Safety Evaluation Report 

Related to the License Renewal of 

Kewaunee Power Station 

Docket No. 50-305 

Dominion Energy Kewaunee, Inc. 

Office of Nuclear Reactor Regulation 

NUREG-1958
Safety Evaluation Report 

Related to the License Renewal of 

Kewaunee Power Station 

Docket No. 50-305 

Dominion Energy Kewaunee, Inc. 

Manuscript Completed: January 2011 

Date Published: January 2011 

Office of Nuclear Reactor Regulation 

NUREG-1958 

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Kewaunee Power 

Station (KPS) license renewal application (LRA) by the U.S. Nuclear Regulatory Commission 

(NRC) staff (the staff). By letter dated August 12, 2008, Dominion Energy Kewaunee, Inc. 

(Dominion, DEK, 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.‖ Dominion requests renewal of the KPS operating license (Facility Operating 

License Number DPR-43) for a period of 20 years beyond the current expiration at midnight on 

December 21, 2013.

KPS is located in the Town of Carlton, Wisconsin, in the southeast corner of Kewaunee County, 

Wisconsin, on the western shore of Lake Michigan. The staff issued the original construction 

permit for KPS on August 6, 1968, and the operating license on December 21, 1973. The plant‘s 

nuclear steam supply system consists of a 2-loop pressurized water reactor with a dry, ambient 

containment (PWR-DRYAMB). The nuclear steam supply system was supplied by 

Westinghouse. The balance of the plant was originally designed and constructed by Pioneer 

Service and Engineer Company. KPS operates at a licensed power output of 

1,772 megawatt-thermal (MWt), with a gross electrical output of approximately 

590 megawatt-electric (MWe). 

Unless otherwise indicated, this SER presents the status of the staff‘s review of information 

submitted through October 20, 2010, the cutoff date for consideration in the SER. The four open 

items previously identified by the staff for the SER with open items have been closed (see SER 

Section 1.5); therefore, no open items remain to be resolved before the final determination is 

reached by the staff on the LRA.

v

TABLE OF CONTENTS

Abstract.................................................................................................................................. iii

Table of Contents ....................................................................................................................v

List of Tables......................................................................................................................... xii

Abbreviations and Acronyms ................................................................................................ xiii

Section 1 Introduction and General Discussion ................................................................. 1-1

1.1 Introduction.................................................................................................................. 1-1

1.2 License Renewal Background ..................................................................................... 1-2

1.2.1 Safety Review....................................................................................................... 1-3

1.2.2 Environmental Review .......................................................................................... 1-4

1.3 Principal Review Matters ............................................................................................. 1-5

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

1.5 Summary of Open Items.............................................................................................. 1-8

1.6 Summary of Confirmatory Items ................................................................................ 1-10

1.7 Summary of Proposed License Conditions ................................................................ 1-11

Section 2 Structures and Components Subject to Aging Management Review.................. 2-1

2.1 Scoping and Screening Methodology .......................................................................... 2-1

2.1.1 Introduction ........................................................................................................... 2-1

2.1.2 Summary of Technical Information in the Application ............................................ 2-1

2.1.3 Scoping and Screening Program Review.............................................................. 2-2

2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping 

and Screening .............................................................................................................. 2-3

2.1.3.2 Quality Controls Applied to LRA Development................................................ 2-6

2.1.3.3 Training .......................................................................................................... 2-6

2.1.3.4 Scoping and Screening Program Review Conclusion ..................................... 2-7

2.1.4 Plant Systems, Structures, and Components Scoping Methodology ..................... 2-7

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1)................................. 2-8

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

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)............................... 2-16

2.1.4.4 Plant-Level Scoping of Systems and Structures ........................................... 2-21

2.1.4.5 Mechanical Component Scoping .................................................................. 2-23

2.1.4.6 Structural Scoping ........................................................................................ 2-25

2.1.4.7 Electrical Component Scoping...................................................................... 2-26

2.1.4.8 Scoping Methodology Conclusion................................................................. 2-27

2.1.5 Screening Methodology ...................................................................................... 2-28

2.1.5.1 General Screening Methodology .................................................................. 2-28

2.1.5.2 Mechanical Component Screening ............................................................... 2-29

2.1.5.3 Structural Component Screening.................................................................. 2-31

2.1.5.4 Electrical Component Screening................................................................... 2-32

2.1.5.5 Screening Methodology Conclusion.............................................................. 2-33

2.1.6 Summary of Evaluation Findings......................................................................... 2-33

2.2 Plant-Level Scoping Results ...................................................................................... 2-34

2.2.1 Introduction ......................................................................................................... 2-34

2.2.2 Summary of Technical Information in the Application .......................................... 2-34
Table of Contents

vi

2.2.3 Staff Evaluation ................................................................................................... 2-34

2.2.4 Conclusion .......................................................................................................... 2-35

2.3 Scoping and Screening Results: Mechanical Systems ............................................... 2-35

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ..................................... 2-36

2.3.1.1 Reactor Vessel.............................................................................................. 2-37

2.3.1.2 Reactor Vessel Internals ............................................................................... 2-38

2.3.1.3 Reactor Coolant System ............................................................................... 2-39

2.3.1.4 Steam Generators......................................................................................... 2-41

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

2.3.2.1 Containment Vessel Internal Spray System .................................................. 2-42

2.3.2.2 Safety Injection System................................................................................. 2-45

2.3.2.3 Residual Heat Removal System.................................................................... 2-46

2.3.3 Auxiliary Systems ................................................................................................ 2-47

2.3.3.1 New Fuel Storage System............................................................................. 2-48

2.3.3.2 Spent Fuel Storage System .......................................................................... 2-49

2.3.3.3 Spent Fuel Pool Cooling System................................................................... 2-50

2.3.3.4 Fuel Handling System ................................................................................... 2-51

2.3.3.5 Cranes (Excluding Fuel Handling) System .................................................... 2-51

2.3.3.6 Service Water System................................................................................... 2-52

2.3.3.7 Component Cooling Water System ............................................................... 2-54

2.3.3.8 Station and Instrument Air System ................................................................ 2-56

2.3.3.9 Chemical and Volume Control System.......................................................... 2-58

2.3.3.10 Control Room Air Conditioning System ....................................................... 2-59

2.3.3.11 Auxiliary Building Air Conditioning System .................................................. 2-61

2.3.3.12 Auxiliary Building Special Ventilation and Steam Exclusion System............ 2-64

2.3.3.13 Auxiliary Building Ventilation System........................................................... 2-65

2.3.3.14 Reactor Building Ventilation System............................................................ 2-67

2.3.3.15 Turbine Building and Screenhouse Ventilation System ............................... 2-70

2.3.3.16 Shield Building Ventilation System .............................................................. 2-71

2.3.3.17 Technical Support Center Ventilation System ............................................. 2-72

2.3.3.18 Fire Protection System................................................................................ 2-74

2.3.3.19 Diesel Generator System ............................................................................ 2-85

2.3.3.20 Circulating Water System............................................................................ 2-86

2.3.3.21 Gaseous Waste Processing and Discharge System.................................... 2-87

2.3.3.22 Liquid Waste Processing and Discharge System ........................................ 2-88

2.3.3.23 Radiation Monitoring System....................................................................... 2-90

2.3.3.24 Makeup and Demineralizer System............................................................. 2-90

2.3.3.25 Service Water Pretreatment System ........................................................... 2-92

2.3.3.26 Miscellaneous Drains and Sumps System................................................... 2-93

2.3.3.27 Miscellaneous Gas System ......................................................................... 2-95

2.3.3.28 Potable Water System ................................................................................ 2-96

2.3.3.29 Primary Sampling System ........................................................................... 2-96

2.3.4 Steam and Power Conversion Systems............................................................... 2-97

2.3.4.1 Turbine System............................................................................................. 2-97

2.3.4.2 Main Steam and Steam Dump System.......................................................... 2-99

2.3.4.3 Bleed Steam System................................................................................... 2-100

2.3.4.4 Feedwater System ...................................................................................... 2-101

2.3.4.5 Condensate System.................................................................................... 2-101

2.3.4.6 Steam Generator Blowdown Treatment System.......................................... 2-103

2.3.4.7 Auxiliary Feedwater System........................................................................ 2-104

2.3.4.8 Air Removal System.................................................................................... 2-106
Table of Contents

vii

2.3.4.9 Heater and Moisture Separator Drains System........................................... 2-107

2.3.4.10 Heating Steam System ............................................................................. 2-108

2.3.4.11 Main Generator (Mechanical) and Auxiliaries System............................... 2-109

2.3.4.12 Secondary Sampling System.................................................................... 2-110

2.3.4.13 Turbine Oil Purification System................................................................. 2-110

2.3.4.14 Turbine Room Traps and Drains System .................................................. 2-111

2.4 Scoping and Screening Results: Structures............................................................. 2-111

2.4.1 Reactor Containment Vessel............................................................................. 2-112

2.4.1.1 Summary of Technical Information in the Application.................................. 2-112

2.4.1.2 Staff Evaluation .......................................................................................... 2-113

2.4.1.3 Conclusion.................................................................................................. 2-114

2.4.2 Structures and Component Supports ................................................................ 2-114

2.4.2.1 Shield Building............................................................................................ 2-114

2.4.2.2 Administration Building ............................................................................... 2-116

2.4.2.3 Auxiliary Building ........................................................................................ 2-117

2.4.2.4 Screenhouse Access Tunnel ...................................................................... 2-118

2.4.2.5 Technical Support Center ........................................................................... 2-119

2.4.2.6 Turbine Building.......................................................................................... 2-120

2.4.2.7 Yard Structures........................................................................................... 2-121

2.4.2.8 Discharge Structure.................................................................................... 2-123

2.4.2.9 Discharge Tunnel and Pipe......................................................................... 2-125

2.4.2.10 Intake Structure ........................................................................................ 2-125

2.4.2.11 Screenhouse ............................................................................................ 2-127

2.4.3 Component Supports ........................................................................................ 2-128

2.4.3.1 Summary of Technical Information in the Application.................................. 2-128

2.4.3.2 Conclusion.................................................................................................. 2-128

2.4.4 Miscellaneous Structural Commodities.............................................................. 2-128

2.4.4.1 Summary of Technical Information in the Application.................................. 2-128

2.4.4.2 Staff Evaluation .......................................................................................... 2-129

2.4.4.3 Conclusion.................................................................................................. 2-130

2.4.5 Nuclear Steam Supply System Structural Supports........................................... 2-130

2.4.5.1 Summary of Technical Information in the Application.................................. 2-130

2.4.5.2 Conclusion.................................................................................................. 2-131

2.5 Scoping and Screening Results: Electrical Systems/Commodity Groups................. 2-131

2.5.1 Electrical and Instrumentation and Controls Systems........................................ 2-132

2.5.1.1 Summary of Technical Information in the Application.................................. 2-132

2.5.1.2 Staff Evaluation .......................................................................................... 2-133

2.5.1.3 Conclusion.................................................................................................. 2-133

2.6 Conclusion for Scoping and Screening .................................................................... 2-134

Section 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 ............................................................................................. 3-4

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
Table of Contents

viii

3.0.3.1 AMPs That Are Consistent with the GALL Report ......................................... 3-10

3.0.3.2 AMPS That Are Consistent with the GALL Report with Exceptions 

or Enhancements........................................................................................................ 3-46

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

GALL Report............................................................................................................. 3-172

3.0.4 Quality Assurance Program Attributes Integral to Aging Management 

Programs.......................................................................................................... 3-180

3.0.4.1 Summary of Technical Information in the Application .................................. 3-180

3.0.4.2 Staff Evaluation........................................................................................... 3-180

3.0.4.3 Conclusion .................................................................................................. 3-181

3.1 Aging Management of Reactor Coolant System....................................................... 3-182

3.1.1 Summary of Technical Information in the Application ........................................ 3-182

3.1.2 Staff Evaluation ................................................................................................. 3-182

3.1.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-200

3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation is Recommended ........................................................................ 3-214

3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

GALL Report............................................................................................................. 3-233

3.1.3 Conclusion ........................................................................................................ 3-239

3.2 Aging Management of Engineered Safety Features ................................................. 3-240

3.2.1 Summary of Technical Information in the Application ........................................ 3-240

3.2.2 Staff Evaluation ................................................................................................. 3-240

3.2.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-250

3.2.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation Is Recommended........................................................................ 3-260

3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

GALL Report............................................................................................................. 3-269

3.2.3 Conclusion ........................................................................................................ 3-274

3.3 Aging Management of Auxiliary Systems ................................................................. 3-274

3.3.1 Summary of Technical Information in the Application ........................................ 3-275

3.3.2 Staff Evaluation ................................................................................................. 3-275

3.3.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-292

3.3.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation is Recommended ........................................................................ 3-303

3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

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

3.3.3 Conclusion ........................................................................................................ 3-370

3.4 Aging Management of Steam and Power Conversion Systems................................ 3-371

3.4.1 Summary of Technical Information in the Application ........................................ 3-371

3.4.2 Staff Evaluation ................................................................................................. 3-371

3.4.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-378

3.4.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation is Recommended ........................................................................ 3-385

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

GALL Report............................................................................................................. 3-397

3.4.3 Conclusion ........................................................................................................ 3-408

3.5 Aging Management of Containments, Structures, and Component Supports ........... 3-409

3.5.1 Summary of Technical Information in the Application ........................................ 3-409

3.5.2 Staff Evaluation ................................................................................................. 3-410

3.5.2.1 AMR Results That Are Consistent with the GALL Report ............................ 3-423
Table of Contents

ix

3.5.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation is Recommended........................................................................ 3-429

3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

GALL Report ............................................................................................................ 3-447

3.5.3 Conclusion ........................................................................................................ 3-457

3.6 Aging Management of Electrical Commodity Group................................................. 3-458

3.6.1 Summary of Technical Information in the Application........................................ 3-458

3.6.2 Staff Evaluation................................................................................................. 3-458

3.6.2.1 AMR Results That Are Consistent with the GALL Report............................ 3-461

3.6.2.2 AMR Results That Are Consistent with the GALL Report, for Which 

Further Evaluation is Recommended........................................................................ 3-462

3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed in the 

GALL Report ............................................................................................................ 3-467

3.6.3 Conclusion ........................................................................................................ 3-469

3.7 Conclusion for Aging Management Review Results................................................. 3-470

Section 4 Time-Limited Aging Analyses............................................................................. 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 ............................................................................................................ 4-4

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

4.2.1 Neutron Fluence ................................................................................................... 4-4

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

4.2.1.2 Staff Evaluation .............................................................................................. 4-5

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

4.2.1.4 Conclusion...................................................................................................... 4-7

4.2.2 Upper-Shelf Energy Evaluation ............................................................................. 4-7

4.2.2.1 Summary of Technical Information in the Application...................................... 4-7

4.2.2.2 Staff Evaluation .............................................................................................. 4-8

4.2.2.3 USAR Supplement.......................................................................................... 4-9

4.2.2.4 Conclusion...................................................................................................... 4-9

4.2.3 Pressurized Thermal Shock Limits for Reactor Vessel Materials Due to 

Neutron Embrittlement ......................................................................................... 4-9

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

4.2.3.2 Staff Evaluation ............................................................................................ 4-10

4.2.3.3 USAR Supplement........................................................................................ 4-11

4.2.3.4 Conclusion.................................................................................................... 4-11

4.2.4 Pressure-Temperature Limits.............................................................................. 4-12

4.2.4.1 Summary of Technical Information in the Application.................................... 4-12

4.2.4.2 Staff Evaluation ............................................................................................ 4-12

4.2.4.3 USAR Supplement........................................................................................ 4-13

4.2.4.4 Conclusion.................................................................................................... 4-13

4.3 Metal Fatigue............................................................................................................. 4-13

4.3.1 Fatigue of ASME Class 1 Components ............................................................... 4-14

4.3.1.1 Component Design Transient Cycles............................................................ 4-15

4.3.1.2 ASME Class 1 Vessels and Surge Line Piping ............................................. 4-17

4.3.1.3 Reactor Coolant Loop Piping ........................................................................ 4-19

4.3.1.4 Pressurizer Lower Head and Surge Line ...................................................... 4-20

4.3.1.5 Effects of Reactor Coolant Environment on Fatigue Life of ASME Code 

Class 1 Piping and Components................................................................................. 4-22
Table of Contents

x

4.3.2 Fatigue of Non-ASME Code Class 1 Components............................................... 4-29

4.3.2.1 Non-Class 1 Piping ....................................................................................... 4-29

4.3.2.2 Auxiliary Heat Exchangers ............................................................................ 4-31

4.4 Environmental Qualification of Electrical Equipment................................................... 4-32

4.4.1 Summary of Technical Information in the Application .......................................... 4-33

4.4.2 Staff Evaluation ................................................................................................... 4-33

4.4.3 USAR Supplement .............................................................................................. 4-33

4.4.4 Conclusion .......................................................................................................... 4-34

4.5 Concrete Containment Tendon Prestress .................................................................. 4-34

4.5.1 Summary of Technical Information in the Application .......................................... 4-34

4.5.2 Staff Evaluation ................................................................................................... 4-34

4.5.3 USAR Supplement .............................................................................................. 4-34

4.5.4 Conclusion .......................................................................................................... 4-34

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis .... 4-35

4.6.1 Reactor Containment Vessel Fatigue .................................................................. 4-35

4.6.1.1 Summary of Technical Information in the Application .................................... 4-35

4.6.1.2 Staff Evaluation............................................................................................. 4-35

4.6.1.3 USAR Supplement........................................................................................ 4-35

4.6.1.4 Conclusion .................................................................................................... 4-36

4.6.2 Containment Penetration Fatigue ........................................................................ 4-36

4.6.2.1 Summary of Technical Information in the Application .................................... 4-36

4.6.2.2 Staff Evaluation............................................................................................. 4-36

4.6.2.3 USAR Supplement........................................................................................ 4-36

4.6.2.4 Conclusion .................................................................................................... 4-36

4.7 Other Plant-Specific Time-Limited Aging Analyses..................................................... 4-37

4.7.1 Crane Load Cycle Limit ....................................................................................... 4-37

4.7.1.1 Summary of Technical Information in the Application .................................... 4-37

4.7.1.2 Staff Evaluation............................................................................................. 4-37

4.7.1.3 USAR Supplement........................................................................................ 4-38

4.7.1.4 Conclusion .................................................................................................... 4-38

4.7.2 Reactor Coolant Pump Flywheel ......................................................................... 4-38

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

4.7.2.2 Staff Evaluation............................................................................................. 4-38

4.7.2.3 USAR Supplement........................................................................................ 4-39

4.7.2.4 Conclusion .................................................................................................... 4-39

4.7.3 Leak-Before-Break .............................................................................................. 4-39

4.7.3.1 Summary of Technical Information in the Application .................................... 4-39

4.7.3.2 Staff Evaluation............................................................................................. 4-40

4.7.3.3 USAR Supplement........................................................................................ 4-47

4.7.3.4 Conclusion .................................................................................................... 4-47

4.7.4 Reactor Vessel Underclad Cracking .................................................................... 4-47

4.7.4.1 Summary of Technical Information in the Application .................................... 4-47

4.7.4.2 Staff Evaluation............................................................................................. 4-47

4.7.4.3 USAR Supplement........................................................................................ 4-48

4.7.4.4 Conclusion .................................................................................................... 4-49

4.7.5 Reactor Coolant Loop Piping Flaw Tolerance Evaluation .................................... 4-49

4.7.5.1 Summary of Technical Information in the Application .................................... 4-49

4.7.5.2 Staff Evaluation............................................................................................. 4-49

4.7.5.3 USAR Supplement........................................................................................ 4-52

4.7.5.4 Conclusion .................................................................................................... 4-53
Table of Contents

xi

4.8 Conclusion for Time-Limited Aging Analyses ............................................................. 4-53

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

Section 6 Conclusion......................................................................................................... 6-1

Appendix A Commitments for License Renewal of Kewaunee Power Station....................A-1

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

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

Appendix D References.....................................................................................................D-1
Table of Contents

xii

LIST OF TABLES

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

Table 3.0.3-1 KPS 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............................................................... 3-183

Table 3.2-1 Staff Evaluation for Engineered Safety Features System Components in the 

GALL Report ....................................................................................................................... 3-241

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report ........... 3-276

Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components in the 

GALL Report ....................................................................................................................... 3-372

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components in the 

GALL Report ....................................................................................................................... 3-411

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

GALL Report ....................................................................................................................... 3-459
xiii

ABBREVIATIONS AND ACRONYMS

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ACSR aluminum conductor steel reinforced

ACU air compressor unit

ADAMS Agencywide Document Access and Management System

AERM aging effect requiring management

AFW auxiliary feedwater

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

APCSB Auxiliary and Power Conversion Systems Branch

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATF administration training facility

ATP adenosine triphosphate

ATWS anticipated transient without scram

B&PV boiler and pressure vessel

B&W Babcock & Wilcox Co.

BMI bottom-mounted instrumentation

BTP branch technical position

BWR boiling water reactor

CASS cast austenitic stainless steel

CBF cycle-based fatigue

CFR Code of Federal Regulations

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CO2 carbon dioxide
Abbreviations and Acronyms

xiv

CRD control rod drive

CRDM control rod drive mechanism

CRPA control room post-accident

Cu copper

CUF cumulative usage factor

CVCS chemical and volume control system

DBA design-basis accident

DBD design-basis document

DBE design-basis event

DCI Division of Component Integrity

DEK Dominion Energy Kewaunee, Inc.

DO dissolved oxygen

EAF environmentally-assisted fatigue

ECCS emergency core cooling system

EDG emergency diesel generator

EFPY effective full-power year

EMPAC enterprise maintenance planning and control

EOCI Electric Overhead Crane Institute

EPRI Electric Power Research Institute

EQ environmental qualification

ER environmental report (applicant‘s environmental report operating 

license renewal stage)

ESF engineered safety features

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FR Federal Register

FRN Federal Register notice

FSAR final safety analysis report
Abbreviations and Acronyms

xv

ft-lb foot-pound

GALL Generic Aging Lessons Learned Report

GEIS generic environmental impact statement

GL generic letter

gm/cm2grams per square centimeter

GSI generic safety issue

HELB high-energy line break

HEPA high-efficiency particulate air

HPSI high-pressure safety injection

HVAC heating, ventilation, and air conditioning

I&C instrumentation and control

IA instrument air

IASCC irradiation-assisted stress-corrosion cracking

IEEE Institute of Electrical and Electronics Engineers

IGSCC intergranular stress-corrosion cracking

IN information notice

INPO Institute of Nuclear Power Operations

IPA integrated plant assessment

ISG interim staff guidance

ISI inservice inspection

KV or kV kilovolt

KPS Kewaunee Power Station

ksi kilopounds per square inch

LBB leak-before-break

LCO limiting condition for operation

LOCA loss of coolant accident
Abbreviations and Acronyms

xvi

LRA license renewal application

LTOP low-temperature overpressure protection

μm micrometer

M/C measured-to-calculated

MCM thousands of circular mils

MEA material, environment, and aging effect

MEB metal-enclosed bus

MeV million electron volts

MIC microbiologically-influenced corrosion

MPa megapascal

MWe megawatt-electric

MWt megawatt-thermal

n/cm2 neutrons per square centimeter

NACE National Association of Corrosion Engineers

NDE nondestructive examination

NEI Nuclear Energy Institute

NEPA National Environmental Policy Act

NESC National Electric Safety Code

NFPA National Fire Protection Association

Ni nickel

NPS nominal pipe size

NRC U.S. Nuclear Regulatory Commission

NRR Office of Nuclear Reactor Regulation

NSSS nuclear steam supply system

ODSCC outside-diameter stress-corrosion cracking

OE operating experience

OI open item

OTSG once-through steam generator
Abbreviations and Acronyms

xvii

P&ID piping and instrumentation diagram

PDI performance demonstration initiative

pH potential of hydrogen

ppb parts per billion

ppm parts per million

psi pounds per square inch

psig pounds per square inch gauge

P-T pressure-temperature

PTS pressurized thermal shock

PVC polyvinyl chloride

PWR pressurized water reactor

PWR-DRYAMB pressurized water reactor with a dry, ambient containment

PWSCC primary water stress-corrosion cracking

QA quality assurance

QAP quality assurance program

RAI request for additional information

RAT reserve auxiliary transformer

RCCA rod cluster control assembly

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RCV reactor containment vessel

RG regulatory guide

RHR residual heat removal

RIS regulatory issue summary

RPV reactor pressure vessel

RTNDT reference temperature nil ductility transition
Abbreviations and Acronyms

xviii

RTPTS reference temperature for pressurized thermal shock

RVI reactor vessel internal

RVID Reactor Vessel Integrity Database

RVLIS reactor vessel level instrumentation system

SAMA severe accident mitigation alternatives

SAW submerged arc welds

SBF stress-based fatigue

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SER safety evaluation report

SFP spent fuel pool

SG steam generator

SGBD steam generator blowdown

SGMP Steam Generator Management Program

SI safety injection

SOC statement of consideration

SOER significant operating experience report

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

for Nuclear Power Plants

SSC system, structure, and component

SW service water

TAT tertiary auxiliary transformer

TLAA time-limited aging analysis

TS technical specification

TSC technical support center

TT thermally treated
Abbreviations and Acronyms

xix

ULSD ultra-low-sulfur diesel

USAR updated safety analysis report

USAS United States of America Standards

USE upper-shelf energy

UT ultrasonic testing

UV ultraviolet

V volt

VT visual testing

W Westinghouse

WCP work control process

WOG Westinghouse Owner‘s Group

yr year

Zn zinc

1/4 T one-fourth of the way through the vessel wall measured from the 

internal surface of the vessel

1-1

SECTION 1 

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Kewaunee Power Station Unit 1 (KPS or Kewaunee), as filed by Dominion Energy Kewaunee, 

Inc. (Dominion, DEK, or the applicant). By letter dated August 12, 2008, Dominion submitted its 

application to the U.S. Nuclear Regulatory Commission (NRC) for renewal of the KPS operating 

license for an additional 20 years. The NRC staff (the staff) prepared this report, which 

summarizes the results of its safety review of the renewal application for compliance with the 

requirements of Title 10, Part 54, of the Code of Federal Regulations (10 CFR Part 54), 

―Requirements for Renewal of Operating Licenses for Nuclear Power Plants.‖ The NRC license 

renewal project manager for the KPS license renewal review is John Daily. Mr. Daily can be 

contacted by telephone at 301-415-3873 or by email at John.Daily@nrc.gov. Alternatively, 

written correspondence may be sent to:

U.S. Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Division of License Renewal

Washington, D.C. 20555-0001

Attention: John Daily, Mail Stop 0-11F1

In its August 12, 2008, submission letter, the applicant requested renewal of the operating 

license issued under Section 104b (Operating License No. DPR-43) of the Atomic Energy Act of 

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

midnight, December 21, 2013. KPS is located in the Town of Carlton, Wisconsin, in the 

southeast corner of Kewaunee County, Wisconsin, on the western shore of Lake Michigan. The 

staff issued the original construction permit for KPS on August 6, 1968, and the operating 

license on December 21, 1973. The plant‘s nuclear steam supply system consists of a 2-loop, 

Westinghouse (W) pressurized water reactor (PWR). The primary containment is of the dry 

ambient type. The balance of the plant was originally designed and constructed by Pioneer 

Service and Engineer Company. KPS operates at a licensed power output of 1,772 

megawatt-thermal (MWt), with a gross electrical output of approximately 590 megawatt-electric

(MWe). The updated safety analysis report (USAR) contains 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 KPS license renewal is based on the applicant‘s LRA and 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 October 20, 2010. The staff reviewed information received after this date 

depending on the stage of the safety review and the volume and complexity of the information. 

The public may view the LRA and all pertinent information and materials, including the USAR, at 
Introduction and General Discussion

1-2

the NRC Public Document Room located on the first floor of One White Flint North, 

11555 Rockville Pike, Rockville, Maryland 20852-2738 (301-415-4737 / 800-397-4209), and at 

the Kewaunee Public Library, 822 Juneau Street, Kewaunee, Wisconsin 54216. In addition, the 

public may find the LRA, as well as materials related to the license renewal review, on the NRC 

website 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 plant-specific supplement to 

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

Plants (GEIS).‖ This supplement discusses the environmental considerations for license 

renewal for KPS. The staff issued plant-specific GEIS Supplement 40, ―Generic Environmental 

Impact Statement for License Renewal of Nuclear Plants: Regarding Kewaunee Power Station,‖ 

on August 19, 2010.

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. These licenses can be renewed 

for up to 20 additional years. The original 40-year license term was selected on the basis of 

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

individual plant and equipment designs may have been engineered based on 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 staff to establish a comprehensive program plan for nuclear 

plant aging research. On the basis of the results of that research, a technical review group 

concluded that many aging phenomena are readily manageable and pose no technical issues 

that would preclude 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.
Introduction and General Discussion

1-3

In 1991, the staff published the license renewal rule in 10 CFR Part 54 (the Rule). The staff 

participated in an industry-sponsored demonstration program to apply the Rule to a pilot plant 

and to gain experience necessary to develop implementation guidance. To establish a scope of 

review for license renewal, the Rule defined age-related degradation unique to license renewal; 

however, during the demonstration program, the staff found that many aging mechanisms occur 

to plant systems and components with effects managed during the initial license period. In 

addition, the staff found that the scope of the review did not allow sufficient credit for existing 

programs, particularly the implementation of the Maintenance Rule, which also manages 

plant-aging phenomena.

As a result, the staff amended the Rule in 1995. As amended, 10 CFR Part 54 established a 

regulatory process that is simpler, more stable, and more predictable than the previous Rule. In 

particular, as amended, 10 CFR Part 54 focused on management of adverse aging effects 

rather than on identification of age-related degradation unique to license renewal. The staff 

initiated 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 revised Rule clarified and simplified the integrated plant assessment (IPA) 

process for consistency with the revised focus on passive, long-lived structures and 

components (SCs).

