of Electrical and Electronics Engineers (IEEE) 344-1975, "Recommended

Practices for Seismic Qualification of Class 1 E Equipment for Nuclear Power

Generating Stations."

D-1
* .- APPENDIX.D: REFERENCES

*Item. Reference

Number: (

14 N RC Generic Letter 89-13, "Service Water System Problems Affecting

Safety-Related Equipment," July 1989.

15 Wolf Creek Nuclear Operating Center Procedure QCP-20-31 8, "Visual Examination

of Heat Exchangers and Piping Components."

16 Electric Power Research Institute (EPRI) Report TR-1 07514.

17 EPRI Report TR-105714,

18 EPRI Report TR-102134,

19 EPRI NP-5769, Volume 2, Section 10,

20 NRC Information Notice 92-8, "Potential Deficiency of Electrical Cables With

Bonded Hyalon Jackets."

21 NRC Information Notice 98-21 "Potential Deficiency of Electrical Cable/Connection

Systems."

22 NRC Information Notice 99-10, "Degradation of Prestressing Tendon Systems in

Prestressed Concrete Containments."

23 NRC Order EA-03-009, "Issuance of Order Establishing Interim Inspection _Requirements for Reactor Pressure Vessel Heads at Pressurized Water Reactors."

24 Bechtel Topical Report BC-TOP-5A Revision 3,

25 Bechtel Topical Report BC-TOP- 1 Revision 1, "Containment Building Liner Plate

_ Design Report."

26 The Westinghouse Commercial Atomic Power (WCAP)-10691, "Technical Basis for

Eliminating Large Primary Loop Pipe Rupture as a Structural Design Basis for

Callaway and Wolf Creek Plants."

27 WCAP-1 6028, Revision 0, "Analysis of Capsule X from Wolf Creek Nuclear

Operating Corporation, Wolf Creek Reactor Vessel Radiation Surveillance

Program," March, 2003.

28 f WCAP-1 5666, "Extension of Reactor Coolant Pump Motor Flywheel Examination."

29 WCAP-12893, "Structural Evaluation of the Wolf Creek and Callaway Pressurizer

Surge Lines, Considering the effects of Thermal Stratification."

30 WCAP-1 4575-A, "Aging Management Evaluation for Class 1 Piping and Associated

Pressure Boundary Components."

31 WCAP-15666, "Extension of Reactor Coolant Pump Motor Flywheel Examination."

D-2
AP-PENDIX%.D: REFERENCES

Item Reference

,Number

32 NUREG-0588, "Interim Staff Position on Environmental Qualification of

Safety-Related Electrical Equipment."

33 NRC Bulletin No. 88-11, "Pressurizer Surge Line Thermal Stratification,"

December 20, 1988.

34 XX-E-013, "Post-Fire Safe Shutdown Analysis."

35 Regulatory Guide (RG) 1.89 Revision 1, "Environmental Qualification of Certain

Electric Equipment Important to Safety for Nuclear Power Plants."

36 RG 1.188 Revision 1, "Standard Format and Content for Applications to Renew

Nuclear Power Plant Operating Licenses."

37 RG 1.127 Revision 1, "Inspection of Water Control Structures Associated with

Nuclear Power Plants."

38 RG 1.190 Revision 0, "Calculational and Dosimetry Methods for Determining

Pressure Vessel Neutron Fluence."

39 RG 1.99 Revision 2, "Radiation Embrittlement of reactor Vessel Materials."

40 .American Society of Mechanical Engineers (ASME) "Boiler and Pressure Vessel

Code, Section III, Rules for Construction of Nuclear Power Plant Components"'

(ASME Code Section I11).

41 ASME Code Section Xl

42 Auxiliary and Power Conversion Systems Branch (APCSB) 9.5-1, "Guidelines for

Fire Protection for Nuclear Power Plants," May 1976.

43 Branch Technical Position (BTP) APCSB 9.5-1, Appendix A, August 23,1976.

44 BTP ASB 3-1, "Protection Against Postulated Piping Failures in Fluid Systems

Outside Containment."