In parallel with these efforts, in a separate rulemaking effort, the staff amended 10 CFR Part 51 

to focus the scope of the review of environmental impacts of license renewal and fulfill the staff‘s 

responsibilities under the National Environmental Policy Act of 1969 (NEPA).

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 exception of 

the detrimental aging effects on the function 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 defines the scope of license renewal as 

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

functions, and (3) that are relied on to demonstrate compliance with NRC 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), an applicant for a renewed license must review all SSCs within 

the scope of the Rule to identify SCs subject to an aging management review (AMR). SCs 

subject to an AMR are those which perform an intended function without moving parts or without 

a change in configuration or properties (i.e., are ―passive‖), and are not subject to replacement 

based on a qualified life or specified time period (i.e., are ―long-lived‖). As required by 

10 CFR 54.21(a), an applicant for a renewed license must demonstrate that aging effects will be 

managed in such a way that the intended functions of those SSCs will be maintained, consistent 
Introduction and General Discussion

1-4

with the current licensing basis (CLB), for the period of extended operation; however, active 

equipment is considered adequately monitored and maintained by existing programs. In other 

words, detrimental aging effects that may affect active equipment are readily detectable and can 

be identified and corrected through routine surveillance, performance monitoring, and 

maintenance. Surveillance and maintenance programs for active 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), each LRA is required to include an USAR supplement that must 

have a summary description of the applicant‘s programs and activities for managing aging 

effects and the 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 are made about the length of time the plant can operate. These 

assumptions are incorporated into design calculations for several plant SSCs. In accordance 

with 10 CFR 54.21(c)(1), the applicant must 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 effects of aging on these SSCs can be adequately managed for 

the period of extended operation.

In 2001, the staff developed and issued 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 3, ―Industry Guideline for Implementing the 

Requirements of 10 CFR Part 54 - The License Renewal Rule,‖ issued in March 2001 by the 

NEI. NEI 95-10 details an acceptable method of implementing the Rule. The staff also used the 

SRP-LR to review this application.

In its LRA, the applicant stated that it utilized the overall outline and approach as described in 

NEI 95-10, Revision 6 (issued June 2005), along with NUREG-1800, ―Standard Review Plan for 

the Review of License Renewal Applications for Nuclear Power Plants,‖ and NUREG-1801, 

―Generic Aging Lessons Learned (GALL) Report,‖ as revised in September 2005. The GALL 

Report provides a summary of staff-approved aging management programs (AMPs) for the 

aging of many SCs subject to an AMR. If an applicant commits to implementing these 

staff-approved AMPs, the time, effort, and resources to review an applicant‘s LRA can be 

greatly reduced, thereby 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 SCs used throughout the industry. The 

report is also a reference for both applicants and staff reviewers to quickly identify AMPs and 

activities that can provide adequate aging management during the period of extended operation.

1.2.2 Environmental Review

In December 1996, the staff revised the environmental protection regulations to facilitate the 

environmental review for license renewal. The staff prepared a ―Generic Environmental Impact 

Statement (GEIS) for License Renewal of Nuclear Plants‖ (NUREG-1437, Revision 1) to 

document its evaluation of the possible environmental impacts associated with renewing 

licenses of nuclear power plants. For certain types of environmental impacts, the GEIS 

establishes generic findings applicable to all nuclear power plants. These generic findings are 

codified in Appendix B to Subpart A of 10 CFR 51. Pursuant to 10 CFR 51.53(c)(3)(i), an 
Introduction and General Discussion

1-5

applicant for license renewal may incorporate these generic findings in its environmental report. 

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

of environmental impacts that must be evaluated on a plant-specific basis (i.e., Category 2 

issues).

In accordance with NEPA and 10 CFR Part 51, the staff reviewed the plant-specific 

environmental impacts of license renewal, including any new and significant information not 

considered in the GEIS. As part of its scoping process, the staff held a public meeting on 

October 22, 2008, in the Town of Carlton, Wisconsin, to identify plant-specific environmental 

issues. The staff‘s draft plant-specific GEIS Supplement 40, issued in January of 2010, 

documents the results of the environmental review and includes a preliminary recommendation 

for license renewal action. Another public meeting was held on March 24, 2010, in the Town of 

Carlton, Wisconsin, to discuss the draft GEIS Supplement. After considering comments on the 

draft, the staff issued GEIS Supplement 40, ―Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants: Regarding Kewaunee Power Station,‖ on August 19, 2010.

1.3 Principal Review Matters

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 LRA include ―conforming changes to 

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

term of the proposed renewed license.‖ On this issue, the applicant stated the following in 

LRA Section 1.3.8:

...10 CFR 54.19(b) requires that license renewal applications include, 

―...conforming changes to the standard indemnity agreement, 10 CFR 140.92, 

Appendix B, to account for the expiration term of the proposed renewed license.‖ 

The current indemnity agreement for the unit does not contain a specific 

expiration term for the operating license. Therefore, conforming changes to 

account for the expiration term of the proposed renewed license are not 

necessary, unless the license number is changed upon issuance of the renewed 

license.

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 

the 10 CFR 54.19(b) requirements have been met.
Introduction and General Discussion

1-6

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

that the LRA contain four portions:

● an integrated plant assessment

● a description of any CLB changes during the staff‘s review of the LRA

● an evaluation of TLAAs

● a USAR supplement

LRA Sections 3 and 4 and Appendix B address the license renewal requirements 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 3 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. The applicant has submitted two annual updates, as 

follows:

● By letter dated July 27, 2009, the applicant submitted its first LRA update, which 

summarizes the CLB changes that occurred since submittal of the LRA through the 

update‘s issue date (Agencywide Document Access and Management System (ADAMS)

Accession No. ML092090314). This submission is in accordance with 10 CFR 54.21(b) 

requirements and states that no changes were identified for the KPS LRA.

● By letter dated August 9, 2010, the applicant submitted its second LRA update (ADAMS 

Accession No. ML1022901411), which summarizes the CLB changes that occurred 

since issuance of the first update. This submission is in accordance with 

10 CFR 54.21(b) requirements and states that one change was identified for the KPS

LRA, involving modifications made to the substation and switchyard as part of a plan to 

improve the reliability and maintainability of the offsite power supply and to increase grid 

reliability.

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 (TSs) 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 TS changes necessary for 

issuance of the renewed KPS 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 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.

In accordance with 10 CFR 54.25, ―Report of the Advisory Committee on Reactor Safeguards,‖ 

the ACRS will issue a report documenting its evaluation of the staff‘s LRA review and SER. SER 

Section 5 is reserved for the ACRS report when it is issued. SER Section 6 documents the 

findings required by 10 CFR 54.29.
Introduction and General Discussion

1-7

1.4 Interim Staff Guidance

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 the GALL 

Report.

Table 1.4-1 shows the current set of approved ISGs as well as the SER sections to which the 

ISG may apply. 

Table 1.4-1 Current Interim Staff Guidance

ISG Issue

(Approved ISG Number)

Purpose SER Section

Corrosion of drywell shell in Mark I 

containments

(LR-ISG-2006-01)

Addresses concerns related to 

corrosion of drywell shell in Mark I 

containments (for BWRs)

Not applicable for Kewaunee; 

Kewaunee is a PWR.

Preparing Severe Accident 

Mitigation Alternatives (SAMA) 

Analyses 

(LR-ISG-2006-03)

Staff Guidance for Preparing SAMA 

Analyses.

Not applicable to SERs; applies to 

supplemental environmental impact 

statements (SEIS).

License Renewal Interim Staff 

Guidance Process 

(LR-ISG-2007-01)

License Renewal Interim Staff 

Guidance Process, Revision 1.

This LR-ISG issues a revised 

process for guiding the development 

and implementation of LR–ISGs.

Not applicable for Kewaunee; this is 

administrative only.

Changes to the GALL Report 

AMP XI.E6

(LR-ISG-2007-02)

Provides interim guidance to one 

approach acceptable to the staff for 

managing effects of aging for certain 

electrical cable connections within 

the scope of the license renewal 

rule, but which are not subject to EQ

Section 3.0.3.1.6

Staff Guidance Regarding 

Plant-Specific AMR and AMP for 

Neutron-Absorbing Material in Spent 

Fuel Pools

(LR-ISG-2009-01)

Proposes to revise SRP-LR and 

NUREG-1801 to provide guidance to 

address potential loss of material 

and loss of neutron-absorbing 

capability in spent fuel pools during 

the period of extended operation. 

Also proposes an AMP that can 

address this issue. This LR-ISG 

does not apply to Boraflex

Section 3.3.2.2.6
Introduction and General Discussion

1-8

1.5 Summary of Open Items

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

October 20, 2010, the staff closed the four open items (OIs) previously identified in the ―Safety 

Evaluation Report With Open Items – Related to the License Renewal of Kewaunee Power 

Station‖ (ADAMS Accession No. ML101190345). The staff has identified no other open items. 

An item is considered open if, in the staff‘s judgment, it does not meet all applicable regulatory 

requirements at the time of the issuance of this SER. 

The summary of the closed OIs is as follows:

Open Item 3.0.3.2.20-1 (SER Sections 3.0.3.2.20 and 4.3 – Use of the Nonconforming 

Software FatigueProTM) 

The staff noted that the applicant‘s Metal Fatigue of Reactor Coolant Pressure Boundary

Program relies on nonconforming software, FatigueProTM, to perform fatigue usage calculations. 

LRA Section B3.2 states that its fatigue managing program utilizes all three modules of the 

Electric Power Research Institute (EPRI) software, FatigueProTM, to perform several fatigue 

monitoring-related calculations. However, the staff noted that in FatiguePro‘sTM stress-based 

fatigue (SBF) monitoring module, the application does not use all six components of a transient 

stress tensor to perform fatigue analysis in accordance with ASME Code Section III NB-3200. 

NRC Regulatory Issue Summary (RIS) 2008-30 recommends that the license renewal 

applicants that have used this simplified methodology to calculate fatigue usage perform 

confirmatory analyses to demonstrate that the simplified analyses provide acceptable results.

By letter dated July 13, 2009, the staff issued RAI B3.2-2 requesting that the applicant: (a) make 

appropriate adjustments and corrections regarding the use of the ―stress-based monitoring‖ and 

―SBF‖ terminologies, and reliance on the SBF monitoring methodology for fatigue usage 

calculations; and (b) re-evaluate the cumulative usage factor (CUF), in accordance with the 

guidelines described in ASME Code Section III NB-3200 guidance, for those components 

whose CUFs were calculated using the FatigueProTM SBF monitoring methodology. 

In its response dated August 17, 2009, the applicant stated that the reanalysis of locations 

subject to evaluation of the environmental effects on fatigue usage in accordance with 

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components,‖ that were initially evaluated using SBF monitoring methods, is 

currently in progress. The applicant further stated that the response to RAI B3.2-2 will be 

provided following completion of the reanalysis.

This item impacts SER Sections 3.0.3.2.20, ―Metal Fatigue of Reactor Coolant Pressure 

Boundary‖; 4.3.1.4, ―Pressurizer Lower Head and Surge Line [TLAA]‖; and 4.3.1.5, ―Effects of 

Reactor Coolant Environment on Fatigue Life of ASME Code Class 1 Piping and Components 

[TLAA].‖

The staff identified this as Open Item 3.0.3.2.20-1. 

The staff‘s evaluation and closure of Open Item 3.0.3.2.20-1 is documented in LRA 

Section 3.0.3.2.20.
Introduction and General Discussion

1-9

Open Item B2.1.32-1 (SER Section 3.0.3.2.19 – Work Control Process Program)

In a letter dated September 25, 2009, the applicant changed the Work Control Process (WCP) 

Program from a plant-specific program to a new AMP that, when enhanced, will be consistent 

with the program elements recommended in GALL AMP XI.M32, ―One-Time Inspection,‖ and 

GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,‖ under defined circumstances. During its review of the WCP Program, the staff 

identified several issues with the submittal and issued RAI B2.1.32-5:

● The staff noted that the applicant credited a methodology in EPRI TR-107514 as the 

basis for selecting sample sizes for component-material-effect combinations that will be 

managed, yet did not fully specify minimum percentage(s) of various populations being

used to establish the sample sizes for the one-time examinations, nor when the one-time 

inspections for the WCP would be completed. 

● The staff noted that the applicant‘s basis does not establish minimum sample size(s) that 

will be used for the material-environment-aging effect populations being managed on a 

periodic basis, nor minimum inspection frequencies.

● The staff noted that, in regard to operating experience (OE) examples that were 

provided, the OE discussions create uncertainties on whether the implementation of the 

WCP will be capable of detecting the aging effects for which it is credited, prior to a loss 

of component intended function.

● The staff could not determine the precise nature of Commitment No. 25: whether it 

reflects a simple need for implementing the WCP during the period of extended 

operation without any enhancements, or that it reflects that certain criteria of the WCP 

need to be enhanced to make them consistent with the GALL Report.

The staff identified this as Open Item B2.1.32-1. 

The staff‘s evaluation and closure of RAI B2.1.32-5 and Open Item B2.1.32-1 are documented 

in LRA Section 3.0.3.2.19.

Open Item 3.1.2.1.7-1 (Nickel-Alloy Steam Generator Divider Plate Cracking Due to Primary 

Water Stress-Corrosion Cracking)

LRA Table 3.1.1, item 3.1.1-81 addresses cracking due to primary water stress-corrosion 

cracking (PWSCC) for nickel alloy or nickel-alloy clad steam generator divider plate exposed to 

reactor coolant. The staff noted that, from recent foreign OE in steam generators with a similar 

design to that of the applicant, extensive cracking due to PWSCC has been identified in steam 

generator divider plates, even with proper primary water chemistry; specifically, cracks have 

been detected in the stub runner, very close to the tubesheet/stub runner weld and with depths 

of almost a third of the divider plate thickness. Therefore, the staff noted that the Primary Water 

Chemistry Program alone may not be effective in managing aging effects of cracking due to 

PWSCC in the steam generator divider plate. 

By letter dated March 11, 2010, the staff issued RAI 3.1.2.2.13-1 requesting that the applicant: 

(1) discuss the materials of construction of the steam generator divider plate assembly; and 

(2) if these materials are susceptible to cracking (e.g., Alloy 600 or the associated Alloy 600 
Introduction and General Discussion

1-10

weld materials), discuss the potential that cracking in the divider plate might propagate into 

other components (e.g., tubesheet cladding). Finally, the staff requested that if propagation into 

these other components cannot be ruled out, the applicant should describe an inspection 

program for ensuring that there are no cracks propagating into other items that could challenge 

the integrity of those other items.

The staff identified this as Open Item 3.1.2.1.7-1. 

The staff‘s evaluation and closure of RAI 3.1.2.2.13-1 and Open Item 3.1.2.1.7-1 are 

documented in LRA Section 3.1.2.1.7.

Open Item 3.0.3.2.4-1 (RAI concerning recent OE for buried and underground piping and tanks)

The staff has noted a number of recent industry events involving radioactive fluid leakage from 

buried and underground piping and tanks. In light of this recent industry OE, the staff is 

concerned about the continued susceptibility to failure of buried and/or underground piping that 

are within the scope of 10 CFR 54.4 and subject to aging management for license renewal. In 

reviewing the applicant‘s Buried Piping and Tanks Inspection and the External Surfaces 

Monitoring programs along with the applicable AMR items associated with them, the staff is not 

clear whether: (1) the components addressed by these AMPs clearly include both buried and 

underground piping (piping which is below grade and contained in a vault or other structure 

where it is exposed to air and where access is limited), and (2) whether such programs are 

being updated to incorporate lessons learned from these recent events as well as any OE from 

the applicant‘s own history.

In a letter dated May 27, 2010, the staff issued RAI B2.1.7-3 and requested that the applicant 

address these issues.

The staff identified this as Open Item 3.0.3.2.4-1.

The staff‘s evaluation and closure of RAI B2.1.7-3 and Open Item 3.0.3.2.4-1 are documented in 

LRA Section 3.0.3.2.4.

1.6 Summary of Confirmatory Items

An item is considered confirmatory if the staff and the applicant have reached a satisfactory 

resolution, but the applicant has not yet formally submitted the resolution. The staff assigns a 

unique identifying number to each confirmatory item. The staff has identified no confirmatory 

items for this SER.
Introduction and General Discussion

1-11

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 the applicant to complete the commitments in the 

USAR supplement in accordance with Appendix A of this SER, and to notify the staff in

writing when implementation of those activities required prior to the period of extended 

operation are complete and can be verified by NRC inspection. 

● The third license condition requires: (1) adherence to requirements of American Society 

of Testing and Materials (ASTM) E 185-82 for all capsules in the reactor vessel that are 

removed and tested, (2) that changes to capsule withdrawal schedules or to storage 

requirements must receive prior approval of the staff, and (3) that all capsules placed in 

storage must be maintained for future insertion.

2-1

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 54.21) requires an integrated plant assessment (IPA) for each license 

renewal application (LRA). The IPA must list and identify all of the structures, systems, and 

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

(SCs) subject to an aging management review (AMR) in accordance with 10 CFR 54.4. 

LRA Section 2.1, ―Scoping and Screening Methodology,‖ describes the scoping and screening 

methodology used to identify the SSCs at the Kewaunee Power Station (KPS) within the scope 

of license renewal and the SCs subject to an AMR. The staff reviewed the scoping and 

screening methodology of Dominion Energy Kewaunee, Inc. (Dominion, DEK, or the applicant) 

to determine whether or not it meets the scoping requirements of 10 CFR 54.4(a) and the 

screening requirements of 10 CFR 54.21.

In developing its scoping and screening methodology for the LRA, the applicant stated the 

following in Section 2.1.1:

Scoping and screening were performed consistent with the guidelines presented 

in NEI [Nuclear Energy Institute] 95-10, with the following clarifications:

● Scoping was performed at the system/structure level. Screening was 

performed on a component level basis and the scoping results (intended 

functions, applicable scoping criteria, etc.) were then reviewed and 

revised as required to be consistent with the screening results.

● The screening process identified in-scope passive components. The 

short-lived passive components that could be excluded from an AMR on 

the basis of a qualified life or a specified replacement time period were 

identified and removed from any further aging evaluation consideration.

2.1.2 Summary of Technical Information in the Application

In LRA Sections 2 and 3, the applicant provided the technical information required by 

10 CFR 54.4, ―Scope,‖ and 10 CFR 54.21(a). Throughout this safety evaluation report (SER), 

sections are provided entitled ―Summary of Technical Information in the Application,‖ which 

contain summaries of information provided by the applicant in the LRA.

In LRA Section 2.1, the applicant described the process used to identify the SSCs that meet the 

license renewal scoping criteria under 10 CFR 54.4(a), and the process used to identify the SCs 
Structures and Components Subject to Aging Management Review

2-2

that are subject to an AMR, as required by 10 CFR 54.21(a)(1). The applicant provided the 

results of the process used for identifying the SCs subject to an AMR in the following LRA 

sections:

 (a) LRA Section 2.2, ―Plant Level Scoping Results‖

 (b) LRA Section 2.3, ―Scoping and Screening Results: Mechanical Systems‖

 (c) LRA Section 2.4, ―Scoping and Screening Results: Structures‖ 

 (d) LRA Section 2.5, ―Scoping and Screening Results: Electrical and Instrumentation and 

Controls Systems‖

In LRA Section 3.0, ―Aging Management Review Results,‖ the applicant described its aging 

management results as follows:

 (a) LRA Section 3.1, ―Aging Management of Reactor Vessel, Internals, and Reactor Coolant 

System‖ 

 (b) LRA Section 3.2, ―Aging Management of Engineered Safety Features Systems‖ 

 (c) LRA Section 3.3, ―Aging Management of Auxiliary Systems‖ 

 (d) LRA Section 3.4, ―Aging Management of Steam and Power Conversion System‖ 

 (e) LRA Section 3.5, ―Aging Management of Containment, Structures, and Component 

Supports‖

 (f) LRA Section 3.6, ―Aging Management of Electrical and Instrumentation and Controls‖ 

LRA Section 4.0, ―Time-Limited Aging Analyses,‖ contains the applicant‘s identification and 

evaluation of time-limited aging analyses (TLAAs).

2.1.3 Scoping and Screening Program Review

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

guidance contained in NUREG-1800, Revision 1, ―Standard Review Plan for Review of License 

Renewal Applications for Nuclear Power Plants‖ (SRP-LR), Section 2.1, ―Scoping and 

Screening Methodology.‖ The following regulations form the basis for the acceptance criteria for 

the scoping and screening methodology review:

● 10 CFR 54.4(a), as it relates to the identification of plant SSCs within the scope of the 

Rule

● 10 CFR 54.4(b), as it relates to the identification of the intended functions of SSCs within 

the scope of the Rule

● 10 CFR 54.21(a)(1) and (a)(2), as they relate to the methods used by the applicant to 

identify plant SCs subject to an AMR
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As part of the review of the applicant‘s scoping and screening methodology, the staff reviewed 

the activities described in the following sections of the LRA using the guidance contained in the 

SRP-LR:

● Section 2.1, to ensure that the applicant described a process for identifying SSCs that 

are within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a)

● Section 2.1, to ensure that the applicant described a process for determining the SCs 

that are subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1) 

and (a)(2)

In addition, the staff conducted a scoping and screening methodology audit at KPS, located in 

the Town of Carlton, Wisconsin, during the week of March 10–13, 2009. The audit focused on 

ensuring that the applicant had developed and implemented adequate guidance to conduct the 

scoping and screening of SSCs in accordance with the methodologies described in the LRA and 

the requirements of the Rule. The staff reviewed implementation of the project-level guidelines 

and reports describing the applicant‘s scoping and screening methodology. The staff conducted 

detailed discussions with the applicant on the implementation and control of the license renewal 

program and reviewed the administrative control documentation used by the applicant during 

the scoping and screening process, the quality practices used by the applicant to develop the 

LRA, and the training and qualification of the LRA development team. 

The staff evaluated the quality attributes of the applicant‘s aging management program (AMP) 

activities described in LRA Appendix A, ―USAR Supplement,‖ and LRA Appendix B, ―Aging 

Management Programs.‖ On a sampling basis, the staff performed a system review of the 

auxiliary feedwater, safety injection, spent fuel pool cooling, and the turbine building, including a 

review of the scoping and screening results reports and supporting design documentation used 

to develop the reports. The purpose of the staff‘s review was to ensure that the applicant had 

appropriately implemented the methodology outlined in the administrative controls and to verify 

that the results are consistent with the current licensing basis (CLB) documentation. 

2.1.3.1 Implementing Procedures and Documentation Sources Used for Scoping and 

Screening

The staff reviewed the applicant‘s scoping and screening implementing procedures as 

documented in the scoping and screening methodology audit trip report, dated July 13, 2009 

(Agencywide Document Access and Management System (ADAMS) Accession No. 

ML091900081), to verify that the process used to identify SCs subject to an AMR was 

consistent with the SRP-LR. Additionally, the staff reviewed the scope of CLB documentation 

sources and the process used by the applicant to ensure that the applicant‘s commitments, as 

documented in the CLB and relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21, 

were appropriately considered and that the applicant adequately implemented its procedural 

guidance during the scoping and screening process.
Structures and Components Subject to Aging Management Review

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2.1.3.1.1 Summary of Technical Information in the Application

In LRA Section 2.1, the applicant addressed the following information sources for the license 

renewal scoping and screening process:

● updated safety analysis report (USAR)

● maintenance rule program documentation 

● enterprise maintenance planning and control (EMPAC) equipment database

● system descriptions

● design-basis documents (DBDs)

● 10 CFR 54.4(a)(2) report

● 10 CFR 54.4(a)(3) reports

● drawings

● project design manual

● design change documentation

● technical reports

● engineering correspondence

2.1.3.1.2 Staff Evaluation

Scoping and Screening Implementing Procedures. The staff reviewed the applicant‘s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents, and reports, as documented in the audit report, to ensure the guidance is consistent 

with the requirements of the Rule, the SRP-LR, and NEI 95-10. The staff finds that the overall 

process used to implement the 10 CFR Part 54 requirements described in the implementing 

procedures and AMRs is consistent with the Rule, the SRP-LR, and industry guidance.

The applicant‘s implementing procedures contain guidance for determining plant SSCs within 

the scope of the Rule, and for determining which SCs within the scope of license renewal are 

subject to an AMR. During the review of the implementing procedures, the staff focused on the 

consistency of the detailed procedural guidance with information in the LRA, including the 

implementation of U.S. Nuclear Regulatory Commission (NRC) staff positions documented in 

the SRP-LR, and the information in the applicant‘s responses, dated May 28, 2009, to the staff‘s 

requests for additional information (RAIs) dated April 30, 2009.

After reviewing the LRA and supporting documentation, the staff determined that the scoping 

and screening methodology instructions are consistent with the methodology description 

provided in LRA Section 2.1. The applicant‘s methodology is sufficiently detailed to provide 

concise guidance on the scoping and screening implementation process to be followed during 

the LRA activities.

Sources of CLB Information. The staff reviewed the scope and depth of the applicant‘s CLB 

review to verify that the methodology is sufficiently comprehensive to identify SSCs within the 

scope of license renewal, as well as SCs requiring an AMR. Pursuant to 10 CFR 54.3(a), the 

CLB is the set of NRC requirements applicable to a specific plant and a licensee‘s written 

commitments for ensuring compliance with, and operation within, applicable NRC requirements 

and the plant-specific design bases that are docketed and in effect. The CLB includes 

applicable NRC regulations, orders, license conditions, exemptions, technical specifications, 

and design-basis information (documented in the most recent USAR). The CLB also includes 

licensee commitments remaining in effect that were made in docketed licensing 
Structures and Components Subject to Aging Management Review

2-5

correspondence, such as licensee responses to NRC bulletins, generic letters, and enforcement 

actions, and licensee commitments documented in NRC safety evaluations or licensee event 

reports.

During the audit, the staff reviewed pertinent information sources used by the applicant 

including the USAR, DBDs, maintenance rule information, and license renewal drawings. In 

addition, the applicant‘s license renewal process identified additional sources of plant 

information pertinent to the scoping and screening process, including the EMPAC equipment 

database, system descriptions, the 10 CFR 54.4(a)(2) report, 10 CFR 54.4(a)(3) reports, plant 

drawings, project design manual, design change documentation, technical reports, and 

engineering correspondence. The staff confirmed that the applicant‘s detailed license renewal 

program guidelines specified the use of the CLB source information in developing scoping 

evaluations. 

The EMPAC equipment database, USAR, and DBDs were the applicant‘s primary repository for 

system identification and component safety classification information. During the audit, the staff 

reviewed the applicant‘s administrative controls for the EMPAC equipment database, DBDs, 

and other information sources used to verify system information. These controls are described 

and implementation is governed by plant administrative procedures. Based on a review of the 

administrative controls, and a sample of the system classification information contained in the 

applicable KPS documentation, the staff concludes that the applicant has established adequate 

measures to control the integrity and reliability of KPS system identification and safety 

classification data and, therefore, the staff concludes that the information sources used by KPS 

during the scoping and screening process provided a sufficiently controlled source of system 

and component data to support scoping and screening evaluations.

During the staff‘s review of the applicant‘s CLB evaluation process, the applicant explained the 

incorporation of updates to the CLB and the process used to ensure those updates are 

adequately incorporated into the license renewal process. The staff determined that LRA 

Section 2.1 provided 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. 

In addition, the staff reviewed the implementing procedures and results reports used to support 

identification of SSCs that the applicant relied on to demonstrate compliance with the 

safety-related criteria, nonsafety-related criteria, and the regulated events criteria pursuant to 

10 CFR 54.4(a). The applicant‘s license renewal program guidelines provided a listing of 

documents used to support scoping and screening evaluations. The staff finds these design 

documentation sources to be useful for ensuring that the initial scope of SSCs identified by the 

applicant was consistent with the plant‘s CLB.

2.1.3.1.3 Conclusion

Based on its review of LRA Section 2.1, the detailed scoping and screening implementing 

procedures, and the results from the scoping and screening audit, the staff concludes that the 

applicant‘s scoping and screening methodology considers CLB information in a manner 

consistent with the Rule, the SRP-LR, and NEI 95-10 guidance and, therefore, is acceptable.
Structures and Components Subject to Aging Management Review

2-6

2.1.3.2 Quality Controls Applied to LRA Development

2.1.3.2.1 Staff Evaluation

The staff reviewed the quality assurance controls used by the applicant to ensure that scoping 

and screening methodologies used in the LRA were adequately implemented. The applicant 

applied the following quality assurance processes during the LRA development:

● The applicant developed written plans and procedures to direct implementation of the 

scoping and screening methodology, control LRA development, and describe training 

requirements and documentation.

● The applicant considered pertinent issues in previous LRAs and corresponding RAIs to 

determine the applicability to the KPS LRA.

● The LRA was reviewed by industry peers, Dominion Power internal assessment teams, 

and the site facility safety review committee prior to submittal to the NRC.

● The applicant addressed comments received through the assessment process and 

managed them through peer and management review.

● The applicant maintains a document modification request database which tracks 

requests and changes made to license renewal documents and drawings. Proposed 

changes were reviewed by a minimum of three personnel prior to the change being 

made.

The staff reviewed the applicant‘s written procedures and documentation of assessment 

activities and determined that the applicant had developed adequate procedures to control the 

LRA development and assess the results of the activities.

2.1.3.2.2 Conclusion

On the basis of its review of pertinent LRA development guidance, discussion with the 

applicant‘s license renewal staff, and a review of the applicant‘s documentation of the activities 

performed to assess the quality of the LRA, the staff concludes that the applicant‘s quality 

assurance activities meet current regulatory requirements and provide assurance that LRA 

development activities were performed in accordance with the applicant‘s license renewal 

program requirements.

2.1.3.3 Training

2.1.3.3.1 Staff Evaluation

The staff reviewed the applicant‘s training process to ensure the guidelines and methodology for 

the scoping and screening activities were applied in a consistent and appropriate manner. As 

outlined in the implementing procedures, the applicant requires training for all personnel 

participating in the development of the LRA and uses only trained and qualified personnel to 

prepare the scoping and screening implementing procedures. 
Structures and Components Subject to Aging Management Review

2-7

The training included the following activities:

● Required training and documentation for personnel participating in the LRA development 

was outlined in the applicant‘s license renewal project guideline. 

● Training materials included the applicant‘s project guidelines; pertinent industry 

documents; 10 CFR Part 54 and its statement of considerations; NEI 95-10; Regulatory 

Guide (RG) 1.188; SRP-LR; and NUREG-1801, ―Generic Aging Lessons Learned 

(GALL) Report.‖ 

● License renewal staff was required to attend an orientation session on license renewal.

● Applicant personnel were required to complete and actively participate in industry 

operating experience (OE) training while participating in LRA related activities for KPS.

● Qualification and training records and a checklist served as documentation for each 

individual‘s completed license renewal training.

The staff reviewed the applicant‘s written procedures and, on a sampling basis, reviewed 

completed qualification and training records and completed checklists for some of the 

applicant‘s license renewal personnel. The staff determined that the applicant had developed 

and implemented adequate procedures to control the training of personnel performing LRA 

activities.

2.1.3.3.2 Conclusion

On the basis of discussions with the applicant‘s license renewal project personnel responsible 

for the scoping and screening process and its review of selected documentation in support of 

the process, the staff concludes that the applicant‘s personnel are adequately trained to 

implement the scoping and screening methodology described in the applicant‘s implementing 

procedures and the LRA.

2.1.3.4 Scoping and Screening Program Review Conclusion

On the basis of a review of information provided in LRA Section 2.1, a review of the applicant‘s 

detailed scoping and screening implementing procedures, discussions with the applicant‘s 

license renewal personnel, and the results from the scoping and screening methodology audit, 

the staff concludes that the applicant‘s scoping and screening program is consistent with the 

SRP-LR and the requirements of 10 CFR Part 54 and, therefore, is acceptable.

2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1 described the applicant‘s methodology used to scope SSCs pursuant to the 

requirements of the 10 CFR 54.4(a) criteria. The LRA states that the scoping process 

categorized the entire plant in terms of SSCs and commodity groups with respect to license 

renewal. According to the LRA, SSC and commodity group functions were identified and 

evaluated against criteria provided in 10 CFR 54.4(a)(1), (2), and (3) to determine whether or 

not the item should be considered within the scope of license renewal. The applicant asserted

that the scoping process identified SSCs that: (1) are safety-related and perform or support an 
Structures and Components Subject to Aging Management Review

2-8

intended function for responding to a design-basis event (DBE); (2) are nonsafety-related but 

their failure could prevent accomplishment of a safety-related function; or (3) support a specific 

requirement for one of the five regulated events applicable to license renewal. LRA 

Section 2.1.1, ―Introduction,‖ states that the scoping methodology used by KPS is consistent 

with the guidance by the industry in NEI 95-10.

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, ―10 CFR 54.4(a)(1) – Safety-Related,‖ states:

10 CFR 54.4(a)(1) requires that plant SSCs within the scope of license renewal 

include safety-related SSCs, which are those relied upon to remain functional 

during and following design-basis events (as defined in 10 CFR 50.49 (b)(1)) to 

ensure the following functions:

 (i) The integrity of the reactor coolant pressure boundary; 

 (ii) The capability to shut down the reactor and maintain it in a safe shutdown 

condition; or 

 (iii) The capability to prevent or mitigate the consequences of accidents which 

could result in potential off-site exposures comparable to those referred to 

in 10 CFR 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11, as 

applicable.

Safety-related components at Kewaunee are designated QA [quality assurance] 

Type 1. The mechanical and electrical components classified as QA Type 1 on 

the station drawings and/or in the Asset Management module of the EMPAC 

equipment database were included in the scope of license renewal under 

10 CFR 54.4(a)(1). The structures (or portions of structures) identified as Nuclear 

Safety Design Class I in the USAR Appendix B, Table B2.1 were also included 

within the scope of license renewal under 10 CFR 54.4(a)(1). However, because

of the vintage of the plant, it was recognized that nonsafety-related SSCs had 

been credited for mitigating design-basis events that were not required to be 

considered in the original plant design basis. Therefore, to ensure the scoping 

criteria of 10 CFR54.4(a) were met, these nonsafety-related components were 

included in-scope under 10 CFR 54.4(a)(2) or (a)(3) as appropriate.

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 DBE to ensure the following functions: (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 capability to prevent or mitigate the 

consequences of accidents that could result in potential offsite exposures comparable to those 

referred to in 10 CFR Parts 50.34(a)(1), 50.67(b)(2), or 100.11. 
Structures and Components Subject to Aging Management Review

2-9

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 [HELB]. 

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, the applicant stated that it evaluated the types of events listed in NEI 95-10 

(i.e., anticipated operational occurrences, design-basis accidents (DBAs), external events, and 

natural phenomena) that were applicable to KPS. The staff reviewed the applicant‘s basis 

documents which described all design-basis conditions in the KPS CLB and addressed all 

events defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The KPS USAR and basis 

documents discussed events such as internal and external flooding, tornados, and missiles. The 

staff concludes that the applicant‘s evaluation of DBEs was consistent with the SRP-LR.

The applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) criterion in accordance with 

the license renewal implementing procedures, which provide guidance for the preparation, 

review, verification, and approval of the scoping evaluations to ensure the adequacy of the 

results of the scoping process. The staff reviewed the implementing procedures governing the 

applicant‘s evaluation of safety-related SSCs, and sampled the applicant‘s reports of the 

scoping results to ensure that the applicant applied the methodology in accordance with the 

implementing procedures. In addition, the staff discussed the methodology and results with the 

applicant‘s personnel who were responsible for these evaluations.

The staff reviewed the applicant‘s evaluation of the Rule and CLB definitions pertaining to 

10 CFR 54.4(a)(1) and determined that the KPS CLB definition quality assurance (QA) Class 1 

met the definition of safety-related specified in the Rule. The staff reviewed a sample of the 

license renewal scoping results for the: (1) auxiliary feedwater, (2) safety injection, (3) spent fuel 

pool cooling, and (4) turbine building, to provide additional assurance that the applicant 

adequately implemented its scoping methodology with respect to 10 CFR 54.4(a)(1). The staff 

verified that the applicant developed the scoping results for each of the sampled systems 

consistently with the methodology, identified the SSCs credited for performing intended 

functions, and adequately described the basis for the results, as well as the intended functions. 

The staff also confirmed that the applicant had identified and used pertinent engineering and

licensing information to identify the SSCs required to be within the scope of license renewal in 

accordance with the 10 CFR 54.4(a)(1) criteria.

2.1.4.1.3 Conclusion

On the basis of its review of systems (on a sampling basis), discussions with the applicant, and 

review of the applicant‘s scoping process, the staff concludes that the applicant‘s methodology 

for identifying systems and structures is consistent with the SRP-LR and 10 CFR 54.4(a)(1) and,

therefore, is acceptable.
Structures and Components Subject to Aging Management Review

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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, ―10 CFR 54.4(a)(2) – Nonsafety-Related Affecting Safety-Related,‖ states:

10 CFR 54.4(a)(2) requires that plant SSCs within the scope of license renewal 

include non-safety-related SSCs whose failure could prevent satisfactory 

accomplishment of any of the functions identified for 10 CFR 54.4(a)(1). A review 

of the USAR, OE, and CLB documentation was performed to develop the 

guidelines and provide the sources of information to be used as input to scoping 

and screening. This information was augmented by plant walkdowns. The 

results, discussed in Section 2.1.3.6, 10 CFR 54.4(a)(2) Report, identified 

nonsafety-related SSCs for inclusion within the scope of license renewal for 

10 CFR 54.4(a)(2).

LRA Section 2.1.3.6, ―10 CFR 54.4(a)(2) Report,‖ states: 

A review of the USAR, operating experience, and documents indicated in 

Section 2.1.3.1 through Section 2.1.3.5, was performed to identify the 

nonsafety-related SSCs whose failure could prevent satisfactory accomplishment 

of the SR [safety-related] functions identified in 10 CFR 54.4(a)(1). The review 

encompassed the design-basis events and hypothetical failures considered 

within these documents, and included the nonsafety-related SSCs that have 

been credited for mitigating design-basis events as defined in 

10 CFR 50.49(b)(1). The NS [nonsafety-related] SSCs already included within 

the scope of license renewal for 10 CFR 54.4(a)(3) were not identified for 

inclusion under 10 CFR 54.4(a)(2). The results of the review were incorporated 

into a 10 CFR 54.4(a)(2) Report, which was used as input to scoping and 

screening. The report identified the following general categories of NS SSCs for 

inclusion within the scope of license renewal for 10 CFR 54.4(a)(2): 

 (1) NS components containing liquids or steam that are spatially oriented 

such that their failure could prevent the satisfactory accomplishment of a 

safety-related function of a safety-related SSC. 

 (2) NS piping that is attached to SR piping and that is seismically designed 

and supported up to the first equivalent anchor point beyond the SR/NS

boundary. 

 (3) Supports for NS SSCs that are in close proximity to SR SSCs such that 

support system failure during a seismic event could result in adverse 

interaction with SR SSCs. (Seismic (II/I).

 (4) Other evaluated design-basis events [HELBs, internal flooding, external 

flooding, and missiles]
Structures and Components Subject to Aging Management Review

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LRA Section 2.1.3.6.1, ―Spatially Oriented NS-SSCs Not Directly Attached to SR-SSCs,‖ states:

There are two options for scoping spatially oriented components in NEI 95-10: a 

mitigative option or a preventative option. The components for both options have 

been included in scope for 10 CFR 54.4(a)(2). Non-safety-related mitigative 

features consist of jet impingement shields, spray shields, pipe whip restraints, 

seismic supports, and flood barriers. They are evaluated as commodities in 

Section 3.5, Aging Management of Containment, Structures and Component 

Supports. NS SSCs are included in-scope if they were spatially oriented such 

that their failure could prevent the satisfactory accomplishment of a SR-function 

of SR-SSC, even if a mitigative feature did exist. 

Non-safety-related fluid-containing components (e.g., piping, valves, heat 

exchangers, relief valves discharge piping, etc.) contain or have the potential to 

contain liquid or steam. These fluid-containing components may spray, leak or 

physically impact safety-related components. Additionally, fluid-containing 

components may contain contaminants, which could result in internal age-related 

degradation, or reach temperatures below the dew point of the air surrounding 

the component, which may produce intermittent wetting conditions on the 

external surfaces and cause age-related degradation. Therefore, 

NS-fluid-containing components spatially oriented near SR-components were 

evaluated to determine if they met the criteria defined in 10 CFR 54.4(a)(2). 

When determining the scoping boundary for NS-components, the following 

criteria were applied within the buildings that house SR-components:

 (1) NS components containing or potentially containing high-energy fluid 

(i.e., >200°F and >275 psig) were included within the scope of license 

renewal regardless of their location within the building.

 (2) NS-components containing or potentially containing moderate or low 

energy fluids (i.e.,

renewal scope unless both 2(a) and 2(b) below applied:

 (a) The NS component could not directly leak or spray on SR 

components in the immediate area because one of the following 

conditions existed: 

● The NS component was located in a room, cubicle, 

enclosure, tunnel, or enclosed corridor, which did not contain 

any SR mechanical or electrical components.

● The NS component was located in an open space, but was 

separated from SR mechanical or electrical components by 

solid physical barriers such as walls, floors, ceilings and/or 

major plant equipment (e.g., the main condenser).

● The NS component was located in an open space, was 

maintained at or near atmospheric pressure, and there were 

no SR mechanical or electrical components located within 

the collapse envelope of the NS component.
Structures and Components Subject to Aging Management Review

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 (b) The fluid contents of the NS components could not flow from the 

area through doorways, grating, or floor penetrations, and then 

drain or drip on or flood SR mechanical or electrical components 

in adjacent areas, unless an analysis demonstrated that the SR 

components would not be adversely impacted. 

For components included in-scope for spatial orientation, the license renewal 

boundary would normally extend to:

● A wall or floor of the SR area. If the wall or floor was not shown on the 

system P&ID [piping and instrumentation diagram], then a note was used 

to denote the boundary on the license renewal drawing.

● A NS component that was located within the SR area and that was 

excluded from scope under item 2 above.

● A convenient location (preferably the first valve, tank, etc.) outside the SR 

area. 

LRA Section 2.1.3.6.2, ―NS Piping Attached to SR Piping,‖ states:

Section B.7.2 of the USAR states, ―All Class I piping was isolated from piping for 

which Class I analysis was not required by structural anchors. Non-Class I pipe 

which was connected to Class I pipe was analyzed as Class I pipe up to a 

structural anchor which provided a means for isolating the Class I piping from the 

non-Class I piping, or up to an equipment connection when isolation by structural 

anchor was not practical.‖ A structural anchor is a device that ensures forces and 

moments are restrained in each of the three orthogonal directions. At Kewaunee, 

the piping systems were designed and constructed such that structural anchors 

were primarily used to provide the restraints. 

The NS piping up to and including the structural anchors were included in scope 

per 10 CFR 54.4(a)(2). In the event an equipment connection is credited for 

providing restraint in one or more of the orthogonal directions, the credited 

component and its associated supports were included in the scope of license 

renewal per 10 CFR 54.4(a)(2). The supports were evaluated as a commodity in 

Section 2.4.3 and the mechanical components were evaluated with their 

respective system in Section 2.3. 

The extent of NS piping included in the scope of license renewal was generally 

determined from controlled drawings. In the event that a structural anchor used in 

a seismic analysis for a SR-piping system was not identified on those drawings, 

the bounding scoping methodology described in Appendix F, Section 4, 

paragraphs (a) through (f) of NEI 95-10 was applied. In some cases the bounding 

approach was overly conservative and it was deemed appropriate to limit the 

additional scope for a piping system by specifically identifying structural anchors 

via a review of isometric drawings. In a limited number of cases, where isometric 

drawings were not available, plant walkdowns were performed by experienced 

personnel to determine the location of the structural anchors. Mechanical 

components that are included in-scope per these criteria are evaluated with their 

respective systems and supports that are included in-scope per this criteria are 
Structures and Components Subject to Aging Management Review

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evaluated as a commodity. Additionally, NS structures in which these NS piping 

segments and associated pipe supports are located were also included within the 

scope of license renewal in that they provide structural support and shelter for 

these components.

2.1.4.2.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs whose 

failure could prevent the satisfactory accomplishment of safety-related functions for SSCs relied 

on to remain functional during and following a 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 capability to prevent or mitigate the consequences of accidents 

that could result in potential offsite exposures comparable to those referred to in 10 CFR Parts 

50.34(a)(1), 50.67(b)(2), or 100.11.

RG 1.188, Revision 1 endorses the use of NEI 95-10, Revision 6. NEI 95-10 discusses the 

staff‘s position on 10 CFR 54.4(a)(2) scoping criteria, including nonsafety-related SSCs typically 

identified in the CLB; consideration of missiles, cranes, flooding, and HELBs; nonsafety-related 

SSCs connected to safety-related SSCs; nonsafety-related SSCs in proximity to safety-related 

SSCs; and mitigative and preventative options related to nonsafety-related and safety-related 

SSCs interactions. 

In addition, the staff‘s position (as discussed in NEI 95-10, Revision 6) is that applicants should 

not consider hypothetical failures, but rather should base their evaluation on the plant‘s CLB, 

engineering judgment and analyses, and relevant OE. NEI 95-10 further describes OE as all 

documented plant-specific and industrywide experience that can be used to determine the 

plausibility of a failure. Documentation would include NRC generic communications and event 

reports, plant-specific condition reports, industry reports such as safety operational event 

reports, and engineering evaluations. The staff reviewed LRA Section 2.1.3.6, in which the 

applicant described the scoping methodology for nonsafety-related SSCs pursuant to 

10 CFR 54.4(a)(2). In addition, the staff reviewed the applicant‘s implementing document and 

results report which documented the guidance and corresponding results of the applicant‘s 

scoping review pursuant to 10 CFR 54.4(a)(2). The applicant stated that it performed the review 

in accordance with the guidance contained in NEI 95-10, Revision 6, Appendix F.

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs. The staff confirmed that 

nonsafety-related SSCs, directly connected to SSCs, had been reviewed by the applicant for 

inclusion within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The staff 

reviewed the evaluating criteria discussed in LRA Section 2.1.3.6.2, ―NS Piping Attached to SR 

Piping,‖ and the applicant‘s 10 CFR 54.4(a)(2) implementing document. The applicant had 

reviewed the safety-related to nonsafety-related interfaces for each mechanical system in order 

to identify the nonsafety-related components located between the safety to nonsafety-related 

interface and license renewal structural boundary. 
Structures and Components Subject to Aging Management Review

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The staff determined that, in order to identify the nonsafety-related SSCs connected to 

safety-related SSCs and required to be structurally sound to maintain the integrity of the 

safety-related SSCs, the applicant used a combination of the following to identify the portion of 

nonsafety-related piping systems to include within the scope of license renewal:

● seismic anchors

● equivalent anchors identified by walkdowns

● bounding conditions described in NEI 95-10, Appendix F (base mounted component, 

flexible connection, or inclusion of the entire piping run)

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs.

The staff confirmed that nonsafety-related SSCs with the potential for spatial interaction with 

safety-related SSCs had been reviewed by the applicant for inclusion within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). The staff reviewed the evaluating criteria 

discussed in LRA Sections 2.1.3.6.1, ―Spatially Oriented NS SSCs Not Directly Attached to SR 

SSCs,‖ and 2.1.3.6.3, ―Seismic II/I,‖ and the applicant‘s 10 CFR 54.4(a)(2) implementing 

procedure. The applicant had considered physical impacts (pipe whip, jet impingement), harsh 

environments, flooding, spray, and leakage when evaluating the potential for spatial interactions 

between nonsafety-related systems and safety-related SSCs. The staff further confirmed that 

the applicant used a spaces approach to identify the portions of nonsafety-related systems with 

the potential for spatial interaction with safety-related SSCs. The spaces approach focused on 

the interaction between nonsafety-related and safety-related SSCs that are located in the same 

space, which was defined for the purposes of the review as a structure containing active or 

passive safety-related SSCs.

LRA Section 2.1.3.6.4, ―Other Evaluated Design-Basis Events,‖ and the applicant‘s 

implementing document state that the applicant had used a mitigative approach when 

considering the impact of nonsafety-related SSCs on safety-related SSCs for occurrences 

discussed in the CLB. The staff reviewed the applicant‘s CLB information, primarily contained in 

the USAR, regarding missiles, flooding, and HELBs. The staff determined that the applicant had 

included the features designed to protect safety-related SSCs from the effects of these 

occurrences through the use of mitigating features such as walls, curbs, dikes, doors, whip 

restraints, protective covers, guard pipes, and jet impingement shields. The applicant had also 

used a mitigative approach to exclude spaces which did not contain safety-related SSCs by 

including the mitigative features such as walls, floors, doors, and dikes, which would mitigate 

the interaction of spray, leakage, or flooding on safety-related SSCs located outside of the 

excluded space. The staff confirmed that the applicant had included the mitigating features 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

LRA Sections 2.1.3.6.1 and 2.1.3.6.3 and the applicant‘s implementing document state that the

applicant had used a preventive approach which considered the impact of nonsafety-related 

SSCs contained in the same space as safety-related SSCs. The staff determined that the 

applicant had evaluated all nonsafety-related SSCs containing liquid or steam and located in 

spaces containing safety-related SSCs. The applicant used a spaces approach to identify the 

nonsafety-related SSCs which were located within the same space as safety-related SSCs. For

the purpose of the scoping review, a space was defined as a structure containing active or 

passive safety-related SSCs. In addition, the staff determined that, following the identification of 

the applicable mechanical systems, the applicant identified their corresponding structures for 
Structures and Components Subject to Aging Management Review

2-15

potential spatial interaction, based on a review of the CLB and plant walkdowns. 

Nonsafety-related systems and components that contain liquid or steam, and are located inside 

structures that contain safety-related SSCs, were included within the scope of license renewal, 

unless it was in an excluded space. The staff also determined that based on plant and industry 

OE, the applicant excluded the nonsafety-related SSCs containing air or gas from the scope of 

license renewal, with the exception of portions that are attached to safety-related SSCs and 

required for structural support. The staff confirmed that those nonsafety-related SSCs 

determined to contain liquid or steam, and located within a space containing safety-related 

SSCs, were included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2).

The staff reviewed the implementation of LRA Section 2.1.3.6.1 which states, in part, that 

nonsafety-related components containing or potentially containing moderate or low-energy fluids 

(i.e., less than or equal to 200 °F or less than or equal to 275 pounds per square inch (psig)) 

were also included within the scope of license renewal unless both 2(a) and 2(b) below applied:

 (a) The nonsafety-related component could not directly leak or spray on safety-related 

components in the immediate area because one of the following conditions existed:

● The nonsafety-related component was located in a room, cubicle, 

enclosure, tunnel, or enclosed corridor, which did not contain any 

safety-related mechanical or electrical components.

● The nonsafety-related component was located in an open space, but was 

separated from safety-related mechanical or electrical components by 

solid physical barriers such as walls, floors, ceilings, and/or major plant 

equipment (e.g., the main condenser).

● The nonsafety-related component was located in an open space, was 

maintained at or near atmospheric pressure, and there were no 

safety-related mechanical or electrical components located within the 

collapse envelope of the nonsafety-related component.

 (b) The fluid contents of the nonsafety-related components could not flow from the area 

through doorways, grating, or floor penetrations, and then drain, drip on, or flood 

safety-related mechanical or electrical components in adjacent areas, unless an analysis 

demonstrated that the safety-related components would not be adversely impacted.

During the scoping and screening methodology audit, the staff performed a walkdown of two 

nonsafety-related systems in the proximity of safety-related SSCs which were not included 

within the scope of license renewal based on the concept of the ―collapse envelope.‖

The staff determined that additional information would be required to complete the review of the 

applicant‘s scoping methodology. RAI 2.1-1, dated April 30, 2009, states that the staff 

determined that the term ―collapse envelope‖ is not addressed in NEI 95-10, Appendix F, as a 

basis for not including fluid-filled nonsafety-related SSCs, in the proximity of safety-related 

SSCs, within the scope of license renewal. The staff requested that the applicant provide a 

discussion which states whether or not an exception was taken to the guidance of NEI 95-10 

and provide the basis for the use of a ―collapse envelope‖ for not including nonsafety-related 

SSCs, within the proximity of safety-related SSCs, within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2).
Structures and Components Subject to Aging Management Review

2-16

The applicant responded to RAI 2.1-1 by letter dated May 28, 2009, which states that the 

concept of the ―collapse envelope‖ was limited to the evaluation of tanks at atmospheric 

pressure, addressed the area directly beneath and around the tank, and evaluated the effects of 

spray and leakage due to the failure of the tank pressure boundary. The RAI response states 

that the ―collapse envelope‖ criterion was established to account for the potential leakage from 

tanks at atmospheric pressure that could project outward, due to the static head associated with 

the height of fluid in the tank, and potentially affect safety-related SSCs. The RAI states that the 

applicant had evaluated each tank and considered the range of leakage or spray that could 

result from a failure of the tank pressure boundary and that the applicant had determined that 

SSCs could not be directly impacted by spray from a tank wall failure. In addition, the RAI 

response states that the applicant had evaluated the potential effects of the flooding of leaked 

fluid on safety-related SSCs and determined that the effects of flooding would be mitigated by 

walls, floors, curbing, berms, sumps, and elevated equipment pads, all of which were included 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) as mitigative features.

The staff determined that the applicant had performed an evaluation to determine that the 

nonsafety-related tanks, not included within the scope of license renewal on the basis of the 

concept of a ―collapse envelope,‖ would not affect safety-related SSCs due to spray resulting 

from a tank wall failure. In addition, the staff determined that the applicant had appropriately 

included features which would mitigate the effects of the flooding of leaked fluids from a tank 

failure within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The issue 

addressed by RAI 2.1-1 is closed.

2.1.4.2.3 Conclusion

On the basis of its review of the applicant‘s scoping process, discussions with the applicant, and 

review of the information provided in the response to RAI 2.1-1, the staff concludes that the 

applicant‘s methodology for identifying and including nonsafety-related SSCs that could affect 

the performance of safety-related SSCs within the scope of license renewal is consistent with 

the scoping criteria 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

Scoping for Regulated Events. LRA Section 2.1.2.3, ―10 CFR 54.4(a)(3) – Regulated Events,‖ 

states:

10 CFR 54.4(a)(3) requires that plant SSCs within the scope of license renewal 

include SSCs relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the Commission's regulations for fire 

protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), 

pressurized thermal shock (10 CFR 50.61), anticipated transients without scram 

(10 CFR 50.62), and station blackout (10 CFR 50.63). For each of these 

regulated events, a report was prepared to provide input into the scoping and 

screening processes. These reports (1) identified the systems and structures that 

are relied on for each of the regulated events, and/or (2) either identified specific 

components, or provided a reference to the documentation to be used as input 

for screening.
Structures and Components Subject to Aging Management Review

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Fire Protection. LRA Section 2.1.3.7.1, ―Fire Protection,‖ states:

The Fire Protection Program Plan was developed to maintain compliance with 

10 CFR 50.48 and Appendix R to 10 CFR 50 by meeting the following objectives 

in fire areas important to safety:

● Reduce the likelihood of fires

● Promptly detect and extinguish fires that do occur

● Maintain safe-shutdown capability if a fire does occur

● Prevent release of a significant amount of radioactive material if a fire 

does occur

A review was performed to identify the specific SSCs that fall within the scope of 

license renewal for fire protection, including the SSCs relied upon in the Fire 

Protection Program Plan. As a result of that review, the following features and 

equipment were included within the scope of license renewal for fire protection: 

● Fire detection and suppression equipment

● Passive fire protection features such as reactor coolant pump lube oil 

collection components, dikes, curbs, and drains

● Fire-rated assemblies such as walls, floors, ceilings, cable tray 

enclosures, and other fire barriers

● Fire-rated penetrations assemblies (including fire doors, fire dampers, 

cable, piping, and ventilation duct penetration seals)

● Manual firefighting equipment (hydrants, hose stations, extinguishers, 

etc.) 

● Ventilation equipment (smoke removal)

● Emergency lighting (fire safe shutdown and life safety lighting)

● Communications equipment (fire brigade and fire safe shutdown)

● Safe shutdown equipment

The screening methodology was applied to the post-fire repair equipment that is 

maintained in storage.
Structures and Components Subject to Aging Management Review

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Environmental Qualification (EQ). LRA Section 2.1.3.7.2 states:

The EQ program was developed to maintain compliance with 10 CFR 50.49. The 

program applies to the following electrical equipment that is important to safety 

and is located in a harsh environment:

● Safety-related electrical equipment that is relied on to remain functional 

during and following a design-basis accident.

● Nonsafety-related electrical equipment whose failure, under postulated 

environmental conditions, could prevent accomplishment of safety 

functions of the safety-related electrical equipment identified above.

● Category 1 and 2 post-accident monitoring equipment described in 

response to Regulatory Guide 1.97.

DOR [Division of Operating Reactors] Guidelines delineated in Enclosure 4 of 

IE Bulletin 79-01B (Reference 2.1-4) and IEEE [Institute of Electrical and 

Electronics Engineers] 323-1974 (Reference 2.1-5) are the qualification basis.

The electrical components that fall within the scope of the EQ program are 

identified in the Asset Management module of EMPAC system equipment 

database (Section 2.1.3.3). Components that provide a barrier between mild and 

harsh areas of the plant, such as doors, penetrations, seals, dampers, walls, and 

floors, while not in the EQ program, were also included within the scope of 

license renewal.

Pressurized Thermal Shock (PTS). LRA Section 2.1.3.7.3, ―Pressurized Thermal Shock,‖ states:

10 CFR 50.61 requires that each licensee project a value for the reference 

temperature for PTS for the limiting reactor vessel materials for end-of-life 

neutron fluence. The licensee is also required to implement those flux reduction 

programs, plant modifications and/or operational changes that are reasonable to 

avoid exceeding the pressurized thermal shock screening criteria set forth in 

10 CFR 50.61. The evaluation of reactor pressure vessel material RTPTS is 

provided in Section 4.2, Reactor Vessel Neutron Embrittlement. [Time Limited 

Aging Analyses]

Anticipated Transient Without Scram (ATWS). LRA Section 2.1.3.7.4, ―Anticipated Transient 

Without Scram,‖ states:

Plant modifications were implemented in response to 10 CFR 50.62 which 

require each pressurized water reactor to have equipment, from sensor to final 

actuation device, that is diverse from the reactor trip system. The ATWS 

Mitigating System Actuating Circuitry design and the Diverse Scram system, 

described in USAR Section 14.1.12, fulfills the NRC requirements addressed in 

10 CFR 50.62 that provides the following initiations:

 1 Initiation of auxiliary feedwater flow

 2 Initiation of a turbine trip, and
Structures and Components Subject to Aging Management Review

2-19

 3 Interruption of power to the control rods.

The equipment is required to reduce the likelihood of failure to shut down the reactor following 

anticipated transients and to mitigate the consequences of an ATWS event. All ATWS 

equipment/components were included within the scope of license renewal. 