45 Interim Staff Guidance (ISG)-5, "Identification and Treatment of Electrical Fuse

Holders for License Renewal."

46 "Staff Guidance on Scoping of Equipment Relied on to Meet the Requirements of

the Station Blackout Rule (10 CFR 50.63) for License Renewal

(10 CFR 54.4(a)(3))," Letter dated April 1, 2002. (ADAMS Accession

No. ML020920464)

47 Letter dated April 7, 2003. (ADAMS Accession No. ML030990052)

48 Proposed License Renewal Interim Staff Guidance LR-ISG-2007-02 (ADAMS

Accession No. ML0717703761)

D-3

NRC FORM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

(9-2004) (Assigned by NRC, Add Vol., Supp., Rev.,

NRCMD 3.7 and Addendum Numbers, if any.)

BIBLIOGRAPHIC DATA SHEET

(See instructions on the reverse) NUREG-1915

2. TITLE AND SUBTITLE 3. DATE REPORT PUBLISHED

Safety Evaluation Report Related to the License Renewal of Wolf Creek Generating Station, MONTH YEAR

Unit 1

October 2008

4. FIN OR GRANT NUMBER

5. AUTHOR(S) 6. TYPE OF REPORT

Tam Tran

7. PERIOD COVERED (Inclusive Dates)

10/04/2006 - 07/29/2008

8. PERFORMING ORGANIZATION - NAME AND ADDRESS (If NRC, provide Division, Office or Region, U.S. Nuclear Regulatory Commission, and mailing address; if contractor,

provide name and mailing address.)

Division of License Renewal

Office of Nuclear Reactor Regulation

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

9. SPONSORING ORGANIZATION - NAME AND ADDRESS (If NRC, type 'Same as above'; if contractor, provide NRC Division, Office or Region, U.S. Nuclear Regulatory Commission,

and mailing address.)

Same as above

10. SUPPLEMENTARY NOTES

T. Tran, Project Manager

11. ABSTRACT (200 words or less)

This safety evaluation report (SER) documents the technical review of the Wolf Creek Generating Station (WCGS), Unit 1,

license renewal application (LRA) by the United States (US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter

dated September 27, 2006, Wolf Creek Nuclear Operating Corporation (WCNOC or the applicant) submitted the LRA in

accordance with Title 10, Part54, of the Code of Federal Regulations, "Requirements for Renewal of Operating Licenses for

Nuclear Power Plants." WCNOC requests renewal of the WCGS operating license (Facility Operating License Number

NPF-42) for a period of 20 years beyond the current expiration at midnight March 11, 2025.

WCGS is located approximately 3.5 miles northeast of Burlington, Kansas. The NRC issued the construction permit for WCGS

on May 31,1977, and operating license on June 4, 1985. WCGS Unit 1 is of a PWR design. Westinghouse Electric

Corporation supplied the nuclear steam supply system and Daniel International originally designed and constructed the balance

of the plant with the assistance of its agent, Bechtel. The WCGS Unit 1 licensed power output is 3565 megawatt thermal with a

gross electrical output of approximately 1228 megawatt electric.

This SER presents the staff's review of information submitted through August 1, 2008, the cutoff date for consideration in the

SER, and the final conclusion on the LRA review.

12. KEY WORDS/DESCRI PTORS (List words or phrases that will assist researchers in locating the report.) 13. AVAILABILITY STATEMENT

10 CFR Part 54, license renewal, Wolf Creek Generating Station, scoping and screening, aging unlimited

management, time-limited aging analysis, safety evaluation report 14. SECURITY CLASSIFICATION

(This Page)

unclassified

(This Report)

unclassified

15. NUMBER OF PAGES

16. PRICE

NRC ORM33519-2041PRITEDON RCYCED APE 1 0 NRC FORM 335 (9-2004) PRINTED ON RECYCLED PAPER
FSuml R-oycling Progra

UNITED STATES

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

OFFICIAL BUSINESS