Station Blackout. LRA Section 2.1.3.7.5, ―Station Blackout,‖ states:

Plant modifications and procedure changes were implemented in response to 

10 CFR 50.63 to enable the station to withstand and recover from a station 

blackout (SBO) of a specified duration (4 hours based on the Kewaunee 

parameters). The Kewaunee required functions to cope with an SBO event are 

described in USAR Section 8.2.4. Recovery includes the ability to achieve and 

maintain hot shutdown. The SSCs required for compliance with 10 CFR 50.63 

were identified in a regulated event report which was used as input to the 

scoping and screening processes. The in-scope SSCs include the TSC [technical 

support center] diesel generator, its support systems, the TSC Diesel Generator 

Room, and other equipment relied upon to mitigate an SBO event.

2.1.4.3.2 Staff Evaluation

The staff reviewed the applicant‘s approach to identifying mechanical systems and structures 

relied upon to perform functions meeting the requirements of the fire protection, EQ, PTS, 

ATWS, and SBO regulations. As part of this review, the staff discussed the methodology with 

the applicant, reviewed the documentation developed to support the approach, and evaluated 

mechanical systems and structures (on a sampling basis) included within the scope of license 

renewal pursuant to 10 CFR 54.4(a)(3).

The staff confirmed that the applicant‘s implementing procedures describe the process for 

identifying systems and structures within the scope of license renewal pursuant to 

10 CFR 54.4(a)(3). The procedures state that all mechanical systems and structures that 

perform functions addressed in 10 CFR 54.4(a)(3) are to be included within the scope of license 

renewal and that the results are to be documented in scoping results reports. The staff 

determined that the results reports reference the information sources used for determining the

systems and structures credited for compliance with the events listed in the specified 

regulations. 

Fire Protection. The staff determined that the applicant‘s implementing procedures indicated 

that it had included systems and structures within the scope of license renewal required for 

post-fire safe shutdown, fire detection suppression, and commitments made to Appendix A to 

Branch Technical Position (BTP), Auxiliary and Power Conversion Systems Branch 

(APCSB) 9.5-1, ―Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to 

July 1, 1976,‖ issued May 1976. The applicant noted that it had considered CLB documents to 

identify systems and structures within the scope of license renewal. These documents included 

the USAR, the Appendix R design description and composite flow diagrams, the Fire Protection 

Program Plan, and other KPS source documents. The staff reviewed, on a sampling basis, the 

scoping results in conjunction with the LRA and CLB information to validate the methodology for 

including the proper systems and structures within the scope of license renewal. The sample 

review showed that the scoping results include systems and structures that perform intended 

functions to meet 10 CFR 50.48 requirements. Based on its review of the CLB documents and 

the sample review, the staff determined that the applicant‘s scoping methodology was adequate 
Structures and Components Subject to Aging Management Review

2-20

for including SSCs credited in performing fire protection functions within the scope of license 

renewal.

Environmental Qualification. The staff confirmed that the applicant‘s implementing procedures 

required the inclusion of safety-related electrical equipment, nonsafety-related electrical 

equipment whose failure under postulated environmental conditions could prevent satisfactory 

accomplishment of safety functions of the safety-related equipment, and certain post-accident 

monitoring equipment, as defined in 10 CFR 50.49(b)(1), (b)(2), and (b)(3). The staff determined 

that the applicant used the plant equipment database to identify SCs necessary to meet the 

requirements of 10 CFR 50.49. The staff reviewed the LRA, implementing procedures, the EQ 

master list, and scoping results to verify that the applicant had identified SSCs within the scope 

of license renewal. Based on its review, the staff determined that the applicant‘s scoping 

methodology was adequate for identifying EQ SSCs within the scope of license renewal.

Pressurized Thermal Shock. The staff determined that the applicant‘s scoping methodology 

required the applicant to review the activities performed to meet 10 CFR 50.61, to identify SSCs 

within the scope of license renewal pursuant to 10 CFR 54.4(a)(3). The staff reviewed the basis 

document and the implementing procedure and determined that the methodology was 

appropriate for identifying SSCs with functions credited for complying with the PTS regulation 

and within the scope of license renewal. Accordingly, the staff finds that the scoping results 

included the systems and structures that perform intended functions to meet the requirements of 

10 CFR 50.61. The staff determined that the applicant‘s scoping methodology was adequate for 

including SSCs credited in meeting PTS requirements within the scope of license renewal. 

Anticipated Transient Without Scram. The staff determined that the applicant had identified the 

plant systems credited for ATWS mitigation based on review of the plant drawings, the USAR, 

docketed correspondence, modifications, and the plant equipment database. The staff reviewed 

these documents and the LRA, in conjunction with the scoping results, to validate the 

methodology for identifying ATWS systems and structures that are within the scope of license 

renewal. The staff finds that the scoping results included systems and structures that perform 

intended functions meeting 10 CFR 50.62 requirements. The staff, therefore, determined that 

the applicant‘s scoping methodology was adequate for identifying SSCs with functions credited 

for complying with the ATWS regulation.

Station Blackout. The staff determined that the applicant identified those systems and structures 

associated with coping and safe shutdown of the plant following an SBO event by reviewing 

plant-specific SBO calculations, the USAR, drawings, modifications, the plant equipment 

database, and plant procedures. The staff reviewed, on a sampling basis, these documents and 

the LRA in conjunction with the scoping results to validate the applicant‘s methodology. The 

staff determined, based on its review, that the scoping results included systems and structures 

that perform intended functions meeting 10 CFR 50.63 requirements. The staff determined that 

the applicant‘s scoping methodology was adequate for identifying SSCs credited in complying 

with the SBO regulation within the scope of license renewal. 

2.1.4.3.3 Conclusion

On the basis of the sample reviews, discussion with the applicant, review of the LRA, and 

review of the implementing procedures and reports, the staff concludes that the applicant‘s 

methodology for identifying systems and structures meets the scoping criteria pursuant to 

10 CFR 54.4(a)(3) and, therefore, is acceptable. 
Structures and Components Subject to Aging Management Review

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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. LRA Section 2.1, ―Introduction,‖ states:

The first step in the Integrated Plant Assessment involved the identification of the 

plant SSCs that are within the scope of license renewal and that require an aging 

management review. This section provides the information that meets the 

requirements of 10 CFR 54.21(a)(1) and (a)(2). Scoping and screening were 

performed consistent with the guidelines presented in NEI 95-10 

(Reference 2.1-1) with the following clarifications: 

● Scoping was performed at the system/structure level. Screening was 

performed on a component level basis and the scoping results (intended 

functions, applicable scoping criteria, etc.) were then reviewed and 

revised as required to be consistent with the screening results. 

● The screening process identified in-scope passive components. The 

short-lived passive components, that could be excluded from an AMR on 

the basis of a qualified life or a specified replacement time period, were 

identified and removed from any further aging evaluation consideration.

LRA Section 2.1.2, ―Application of the Scoping Criteria in 10 CFR 54.4(a),‖ states: 

10 CFR 54.4(a)(1), (a)(2) and (a)(3) contain criteria for including systems, 

structures, and components within the scope of license renewal. The application 

of these criteria to plant SSCs is discussed in Section 2.1.2.1 [10 CFR 54.4(a)(1) 

– Safety-Related], Section 2.1.2.2 [10 CFR 54.4(a)(2) – Nonsafety-related 

Affecting Safety-Related], and Section 2.1.2.3 [10 CFR 54.4(a)(3) – Regulated 

Events].

LRA Section 2.1.4.1, ―System Scoping Methodology,‖ states:

Mechanical and electrical system scoping was performed by applying the criteria 

described below. If any of the criteria were met, indicating that a system 

performed one or more intended functions, the system was listed as potentially 

within the scope of license renewal.

 1 EMPAC contains data that indicates that the system contains one or more 

components that have been determined to meet the scoping criteria in 

10 CFR 54.4.

 2 The USAR, Maintenance Rule documentation, system descriptions, 

and/or DBDs list one or more system functions that were determined to 

meet the scoping criteria in 10 CFR 54.4.

 3 The 10 CFR 54.4(a)(2) Report, and/or one of the 10 CFR 54.4(a)(3) 

regulated event reports indicate that the system performs an intended 

function.
Structures and Components Subject to Aging Management Review

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 4 Controlled station drawings and/or EMPAC data indicate that the system 

contains one or more NS fluid-containing components located in a Class I 

(SR) structure or in the non-Class I portion of the turbine building. In 

these instances, spatial interactions between NS and SR components is a 

potential concern.

 5 Controlled station drawings indicate that the system contains NS piping 

that is attached to SR piping and is required to be seismically supported.

The preliminary scoping results were used as input to the screening process. The 

results of the completed screening process were used as input for reviewing and 

updating the system scoping results (intended functions, applicable scoping 

criteria, etc.). 

LRA Section 2.1.3.8, ―Drawings,‖ states:

Mechanical flow (P&ID) drawings were marked-up to show the in-scope 

mechanical components that support one or more system intended functions. 

The marked-up drawings were subsequently used to create a set of license 

renewal drawings identifying the in-scope passive mechanical components. A 

unique style of highlighting was used to distinguish the in-scope mechanical 

components for each system. For each unique style of highlighting, the color blue 

was used to identify components included in-scope for 10 CFR 54.4(a)(1) and 

(a)(3), and the color orange was used to identify components included within the 

scope of license renewal for 10 CFR 54.4(a)(2). In addition, seismic anchors 

were indicated on the drawings when the anchor established the LR boundary.

Consumables. LRA Section 2.1.5.7, ―Identification of Short-Lived Components and 

Consumables,‖ states:

Components subject to periodic replacement, or components found to have an 

established qualified life (e.g., for EQ purposes), were included within the scope 

of license renewal, but later screened out as short-lived and did not require an 

aging management review. Consumables are a special class of short-lived items 

that can include packing, gaskets, component seals, O-rings, oil, grease, 

component filters, system filters, fire extinguishers, fire hoses, and air packs. 

Many types of consumables are part of a component such as a valve or a pump 

and, therefore, were identified during screening. Items potentially treatable as 

consumables were evaluated consistent with the information presented in 

NEI 95-10.

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant‘s methodology for performing the scoping of plant systems and 

components to ensure it was consistent with 10 CFR 54.4. The methodology used to determine 

the systems and components within the scope of license renewal was documented in 

implementing procedures and scoping results reports for systems. The scoping process defined 

the plant in terms of systems and structures. Specifically, the implementing procedures 

identified the systems and structures that are subject to 10 CFR 54.4 review, described the 

processes for capturing the results of the review, and were used to determine if the system or 

structure performed intended functions consistent with the criteria of 10 CFR 54.4(a). The 
Structures and Components Subject to Aging Management Review

2-23

process was completed for all systems and structures to ensure that the entire plant was 

addressed. 

The applicant documented the results of the plant-level scoping process in accordance with the 

implementing documents. The results were provided in the systems and structures documents 

and reports which contained information including a description of the structure or system, a 

listing of intended functions performed by the system or structure, the 10 CFR 54.4(a) scoping 

criteria met by the system or structure, references, and the basis for the classification of the 

system or structure intended functions. During the audit, the staff reviewed a sampling of the 

documents and reports and concluded that the applicant‘s scoping results contained an 

appropriate level of detail to document the scoping process.

2.1.4.4.3 Conclusion

Based on its review of the LRA, site guidance documents, and a sampling of system scoping 

results reviewed during the audit, the staff concludes that the applicant‘s methodology for 

identifying SSCs within the scope of license renewal, and their intended functions, is consistent 

with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.5 Mechanical Component Scoping

2.1.4.5.1 Summary of Technical Information in the Application

LRA Section 2.1.4.1, ―System Scoping Methodology,‖ states:

Mechanical and electrical system scoping was performed by applying the criteria 

described below. If any of the criteria were met, indicating that a system 

performed one or more intended functions, the system was listed as potentially 

within the scope of license renewal.

 1 EMPAC contains data that indicates that the system contains one or more 

components that have been determined to meet the scoping criteria in 

10 CFR 54.4.

 2 The USAR, Maintenance Rule documentation, system descriptions, 

and/or DBDs list one or more system functions that were determined to 

meet the scoping criteria in 10 CFR 54.4.

 3 The 10 CFR 54.4(a)(2) Report, and/or one of the 10 CFR 54.4(a)(3) 

regulated event reports indicate that the system performs an intended 

function.

 4 Controlled station drawings and/or EMPAC data indicate that the system 

contains one or more NS fluid-containing components located in a Class I 

(SR) structure or in the non-Class I portion of the Turbine Building. In 

these instances, spatial interactions between NS and SR components is a 

potential concern.

 5 Controlled station drawings indicates that the system contains NS piping 

that is attached to SR piping and is required to be seismically supported.
Structures and Components Subject to Aging Management Review

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The preliminary scoping results were used as input to the screening process. The 

results of the completed screening process were used as input for reviewing and 

updating the system scoping results (intended functions, applicable scoping 

criteria, etc.). 

2.1.4.5.2 Staff Evaluation

The staff evaluated LRA Section 2.1.4.1 and the guidance in the implementing procedures and 

reports to perform the review of the mechanical scoping process. The project documents and 

reports provided instructions for identifying the evaluation boundaries. Determination of the 

mechanical system evaluation boundary required an understanding of system operations in 

support of intended functions.

The staff determined that the process was based on the review of the USAR, DBDs, the plant 

equipment database, NRC docketed correspondence and documents, and plant drawings. The 

evaluation boundaries for mechanical systems were documented on license renewal drawings 

that were created by marking mechanical P&IDs to indicate the components within the scope of 

license renewal. The staff determined that components within the evaluation boundary were 

reviewed to determine whether or not they perform an intended function. Intended functions 

were established based on whether or not a particular function of a component was necessary 

to support the system functions that meet the scoping criteria. 

The staff reviewed the implementing documents and the CLB documents associated with 

mechanical system scoping and finds 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 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 implementing procedures and whether the 

scoping results were consistent with CLB requirements. The staff determined that the 

applicant‘s procedure was consistent with the description provided in LRA Section 2.1.4.1 and 

the guidance contained in SRP-LR Section 2.1 and was adequately implemented. 

On a sampling basis, the staff reviewed the applicant‘s scoping reports for the auxiliary 

feedwater, safety injection, and spent fuel pool cooling systems to ensure they met the scoping 

criteria of 10 CFR 54.4. The staff also reviewed the implementing procedures and discussed the 

methodology and results with the applicant. The staff verified that the applicant had identified 

and used pertinent engineering and licensing information in order to determine the auxiliary 

feedwater, safety injection, and spent fuel pool cooling 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, safety injection, and spent fuel 

pool cooling systems, the basis for inclusion of the intended function, and the process used to 

identify each of the system component types. The staff verified that the applicant had identified 

and highlighted system P&IDs to develop the license renewal boundaries in accordance with the 

procedural guidance. Additionally, the staff determined that the applicant had independently 

verified the results in accordance with the governing procedures. The staff confirmed that the 

applicant‘s license renewal personnel who were knowledgeable about the system had 

performed independent reviews of the marked-up drawings to ensure accurate identification of 

system intended functions, and that the applicant had performed additional cross-discipline 

verification and independent reviews of the resultant highlighted drawings before final approval 

of the scoping effort.
Structures and Components Subject to Aging Management Review

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2.1.4.5.3 Conclusion

On the basis of its review of the LRA and supporting documents, discussion with the applicant,

and the sampling system review of mechanical scoping results, the staff concludes that the 

applicant‘s methodology for identifying mechanical SSCs within the scope of license renewal is 

in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.6 Structural Scoping

2.1.4.6.1 Summary of Technical Information in the Application

LRA Section 2.1.4.2, ―Structure Scoping Methodology,‖ states:

Structure scoping was performed by applying the criteria described below. If any 

of the criteria were met, indicating that a structure performed one or more 

intended functions, the structure was listed as potentially within the scope of 

license renewal. 

 1 The Maintenance Rule documentation indicates that the structure 

performs one or more intended functions that were determined to meet 

the scoping criteria in 10 CFR 54.4.

 2 The USAR identifies the structure as Class I, I* or III*. 

 3 The 10 CFR 54.4(a)(2) Report, and/or one of the 10 CFR 54.4(a)(3) 

regulated event reports indicate that the structure performs an intended 

function.

 4 A plant walkdown identifies that the failure of the structure could 

adversely impact SR-SSCs.

After the screening process for systems and electrical components was 

completed, the list of in-scope structures was reviewed to (1) ensure that all 

structures housing in-scope mechanical and/or electrical components were 

included within the scope of license renewal, and to (2) validate the intended 

functions for the in-scope structures.

2.1.4.6.2 Staff Evaluation

The staff evaluated LRA Section 2.1.4.2, the guidance contained in the implementing 

procedures, and applicable reports to perform the review of structural scoping process. The staff 

reviewed the applicant‘s approach to 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 a sample of structures that were identified within the scope of license 

renewal. The staff determined that the applicant had identified and developed a list of plant 

structures and their intended functions through a review of plant equipment database, USAR, 

DBDs, drawings, procedures, and walkdowns. Each structure the applicant identified was 

evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3).
Structures and Components Subject to Aging Management Review

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The staff reviewed selected portions of the plant equipment database, USAR, DBDs, drawings, 

procedures, and implementing procedures to verify the adequacy of the methodology. The staff 

reviewed the applicant‘s methodology for identifying structures meeting the scoping criteria as 

defined in the Rule. The staff also reviewed the scoping methodology implementing procedures 

and discussed the methodology and results with the applicant. In addition, the staff reviewed, on 

a sampling basis, the applicant‘s scoping reports including information contained in the source 

documentation, for the turbine building to verify that application of the methodology would 

provide the results as documented in the LRA. The staff verified that the applicant had identified 

and used pertinent engineering and licensing information in order to determine that the turbine 

building and the screenhouse were required to be included within the scope of license renewal. 

As part of the review process, the staff evaluated the intended functions identified for the turbine

building and the structural components, the basis for inclusion of the intended function, and the 

process used to identify each of the component types.

2.1.4.6.3 Conclusion

On the basis of its review of information in the LRA and supporting documents, discussions with 

the applicant, and a sampling review of structural scoping results, the staff concludes that the 

applicant‘s methodology for identification of the structural SSCs within the scope of license 

renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, is acceptable.

2.1.4.7 Electrical Component Scoping

2.1.4.7.1 Summary of Technical Information in the Application

LRA Section 2.1.4.1, ―System Scoping Methodology,‖ states:

Mechanical and electrical system scoping was performed by applying the criteria 

described below. If any of the criteria were met, indicating that a system 

performed one or more intended functions, the system was listed as potentially 

within the scope of license renewal.

 1 EMPAC contains data that indicates that the system contains one or more 

components that have been determined to meet the scoping criteria in 

10 CFR 54.4.

 2 The USAR, Maintenance Rule documentation, system descriptions, 

and/or DBDs list one or more system functions that were determined to 

meet the scoping criteria in 10 CFR 54.4.

 3 The 10 CFR 54.4(a)(2) Report, and/or one of the 10 CFR 54.4(a)(3) 

regulated event reports indicate that the system performs an intended 

function.

 4 Controlled station drawings and/or EMPAC data indicate that the system 

contains one or more NS-fluid-containing components located in a Class I 

(SR-) structure or in the non-Class I portion of the Turbine Building. In 

these instances, spatial interactions between NS-and SR-components is 

a potential concern.
Structures and Components Subject to Aging Management Review

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 5 Controlled station drawings indicates that the system contains NS-piping 

that is attached to SR-piping and is required to be seismically supported.

The preliminary scoping results were used as input to the screening process. The 

results of the completed screening process were used as input for reviewing and 

updating the system scoping results (intended functions, applicable scoping 

criteria, etc.). 

2.1.4.7.2 Staff Evaluation

The staff evaluated LRA Section 2.1.4.1 and the guidance contained in the implementing 

procedures and reports to perform the review of the electrical scoping process. The staff 

reviewed the applicant‘s approach to identifying electrical and instrumentation and control (I&C) 

SSCs relied upon to perform the functions described in 10 CFR 54.4(a). The staff reviewed 

portions of the documentation used by the applicant to perform the electrical scoping process 

including the USAR, plant equipment database, CLB documentation, DBDs, databases and 

documents, procedures, drawings, specifications, and codes/standards. As part of this review, 

the staff discussed the methodology with the applicant, reviewed the implementing procedures 

developed to support the review, and evaluated the scoping results for a sample of SSCs that 

were identified within the scope of license renewal. The staff determined that the applicant had 

included electrical and I&C components, including electrical and I&C components contained in 

mechanical or structural systems, within the scope of license renewal on a commodity basis. 

2.1.4.7.3 Conclusion

On the basis of its review of information contained in the LRA and supporting documents, 

discussions with the applicant, and a sampling review of electrical scoping results, the staff 

concludes that the applicant‘s methodology for the identification of electrical SSCs within the 

scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, 

is acceptable.

2.1.4.8 Scoping Methodology Conclusion

On the basis of its review of the LRA, scoping implementing procedures, and a sampling review 

of scoping results, the staff concludes that the applicant‘s scoping methodology was consistent 

with the guidance contained in the SRP-LR and identified those SSCs: (1) that are 

safety-related, (2) whose failure could affect safety-related functions, and (3) that are necessary 

to demonstrate compliance with the NRC regulations for fire protection, EQ, PTS, ATWS, and 

SBO. The staff concluded that the applicant‘s methodology is consistent with the requirements 

of 10 CFR 54.4(a) and, therefore, is acceptable.
Structures and Components Subject to Aging Management Review

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2.1.5 Screening Methodology

2.1.5.1 General Screening Methodology

2.1.5.1.1 Summary of Technical Information in the Application

LRA Section 2.1.5, ―Screening Methodology,‖ and subsections, describes the screening process 

that identifies the SCs within the scope of license renewal that are subject to an AMR. LRA 

Section 2.1.5 states: 

For each of those systems and structures, screening was performed to identify 

the passive components, structural members, and commodities that support an 

intended function. The components that are short-lived (and therefore did not 

require an AMR) were identified and removed from any further aging evaluation 

consideration. Screening was divided by engineering discipline into three primary 

areas: (1) system (mechanical), (2) structural, and (3) electrical/instrumentation 

and controls (I&C).

LRA Section 2.1.5.6, ―Screening of Stored Equipment,‖ states:

A review was performed to identify equipment that: 1) is maintained in storage, 

2) is reserved for installation in the plant in response to a design-basis accident 

or regulated event, and 3) requires an AMR. The equipment in storage that 

performs an intended function and is subject to aging management review 

includes hardware dedicated to mitigate the effects of a fire as identified in the 

Kewaunee Fire Protection Plans and Appendix R/Fire Safe Shutdown 

Compliance Reports. Cables and connections are stored equipment identified as 

requiring an AMR and have been evaluated with Cables and Connections.

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 (passive), 

as well as components that are not subject to periodic replacement based on a qualified life or 

specified time period (long-lived). In addition, the IPA must include a description and justification 

of the methodology used to determine the passive and long-lived SCs, and a demonstration that 

the effects of aging on those SCs will be adequately managed so that the intended functions 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 identify the mechanical and 

structural components and electrical commodity groups within the scope of license renewal that 

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 2.1.5, and subsections, the applicant discussed these screening activities as they 

related to the component types and commodity groups within the scope of license renewal.

The staff determined that the screening process evaluated the component types and commodity 

groups, included within the scope of license renewal, to determine which ones were long-lived 

and passive and, therefore, subject to an AMR. The staff reviewed LRA Section 2.3, ―Scoping 
Structures and Components Subject to Aging Management Review

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and Screening Results: Mechanical Systems‖; LRA Section 2.4, ―Scoping and Screening 

Results: Structures‖; and LRA Section 2.5, ―Scoping and Screening Results: Electrical and 

Instrumentation and Control Systems.‖ These sections of the LRA provided the results of the 

process used to identify component types and commodity groups subject to an AMR. The staff 

also reviewed, on a sampling basis, the screening results reports for the auxiliary feedwater 

system, safety injection system, spent fuel pool cooling system, and the turbine building.

The applicant provided the staff with a detailed discussion of the processes used for each 

discipline and provided administrative documentation that described the screening 

methodology. Specific methodology for mechanical, electrical, and structural is discussed 

below.

2.1.5.1.3 Conclusion

On the basis of a review of the LRA, the implementing procedures, and a sampling of screening 

results, the staff concludes that the applicant‘s screening methodology was consistent with the 

guidance contained in the SRP-LR and was capable of identifying passive, long-lived 

components within the scope of license renewal that are subject to an AMR. The staff concludes 

that the applicant‘s process for determining which component types and commodity groups are 

subject to an AMR is consistent with 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 2.1.5, subsections 2.1.5.1, ―Identification of In-Scope Passive Components‖;

2.1.5.2, ―System (Mechanical) Screening‖; 2.1.5.3, ―Major Components Screening‖; and 2.1.5.7, 

―Identification of Short-Lived Components and Consumables,‖ discuss the screening process 

that identifies the passive, long-lived mechanical components within the scope of license 

renewal that are subject to an AMR. 

LRA Section 2.1.5.7 states, ―Components subject to periodic replacement, or components found 

to have an established qualified life (e.g., for EQ purposes), were included within the scope of 

license renewal, but later screened out as short-lived and did not require an aging management 

review.‖

LRA Section 2.1.5.2 states:

Each system identified during scoping as being within the scope of license 

renewal was screened to identify the mechanical components (pumps, valves, 

piping, etc.) that support the system intended functions. The electrical/I&C 

components (such as heaters) that are in-scope only because they perform a 

system pressure boundary function, were treated as mechanical components 

and were also identified during system screening and therefore, the passive 

components that supported a system intended function were subject to aging 

management review.
Structures and Components Subject to Aging Management Review

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LRA Section 2.1.5.3 states:

The major components within the Reactor Coolant System, i.e., the reactor 

vessel, the reactor vessel internals, and the steam generators, were screened 

separately from the remainder of the Reactor Coolant System components. 

Detailed screening was performed to identify subcomponents that perform or 

support intended functions.

2.1.5.2.2 Staff Evaluation

The staff reviewed the mechanical screening methodology discussed and documented in LRA 

Section 2.1.5 and subsections, the implementing documents, the scoping and screening 

reports, and the license renewal drawings. The staff determined that the mechanical system 

screening process began with the results from the scoping process and that the applicant 

reviewed each system evaluation boundary as illustrated on P&IDs to identify passive and 

long-lived components. In addition, the staff determined that the applicant had identified all

passive, long-lived components that perform or support an intended function within the system 

evaluation boundaries and determined those components to be subject to an AMR. The results 

of the review were documented in the scoping and screening reports which contain information 

such as the information sources reviewed and the component intended functions.

The staff verified that mechanical system evaluation boundaries were established for each 

system within the scope of license renewal and that the boundaries were determined by 

mapping the system intended function boundary onto P&IDs. The staff confirmed that the 

applicant reviewed the components within the system intended function boundary to determine 

if the component supported the system intended function, and that those components that 

supported the system intended function were reviewed to determine if the component was 

passive and long-lived and, therefore, subject to an AMR.

The staff reviewed selected portions of the USAR, plant equipment database, CLB 

documentation, DBDs, databases and documents, procedures, drawings, specifications, 

codes/standards, and selected scoping and screening reports. The staff conducted detailed 

discussions with the applicant‘s license renewal team and reviewed documentation pertinent to 

the screening process. The staff assessed whether the mechanical screening methodology 

outlined in the LRA and procedures was appropriately implemented and if the scoping results 

were consistent with CLB requirements. During the scoping and screening methodology audit,

the staff discussed the screening methodology with the applicant and, on a sampling basis, 

reviewed the applicant‘s screening reports for the auxiliary feedwater, safety injection, and spent 

fuel pool cooling systems to verify proper implementation of the screening process. Based on 

these audit activities, the staff did not identify any discrepancies between the methodology 

documented and the implementation results. 

2.1.5.2.3 Conclusion

On the basis of its review of the LRA, the screening implementing procedures, selected portions 

of the USAR, plant equipment database, CLB documentation, DBDs, databases and 

documents, procedures, drawings, specifications, codes/standards, selected scoping and 

screening reports, and its sample of selected system screening results, the staff concludes that 

the applicant‘s methodology for identification of mechanical components within the scope of 

license renewal and subject to an AMR is in accordance with the requirements of 

10 CFR 54.21(a)(1) and, therefore, is acceptable.
Structures and Components Subject to Aging Management Review

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2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

LRA Sections 2.1.5, 2.1.5.1, 2.1.5.4, ―Structural Screening,‖ and 2.1.5.7 discuss the screening 

process that identifies the passive, long-lived structural components within the scope of license 

renewal that are subject to an AMR. 

LRA Section 2.1.5.7 states, ―Components subject to periodic replacement, or components found 

to have an established qualified life (e.g., for EQ purposes), were included within the scope of 

license renewal, but later screened out as short-lived and did not require an aging management 

review.‖

LRA Section 2.1.5.4 states:

Screening was performed for each in-scope structure identified during the 

scoping process... (and) ...Structure screening identified the passive structural 

members and components (e.g., walls, beams, grating, foundations, barriers, 

duct banks, equipment pads, sumps, etc.) that support the structure's intended 

function(s) and, therefore, require an AMR. The structural members that require 

an AMR were identified based upon a review of the structural detail drawings, the 

USAR, and any information available in EMPAC.

2.1.5.3.2 Staff Evaluation

The staff reviewed the structural screening methodology discussed and documented in LRA 

Section 2.1.3.2 and subsections, the implementing procedures, the scoping and screening 

reports, and the license renewal drawings. The staff reviewed the applicant‘s methodology for 

identifying structural components that are subject to an AMR as required by

10 CFR 54.21(a)(1). The staff confirmed that the applicant had reviewed the structures included 

within the scope of license renewal and identified the passive, long-lived components with 

component level intended functions and determined those components to be subject to an 

AMR. 

The staff reviewed selected portions of the USAR and scoping and screening reports which the 

applicant had used to perform the structural scoping and screening activities. The staff also 

reviewed, on a sampling basis, the civil/structural license renewal drawing to document the SCs

within the scope of license renewal. The staff conducted detailed discussions with the 

applicant‘s license renewal team and reviewed documentation pertinent to the screening 

process to assess if the screening methodology outlined in the LRA and implementing 

procedures was appropriately implemented, and if the scoping results were consistent with CLB 

requirements. During the scoping and screening methodology audit, the staff reviewed, on a 

sampling basis, the applicant‘s screening reports for the turbine building to verify proper 

implementation of the screening process. Based upon these onsite review activities, the staff did 

not identify any discrepancies between the methodology documented and the implementation 

results. 
Structures and Components Subject to Aging Management Review

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2.1.5.3.3 Conclusion

On the basis of its review of the LRA, implementing procedures, the USAR, DBDs, and scoping 

and screening reports, and a sampling review of the turbine building screening results, the staff 

concludes that the applicant‘s methodology for identification of structural components within the 

scope of license renewal and subject to an AMR is in accordance with the requirements of 

10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.4 Electrical Component Screening

2.1.5.4.1 Summary of Technical Information in the Application

LRA Sections 2.1.5, 2.1.5.1, 2.1.5.5, ―Electrical/I&C Screening,‖ and 2.1.5.7 discuss the 

screening process that identifies the passive, long-lived electrical and I&C components within 

the scope of license renewal that are subject to an AMR.

LRA Section 2.1.5.5 states: 

Electrical/I&C components were screened and evaluated as commodities... (and)

...(T)he majority of electrical/I&C components (such as transmitters, switches, 

breakers, relays, actuators, radiation monitors, recorders, isolators, signal 

conditioners, meters, batteries, analyzers, chargers, motors, regulators, 

transformers, and fuses) are active components, in accordance with 

10 CFR 54.21(a)(1)(i) and the supplemental guidelines in NEI 95-10, and 

therefore do not require an AMR.

The electrical/I&C components that are in-scope only because they perform a 

passive pressure boundary function were treated as mechanical components and 

identified during the mechanical system screening process.

The following electrical/I&C commodity groups/component types perform a 

passive function:

● Cables and connections (including splices, terminal blocks, insulation 

portion of fuse holders, and transmission conductors)

● Fuse Holder (Metallic portion)

● Metal Enclosed Bus (includes switchyard buses)

● Reactor Containment Vessel electrical penetrations 

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant‘s methodology used for electrical screening in LRA 

Section 2.1.5 and subsections, implementing procedures, bases documents, and electrical 

screening report. The staff confirmed that the applicant used the screening process described in 

these documents along with the information contained in NEI 95-10, Appendix B and the 

SRP-LR, to identify the electrical and I&C components subject to an AMR. 
Structures and Components Subject to Aging Management Review

2-33

The staff determined that the applicant had identified commodity groups which were found to 

meet the passive criteria in accordance with NEI 95-10. In addition, the staff determined that the 

applicant evaluated the identified, passive commodities to identify whether they were subject to 

replacement based on a qualified life or specified time period (short-lived), or not subject to 

replacement based on a qualified life or specified time period (long-lived) and that the remaining 

passive, long-lived components were determined to be subject to an AMR. 

The staff performed a review to determine if the screening methodology outlined in the LRA and 

implementing procedures was appropriately implemented and if the scoping results were 

consistent with CLB requirements. During the scoping and screening methodology audit, the 

staff reviewed selected screening reports and discussed the reports with the applicant to verify 

proper implementation of the screening process. Based upon these onsite review activities, the 

staff did not identify any discrepancies between the methodology documented and the 

implementation results.

2.1.5.4.3 Conclusion

On the basis of its review of the LRA and supporting documents, discussion with the applicant, 

and a sample of the results of the screening methodology, the staff concludes that the 

applicant‘s methodology for identification of electrical components within the scope of license 

renewal and subject to an AMR is in accordance with the requirements of 10 CFR 54.21(a)(1) 

and, therefore, is acceptable.

2.1.5.5 Screening Methodology Conclusion

On the basis of its review of the LRA, the screening implementing procedures, discussions with 

the applicant‘s staff, and a sample review of screening results, the staff concludes that the 

applicant‘s screening methodology was consistent with the guidance contained in the SRP-LR 

and identified those passive, long-lived components within the scope of license renewal that are 

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

On the basis of its review of the information presented in LRA Section 2.1, the supporting 

information in the scoping and screening implementing procedures and reports, the information 

presented during the scoping and screening methodology audit, discussions with the applicant,

sample system reviews, and the applicant‘s response dated May 28, 2009, to the staff‘s RAI, 

the staff confirms that the applicant‘s scoping and screening methodology is consistent with the 

requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also concludes that the 

applicant‘s description and justification of its scoping and screening methodology are adequate 

to meet the requirements of 10 CFR 54.21(a)(1). From this review, the staff concludes that the

applicant‘s methodology for identifying systems and structures within the scope of license 

renewal and SCs requiring an AMR is acceptable.
Structures and Components Subject to Aging Management Review

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2.2 Plant-Level Scoping Results

2.2.1 Introduction

LRA Section 2.1 describes the methodology for identifying systems and structures within the 

scope of license renewal. In LRA Section 2.2, the applicant used its scoping methodology to 

determine which plant-level systems and structures 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 the following three groups:

● systems and structures relied upon to mitigate 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)

● 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)

2.2.2 Summary of Technical Information in the Application

LRA Tables 2.2-1 and 2.2-3 list those mechanical systems, electrical and I&C systems, and 

structures that are within the scope of license renewal. In LRA Tables 2.2-2 and 2.2-4, the 

applicant listed the systems and structures that did not meet the criteria specified in 

10 CFR 54.4(a) and were excluded from the scope of license renewal. The applicant also 

provided an LRA drawing that showed the in-scope structures for license renewal.

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, the staff‘s review focused on the 

implementation results shown in LRA Tables 2.2-1, 2.2-2, 2.2-3, and 2.2-4 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.‖
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The staff‘s review of LRA Section 2.2 identified an area where 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 2.2-01, dated April 3, 2009, the staff noted LRA Table 2.2-2, ―Systems Not Within the 

Scope of License Renewal,‖ includes the administration building air conditioning system. The 

applicant was requested to explain why the administration building air conditioning system, 

which is inside a Class I and Class III structure, was not included in LRA Table 2.2-1.

In its response, by letter dated April 27, 2009, the applicant stated the administration building air 

conditioning system provides conditioned air for the administration building office areas (i.e., the 

two upper levels) that are Class III. The administration building air conditioning system does not 

provide cooling to the Class I portion of the administration building and is not located within the 

Class I areas of the building. Therefore, the system does not perform a license renewal 

intended function and is not included within the scope of license renewal. 

Based on its review, the staff finds the applicant‘s response to RAI 2.2-01 acceptable because 

the administration building air conditioning system does not provide cooling to the Class I 

portion of the administration building, is not located within the Class I areas of the building, and 

does not perform a license renewal intended function. Therefore, the staff‘s concern described 

in RAI 2.2-01 is resolved. 

2.2.4 Conclusion

The staff reviewed LRA Section 2.2, the RAI response, and the USAR supporting information to 

determine whether the applicant failed to identify any systems and structures within the scope of 

license renewal. On the basis of its review, as discussed above, the staff concludes that the 

applicant has appropriately identified the systems and structures within the scope of license 

renewal in accordance with 10 CFR 54.4.

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 the following mechanical systems:

● reactor vessel, reactor vessel internals, and reactor coolant system

● engineered safety features

● auxiliary systems

● steam and power conversion systems

The staff evaluation of the mechanical system scoping and screening results applies to all 

mechanical systems reviewed. Those systems that required RAIs to be generated (if any) 

include an additional staff evaluation which specifically addresses the applicant‘s responses to 

the RAIs.

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 
Structures and Components Subject to Aging Management Review

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applicant properly implemented its methodology, the staff‘s review focused on the 

implementation results. This focus allowed the staff to verify that the applicant identified the 

mechanical system SCs that met the scoping criteria and were subject to an AMR, confirming 

that there were no omissions.

The staff‘s evaluation of mechanical systems was performed using the evaluation methodology 

described here using the guidance in SRP-LR Section 2.3, and took into account (where 

applicable) the system functions described in the USAR. 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 meet the license renewal scoping criteria. 

Similarly, the staff evaluated the applicant‘s screening results to verify that all passive, long-lived 

components are subject to an AMR, as required by 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the LRA, applicable sections of the USAR, and 

license renewal drawings, and other licensing basis documents, as appropriate, for each 

mechanical system within the scope of license renewal. The staff reviewed relevant licensing 

basis documents for each mechanical system to confirm that the LRA specified all intended 

functions defined by 10 CFR 54.4(a). The review then focused on identifying any components 

with intended functions defined by 10 CFR 54.4(a) that the applicant may have omitted from the 

scope of license renewal.

After reviewing the scoping results, the staff evaluated the applicant‘s screening results. For 

those SCs with intended functions delineated under 10 CFR 54.4(a), the staff verified the 

applicant properly screened out only: (1) SCs that have functions performed with moving parts 

or a change in configuration or properties, or (2) SCs that are subject to replacement after a 

qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For SCs not meeting 

either of these criteria, the staff confirmed the remaining SCs received 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 describes the reactor vessel, reactor vessel internals, and reactor coolant 

system (RCS) SCs subject to an AMR for license renewal. The applicant described the 

supporting SCs of the reactor vessel, internals, and RCS in the following sections:

● Section 2.3.1.1, ―Reactor Vessel‖

● Section 2.3.1.2, ―Reactor Vessel Internals‖

● Section 2.3.1.3, ―Reactor Coolant System‖

● Section 2.3.1.4, ―Steam Generator‖

Information provided by the applicant from these sections is summarized below in portions titled 

―Summary of Technical Information in the Application.‖
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2.3.1.1 Reactor Vessel

2.3.1.1.1 Summary of Technical Information in the Application

The reactor vessel is a cylindrical shell with a welded, hemispherical lower head and a 

removable, bolted, flanged, and gasketed (O-ring), hemispherical upper head, which was 

replaced in the fall of 2004. The reactor vessel contains the core, core support structures, 

control rods, and other vessel internals associated with the core. Control rod drive mechanisms 

(CRDMs) are positioned on the reactor closure head. The reactor vessel is vertically mounted 

on six individual air-cooled support pads. Four of the support pads are attached to the bottom 

side of the primary nozzles and two of the support pads are attached to vessel-attached support 

brackets. Four reactor coolant and two safety injection nozzles penetrate the reactor vessel. 

The hemispherical welded bottom head has penetrations for movable in-core thimble tubes, 

which are housed in guide tubes and extend from the seal table into the reactor vessel interior 

and mate with the lower internal assembly.

The intended functions of the reactor vessel component types within the scope of license 

renewal include the following:

● serve as a pressure boundary for containing reactor coolant

● provide a barrier against the release of radioactivity

● support and contain the reactor core and core support structure

● support and guide reactor controls and instrumentation

● mitigate thermal shock

The following license renewal drawing provides the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRXK-100-10

LRA Table 2.3.1-1 lists the component types requiring an AMR as follows:

● bottom-mounted instrumentation (BMI) guide tubes/seal table

● bottom head/bottom head instrument tube penetrations

● closure head/closure head CRDM head penetrations

● closure head instrument tubes/lifting lugs/ventilation shroud support structure/stud 

assembly/vent/reactor vessel level instrumentation system head penetrations

● core support guides

● CRDM pressure housings

● primary nozzles/safe ends

● safety injection nozzle
Structures and Components Subject to Aging Management Review

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● upper, intermediate, and lower shell

● vessel flange/vessel flange leakage monitoring lines

● vessel support brackets 

2.3.1.1.2 Staff Evaluation

The staff evaluated the reactor vessel 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 under 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).

2.3.1.1.3 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 omissions. In addition, the staff 

determined whether the applicant failed to identify any components subject to an AMR. The staff 

finds no omissions. On the basis of its review, the staff concludes that there is reasonable 

assurance that the applicant has adequately identified the reactor vessel 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).

2.3.1.2 Reactor Vessel Internals

2.3.1.2.1 Summary of Technical Information in the Application

The reactor vessel internals system consists of the reactor vessel internals and reactor core, 

which includes the nuclear fuel subsystem. The reactor internals, consisting of the upper and 

lower core support structure, are designed to support, align, and guide the core components;

direct the coolant flow to and from the core components; and support and guide the in-core 

instrumentation. The reactor core, consisting of the fuel assemblies and control rods, provides 

and controls the heat source for the reactor operation. The reactor vessel internals include the 

subcomponents that provide structural support, flow distribution, pressure boundary integrity, 

and gamma and neutron shielding for the vessel. All reactor internals are removable from the 

vessel for the purpose of their inspection as well as the inspection of the vessel internal surface.

The intended functions of reactor vessel internals component types within the scope of license 

renewal include the following:

● direct the main flow of coolant through the core

● maintain fuel alignment and limit fuel assembly movement

● provide gamma and neutron shielding

● support, align, and guide the core components and in-core instrumentation

● maintain the RCS pressure boundary

The LRA states that there is no license renewal drawing for the reactor vessel internals system.
Structures and Components Subject to Aging Management Review

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LRA Table 2.3.1-2 lists the component types that require an AMR as follows:

● baffle/former plates and bolts

● BMI columns

● clevis inserts and bolts

● core barrel/core barrel flange/core barrel outlet nozzles

● flux thimble tubes

● head/vessel alignment pins

● hold down spring

● lower core plate

● lower fuel alignment pins

● lower support columns and bolts/lower support forging

● radial support keys

● rod cluster control assembly guide tubes, bolts, and support pins

● secondary core support assembly

● thermal shield

● upper core plate/alignment pins/fuel alignment pins 

● upper instrumentation columns

● upper support columns/bolts/plate assembly

2.3.1.2.2 Staff Evaluation

The staff evaluated the reactor internals 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 under 10 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).

2.3.1.2.3 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 reviewed 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 internals 

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).

2.3.1.3 Reactor Coolant System

2.3.1.3.1 Summary of Technical Information in the Application

The RCS consists of two identical heat transfer loops connected in parallel to the reactor vessel. 

Each loop consists of a reactor coolant pump, steam generator (SG), and interconnecting 

piping. The pressurizer/pressurizer relief system is connected to RCS loop B by a surge line to 

control RCS pressure and to accommodate volume changes of the coolant due to changes in 

temperature. The pressurizer is also designed to accommodate in-surges and out-surges 

caused by load transients. Primary treated water is circulated through the core at a flow rate and 

temperature consistent with achieving the desired reactor core thermal-hydraulic performance.
Structures and Components Subject to Aging Management Review

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The RCS provides a boundary for containing the coolant under operating temperature and 

pressure conditions. It also serves to confine radioactive material and limits to acceptable 

values any release of radioactive material, and provides a means of venting non-condensable 

gases from system high points after an accident.

The intended functions of the RCS component types within the scope of license renewal include 

the following:

● serve as a pressure boundary and limit the release of fission products

● provide RCS pressure control and limit pressure transients

● provide the capability to monitor water level in the reactor vessel

● provide input to the reactor protection and engineered safeguard features equipment

● provide borated water as a moderator and reflector and for chemical shim control

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRM-203, 205, 216, and 350

● LRXK-100-10, 100-131, 100-18, 100-20, 100-28, 100-35, and 100-44

LRA Table 2.3.1-3 lists the component types that require an AMR as follows:

● bolting

● condensing/seal chambers

● flow elements/flow orifices

● piping/tubing

● pressurizer/pressurizer heater sleeves and sheaths, pressurizer integral support 

● pressurizer manway and pressurizer relief tank

● resistance temperature detectors

● rupture discs

● reactor coolant pumps

● reactor coolant pump motor upper and lower bearing oil coolers

● reactor coolant pump thermal barriers

● thermal sleeves

● valves

2.3.1.3.2 Staff Evaluation

The staff evaluated the RCS 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 under 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).
Structures and Components Subject to Aging Management Review

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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 reviewed 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 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 Steam Generators

2.3.1.4.1 Summary of Technical Information in the Application

Two identical SGs transfer heat from the RCS to the secondary system during normal plant 

conditions, producing steam used by the turbine generator. Each SG is a recirculating-type,

vertical shell and tube heat exchanger, where heat transferred from a single-phase fluid at high 

temperature and pressure (the reactor coolant) on the tube side is used to generate a

two-phase (steam/water) mixture at a lower temperature and pressure on the secondary side. 

The steam/water mixture, generated in the secondary side, flows upward through the moisture 

separators to the steam outlet nozzle at the top of the SG.

The lower portion of each SG was replaced with a Westinghouse (Model 54F) replacement unit

in 2001, utilizing Alloy 690 tubes and stainless steel support plates which have improved 

resistance to known corrosion issues affecting pressurized water reactor SGs. The upper

portion of each SG was refurbished. The refurbishment included installing a steam flow limiter 

inside the steam nozzle, installing a replacement feedring assembly with a welded thermal 

sleeve, feedwater nozzle improvements, and modifications to the moisture separation 

equipment.

The intended functions of SG component types within the scope of license renewal include the 

following:

● transfer heat from the RCS to the secondary systems

● provide RCS pressure boundary functions

● confine radioactive material

The following license renewal drawing provides the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRXK-100-10

LRA Table 2.3.1-4 lists the component types that require an AMR as follows:

● anti-vibration bars

● channel head/closure ring/divider plate

● feedwater inlet ring and supports/feedwater inlet ring J nozzles

● feedwater nozzle/feedwater nozzle thermal sleeve

● flow distribution baffle
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● moisture separator assembly

● primary manway cover/diaphragm/bolting

● primary nozzles/safe end/buttering

● secondary manway/handhole covers/bolting

● secondary-side nozzles

● shell – top elliptical head/shell – upper, lower, and transition cone

● steam nozzle/steam nozzle flow restrictor

● tube bundle support hardware/tube plugs/support plates/wrapper/sleeves

● tubesheet

2.3.1.4.2 Staff Evaluation

The staff evaluated the SG 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 under 10 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).

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 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 SG 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).

2.3.2 Engineered Safety Features

LRA Section 2.3.2 describes the engineered safety features systems, along with their SCs,

subject to an AMR for license renewal. The applicant described the supporting SCs of the 

engineered safety features system in the following LRA sections:

● containment vessel internal spray system

● safety injection system

● residual heat removal system

2.3.2.1 Containment Vessel Internal Spray System

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the containment vessel internal spray system as being designed 

to reduce reactor containment vessel pressure during DBAs in conjunction with the containment 

cooling system (which is part of the reactor building ventilation system). This system also 

functions to scrub fission products out of the vessel atmosphere. This is accomplished by 

spraying treated, borated water into the vessel from the spray nozzles located high inside the 

upper dome of the containment. The system is described as having two trains taking suction 
Structures and Components Subject to Aging Management Review

2-43

from a common line; each train consists of a containment vessel internal spray pump with 

associated valves, piping, and spray nozzles. The system can perform long-term spray 

recirculation by being aligned in conjunction with the residual heat removal (RHR) system‘s 

pumps and heat exchangers.

LRA Table 2.3.2-1 identifies the components subject to an AMR for the containment vessel 

internal spray system by component type and intended function.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1, USAR Sections 1.2, 1.2.8, 1.3.4, 1.3.7, 1.5.5, 1.6.1, 1.8 

(item VII), 5.1.1, 5.4.3, 6.4, and Table B.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 under 10 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).

During its review of LRA Section 2.3.2.1, the staff 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.2-1 and 3.2.2-1 for sealants, pump casings, 

screens, piping, and containment isolation components. 

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify if sealants are within the scope of 

license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 28, 2009, 

the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that, based on the American National Standards Institute (ANSI) B31.1 

and the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) 

Code Section III, these consumable items are not pressure-retaining parts. Therefore, they do 

not perform a license renewal intended function in accordance with 10 CFR 54.4(a) and are not 

within the scope of license renewal.

Pumps (RAI 2.3-3). In a letter dated September 28, 2009, the applicant clarified that pump 

casings meet the intended function of pressure boundary for the component type ―Pump‖ and 

are subject to an AMR. 

Screens (RAI 2.3-5). In a letter dated August 28, 2009, the applicant was requested to clarify if 

the containment sump screens are within the scope of license renewal and subject to an AMR. 

In a letter dated September 28, 2009, the applicant stated that screens for the containment 

sump are within the scope of license renewal and are evaluated with the safety injection system. 
Structures and Components Subject to Aging Management Review

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The screens are highlighted on license renewal drawing LRXK-100-28 as being within the scope 

of license renewal and are included in the component type ―Reactor Containment Vessel Sump 

Strainers,‖ in LRA Table 2.3.2-2. The associated AMR results are provided in LRA 

Table 3.2.2-2. 

Containment Isolation (RAI 2.3-4). The staff noted that a separate discussion about containment 

isolation was not included in the LRA. In a letter dated August 28, 2009, the applicant was 

requested to clarify that all components and any supporting systems that are meant for 

containment isolation are included within the scope of license renewal. 

In a letter dated September 28, 2009, the applicant clarified that containment penetrations 

(including the personnel and emergency airlocks and equipment hatch, piping penetrations, 

electrical penetrations, heating and ventilation penetrations, and the fuel transfer tube 

penetration) are within the scope of license renewal and have been evaluated as part of the 

reactor containment vessel in LRA Section 2.4.1; and that the containment isolation valves and 

the associated connecting piping are within the scope of license renewal and included in the 

tables associated with their respective systems in LRA Section 2.3. The AMR results for these 

components are provided in the AMR result tables associated with their respective systems in 

LRA Section 3.0.

Piping (RAI 2.3.2.1-1). In a letter dated August 28, 2009, the staff requested that the applicant

clarify which components of the ―Containment Vessel Internal Spray System‖ shown in license 

renewal drawing LRXK-100-131 are within the scope of license renewal.

In a letter dated September 28, 2009, the applicant stated that the two lines located upstream of 

valve RC-509 shown on license renewal drawing LRXK-100-131 (also shown on license 

renewal drawings LRM-217 and LRXK-100-29) are within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-3, RAI 2.3-4, 

RAI 2.3-5, and RAI 2.3.2.1-1 acceptable because the applicant provided an acceptable 

clarification such that the component types are properly identified as within the scope of license 

renewal, and 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). Therefore, the staff‘s

concerns described in RAI 2.3-2, RAI 2.3-3, RAI 2.3-4, RAI 2.3-5, and RAI 2.3.2.1-1 are 

resolved.

2.3.2.1.3 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. The staff finds no such 

omissions. In addition, the staff 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 vessel internal spray system 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).
Structures and Components Subject to Aging Management Review

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2.3.2.2 Safety Injection System

2.3.2.2.1 Summary of Technical Information in the Application

The safety injection system is an engineered safety system used for emergency core cooling to 

deliver borated water to the reactor core in the event of a loss of coolant accident (LOCA). This 

limits the fuel clad temperature and ensures that the core will remain intact and in place, with its 

heat transfer geometry preserved.

The safety injection system consists of two independent trains, each consisting of a safety 

injection pump with a pressurized lube oil subsystem, and interconnecting piping. The safety 

injection pumps are used to deliver water to the RCS from the refueling water storage tank 

during the injection phase and from the RHR pumps during the recirculation phase. The safety 

injection system also contains two safety injection accumulators. They provide rapid filling of the

lower reactor core plenum in the event of a large break in the RCS.

The intended functions of the safety injection system component types within the scope of 

license renewal include the following:

● form part of the RCS pressure boundary

● provide source of emergency core cooling in response to a LOCA

● provide mechanical support for safety-related SSCs

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRM-202-2, 216, 217, 218, and 350

● LRXK-100-10, 100-131, 100-18, 100-20, 100-28, 100-29, 100-36, and 100-38

LRA Table 2.3.2-2 lists the component types that require an AMR as follows:

● accumulators

● bolting

● flow elements/flow indicators/flow orifices

● piping/tubing

● reactor containment vessel sump strainers

● refueling water storage tank

● safety injection pump gland seal coolers/safety injection pump lube oil coolers

● safety injection pumps/safety injection pump lube oil reservoirs

● sight glass

● valves/valve enclosures

2.3.2.2.2 Staff Evaluation

The staff evaluated the safety injection 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 under 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 
Structures and Components Subject to Aging Management Review

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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).

2.3.2.2.3 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 reviewed 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 safety injection system 

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).

2.3.2.3 Residual Heat Removal System

2.3.2.3.1 Summary of Technical Information in the Application

The RHR system is a dual purpose system, operating as a portion of low pressure safety 

injection system during normal operation, and removing decay heat during plant cooldown and 

shutdown/refueling operations. The RHR system consists of two 100 percent capacity 

redundant trains. Each train consists of an RHR pump, heat exchanger, piping, valves, and 

instrumentation. The RHR removes residual and sensible heat from the reactor core during 

shutdown and reduces the temperature of the RCS during plant cooldown and shutdown 

operations. During accident conditions, the RHR is aligned to take suction from the refueling 

water storage tank to provide emergency core cooling low head safety injection. It may also 

provide backup cooling for the spent fuel pool.

The intended functions of the RHR system component types within the scope of license renewal 

include the following:

● form a part of the RCS pressure boundary

● remove residual and sensible heat from the core

● provide low head safety injection and recirculation during accident conditions

● fill and drain the refueling cavity

● provide mechanical support for safety-related SSCs

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRM-217, 218, and 350

● LRXK-100-10, 100-18, 100-19, 100-20, 100-28, 100-29, 100-36, and 100-44

LRA Table 2.3.2-3 lists the component types that require an AMR as follows:

● bolting

● expansion tanks

● flow elements

● miniflow orifices

● piping/tubing
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● residual heat exchangers

● RHR pumps

● rupture disks

● shaft seal heat exchangers

● valves

2.3.2.3.2 Staff Evaluation

The staff evaluated the RHR 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 under 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).

2.3.2.3.3 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 reviewed 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 

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

LRA Section 2.3.3 identifies the auxiliary systems‘ SCs subject to an AMR for license renewal. 

The applicant described the supporting SCs of the auxiliary systems in the following LRA 

sections:

● Section 2.3.3.1, ―New Fuel Storage‖

● Section 2.3.3.2, ―Spent Fuel Storage‖ 

● Section 2.3.3.3, ―Spent Fuel Pool Cooling‖

● Section 2.3.3.4, ―Fuel Handling‖

● Section 2.3.3.5, ―Cranes (Excluding Fuel Handling) System‖

● Section 2.3.3.6, ―Service Water System‖

● Section 2.3.3.7, ―Component Cooling System‖

● Section 2.3.3.8, ―Station and Instrument Air System‖

● Section 2.3.3.9, ―Chemical and Volume Control System‖

● Section 2.3.3.10, ―Control Room Air Conditioning System‖

● Section 2.3.3.11, ―Auxiliary Building Air Conditioning System‖

● Section 2.3.3.12, ―Auxiliary Building Special Ventilation and Steam Exclusion System‖

● Section 2.3.3.13, ―Auxiliary Building Ventilation System‖

● Section 2.3.3.14, ―Reactor Building Ventilation System‖

● Section 2.3.3.15, ―Turbine Building and Screenhouse Ventilation System‖

● Section 2.3.3.16, ―Shield Building Ventilation System‖

● Section 2.3.3.17, ―Technical Support Center Ventilation System‖

● Section 2.3.3.18, ―Fire Protection System‖
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● Section 2.3.3.19, ―Diesel Generator System‖

● Section 2.3.3.20, ―Circulating Water System‖

● Section 2.3.3.21, ―Gaseous Waste Processing and Discharge System‖

● Section 2.3.3.22, ―Liquid Waste Processing and Discharge System‖

● Section 2.3.3.23, ―Radiation Monitoring System‖

● Section 2.3.3.24, ―Makeup and Demineralized Water System‖

● Section 2.3.3.25, ―Service Water Pretreatment System‖

● Section 2.3.3.26, ―Miscellaneous Drains and Sumps System‖

● Section 2.3.3.27, ―Miscellaneous Gas System‖

● Section 2.3.3.28, ―Potable Water System‖

● Section 2.3.3.29, ―Primary Sampling System‖

Auxiliary Systems Generic Requests for Additional Information. As part of the staff‘s review, the 

following RAI identified instances of license renewal drawing errors where the continuation 

notation for piping from one license renewal drawing to another license renewal drawing could 

not be identified or was incorrect.

In RAI 2.3-01, dated April 3, 2009, the staff noted drawings for which drawing numbers and/or 

locations for the continuations could not be identified, or could not be located where identified. 

The applicant was requested to provide the drawing continuation locations. 

In its response dated April 27, 2009, the applicant provided the requested drawing locations.

Based on its review, the staff finds the applicant‘s response to RAI 2.3-01 acceptable because 

the applicant identified the applicable drawing locations on the license renewal drawings.

RAI 2.3-01(a). By letter dated July 7, 2009, the staff noted that while reviewing the applicant‘s 

response to RAI 2.3-01, on LRXK-101-17A, location C-3, a piping section continued to the ―GLD 

STM LEAKOFF TO GLAND CONDENSER‖ that was not included in-scope. Similar piping at 

location C-7 was included in-scope for 10 CFR 54.4(a)(2). The applicant was requested to 

provide a basis for not including the piping continuing to ―GLD STM LEAKOFF TO GLAND 

CONDENSER‖ within the scope of license renewal for 10 CFR 54.4(a)(2).

In its response dated August 6, 2009, the applicant stated that the ―GLD STM LEAKOFF TO 

GLAND CONDENSER‖ is within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant‘s response to RAI 2.3-01(a) acceptable 

because the applicant stated that the subject piping is within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2).

2.3.3.1 New Fuel Storage System

2.3.3.1.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 describes the new fuel storage system as a dry pit adjacent to the spent 

fuel pool, with a Class I dry storage rack able to store 44 new fuel assemblies. The system is 

classified as in-scope because it provides for storage of new fuel and maintains those 

assemblies in a subcritical configuration.

LRA Table 2.3.3-1 contains the components subject to an AMR.
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2.3.3.1.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the new fuel storage system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.2 Spent Fuel Storage System

2.3.3.2.1 Summary of Technical Information in the Application

LRA Section 2.3.3.2 describes spent fuel storage. The applicant stated:

The spent fuel assemblies are stored in high-density vertical Class I storage 

racks in the north and south spent fuel pools, and in the north end of the fuel 

transfer canal pool.

The north and south spent fuel pool storage racks are constructed with boron 

carbide neutron absorber plates located between a stainless steel inner and 

outer wall. These spent fuel racks have been modified to allow venting of the 

space that contains the boron carbide neutron absorber plate to prevent bulging 

of the stainless steel inner and outer walls.

The fuel transfer canal pool storage racks are constructed with Boral neutron 

absorber plates between a stainless steel inner and outer wall. These racks have 

been designed such that the enclosures that contain the Boral are vented. The 

north spent fuel pool storage racks can accommodate 270 spent fuel assemblies, 

the south spent fuel pool storage racks can accommodate 720 spent fuel 

assemblies and the fuel transfer canal pool storage racks can accommodate 215 

spent fuel assemblies.

LRA Tables 2.3.3-2 and 3.3.2-2 identify that the spent fuel storage racks are within the scope of 

license renewal and subject to an AMR. The intended function of the spent fuel storage racks is 

to provide storage for spent fuel assemblies and maintain a subcritical configuration which is 

within the scope of license renewal based on the criteria of 10 CFR 54.4(a)(1).

2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2, and USAR Section 9.5.1, Section 9.5.2, Table 9.5-1,

and Table B.2-1 using the evaluation methodology described in SER Section 2.3 and the 

guidance in the SRP-LR.

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 under 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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2.3.3.2.3 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 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 spent fuel storage 

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), and that the aging management of the 

spent fuel storage is consistent with the GALL Report and is, therefore, acceptable.

2.3.3.3 Spent Fuel Pool Cooling System

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 describes the spent fuel cooling system. The system functions to remove 

decay heat from the spent fuel stored in the spent fuel pool and maintain borated water 

temperature within the design limits. The system contains pumps, heat exchangers, piping, and 

connections to filter, cool, and recirculate cooling water to and from the pool locations. The 

system can also provide water cleanup capability following a refueling on or offload to or from 

the reactor core. 

The applicant stated that the system is classified as in-scope because it:

● provides a pressure boundary for the spent fuel pool and the refueling water storage 

tank

● provides heat removal from the spent fuel pool

● provides an emergency makeup flowpath from the service water system to the spent fuel 

pool

● contains nonsafety-related components spatially-oriented such that they could affect 

safety functions of safety-related SSCs

● contains nonsafety-related piping attached to safety-related piping, which is seismically 

designed and supported up to the first structural anchor location beyond the 

safety/nonsafety boundary 

LRA Table 2.3.3.3 contains the spent fuel pool cooling system components subject to an AMR.

2.3.3.3.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the spent fuel pool cooling system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
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2.3.3.4 Fuel Handling System

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 describes the fuel handling system. The applicant stated that the system 

contains load handling cranes and other refueling support devices. Four sets of components are 

classified within the scope of license renewal:

● auxiliary building fuel upending rig winch

● fuel pool bridge crane

● fuel transfer equipment

● manipulator crane

The applicant classified the system as within scope because it contains safety-related 

equipment to handle and store fuel assemblies, and because of structural members whose 

failure could impact the function of safety-related SSCs. Finally, the applicant noted that the fuel 

transfer tube and gate valve are evaluated as part of the reactor containment vessel structure.

LRA Table 2.3.3-4 contains the components subject to an AMR.

2.3.3.4.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and USAR, the staff concludes that the applicant has appropriately identified the fuel 

handling system mechanical components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified the system components 

subject to an AMR, in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.5 Cranes (Excluding Fuel Handling) System

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 describes the cranes (excluding fuel handling) system as being those 

cranes and devices throughout the plant that support maintenance and operational activities. 

The following cranes and devices are included:

● polar crane

● auxiliary building crane

● turbine building crane

● reactor building pedestal crane

● diesel generators 1A and 1B monorails

● shield building annulus trolley

● boric acid concentrates filter hoist

● filter room hoist

The applicant placed the system within scope because it contains structural members whose 

failure could affect safety-related SSCs.

LRA Table 2.3.3-5 contains the components subject to an AMR.
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2.3.3.5.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA and USAR, the staff concludes that the applicant has appropriately identified the cranes 

(excluding fuel handling) system mechanical components within the scope of license renewal, 

as required by 10 CFR 54.4(a), and that the applicant has adequately identified the system 

components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.6 Service Water System

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 describes the service water system. The applicant described the system as 

an open-cycle cooling system that provides cooling to various safety-related and 

nonsafety-related components. The system is described as containing two redundant headers, 

each of which is capable of providing normal and post-accident heat removal requirements. 

Major equipment includes traveling screens, pumps, associated piping, service water piping up 

to the circulating water system discharge tunnel, inter-system cross connects, and portions of 

the chemical injection system. 

Major cooling loads include the following:

● component cooling heat exchangers

● containment fan coil units

● control room chillers

● emergency diesel generators (EDGs)

The applicant also stated that the system supplies water to the fire protection jockey pump, 

provides an alternate supply to the auxiliary feedwater system, and provides emergency 

makeup to the spent fuel pool and the component cooling systems.

The applicant classified the system as within scope for several reasons, some of which are 

listed as follows:

● provides safety-related cooling to safety-related SSCs

● isolates nonsafety-related portions to ensure cooling to the safety-related SSCs

● provides reactor containment vessel isolation following an accident

● provides various sources of emergency or alternate makeup/water supplies to systems 

described above

● contains spatially oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains components required for safe shutdown following a HELB

● includes components that are EQ, and that fulfill fire protection requirements
Structures and Components Subject to Aging Management Review

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The applicant also stated that passive portions of the traveling water screens are evaluated with 

the screenhouse structure.

LRA Table 2.3.3-6 contains the components subject to an AMR.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 and USAR Sections 6.2, 6.3.1, 6.4.1, 6.6.2, 9.6.2, 

Table 6.2-9, Table B.2-1, Figure 9.6-1, Figure 9.6-2, Figure 9.6-3, and Figure 9.6-4, and the 

license renewal drawings using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3. The staff 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 2.3.3.6-01, dated April 3, 2009, the staff noted license renewal drawing LRM-202-3, 

location F-11, shows a 12-inch line out of the turbine oil cooler as in-scope for license renewal 

for 10 CFR 54.4(a)(2), whereas the 3-inch line connected to this line and going to the fan coil 

units is shown as not in-scope. However, the continuation of this 3-inch line on license renewal 

drawing LRM-606, location A8, shows this line is in-scope under 10 CFR 54.4(a)(2). The 

applicant was requested to provide additional information to explain why there is a difference in 

scope classification between license renewal drawing LRM-202-3 and LRM-606.

In its response dated April 27, 2009, the applicant clarified that the 3-inch line is incorrectly 

shown as not in-scope and it should be highlighted to show it is within scope under

10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.6-01 acceptable 

because the applicant clarified the scoping classification for the 3-inch line in question. 

Therefore, the staff‘s concern described in RAI 2.3.3.6-01 is resolved.

In RAI 2.3.3.6-02, dated April 3, 2009, the staff noted license renewal drawing LRM-202-2, 

location H-9, shows valve SW(T)-251 in-scope for 10 CFR 54.4(a)(1). However, the same valve 

on license renewal drawing LRM-394, location E-7, is shown in-scope for 10 CFR 54.4(a)(2). 

The applicant was requested to provide additional information to explain why there is a 

difference of the in-scope classification between drawings LRM-202-2 and LRM-394.

In its response dated April 27, 2009, the applicant clarified that valve SW(T)-251 is in-scope for 

10 CFR 54.4(a)(3) in support of 10 CFR 50.48 fire protection regulations. The applicant stated 

that valve SW(T)-251 on LRM-394, location E-7, is incorrectly shown as in-scope for 

10 CFR 54.4(a)(2) and should be highlighted to show it as in-scope for 10 CFR 54.4(a)(3).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.6-02 acceptable 

because the applicant stated valve SW(T)251 on LRM-394 is incorrectly shown as in-scope for 

10 CFR 54.4(a)(2) and should be highlighted to show it is in-scope for 10 CFR 54.4(a)(3). 

Therefore, the staff‘s concern described in RAI 2.3.3.6-02 is resolved.

In RAI 2.3.3.6-03, dated April 3, 2009, the staff noted license renewal drawing LRM-202-2, 

locations D-9 and D-10, shows 11⁄2-inch lines downstream of valves SW1260 and SW1263 as 

in-scope for 10 CFR 54.4(a)(2). However, the continuations of these 11⁄2-inch lines on license 

renewal drawing LRM-606, locations G10 and G-11, are shown in-scope for 10 CFR 54.4(a)(1).
Structures and Components Subject to Aging Management Review

2-54

The applicant was requested to provide additional information explaining why there is a 

difference in scope classification between drawings LRM-202-2 and LRM-606.

In its response dated April 27, 2009, the applicant clarified that the 11⁄2-inch lines on license 

renewal drawing LRM-606, locations G-10 and G-11, are shown in-scope for 10 CFR 54.4(a)(3) 

in support of 10 CFR 50.48 fire protection regulations. Additionally the 11⁄2-inch lines 

downstream of valves SW1260 and SW1263 on LRM-202-2 are incorrectly shown as in-scope 

for 10 CFR 54.4(a)(2) and should be highlighted to show them in-scope for 10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.6-03 acceptable 

because the applicant stated the 11⁄2-inch lines downstream of valves SW1260 and SW1263 on 

LRM-202-2 are incorrectly shown as in-scope for 10 CFR 54.4(a)(2) and should be highlighted 

to show them in-scope for 10 CFR 54.4(a)(3). Therefore, the staff‘s concern described in 

RAI 2.3.3.6-03 is resolved.

In RAI 2.3.3.6-04, dated April 3, 2009, the staff noted license renewal drawing LRM-202-2, 

locations C-5 and C-6, shows 11⁄2-inch lines downstream of valves SW850 and SW853 as 

in-scope for 10 CFR 54.4(a)(2). However, the continuations of these 11⁄2-inch lines on license 

renewal drawing LRM-606, locations B-5 and B-6, are shown in-scope for 10 CFR 54.4(a)(1).

The applicant was requested to provide additional information explaining why there is a 

difference in the scope classification between drawings LRM-202-2 and LRM-606.

In its response dated April 27, 2009, the applicant clarified that the 11⁄2-inch lines on license 

renewal drawing LRM-606, locations B-5 and B-6, are shown in-scope for 10 CFR 54.4(a)(3) in 

support of 10 CFR 50.48 fire protection regulations. Additionally, the 11⁄2-inch lines downstream 

of valves SW850 and SW853 on LRM-202-2 are incorrectly shown as in-scope for 

10 CFR 54.4(a)(2) and should be highlighted to show them as in-scope for 10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.6-04 acceptable 

because the 11⁄2-inch lines downstream of valves SW850 and SW853 on LRM-202-2 are 

incorrectly shown as in-scope for 10 CFR 54.4(a)(2) and should be highlighted to show them as 

in-scope for 10 CFR 54.4(a)(3). Therefore, the staff‘s concern described in RAI 2.3.3.6-04 is 

resolved.

2.3.3.6.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and license renewal drawings to determine 

whether the applicant failed to identify any components within the scope of license renewal. In 

addition, the staff determined whether the applicant failed to identify any components subject to 

an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified 

the service water system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the service water 

system mechanical components subject to an AMR, in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.7 Component Cooling Water System

2.3.3.7.1 Summary of Technical Information in the Application

LRA Section 2.3.3.7 describes the component cooling system as a closed-loop system which 

serves as an intermediate cooling loop and boundary between nuclear steam supply system 
Structures and Components Subject to Aging Management Review

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(NSSS) systems and the service water system. Major components include the component 

cooling pumps, component cooling heat exchangers, surge tank, NSSS load coolers, and 

associated piping. The applicant described loads cooled and normal operation as follows: 

Some of the major components cooled by the system include the RHR heat 

exchangers, reactor coolant pumps, letdown and seal water heat exchangers, 

and primary sample coolers. During normal operation, one component cooling 

pump and both component cooling heat exchangers are in service to 

accommodate the heat loads. Heat from the component cooling system is 

transferred to the service water system. The component cooling surge tank 

accommodates expansion, contraction and in-leakage of water. A radiation 

monitor is provided to detect radioactive in-leakage. Demineralized water is the 

normal source of makeup water to the component cooling system, although the 

service water system can be used as an emergency source of makeup water.

The applicant classified the system as in-scope for several reasons, some of which are listed as 

follows:

● provides cooling to safety-related SSCs

● provides for isolation of the reactor coolant pump thermal barrier heat exchanger in case 

of a leak from the RCS through it into the component cooling system

● provides part of reactor containment vessel pressure integrity and isolation post accident

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● includes components that are EQ and that support fire protection requirements

The applicant stated that heat exchangers cooled by the component cooling system are 

evaluated as part of their associated systems, and not as part of the component cooling system.

LRA Table 2.3.3-7 contains the components subject to an AMR.

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7 and USAR Section 9.3.1, Table 9.3-1, Table 9.3-5, 

Table B.2-1, Figure 9.3-1, Figure 9.3-2, and Figure 9.3-3, and the license renewal drawings 

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. The staff 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 2.3.3.7-01, dated April 3, 2009, the staff noted license renewal drawing LRXK-100-20, 

location E-2, shows the distillate cooler and evaporator condenser in-scope for 

10 CFR 54.4(a)(2) while the pipelines entering and leaving the distillate cooler and evaporator 

condenser are shown in-scope for 10 CFR 54.4(a)(1) or (a)(3). The applicant was requested to 

provide additional information explaining why there is a difference in scope classification 

between the attached piping and the distillate cooler and evaporator condenser.
Structures and Components Subject to Aging Management Review

2-56

In its response dated April 27, 2009, the applicant stated the distillate cooler and evaporator 

condenser are subcomponents of the waste evaporator, which is no longer in operation. The 

component cooling piping is safety-related and is within the scope of license renewal for 

10 CFR 54.4(a)(1). The nonsafety-related distillate cooler and evaporator condenser shells are 

included within the scope of license renewal for 10 CFR 54.4(a)(2) since they are relied on to 

provide structural seismic support for the attached safety-related component cooling piping. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.7-01 acceptable 

because the applicant clarified the scoping classification of the pipelines, distillate cooler, and 

evaporator condenser. Therefore, the staff‘s concern described in RAI 2.3.3.7-01 is resolved.

2.3.3.7.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and license renewal drawings to determine 

whether the applicant failed to identify any components within the scope of license renewal. In 

addition, the staff determined whether the applicant failed to identify any components subject to 

an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified 

the component cooling system mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the component 

cooling system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.8 Station and Instrument Air System

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 describes the station and instrument air system. The applicant described 

the system as that which supplies oil-free air for operation of various components, instruments,

and hose connections. The system‘s major components include compressors (both high and 

low capacity), instrument air dryers, air accumulator tanks, filters, and associated piping.

The applicant classified the system as in-scope for several reasons, some of which are 

summarized as follows:

● provides reactor containment vessel isolation

● provides back-up air supply to important air-operated valves and dampers

● provides control room isolation

● provides post-LOCA hydrogen control

● includes EQ components and components that support fire protection and SBO

LRA Table 2.3.3-8 contains the components subject to an AMR.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3, USAR Table B.2-1, and the license renewal drawings 

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. The staff 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 2.3.3.8-01, dated April 3, 2009, the staff noted license renewal drawing LRM-213-4, 

location H-5, shows a continuation ―To POS. FOR CV-31396 SHEET 3 D1‖ as in-scope for 

10 CFR 54.4(a)(2). The continuation on license renewal drawing LRM-213-3, location D-1, does 

not show this section of piping to be in-scope. The applicant was requested to provide additional 

information to clarify the scoping classification of this section of piping.

In its response dated April 27, 2009, the applicant stated the continuation of this line on license 

renewal drawing LRM-213-3 was incorrectly not highlighted, but is within the scope of license 

renewal for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.8-01 acceptable 

because the applicant clarified the scoping classification of the pipeline. Therefore, the staff‘s 

concern described in RAI 2.3.3.8-01 is resolved.

In RAI 2.3.3.8-02, dated April 3, 2009, the staff noted license renewal drawing LRM-213-3, 

location A-3, downstream of valve SA-201 shows a continuation to license renewal drawing 

LRM-213-1, location B-5, as in-scope for 10 CFR 54.4(a)(2). The continuation on license 

renewal drawing LRM-213-1 is not in-scope. The applicant was requested to provide additional 

information to clarify the scoping classification for this section of piping.

In its response dated April 27, 2009, the applicant stated the station air system pressure 

sensing line from the station air piping shown on license renewal drawing LRM-213-1 through 

valve SA-201, to the positioner for CV-31308 was incorrectly highlighted on license renewal 

drawing LRM-213-3 and is not within the scope of license renewal, as is the continuation of this 

sensing line on license renewal drawing LRM-213-1. The applicant also identified that the valve 

positioner output line to the CV-31308 valve actuator, shown on license renewal drawing 

LRM-213-1 (location B-5), was incorrectly not highlighted, but is within the scope of license 

renewal for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.8-02 acceptable 

because the applicant clarified the scoping classification of the pipeline. Therefore, the staff‘s 

concern described in RAI 2.3.3.8-02 is resolved.

In RAI 2.3.3.8-03, dated April 3, 2009, the staff noted license renewal drawing LRM-213-5, 

location A-12, shows a continuation ―To POS. FORCV-31120 SHT 206‖ as in-scope for 

10 CFR 54.4(a)(2). The continuation on LRM-213-2, location D-6, shows this section of piping to 

be in-scope for 10 CFR 54.4(a)(1) or (a)(3). The applicant was requested to provide additional 

information to clarify the scoping classification of this section of piping.

In its response dated April 27, 2009, the applicant confirmed that the air line to the positioner for 

CV-31120 is within the scope of license renewal for 10 CFR 54.4(a)(2). The applicant further 

stated the continuation of the line on license renewal drawing LRM-213-2 was incorrectly not 

highlighted, but is within the scope of license renewal for 10 CFR 54.4(a)(2). The line from the 

positioner to CV-31120 is correctly highlighted as within the scope of license renewal for 

10 CFR 54.4(a)(3) for fire protection. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.8-03 acceptable 

because the applicant clarified the scoping classification of the pipelines. Therefore, the staff‘s 

concern described in RAI 2.3.3.8-03 is resolved.
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2.3.3.8.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and license renewal drawings to determine 

whether the applicant failed to identify any components within the scope of license renewal. In 

addition, the staff determined whether the applicant failed to identify any components subject to 

an AMR. On the basis of its review, the staff concludes the applicant has appropriately identified 

the station and instrument air system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

station and instrument air system mechanical components subject to an AMR, in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.9 Chemical and Volume Control System

2.3.3.9.1 Summary of Technical Information in the Application

The chemical and volume control system (CVCS) is a support system for the RCS during all 

normal modes of plant operation. The CVCS provides a method for controlling the inventory, 

boration, and chemistry of the RCS and supplies seal injection flow for the reactor coolant 

pumps. It also provides a method for boron recovery and emergency boration. The CVCS 

consists of the volume control tank, charging pumps, letdown and excess letdown heat 

exchangers, seal water heat exchanger, regenerative heat exchanger, letdown orifices, filters, 

piping, valves, and instrumentation.

The intended functions of CVCS component types within the scope of license renewal include 

the following:

● form part of the RCS pressure boundary

● maintain the required water inventory in the RCS

● provide cooling water to the reactor coolant pump seal

● provide boron to maintain the required shutdown margin during refueling

● provide mechanical support for safety-related SSCs

The following license renewal drawings provide the details of SSCs for the scope of license 

renewal and subject to an AMR:

● LRM-216, 218, 350, 368, 385, and 605-1

● LRXK-100-10, 100-131, 100-132, 100-18, 100-19, 100-20, 100-29, 100-35, 100-36, 

100-37, 100-38, 100-400, and 100-44

LRA Table 2.3.3.9 lists the component types that require an AMR as follows:

● absorption tower

● batching tank

● bolting

● boric acid tanks

● chemical mixing tanks

● demineralizers and ion exchangers

● evaporator/evaporator condenser
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● filter elements/filter housings

● flow elements/flow indicators/flow orifices

● holdup tanks

● letdown heat exchanger

● monitor tanks

● piping/tubing

● pulsation dampers

● pumps

● regenerative heat exchanger

● seal water heat exchanger

● standpipes

● stripping column

● suction stabilizers

● tank heaters

● valves

● vent condenser

● volume control tank

2.3.3.9.2 Staff Evaluation

The staff evaluated the CVCS functions 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 under 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).

2.3.3.9.3 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 reviewed 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 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).

2.3.3.10 Control Room Air Conditioning System

2.3.3.10.1 Summary of Technical Information in the Application

LRA Section 2.3.3.10 describes the control room air conditioning system. The applicant stated 

that the system supplies conditioned and controlled air to the control room environmental zone 

(including the control room and other spaces), keeping the control room under positive air 

pressure with respect to the auxiliary building and the turbine building, to prevent air in-leakage, 

especially during accidents. The applicant stated that the system is composed of two, 

100 percent capacity trains of air conditioning units along with associated heating coils, filters, 

dampers, and ductwork. 
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The applicant classified the system as in-scope because it supplies cooling air for the control 

room environmental zone in both normal and post-accident conditions, contains safety-related 

instrumentation and controls, supports safe shutdown for HELB accidents, and has SSCs that

support EQ and fire protection.

LRA Table 2.3.3-10 contains the components subject to an AMR.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10 and USAR Sections 9.6.4, 10A.3.3, 10A.4.3, 11.2.4, 

and Table B2-1 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 under 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).

During its review of LRA Section 2.3.3.10, the staff identified area(s) 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.3-10 and 3.3.2-10 for sealants, pump 

casings, screens, and control room post-accident (CRPA) recirculation filter housings.

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Pumps (RAI 2.3-3). In a letter dated September 28, 2009, the applicant clarified that pump 

casings meet the intended function of pressure boundary for the component type ―Pump‖ and 

are subject to an AMR.

Screens (RAI 2.3-5). In a letter dated September 28, 2009, the applicant clarified that the 

component types ―Missile Hood and Bird Screen,‖ ―Exhaust Vent Stack, Missile Cover and 

Screen,‖ and ―Fixed Louvers‖ are listed in LRA Table 2.4.2-3. The component type ―Exhaust 

Vent Stack, Missile Cover and Screen‖ is associated with the auxiliary building vent stack, which 

handles exhaust from the other heating, ventilation, and air conditioning (HVAC) systems 

including the control room air conditioning system.
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Filter Housings (RAI 2.3.3.10-1). In a letter dated August 28, 2009, the applicant was requested 

to clarify whether the filter housings are within the scope of license renewal and subject to an 

AMR.

In a letter dated September 28, 2009, the applicant clarified that the CRPA recirculation filter 

assembly housings and filter element housings are within the scope of license renewal and are 

included in the component type ―CRPA Recirculation Filter Assemblies,‖ in LRA Table 2.3.3-10. 

The associated AMR results are provided in LRA Table 3.3.2-10.

Based on the above, the applicant concluded that a revision is not necessary for LRA 

Tables 2.3.3-10 and 3.2.2-10.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-3, RAI 2.3-5, 

and RAI 2.3.3.10-1 acceptable because the applicant provided an acceptable clarification such 

that the component types are properly identified as within the scope of license renewal, and 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). Therefore, the staff‘s concerns 

described in RAI 2.3-2, RAI 2.3-3, RAI 2.3-5, and RAI 2.3.3.10-1 are resolved.

2.3.3.10.3 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. The staff finds no such 

omissions. In addition, the staff 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 room air conditioning system 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).

2.3.3.11 Auxiliary Building Air Conditioning System

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 describes the auxiliary building air conditioning system. The applicant 

stated that the system operates to maintain auxiliary building environmental conditions. The 

system is described as containing a package chiller unit that is cooled by service water, both 

high-efficiency and charcoal air filters, and associated ductwork and instrumentation. 

The applicant stated that the system is within the scope of license renewal for several reasons, 

some of which are summarized as follows:

● maintains certain zone air pressure boundaries during accidents

● contains nonsafety-related, spatially-oriented components whose failure could impact 

safety functions of safety-related SSCs

● contains components relied upon during safe shutdowns following a HELB

● contains components that support EQ and fire protection
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LRA Table 2.3.3-11 contains the components subject to an AMR.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11 and USAR Table B.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 under 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).

During its review of LRA Section 2.3.3.11, the staff identified area(s) 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.3-11 and 3.3.2-11 for the sealants, screens, 

condenser tubesheets and condenser tubes, filter element housings for auxiliary building supply 

vent units, spent fuel pool exhaust filter assembly housings, heating coils, cooling coils, and 

tubing.

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Screens (RAI 2.3-5). In a letter dated September 28, 2009, the applicant clarified that the 

component types ―Missile Hood and Bird Screen,‖ ―Exhaust Vent Stack, Missile Cover and 

Screen,‖ and ―Fixed Louvers‖ are listed in LRA Table 2.4.2-3. The component type ―Exhaust 

Vent Stack, Missile Cover and Screen‖ is associated with the auxiliary building vent stack, which 

handles exhaust from the other HVAC systems including the auxiliary building air conditioning 

system.

Condenser Tubesheets and Tubes (RAI 2.3.3.11-1). In a letter dated August 28, 2009, the 

applicant was requested to clarify whether the condenser tubesheets and tubes are within the 

scope of license renewal and subject to an AMR.

In a letter dated September 28, 2009, the applicant clarified that the condenser tubesheets and 

tubes do not perform an intended function as a seismic anchor and, therefore, are not within the 

scope of license renewal. The condenser shell and channel heads are required for the 

condenser to perform its intended function and are included in the component type 
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―Condensers,‖ in LRA Table 2.3.3-11. The associated AMR results are provided in LRA 

Table 3.3.2-11.

Filter Housings (RAI 2.3.3.11-1). In a letter dated August 28, 2009, the applicant was requested 

to clarify whether the filter housings are within the scope of license renewal and subject to an 

AMR.

In a letter dated September 28, 2009, the applicant clarified that the element housings for 

auxiliary building supply vent units and spent fuel pool exhaust filter assembly housings are 

included within the scope of license renewal and included in the component type ―Filter 

Assemblies,‖ in LRA Table 2.3.3-13. The associated AMR results are provided in LRA 

Table 3.3.2-13.

Heating Coils and Cooling Coils (RAI 2.3.3.11-1). In a letter dated August 28, 2009, the 

applicant was requested to clarify whether the heating coils and cooling coils are within the 

scope of license renewal and subject to an AMR.

In a letter dated September 28, 2009, the applicant clarified that the heating coils associated 

with the auxiliary building air supply ventilation units are included within the component type 

―Heating Coils,‖ in LRA Table 2.3.3-13. The associated AMR results are provided in LRA 

Table 3.3.2-13. There are no heating coils or cooling coils associated with the spent fuel pool 

exhaust filter assemblies.

Tubing (RAI 2.3.3.11-1). In a letter dated August 28, 2009, the applicant was requested to clarify

whether the tubing is within the scope of license renewal and subject to an AMR.

In a letter dated September 28, 2009, the applicant clarified that the tubing associated with the 

spent fuel pool exhaust filter assemblies and the auxiliary building air supply ventilation units is 

within the scope of license renewal and included in the component type ―Tubing,‖ in LRA 

Table 2.3.3-13. The associated AMR results are provided in LRA Table 3.3.2-13. Additionally, 

for all the ventilation systems, the instrument air tubing for the air operated dampers is included 

within the scope of license renewal and evaluated with the station and instrument air system 

discussed in LRA Section 2.3.3.8.

Based on the above, the applicant concluded that a revision is not necessary for LRA 

Tables 2.3.3-11 and 3.2.2-11.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-5, and 

RAI 2.3.3.11-1 acceptable because the applicant provided an acceptable clarification such that 

the component types are properly identified as within the scope of license renewal, and 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). Therefore, the staff‘s concerns 

described in RAI 2.3-2, RAI 2.3-5, and RAI 2.3.3.11-1 are resolved.

2.3.3.11.3 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. The staff finds no such 

omissions. In addition, the staff 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 
Structures and Components Subject to Aging Management Review

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identified the auxiliary building air conditioning system 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).

2.3.3.12 Auxiliary Building Special Ventilation and Steam Exclusion System

2.3.3.12.1 Summary of Technical Information in the Application

LRA Section 2.3.3.12 describes the auxiliary building special ventilation and steam exclusion 

system. The applicant stated that this ventilation system collects and filters potential 

containment vessel leakage that may bypass the shield building annulus (thus preventing it from 

reaching the environment) and that it provides emergency ventilation in some areas of the 

auxiliary building during certain accident conditions. The system contains two parallel trains of 

exhaust equipment, with dampers, exhaust fans, associated ductwork, and filters. 

The applicant stated that the system is in-scope because it collects and filters potentially 

radioactive leakage during a DBA, provides emergency ventilation during certain accidents, 

contains components used in safe shutdown scenarios such as the HELB, and contains 

components that support EQ and fire protection.

LRA Table 2.3.3-12 contains the components subject to an AMR.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12 and USAR Sections 1.2.8, 5.7.3. 7.2.1, 9.6.5, 11.2.1, 

14.3.5, and Table B.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 under 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).

During its review of LRA Section 2.3.3.12, the staff 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.3-12 and 3.3.2-12 for the sealants, screens,

and filter housings.

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 
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consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Screens (RAI 2.3-5). In a letter dated September 28, 2009, the applicant clarified that the 

component types ―Missile Hood and Bird Screen,‖ ―Exhaust Vent Stack, Missile Cover and 

Screen,‖ and ―Fixed Louvers‖ are listed in LRA Table 2.4.2-3. The component type ―Exhaust

Vent Stack, Missile Cover and Screen‖ is associated with the auxiliary building vent stack, which 

handles exhaust from the other HVAC systems including auxiliary building special ventilation 

and steam exclusion system.

Filter Housings (RAI 2.3.3.12-1). In a letter dated August 28, 2009, the applicant was requested 

to clarify whether the filter housings are within the scope of license renewal and subject to an 

AMR.

In a letter dated September 28, 2009, the applicant clarified that the filter element housings are 

within the scope of license renewal and are included in the component type ―Zone SV Exhaust 

Filter Assemblies,‖ in LRA Table 2.3.3-12. The associated AMR results are provided in LRA 

Table 3.3.2-12.

Based on the above, the applicant concluded that a revision is not necessary for LRA 

Tables 2.3.3-12 and 3.2.2-12.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-5, and 

RAI 2.3.3.12-1 acceptable because the applicant provided acceptable clarifications such that 

the component types are properly identified as within the scope of license renewal, and 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). Therefore, the staff‘s concerns 

described in RAI 2.3-2, RAI 2.3-5, and RAI 2.3.3.12-1 are resolved. 

2.3.3.12.3 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. The staff finds no such 

omissions. In addition, the staff 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 special ventilation and steam exclusion system 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).

2.3.3.13 Auxiliary Building Ventilation System

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 describes the auxiliary building ventilation system. The applicant stated 

that this system provides general heating and ventilation for the auxiliary building, including 

such locations as general floor areas, equipment rooms, the spent fuel pool area, and the 

control room area. The system is designed to maintain air flows from cleaner, lower-level 

radioactive spaces to areas of potentially higher activity in order to minimize spread of 
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contamination. The system exhausts its air to the outside through high-efficiency particulate air 

(HEPA) filters in order to reduce any radioactive leakage to the environment. 

The applicant classified this ventilation system as in-scope because it provides cooling for 

safety-related equipment, maintains pressure boundary integrity for zone SV, contains 

components used in safe shutdown scenarios such as the HELB, and contains components that 

support EQ and fire protection.

LRA Table 2.3.3-13 contains the components subject to an AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and USAR Sections 9.6.3, 11.1.2, 11.2.3, H-2, and 

Table B.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 under 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).

During its review of LRA Section 2.3.3.13, the staff identified area(s) 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.3-13 and 3.3.2-13 for the sealants, screens, 

and filter housings.

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables, such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Screens (RAI 2.3-5). In a letter dated September 28, 2009, the applicant clarified that the 

component types ―Missile Hood and Bird Screen,‖ ―Exhaust Vent Stack, Missile Cover and 

Screen,‖ and ―Fixed Louvers‖ are listed in LRA Table 2.4.2-3. The component type ―Exhaust 

Vent Stack, Missile Cover and Screen‖ is associated with the auxiliary building vent stack, which 

handles exhaust from the other HVAC systems including the auxiliary building ventilation 

system.
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Filter Housings (RAI 2.3.3.13-1). In a letter dated August 28, 2009, the applicant was requested 

to clarify whether the filter housings are within the scope of license renewal and subject to an 

AMR.

In a letter dated September 28, 2009, the applicant clarified that the filter element housings for 

the auxiliary building supply air ventilation unit, the spent fuel pool exhaust filter assembly, and 

the auxiliary building exhaust filter assembly are within the scope of license renewal and are 

included in the component type ―Filter Assemblies,‖ in LRA Table 2.3.3-13. The associated AMR 

results are provided in LRA Table 3.3.2-13.

Based on the above, the applicant concluded that a revision is not necessary for LRA 

Tables 2.3.3-13 and 3.2.2-13.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-5, and 

RAI 2.3.3.13-1 acceptable because the applicant provided an acceptable clarification such that 

the component types are properly identified as within the scope of license renewal, and 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). Therefore, the staff‘s concerns 

described in RAI 2.3-2, RAI 2.3-5, and RAI 2.3.3.13-1 are resolved.

2.3.3.13.3 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. The staff finds no such 

omissions. In addition, the staff 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 ventilation system 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).

2.3.3.14 Reactor Building Ventilation System

2.3.3.14.1 Summary of Technical Information in the Application

LRA Section 2.3.3.14 describes the reactor building ventilation system. The applicant stated that 

this system is comprised of eight ventilation and cooling subsystems:

● containment air cooling subsystem

● reactor support cooling subsystem

● reactor gap and neutron detector cooling subsystem

● containment dome ventilation subsystem

● containment purge and vent subsystem

● CRDMs cooling subsystem

● post-LOCA hydrogen control subsystem

● vacuum relief subsystem

The containment air cooling subsystem provides general air cooling for the containment vessel 

interior and operates to limit post-LOCA containment pressure temperature for a DBA. The 

post-LOCA hydrogen control subsystem (which contains the containment hydrogen analyzers) 
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controls hydrogen concentrations for post-LOCA containment environments. The vacuum relief 

system protects the containment vessel from damage due to negative pressures. The remaining 

subsystems operate to supply ventilation, cooling, supply, and/or exhaust air for their respective 

areas in order to cool and protect equipment and structures from high temperatures.

The applicant classified this system as in-scope for several reasons, some of which are as 

follows:

● cools and depressurizes the containment volume post-accident

● controls and disperses hydrogen concentrations post-LOCA

● protects the containment vessel from excessive negative pressures

● maintains vessel and zones pressure boundaries and integrities

● includes components that cool key portions of containment concrete structures

● allows for use of an external post-LOCA hydrogen control unit

● contains EQ components and components that support fire protection

LRA Table 2.3.3-14 contains the components subject to an AMR.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14 and USAR Section 5.4, Figure 14.3-32, and 

Table B.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 under 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).

During its review, the staff identified several areas in which additional information was 

necessary to complete the review of the applicant‘s scoping and screening results.

In RAI 2.3-2, dated August 28, 2009, the applicant was requested to clarify whether sealants are 

within the scope of license renewal in accordance with 10 CFR 54.21(a)(1).

In a letter dated September 28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies 

short-lived components and consumables, such as packing, gaskets, component seals, duct 

sealants, and O-rings. The applicant further stated that based on ANSI B31.1 and the ASME 

B&PV Code Section III, these consumable items are not pressure-retaining parts. Therefore, 

they do not perform a license renewal intended function in accordance with 10 CFR 54.4(a) and 

are not within the scope of license renewal.

In RAI 2.3.3.14-1, dated August 28, 2009, the applicant was asked to explain its reasoning why 

the containment air hydrogen analyzers are not included in the AMR, as these components 

were identified both as within the scope of license renewal and as active components by Note 1 

in license renewal drawing LRM-403. In addition, the applicant was asked to explain why the 

calibration gas connecting lines and the associated valves are not included within the scope of 

license renewal.
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In a letter dated September 28, 2009, the applicant stated that the containment air hydrogen 

analyzers fulfill the requirements of NUREG-0737 [―Clarification of TMI Action Plan 

Requirements‖ (November 1980)], item II.F.1.6. The applicant further clarified that Note 1 in 

license renewal drawing LRM-403 was incorrect and should have noted that the internal 

components of the containment air hydrogen analyzers are active and do not require an AMR. 

The applicant further stated that Note 1 should have indicated that the containment air hydrogen 

analyzer panels are within the scope of license renewal and evaluated with miscellaneous 

structural commodities. The containment air hydrogen analyzer panels are included in the 

commodity group ―Panels and Cabinets,‖ in LRA Table 2.4.2-13. The associated AMR results 

are provided in LRA Table 3.5.2-14. Regarding the calibration gas lines, the applicant clarified 

that they are excluded from the scope of license renewal in accordance with the scoping and 

screening methodology that is consistent with NEI 95-10, Section 5.2.1.2, ―Equipment used to 

Establish Initial Conditions.‖ Section 5.2.1.2 of NEI 95-10 indicates that nonsafety-related 

equipment required to maintain safety-related equipment within limits consistent with event 

assumptions is excluded from scope, provided that the nonsafety-related equipment does not

perform a function that meets the criteria of 10 CFR 54.4. Since the calibration gas lines do not 

meet any of the criteria in 10 CFR 54.4, they are not within the scope of license renewal.

In RAI 2.3.3.14-1, dated August 28, 2009, the applicant was asked to explain the reasons for 

not including the ductwork on the suction side of containment fan coil units 1A and 1D, as 

shown in license renewal drawing LRM-602, within the scope of license renewal.

In a letter dated September 28, 2009, the applicant clarified that the lines shown in the license 

renewal drawing represent non-ducted air flow.

In response to RAI 2.3.3.14-1, the applicant clarified by letter dated September 12, 2009, that 

the housings of the reactor building ventilation system‘s filter assemblies meet the intended 

function of pressure boundary for the component type ―Filter Assemblies‖ shown in LRA 

Table 2.3.3-14.

The applicant concluded that a revision to the LRA Tables 2.3.3-14 and 3.3.2-14 is not 

necessary.

Based on the applicant‘s responses and clarifications to RAI 2.3-2 and RAI 2.3.3.14-1, the staff 

finds that the component types are properly identified within the scope of license renewal, and 

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). Therefore, the staff‘s questions in 

RAI 2.3-2 and RAI 2.3.3.14-1 are considered resolved. 

2.3.3.14.3 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. The staff finds no such 

omissions. In addition, the staff 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 building ventilation system 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).
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2.3.3.15 Turbine Building and Screenhouse Ventilation System

2.3.3.15.1 Summary of Technical Information in the Application

LRA Section 2.3.3.15 describes the turbine building and screenhouse ventilation system. The 

applicant stated that this system supplies fresh air to maintain proper temperatures in the 

turbine building and screenhouse, and supplies cooling and combustion air for the diesel 

generators. Fan coil units are provided for safeguards and for non-safeguards areas and 

components within the system‘s scope. The applicant stated that the safeguards fan coils are 

cooled by the service water system. The system supplies room cooling to the auxiliary 

feedwater pump rooms and to the station battery rooms.

The applicant classified this system as within scope because it supplies air flows to several 

safeguards rooms, equipment, and areas; contains components used in safe shutdown 

scenarios such as during a HELB; includes EQ components; and contains components that 

support fire protection and SBO.

LRA Table 2.3.3-15 contains the components subject to an AMR.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 and USAR Table B.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 under 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).

In a letter dated August 28, 2008, the staff requested additional information to complete the 

review of the applicant‘s scoping and screening results.

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables, such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Applicability of LRA Drawings (RAI 2.3.3.15-1). The staff requested that the applicant confirm 

the applicability of the license renewal drawings listed in LRA Section 2.3.3-15. In a letter dated 

September 28, 2009, the applicant clarified that all the drawings listed in LRA Section 2.3.3-15 

are applicable to the turbine building and screenhouse ventilation system, except for license 

renewal drawing LRM-604, which was incorrectly listed.

Temperature Elements (RAI 2.3.3.15-1). The applicant was requested to clarify the reasons for 

including temperature elements in LRA Table 2.3.3-15. In a letter dated September 28, 2009, 
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the applicant stated that temperature elements perform a pressure boundary function and are 

used to close dampers upon high temperature for protection of steam exclusion zones, as 

described in USAR Section 10A.3.3.5. Therefore, the temperature elements were included 

within the scope of license renewal as highlighted in license renewal drawings LRM-601 and 

LRM-603.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2 and RAI 2.3.3.15-1 

acceptable because the applicant has properly identified the component types and the reasons 

for their inclusion within the scope of license renewal.

2.3.3.15.3 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. The staff finds no such 

omissions. In addition, the staff determined if 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 and screenhouse ventilation system 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).

2.3.3.16 Shield Building Ventilation System

2.3.3.16.1 Summary of Technical Information in the Application

LRA Section 2.3.3.16 describes the shield building ventilation system. The applicant stated that 

this system consists of two redundant trains of ventilation equipment and operates during 

accidents to both recirculate the containment vessel-shield building annulus air volume and 

clean it from radioactive leakage contaminants.

The applicant classified this system as within scope because it performs during DBAs to 

minimize potentially radioactive containment leakage to the environment, to maintain pressure 

boundary integrity and temperature/pressure control for zone SV, and because it contains EQ 

components.

LRA Table 2.3.3-16 contains the components subject to an AMR.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16 and USAR Sections 5.1, 5.2, 5.5, 5.8, H.3, and 

Table B.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 under 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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In a letter dated August 28, 2008, the staff requested additional information to complete the 

review of the applicant‘s scoping and screening results.

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables, such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Shield Building Ventilation Filter Assembly (RAI 2.3.3.16-1). In response to the staff‘s request to 

clarify what part of the shield building filter assembly is required to meet the intended function of 

pressure boundary, in a letter dated September 28, 2008, the applicant stated that the housing 

of the shield building filter assembly meets the intended function of pressure boundary.

Demister and Electric Heater (RAI 2.3.3.16-1). In a letter dated August 28, 2009, the staff asked 

the applicant whether the demister and the electric heater are included within the scope of 

license renewal.

In a letter dated September 28, 2009, the applicant stated that the demisters are within the 

scope of license renewal, but the electric heaters are not. The applicant stated that the 

demisters are included in the component type ―Filter Elements,‖ in LRA Table 2.3.3-16. The 

electric heaters are located internal to the filter assembly housing and do not perform a license 

renewal intended function. The applicant further stated that the electric heaters were removed 

from the operability and surveillance requirements of the technical specifications by Amendment 

No. 201, issued by the staff, in a letter dated December 30, 2008.

The staff finds the applicant‘s response to RAI 2.3.3.16-1 acceptable because the applicant has 

provided requested clarifications and properly identified the component types and the reasons 

for their inclusion or exclusion from the scope of license renewal.

2.3.3.16.3 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. The staff finds no such 

omissions. In addition, the staff determined if 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 

shield building ventilation system 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).

2.3.3.17 Technical Support Center Ventilation System

2.3.3.17.1 Summary of Technical Information in the Application

LRA Section 2.3.3.17 describes the technical support center (TSC) ventilation system. The 

applicant stated that this ventilation system has the function of keeping the TSC habitable 

during a plant emergency. During those times, the system handles 100 percent recirculated air, 
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pressurizes it, decontaminates it, conditions it, and prevents all but small amounts of air 

inleakage to its covered areas.

The applicant classified this system as within scope because it includes components that 

support fire protection and SBO.

LRA Table 2.3.3-17 contains the components subject to an AMR.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13 and the USAR 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 under 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).

During its review of LRA Section 2.3.3.17, the staff identified area(s) 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 a letter dated August 28, 2009, the staff requested that the applicant provide clarification for 

not listing the component types in LRA Tables 2.3.3-17 and 3.3.2-17 for the sealants, screens, 

battery room air compressor unit (ACU) cooling coils/fins, ACU compressor casings, and filter 

housings for filter elements.

By letter dated September 28, 2009, the applicant clarified the above component types as 

follows:

Sealants (RAI 2.3-2). The applicant was requested to clarify whether sealants are within the 

scope of license renewal in accordance with 10 CFR 54.21(a)(1). In a letter dated September 

28, 2009, the applicant clarified that LRA Section 2.1.5.7 identifies short-lived components and 

consumables, such as packing, gaskets, component seals, duct sealants, and O-rings. The 

applicant further stated that based on ANSI B31.1 and the ASME B&PV Code Section III, these 

consumable items are not pressure-retaining parts. Therefore, they do not perform a license 

renewal intended function in accordance with 10 CFR 54.4(a) and are not within the scope of 

license renewal.

Screens (RAI 2.3-5). In a letter dated September 28, 2009, the applicant clarified that the 

component type ―Louvers and Bird Screens‖ is listed in LRA Table 2.4.2-5. 

Casings, Cooling Coils, Fins, and Filter Housings (RAI 2.3.3.17-1). In a letter dated August 28, 

2009, the applicant was requested to clarify whether the casings, cooling coils, and filter 

housings are within the scope of license renewal and subject to an AMR.

In a letter dated September 28, 2009, the applicant clarified that the battery room ACU cooling 

coils/fins, ACU compressor casings, and filter housings for the filter elements are within the 

scope of license renewal and are included in the component type ―Air Conditioning Units‖ and 
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―Air Handling Units,‖ in LRA Table 2.3.3-17. The AMR results for these components are 

provided in LRA Table 3.3.2-17.

Based on the above, the applicant concluded that a revision is not necessary for LRA 

Tables 2.3.3-17 and 3.3.2-17.

Based on its review, the staff finds the applicant‘s responses to RAI 2.3-2, RAI 2.3-5, and 

RAI 2.3.3.17-1 acceptable because the applicant provided an acceptable clarification such that 

the component types are properly identified as within the scope of license renewal, and 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). Therefore, the staff‘s concerns 

described in RAI 2.3-2, RAI 2.3-5, and RAI 2.3.3.17-1 are resolved.

2.3.3.17.3 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. The staff finds no such 

omissions. In addition, the staff determined if 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 

TSC ventilation system 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).

2.3.3.18 Fire Protection System

2.3.3.18.1 Summary of Technical Information in the Application

LRA Section 2.3.3.18 describes the fire protection system. The applicant stated that this system 

operates to detect and suppress fires so as to minimize equipment damage and to allow the 

plant to achieve and maintain safe shutdowns for fires and associated situations. The fire 

protection system consists of smoke detection components, alarms, and water-based, 

Halon-based, and carbon dioxide (CO2)-based fire suppression subsystems and components.

● The water-based fire-suppression systems take water from Lake Michigan and use two 

fire pumps and a jockey pump to distribute fire water to piping, automatic sprinkler

systems, and standpipe and hose stations.

● The low-pressure CO2 fire suppression subsystem uses gas from a 7.5 ton capacity 

storage tank to protect the diesel generator rooms and to supply CO2 to manual hose 

stations at various locations in the turbine and auxiliary buildings.

● The Halon fire-suppression subsystem is a self-contained system that protects various 

plant locations, including the computer rooms and the count room areas in the TSC.

The applicant stated in LRA Section 2.3.3.18 that the fire protection system is within the scope 

of license renewal because the system has intended functions that meet the criteria stated in 

10 CFR 54.4(a). The system meets 10 CFR 54.4(a)(1) because the system provides fire 

protection for the EDGs. Further, the applicant stated that the system also meets criteria stated 

in 10 CFR 54.4(a)(3) because the system includes components that support fire protection.
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LRA Table 2.3.3-18 contains the components subject to an AMR.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and USAR Sections 7.7.5, 8.2.2, 9.6.1, and 

Table B.2-1, and license renewal drawings 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 had not omitted 

from the scope of license renewal any components with intended functions pursuant to 

10 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 had not omitted any passive or 

long-lived components subject to an AMR, in accordance with 10 CFR 54.21(a)(1).

The staff also reviewed the fire protection CLB documents listed in the KPS Operating License 

Condition 2.C(3). This review included KPS commitments to 10 CFR 50.48, ―Fire Protection‖ 

(i.e., approved fire protection program), as provided in the responses to Appendix A to the BTP

APCSB 9.5-1, ―Guidelines for Fire Protection for Nuclear Power Plants,‖ May 1, 1976, 

documented in the KPS SERs, dated November 25, 1977, December 12, 1978, and February 

13, 1981.

During its review of LRA Section 2.3.3.18, the staff identified areas in which additional 

information was necessary to complete its review of the applicant‘s scoping and screening 

results. The applicant responded to the staff‘s RAIs as discussed below.

In RAI 2.3.3.18-1, dated July 16, 2009, the staff stated that license renewal drawing LRM-202-3 

shows fire hose connections at locations F9, F10, F11, G9, G10, and G11 as not within the 

scope of license renewal (i.e., not colored in brown). The staff requested that the applicant verify 

whether these fire hose connections 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). The staff also 

requested that, if these hose connections were excluded from the scope of license renewal and 

were not subject to an AMR, the applicant provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the fire hose connections at 

locations F9, F10, F11, G9, G10, and G11 on license renewal drawing LRM-202-3 are used 

only for non-fire purposes (e.g., station services) and do not perform a license renewal intended 

function.

In evaluating this response, the staff found that it was incomplete and that review of LRA 

Section 2.3.3.18 could not be completed. The applicant did not explain why the fire hose 

connections in question are used only for non-fire purposes (e.g., station services). National Fire 

Protection Association codes do not allow fire hose connections to be used for non-fire 

purposes. This resulted in the staff holding a telephone conference with the applicant on 

September 18, 2009, to discuss information necessary to resolve the concern in RAI 2.3.3.18-1. 

The product of the telephone conference was an agreement by the applicant to transmit the 

required information by a follow-up letter.

By letter dated November 13, 2009, the applicant stated that the hose connections shown at 

locations F9, F10, F11, G9, G10, and G11 on license renewal drawing LRM-202-3 are 

connections that can be used for general plant services. The applicant also stated that these 

hose connections are only used for non-fire purposes (e.g., station services) and do not perform 

a license renewal intended function. Finally, the applicant stated that certain fire hose stations 
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which are a part of the service water system, such as the one shown at location B6 on license 

renewal drawing LRM-202-3, are designated as fire hose stations and have been included 

within the scope of license renewal for 10 CFR 54.4(a)(3).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-1, including the 

information in the teleconference and letter dated November 13, 2009, acceptable because it 

clarifies that the components in question at the six locations are hose connections off of the 

service water system for general plant services and are not fire hose connections. The staff also 

finds that, as a result, the National Fire Protection Association code would not apply to these 

components. Fire hose connections that are designated as fire hose stations are highlighted on 

license renewal drawing LRM-202-3. Therefore, the staff‘s concern described in RAI 2.3.3.18-1 

is resolved.

In RAI 2.3.3.18-2, dated July 16, 2009, the staff stated that license renewal drawing LRM-208-1 

shows fire hydrants and hose houses (cabinets) as being within the scope of license renewal 

and subject to an AMR. However, license renewal drawing LRM-208-1 shows fire hose cabinets 

at locations G6 and H6 as out of scope (i.e., not colored in blue). The staff requested that the 

applicant verify whether the above fire hose cabinets 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). The staff also requested that, if these cabinets were excluded from the 

scope of license renewal and were not subject to an AMR, the applicant provide justification for 

the exclusion.

In its response dated August 6, 2009, the applicant stated that the LRA Section 2.1.5.4 supports 

are evaluated as commodities within in-scope structures. The fire hose cabinets are within the 

scope of license renewal per 10 CFR 54.4(a)(3) because they support fire protection and,

therefore, are evaluated as commodities. The fire hose cabinets are included in the component 

type/structural member ―Support for Miscellaneous Components – fire hose stations,‖ in LRA 

Table 2.4.2-12, ―Component Support.‖ The associated AMR results are provided in LRA 

Table 3.5.2-13. Items treated as commodities, such as the fire hose cabinets mentioned in the 

RAI, are not highlighted on license renewal drawings.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-2 acceptable 

because the fire hose cabinets in question were identified to be within the scope of license 

renewal and subject to an AMR. Fire hose cabinets are included in LRA Table 2.4.2-12 as an 

in-line item of the component type structural member ―Support for Miscellaneous Components –

fire hose stations,‖ with the AMR results provided in LRA Table 3.5.2-13. 

In RAI 2.3.3.18-3, dated July 16, 2009, the staff stated that license renewal drawing LRM-208-3 

shows fire department pump connections and associated components at locations B1, C1, and 

D1 as out of scope (i.e., not colored in blue). The staff requested that the applicant verify 

whether the fire department connections and 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). The staff also requested that, if they were excluded from the scope of 

license renewal and were not subject to an AMR, the applicant provide justification for the 

exclusion.

In its response dated August 6, 2009, the applicant stated that the fire department pump 

connections and associated components shown at locations B1, C1, and D1 on license renewal 

drawing LRM-208-3 provide fire protection for the administration training facility (ATF). The ATF 

is physically separated from the plant power block and is not included within the scope of 
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license renewal. Therefore, the fire protection piping inside the ATF and the fire department 

connections and associated components do not perform a license renewal intended function 

and have not been included within the scope of license renewal.

The staff confirmed that the fire department pump connections and associated components 

shown at locations B1, C1, and D1 on license renewal drawing LRM-208-3 are for the ATF, 

which is separated from the plant power block. The staff concludes that these fire pump 

department connections and associated components are correctly excluded from the scope of 

license renewal and not subject to an AMR.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-3 acceptable. 

In RAI 2.3.3.18-4, dated July 16, 2009, the staff stated that KPS SER Section 4.3.1.5, dated 

December 22, 1978, states that ―...automatic water spray system[s] are provided on 

combustible liquid hazards in the turbine building (hydrogen seal oil unit, oil storage reservoirs), 

the heating boiler fuel oil pumps in the auxiliary building, and in the oil-filled transformer in the 

yard areas....‖ License renewal drawing LRM-208-3 shows only the yard area oil-filled 

transformer automatic water spray system as being within the scope of license renewal and 

subject to an AMR. The staff requested that the applicant verify whether the automatic water 

spray systems for the hydrogen seal oil unit, oil storage reservoirs, and heating boiler fuel oil 

pumps 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). The staff also requested that, if they were 

excluded from the scope of license renewal and were not subject to an AMR, the applicant 

provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the automatic water spray 

systems for the hydrogen seal oil unit, oil storage reservoirs, and heating boiler fuel oil pumps 

are within the scope of license renewal and included in component groups ―Pipe,‖ ―Sprinkler 

Head,‖ and ―Valves,‖ in LRA Table 2.3.3-18. The associated AMR results are provided in LRA 

Table 3.3.2-18. 

The license renewal drawing and locations identifying the automatic water spray system for the 

hydrogen seal oil unit, oil storage reservoirs, and heating boiler fuel oil pumps are provided 

below:

● Hydrogen seal oil unit – license renewal drawing LRM-208-1 at location D-6 (labeled ―2 

to Hydrogen Seal Oil, See Detail 1‖).

● Oil storage reservoir – license renewal drawing LRM-208-1 at location C-7 (labeled ―To 

Turbine Oil Storage Tank Area Sprinkler System‖) and license renewal drawing 

LRM-208-3 at location D-3 (labeled ―To Turb Oil Storage‖).

● Heating boiler fuel oil pumps – license renewal drawing LRM-208-1 at location D-7 

(labeled ―11/2 To Heat Boiler Fuel Oil Pump Area Sprinkler System (BSMT Floor), See 

Detail 2‖) and license renewal drawing LRM-208-3 at location F-11 (labeled ―To Heating 

Boiler Sprinkler System‖).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-4 acceptable 

because automatic water spray systems for the hydrogen seal oil unit, oil storage reservoirs, 

and heating boiler fuel oil pumps were identified to be within the scope of license renewal and 
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subject to an AMR. The applicant has included the fire suppression systems in question in 

component groups ―Pipe,‖ ―Sprinkler Head,‖ and ―Valves,‖ in LRA Table 2.3.3-18 with AMR 

results provided in LRA Table 3.3.2-18. The staff concludes that these fire suppression systems 

and their associated components are correctly included within the scope of license renewal and 

subject to an AMR. Therefore, the staff‘s concern described in RAI 2.3.3.18-4 is resolved.

In RAI 2.3.3.18-5, dated July 16, 2009, the staff stated that KPS SER Section 4.3.1.5, dated 

December 22, 1978, states that ―...wet pipe sprinklers [are provided] on safety-related electrical 

cable in fire area AX-32, in the hallway of the screenhouse (area SC70), and [there is a plan to] 

to convert the existing wet pipe system in the working material storage (auxiliary building) to a 

deluge system....‖ The wet pipe and deluge sprinkler systems do not appear in LRA 

Section 2.3.3.18 or license renewal drawings as being within the scope of license renewal and 

subject to an AMR. The staff requested that the applicant verify whether the above wet pipe 

and deluge systems 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). The staff also requested that, if 

they were excluded from the scope of license renewal and were not subject to an AMR, the 

applicant provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the wet pipe and deluge sprinkler 

systems mentioned above are within the scope of license renewal and included in component 

groups ―Pipe,‖ ―Sprinkler Head,‖ and ―Valves,‖ in LRA Table 2.3.3-18. The associated AMR 

results are provided in LRA Table 3.3.2-18.

The license renewal drawing and locations identifying the automatic wet pipe and deluge 

sprinkler systems mentioned above are provided below:

● Safety-related electrical cable in fire area AX-32 – license renewal drawing LRM-208-1 

at location F-7 (labeled ―To Cable Tray Fire Protection‖) and license renewal drawing 

LRM-208-3 at location F-12 (labeled ―To Cable Tray Sprinkler System‖).

● Screenhouse hallway (area SC70) – license renewal drawing LRM-208-1 at location E-8 

(labeled ―Screen House Tunnel Cable Tray Sprinkler System‖).

● Working material storage area – license renewal drawing LRM-208-1 at location D-8 

(labeled ―To Working Mat‘l Storage Area Sprinkler System‖) and license renewal drawing 

LRM-208-3 at location D-10 (also labeled ―To Working Mat‘l Storage Sprinkler System‖). 

This system was converted to a deluge sprinkler system in 1979.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-5 acceptable 

because wet pipe and deluge sprinkler systems were identified to be within the scope of license 

renewal and subject to an AMR. The applicant has included the water-based fire suppression 

systems in question in component groups ―Pipe,‖ ―Sprinkler Head,‖ and ―Valves,‖ in LRA 

Table 2.3.3-18 with AMR results provided in LRA Table 3.3.2-18. The staff concludes that these 

water-based fire suppression systems and their associated components are correctly included 

within the scope of license renewal and subject to an AMR. Therefore, the staff‘s concern 

described in RAI 2.3.3.18-5 is resolved.

In RAI 2.3.3.18-6, dated July 16, 2009, the staff stated that SER Section 4.3.1.6, dated 

December 22, 1978, states that ―...one portable foam nozzle and foam concentrate is available. 

The plant had no fixed foam system prior to this review; however, the applicant has installed an 
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automatic foam suppression system on each of the two reactor coolant pumps....‖ The 

automatic foam suppression system for the two reactor coolant pumps does not appear in LRA 

Section 2.3.3.18 or license renewal drawings as being within the scope of license renewal and 

subject to an AMR. The staff requested that the applicant verify whether the automatic foam 

system for reactor coolant pumps 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). The staff also 

requested that, if the foam system was excluded from the scope of license renewal and was not 

subject to an AMR, the applicant provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the foam suppression system for 

the reactor coolant pumps was replaced by a reactor coolant pump motor oil collection system 

in 1982 in accordance with 10 CFR 50, Appendix R. The staff was notified of this modification 

by letter dated February 28, 1983, from Mr. C.W. Giesler (WPSC) to the NRC, which transmitted 

the 1982 Annual Operating Report. The applicant stated that the reactor coolant pump motor oil 

collection system is within the scope of license renewal and included in the component types 

―Drip Pan and Enclosures,‖ ―Flexible Hoses,‖ ―Pipe,‖ and ―Reactor Coolant Pump Oil Collection 

Tank,‖ in LRA Table 2.3.3-18. The applicant also stated that, with the exception of pipes, LRA 

Table 2.3.3-18 includes a footnote for these items indicating that they are not shown on the fire 

protection system license renewal drawings. Finally, the applicant stated that the associated 

AMR results are provided in LRA Table 3.3.2-18. 

The staff reviewed the letter dated February 28, 1983, and confirmed that the reactor coolant 

pump automatic foam suppression system was removed and a reactor coolant pump oil 

collection system was installed in each of the pump vaults. Therefore, the staff‘s concern 

described in RAI 2.3.3.18-6 is resolved.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-6 acceptable.

In RAI 2.3.3.18-7, dated July 16, 2009, the staff stated that the SER, dated December 22, 1978, 

lists various types of fire water suppression systems provided in the plant areas for fire 

suppression activities. The fire suppression systems in various areas are:

● service room (fire area AX-32) automatic wet pipe sprinkler system

● turbine lube oil reservoirs deluge system

● charcoal filter deluge system

The staff requested that the applicant verify whether the above fire suppression systems 

installed in the plant 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). The staff also requested that, if 

they were excluded from the scope of license renewal and were not subject to an AMR, the 

applicant provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the fire water suppression 

systems for the areas mentioned above are within the scope of license renewal and shown on 

the license renewal drawings indicated below:

● Service room (fire area AX-32) – as indicated in Section 5.7 of the SER, dated 

December 12, 1978, the service room refers to an area which contains electrical cables 

in trays and conduit for redundant safety-related systems, as indicated by license 

renewal drawing LRM-208-1 at location F-7 (labeled ―Cable Tray Fire Protection‖) and 
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license renewal drawing LRM-208-3 at location F-12 (labeled ―Cable Tray Sprinkler 

System‖).

● Turbine lube oil reservoir deluge system – license renewal drawing LRM-208-1 (labeled 

―To Oil Reservoir and Conditioner Sprinkler System‖) at location F-5 and license renewal 

drawing LRM-208-3 at location F-5 (labeled ―To Oil Reservoir Sprinkler System‖).

● Charcoal filter deluge system – the charcoal deluge system is supplied by the service 

water system as shown on license renewal drawing LRM-606 at locations B-1, C-1, E-1, 

F-1, B-6.5, E-6.5, F-6.5, and C-8.5.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-7 acceptable 

because fire water suppression systems were identified to be within the scope of license 

renewal and subject to an AMR. The staff has confirmed that the applicant correctly identified 

the service room (fire area AX-32) automatic wet pipe sprinkler system, turbine lube oil reservoir 

deluge system, and charcoal filter deluge system. The staff concludes that these water-based 

fire suppression systems and their associated components are correctly included within the 

scope of license renewal and subject to an AMR. Therefore, the staff‘s concern described in 

RAI 2.3.3.18-7 is resolved.

In RAI 2.3.3.18-8, dated July 16, 2009, the staff stated that the SER dated November 25, 1977,

lists various areas of the plant as being protected with a low pressure CO2 fire suppression 

system. The CO2 fire suppression system serves the following areas:

● adjacent to steam generator blowdown (SGBD) tank room AX-20

● adjacent to 4,160-volt switchgear room AX-21

● adjacent to special ventilation room AX-23

● relay room AX-30

● adjacent to service room AX-32

● diesel generator 1-A TU-90

● diesel generator 1-A, day tank room TU-91

● diesel generator 1-B TU-92

● diesel generator 1-B, day tank room TU-93

● air compressor and pump room TU-95

● battery room 1-A TU-97

● battery room 1-B TU-98

LRA Section 2.3.3.18 states that ―...the CO2 storage tank primarily supplies CO2 for automatic 

total flooding protection for diesel generator rooms and also supplies CO2 to manual hose 

stations at various location in the Turbine Building and the Auxiliary Building....‖ It is not clear 

from review of LRA Section 2.3.3.18 that the total flooding automatic CO2 fire suppression 

system installed in all areas listed above is included within the scope of license renewal and 

subject to an AMR. The staff requested that the applicant verify whether the total flooding 

automatic CO2 fire suppression system installed in these areas 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). The staff also requested that, if it was excluded from the scope of license 

renewal and was not subject to an AMR, the applicant provide justification for the exclusion.

In its response dated August 6, 2009, the applicant stated that the letter dated November 25, 

1977, from Karl R. Goller of the NRC to Mr. E.W. James (WPSC), provided the interim technical 
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specifications on fire protection and listed the above areas in Section 3.15(d). A letter dated 

December 16, 1977, from Mr. E.W. James to Mr. Karl R. Goller, proposed a revision to the 

interim technical specifications that corrected the list of areas serviced by the low pressure fire 

protection CO2 systems. Specifically, the areas identified as ―Adjacent to the Special Ventilation 

Area‖ (AX-23) and ―Adjacent to the Service Room‖ (AX-32) were removed from the list. A letter 

dated March 3, 1978, from Mr. A. Schwencer of the NRC to Mr. E.W. James (WPSC), 

subsequently issued the revised technical specifications for fire protection as Amendment 

No. 20 to the operating license.

The fire protection system limiting conditions for operation (LCOs) and surveillance 

requirements were removed from the technical specifications and relocated to the Fire 

Protection Program, by letter dated March 4, 1991, from Mr. M.J. Davis of the NRC to Mr. K.H. 

Evers (WPSC). The USAR incorporates the Fire Protection Program plan by reference. The Fire 

Protection Program plan states that the low-pressure CO2 fire suppression system shall be 

operable whenever equipment or components in the following area(s) being protected are 

required:

 (1) relay room AX-30

 (2) diesel generator 1-A (TU-90) and day tank room (TU-91)

 (3) diesel generator 1-B (TU-92) and day tank room (TU-93)

 (4) CO2 hose station adjacent to battery rooms 1A (TU-97) and 1B (TU-98)

 (5) CO2 hose station adjacent to air compressor and pump room (TU-95)

 (6) CO2 hose station adjacent to 4,160-volt switchgear room (AX-21) and blowdown tank 

rooms (AX-20)

As indicated in LRA Section 2.3.3.18, the evaluation boundary for the fire protection system 

includes the CO2 and Halon gaseous suppression systems. Therefore, the entire low-pressure 

CO2 fire suppression system has been included within the scope of license renewal in the areas 

identified above, as shown on the license renewal drawings as indicated below. As indicated, 

some of these areas do not utilize automatic suppression as implied in the RAI:

● Relay room (AX-30) – license renewal drawing LRM-384 at locations A-10/A-11 (labeled 

―Relay Room‖). This is a manual trip total flooding system. Additionally, the relay room 

has a hose station (Hose Reel No. 3) shown at the same drawing locations.

● Diesel generator 1-A (TU-90) and day tank room (TU-91) – license renewal drawing 

LRM-384 at location E-4 (labeled ―To Diesel Generator 1-A Area Discharge Nozzles‖). 

This is an automatic total flooding system.

● Diesel generator 1-B (TU-92) and day tank room (TU-93) – license renewal drawing 

LRM-384 at location E-6 (labeled ―To Diesel Generator 1-B Area Discharge Nozzles‖). 

This is an automatic total flooding system.

● Hose station adjacent to battery rooms 1A (TU-97) and 1B (TU-98) – license renewal 

drawing LRM-384 at locations B-11/B-12 (labeled ―To Turbine Room Mezz. Floor 4160 V 

SWGR Bus (Hose Reel No. 2)‖).
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● Hose station adjacent to air compressor and pump room (TU-95) – license renewal 

drawing LRM-384 at locations D-11/D-12 (labeled ―To Turbine Room BSMT Floor 

4160 V SWGR Bus (Hose Reel No. 1)‖).

● Hose station adjacent to 4,160-volt switchgear room (AX-21) and blowdown tank rooms 

(AX-20) – license renewal drawing LRM-384 at locations A-2/A-3 (labeled ―To Main 

4160V SWGR Bus BSMT Floor. (Hose Reel No. 4)‖).

The components of the low-pressure CO2 fire suppression system identified above are included 

in the component types ―Hose Reels/Station,‖ ―Nozzles,‖ ―Odorizers,‖ ―Pipe,‖ and ―Valves,‖ in 

LRA Table 2.3.3.18. The associated AMR results are provided in LRA Table 3.3.2-18.

The staff reviewed the applicant‘s docketed correspondence and confirmed that the applicant 

appropriately identified areas protected by the low pressure CO2 fire suppression system. The 

staff concluded that the applicant correctly included relay room AX-30, diesel generator 1-A 

(TU-90) and day tank room (TU-91), diesel generator 1-B (TU-92) and day tank room (TU-93),

CO2 hose station adjacent to battery rooms 1A (TU-97) and 1B (TU-98), CO2 hose station 

adjacent to air compressor and pump room (TU-95), and CO2 hose station adjacent to 

4,160-volt switchgear room (AX-21) and blowdown tank rooms (AX-20) and their associated 

components within the scope of license renewal and subject to an AMR. Moreover, the staff 

concluded that the applicant correctly excluded areas AX-23 and AX-32 from the scope of 

license renewal and thus, not subject to an AMR. Therefore, the staff‘s concern described in 

RAI 2.3.3.18-8 is resolved.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-8 acceptable.

In RAI 2.3.3.18-9, dated July 16, 2009, the staff stated that LRA Table 2.3.3.18 excludes several 

types of fire protection components that appear in the SER dated December 22, 1978. These 

components are listed below:

● hose racks

● pipe fittings

● pipe supports

● dikes for oil spill confinement

● floor drains and curbs for fire water

For each, the staff requested that the applicant determine whether the component should be 

included in LRA Tables 2.3.3-18 and 3.3.2-18, and, if not, justify the exclusion.

In its response dated August 6, 2009, the applicant stated that the above fire protection 

components are within the scope of license renewal and evaluated for an AMR. Identified below 

are the LRA tables that contain the screening AMR results for each component:

● Hose racks – evaluated as a commodity and are included in the commodity 

type/structural member ―Supports for Miscellaneous Components (fire hose stations),‖ in 

LRA Table 2.4.2-12, ―Component Supports.‖ The associated AMR results are provided 

in LRA Table 3.5.2-13.
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● Pipe fittings – included in the component type ―Pipe,‖ in LRA Table 2.3.3-18. The 

associated AMR results are provided in LRA Table 3.3.2-18. Note that LRA 

Section 2.1.5.1 indicates that ―Pipe‖ includes piping and all of the associated fittings, 

flanges (including blind and spectacle), elbows, reducers, welds, drain lines, vent lines, 

end caps, threaded plugs, fill connections, funnels, and access ports such as manholes.

● Pipe supports for fire protection – evaluated as a commodity and are included in the 

commodity type/structural member ―Supports for Piping and Components,‖ in LRA 

Table 2.4.2-12. The associated AMR results are provided in LRA Table 3.5.2-13.

● Dikes for oil spill confinement – located in the turbine building and evaluated as an 

inherent part of the structure. The concrete dikes are included in the structural member 

―Structural Reinforced Concrete (slabs, beams, columns, and walls),‖ in LRA 

Table 2.4.2-6. The associated AMR results are provided in LRA Table 3.5.2-7.

● Floor drains – as indicated in LRA Section 2.1.3.6.4, floor drainage outside of the reactor 

containment vessel that is credited for protecting safety-related equipment has been 

included within the scope of license renewal per 10 CFR 54.4(a)(2) and evaluated for 

aging management with the miscellaneous drain and sumps system. These floor drains 

are included in the component type ―Pipe,‖ in LRA Table 2.3.3-26, ―Miscellaneous Drain 

and Sumps.‖ The associated AMR results are provided in LRA Table 3.3.2-26.

● Curbs for fire water – steel curbing for fire water is located in the auxiliary building, 

turbine building, and screenhouse and evaluated with the associated structures. The 

steel curbing is included in the structural member ―Miscellaneous Steel (embedded steel 

exposed surfaces (shapes, plates, unistrut, etc.) ladders, grating, checkered plates, 

stairs handrails),‖ identified in LRA Tables 2.4.2-3, 2.4.2-6, and 2.4.2-11. The associated 

AMR results are provided in LRA Tables 3.5.2-4, 3.5.2-7, and 3.5.2-12.

In reviewing the applicant‘s response to the RAI, the staff found that each item in the RAI was 

addressed and resolved satisfactorily as follows:

The applicant stated that hose racks are included under commodity type/structural member 

―Supports for Miscellaneous Components (fire hose stations),‖ in LRA Table 2.4.2-12, 

―Component Supports,‖ with the AMR results provided in LRA Table 3.5.2-13.

Although the description of the ―Pipe‖ line item provided in LRA Table 2.3.3-18 does not list pipe 

fittings specifically, the applicant stated that it considers the pipe fittings, as included in LRA 

Table 2.3.3-18 under the component type ―Pipe,‖ with the AMR results provided in LRA 

Table 3.3.2-18. 

The applicant stated that pipe supports for the fire protection piping are included under 

commodity type/structural member ―Supports for Piping and Components,‖ in LRA 

Table 2.4.2-12, with the AMR results provided in LRA Table 3.5.2-13. 

The applicant stated that dikes for oil spill confinement are included in the line item structural 

member ―Structural Reinforced Concrete (slabs, beams, columns, and walls),‖ in LRA 

Table 2.4.2-6, with the AMR results provided in LRA Table 3.5.2-7.

The applicant also stated that floor drains are evaluated under the component type ―Pipe,‖ in 

LRA Table 2.3.3-26, ―Miscellaneous Drain and Sumps.‖ The associated AMR results are 
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provided in LRA Table 3.3.2-26. The applicant stated that steel curbing for fire water is located 

in the auxiliary building, turbine building, and screenhouse and evaluated with the associated 

structures. 

The applicant also stated that steel curbing is included in the structural member ―Miscellaneous 

Steel,‖ in LRA Tables 2.4.2-3, 2.4.2-6, and 2.4.2-11, with the AMR results provided in LRA 

Tables 3.5.2-4, 3.5.2-7, and 3.5.2-12.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-9 acceptable 

because it resolved the staff‘s concerns regarding scoping and screening of fire protection 

system components listed in the RAI.

In RAI 2.3.3.18-10, dated July 16, 2009, the staff stated that LRA Section 2.3.3-18 states that 

―...the water-based fire suppression subsystem, which takes water from Lake Michigan, 

consists of two fire pumps, a jockey pump, main and branch supply line piping....‖ LRA 

Section 2.3.3.18 discusses requirements for the fire water supply system but does not mention 

trash racks and traveling screens for the fire pump suction water supply. Trash racks and 

traveling screens are located upstream of the fire pump suctions to remove any major debris 

from the fresh or raw water to prevent clogging of the fire protection water supply system. Trash 

racks and traveling screens are typically considered to be passive, long-lived components. Both 

the trash racks and traveling screens are located in a fresh or raw water/air environment and 

are typically constructed of carbon steel. Carbon steel in a fresh or raw water environment or 

water/air environment is subject to loss of material, pitting, crevice formation, and 

microbiologically-influenced corrosion and fouling. The staff requested that the applicant explain 

the apparent exclusion of the trash racks and traveling screens that are located upstream of the 

fire pump suctions from 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).

In its response dated August 6, 2009, the applicant stated that the trash racks are within the 

scope of license renewal and included in the structural member ―Trash Grills‖ and ―Trash 

Anchorage,‖ in LRA Table 2.4.2-10, ―Intake Structure.‖ The associated AMR results are 

provided in LRA Table 3.5.2-11.

The applicant also stated that the traveling water screens are within the scope of license 

renewal. As indicated in LRA Section 2.3.3.6, ―Service Water System,‖ the passive portions of 

the traveling water screens (frames and covers) is evaluated for aging management with the 

screenhouse structure. The frames and covers are included in structural members ―Traveling 

Water Screen Support Frames‖ and ―Traveling Water Screen Covers,‖ respectively, in LRA 

Table 2.4.2-11, ―Screenhouse.‖ The associated AMR results are provided in LRA 

Table 3.5.2-12.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.18-8 acceptable

because the applicant: (1) clarified that trash racks are included in the LRA as part of 

Table 2.4.2-10, under line item structural member ―Trash Grills,‖ with the AMR results provided 

in LRA Table 3.5.2-11; and (2) stated that traveling screens are within the scope of license 

renewal, but only the passive portions of the traveling screens (frames and covers) are included 

in LRA Table 2.4.2-11, with the AMR results provided in LRA Table 3.5.2-12.
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2.3.3.18.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and drawings to determine whether the 

applicant properly identified all fire protection system components within the scope of license 

renewal. In addition, the staff sought to determine if the applicant properly identified all fire 

protection system components subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the fire protection system 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).

2.3.3.19 Diesel Generator System

2.3.3.19.1 Summary of Technical Information in the Application

LRA Section 2.3.3.19 describes the diesel generator system. The applicant stated that this 

system includes both diesel generator-mechanical and diesel generator-electrical systems. The 

applicant further stated that the system contains two EDGs and one TSC diesel generator. The 

diesel generator portion is comprised of five subsystems, which collectively provide dependable, 

onsite electrical power, capable of starting automatically when required, to supply loads 

necessary for safe plant shutdown in all circumstances, including DBA responses such as loss 

of coolant, as well as for SBO situations. The five subsystems for the EDGs are listed as 

follows:

● starting subsystem

● lube oil subsystems

● cooling water subsystems

● air intake and exhaust subsystems

● fuel oil subsystems

Finally, the applicant stated that the TSC diesel generator is used to supply power to specified 

loads during an SBO event. 

The applicant classified this system as within scope for several reasons, some of which are 

listed as follows:

● provides emergency electrical power to operate the engineered safety features 

equipment

● provides air for operation of service water valves and ventilation dampers to the diesel 

generators

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains components used in safe shutdown scenarios such as the HELB

● includes EQ components and contains components that support fire protection and SBO

LRA Table 2.3.3-19 contains the components subject to an AMR.
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2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19 and USAR Sections 8.1.1, 8.2.3, Table 8.2-1, 

Table B.2-1, and Figure 8.2-10, and the license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 

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 2.3.3.19-01, dated April 3, 2009, the staff noted license renewal drawing LRM-213-9, 

locations B-1, B-2, B-3, B-4, B-5, B-7, B-8, B-10, B-11, and B-12, shows nonsafety-related 

piping connected to safety-related components at valves SA2020A-1, SA2020A-2, SA2020A-3 

SA2020A-4, SA2020B-1, SA2020B-2, SA2020B-3, and SA2020B-4, and traps downstream of 

after coolers 166-021 and 166-022 to floor drains. The applicant was requested to provide the 

location of the seismic anchor for the nonsafety-related 3⁄4-inch lines connected to the 

safety-related valves and traps.

In its response dated April 27, 2009, the applicant stated no structural anchors are identified 

because the bounding scoping methodology as described in LRA Section 2.1.3.6.2, ―NS Piping 

Attached to SR Piping,‖ was applied and the entire drain line sections from the safety-related 

valves to the floor drain were included within the scope of license renewal for 

10 CFR 54.4(a)(2). The traps, after coolers, and air dryers are not safety-related and were 

included within the scope of license renewal for 10 CFR 54.4(a)(3) in support of 10 CFR 50.48 

fire protection regulations. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.19-01 acceptable 

because the applicant clarified that: (a) the bounding scoping methodology described in LRA 

Section 2.1.3.6.2 was applied; and (b) the traps, after coolers, and air dryers are not 

safety-related and are included within the scope of license renewal for 10 CFR 54.4(a)(3). 

Therefore, the staff‘s concern described in RAI 2.3.3.19-01 is resolved.

2.3.3.19.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components 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. On the basis of its review, the staff concludes the applicant has 

appropriately identified the diesel generator system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the diesel generator system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.20 Circulating Water System

2.3.3.20.1 Summary of Technical Information in the Application

LRA Section 2.3.3.20 describes the circulating water system. The applicant stated that this 

system is an open-cycle cooling system providing water to the main condensers, while also 

providing normal and alternate water sources for the service water system and the fire 

protection system. Water is provided from Lake Michigan. The applicant also stated that the 

system is comprised of an intake structure and a discharge structure, along with a screenhouse 
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forebay, circulating water pumps, associated piping, valves, and equipment. The system 

contains an alternate, safety-related recirculation line/distribution pipe as an alternate water 

source for the service water system and the fire protection system, as well as for de-icing of the 

traveling water screens.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides the normal and the alternate water sources for the service water system 

● provides flowpaths for de-icing of the traveling water screens

● contains spatially oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● minimizes flooding through tripping features to protect the turbine building basement

● includes components that support fire protection

LRA Table 2.3.3-20 contains the components subject to an AMR.

2.3.3.20.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the circulating water system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.21 Gaseous Waste Processing and Discharge System

2.3.3.21.1 Summary of Technical Information in the Application

LRA Section 2.3.3.21 describes the gaseous waste processing and discharge system. The 

applicant stated that this system collects and processes gaseous radioactive wastes to permit 

their discharge within applicable regulatory limits. 

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides reactor containment vessel integrity and isolation

● maintains a pressure boundary from accidental radioactive gas release

● maintains a pressure boundary for the component cooling water system

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary
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● includes EQ components

LRA Table 2.3.3-21 contains the components subject to an AMR.

2.3.3.21.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the gaseous waste processing and discharge system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the system components subject to an AMR, in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.22 Liquid Waste Processing and Discharge System

2.3.3.22.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.22 describes the liquid waste processing and discharge system. The 

applicant stated that this system collects liquid radioactive wastes from plant operation;

processes them by filtration, dilution, and/or demineralization; and provides the means for their 

release within regulatory limits. 

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows: 

● provides reactor containment vessel integrity and isolation

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes EQ components

In addition, the LRA states that portions of the evaporator subsystem (although this subsystem 

is no longer used) are within scope since they are connected to the component cooling water 

system and provide some structural support.

LRA Table 2.3.3-22 contains the components subject to an AMR.

2.3.3.22.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.22, USAR Section 11.1.2 and Table B.2-1, and the 

license renewal drawings using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3. The staff 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 2.3.3.22-01, dated April 3, 2009, the staff noted license renewal drawing LRXK-100-131, 

location A-7, shows the laundry and hot shower tank 1A within the scope of license renewal per 

10 CFR 54.4(a)(2). The attached blind flange on the overflow connection is shown as not within 

scope (same flange on tank 1B is shown as within scope). The applicant was requested to 

provide a justification for not including the blind flange on the laundry and hot shower tank 1A 

within the scope of license renewal per 10 CFR 54.4(a)(2).

In its response dated April 27, 2009, the applicant stated the subject blank flange for the liquid 

waste processing and discharge system was within the scope of license renewal per 

10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.22-01 acceptable 

because the applicant clarified that the flange in question for the liquid waste processing and 

discharge system is within the scope of license renewal. Therefore, the staff‘s concern 

described in RAI 2.3.3.22-01 is resolved.

In RAI 2.3.3.22-02, dated April 3, 2009, the staff noted license renewal drawing LRXK-100-44, 

location E-8, shows a sample sink and a line to the fume hood sampler as not within the scope 

of license renewal. The staff also noted that all piping entering and exiting the sink, including the 

drain to the waste holdup tank which is shown as belonging to the liquid waste processing and 

discharge system, is shown as within the scope of license renewal for 10 CFR 54.4(a)(2). The 

applicant was requested to explain why the sample sink and sample line to the fume hood 

sampler are not within the scope of 10 CFR 54.4(a)(2).

In its response dated April 27, 2009, the applicant stated the subject sample line to the fume 

hood sampler is incorrectly shown on license renewal drawing LRXK-100-44. The applicant 

stated that this line is no longer installed in the plant. In addition, the applicant provided 

justification as to why the sample sink and its associated drain pipe are not within the scope of 

license renewal by explaining its reasoning behind the conclusion that these two components do 

not perform an intended function in accordance with 10 CFR 54.4(a). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.22-02 acceptable 

because the applicant clarified that the sample sink and associated piping in question are not 

within the scope of license renewal. Therefore, the staff‘s concern described in RAI 2.3.3.22-02 

is resolved.

2.3.3.22.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the liquid waste processing and discharge system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the liquid waste processing and discharge system 

mechanical components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.3.23 Radiation Monitoring System

2.3.3.23.1 Summary of Technical Information in the Application

LRA Section 2.3.3.23 describes the radiation monitoring system. The applicant stated that this 

system performs continuous radiological monitoring of important plant systems and areas to 

warn of problems such as system malfunctions, personnel radiological hazards, potential 

radiological releases, or plant damage.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides reactor containment vessel integrity and isolation

● prevents or minimizes radioactive releases to the environment

● actuates post-accident fans and ventilation components

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● includes EQ components

LRA Table 2.3.3-23 contains the components subject to an AMR.

2.3.3.23.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the radiation monitoring system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.24 Makeup and Demineralizer System

2.3.3.24.1 Summary of Technical Information in the Application

LRA Section 2.3.3.24 describes the makeup and demineralizer system. The applicant stated 

that this system provides degasified and demineralized water from the outlet of the service 

water pretreatment system filters. The applicant described the system as composed of two 

redundant trains of ion exchangers, which then supplies water for both primary and secondary 

systems.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides a safety-related boundary for several systems 

● provides containment volume pressure boundary integrity and isolation
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● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes components that support fire protection and SBO

LRA Table 2.3.3-24 contains the components subject to an AMR.

2.3.3.24.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.24, USAR Figure 9.2-5, and the license renewal drawings 

using the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3. The staff 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 2.3.3.24-01, dated April 3, 2009, the staff noted license renewal drawing LRM-209-2, 

location B-1, shows a 11⁄2-inch line within the scope of license renewal for 10 CFR 54.4(a)(2). 

However, the continuation of this 11⁄2-inch line on license renewal drawing LRM-385, 

location G7, shows this line is not within the scope of license renewal. The applicant was 

requested to provide additional information explaining why there is a difference in scope 

classification between license renewal drawings LRM-209-2 and LRM-385.

In its response dated April 27, 2009, the applicant stated that the continuation of this 11⁄2-inch 

line on license renewal drawing LRM-385 is not within scope because it is located within the 

solid radioactive waste processing cubicle which has no safety-related SSCs. The applicant also 

stated that a note identifying the in-scope boundary was omitted. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.24-01 acceptable 

because the applicant clarified the scoping classification for the 11⁄2-inch line in question. 

Therefore, the staff‘s concern described in RAI 2.3.3.24-01 is resolved.

2.3.3.24.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the makeup and demineralized water system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the makeup and demineralized water system mechanical components 

subject to an AMR, in accordance with the requirements stated in 10 CFR 54.21(a)(1).
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2.3.3.25 Service Water Pretreatment System

2.3.3.25.1 Summary of Technical Information in the Application

LRA Section 2.3.3.25 describes the service water pretreatment system. The applicant stated 

that this system takes water from the potable water system, or as an alternate, from the service 

water system, removes solids, and supplies the output to the makeup and demineralized water 

system, as well as various components in the screenhouse and turbine buildings. 

The applicant classified this system as within scope because it provides a safety-related 

pressure boundary for the service water system; provides bearing lube water to service water 

pump bearings; contains spatially-oriented, nonsafety-related components whose failure could 

impact safety-related SSCs; and contains nonsafety-related piping that is attached to 

safety-related piping, seismically designed, and supported up to the first structural anchoring 

point beyond the safety/nonsafety pipe boundary.

LRA Table 2.3.3-25 contains the components subject to an AMR.

2.3.3.25.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.25 and the license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 

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 2.3.3.25-01, dated April 3, 2009, the staff noted license renewal drawing LRM-394, 

location F-10, shows a 4-inch line downstream of valve SW(T)404 as not within the scope of 

license renewal for 10 CFR 54.4(a)(2). However, the continuation of this 4-inch line, on license 

renewal drawing LRM-211, location G-1, shows this line is within the scope of license renewal 

for 10 CFR 54.4(a)(2). The applicant was requested to provide additional information explaining 

why there is a difference in scope classification between license renewal drawings LRM-394 

and LRM-211.

In its response dated April 27, 2009, the applicant clarified that a portion of the 4-inch line is 

shown as within scope on both license renewal drawings LRM-394 and LRM-211. The applicant 

identifies LRA note 1 which clarifies why the piping downstream of valve SW(T)404 is not within 

the scope of license renewal. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.25-01 acceptable 

because the applicant clarified the scoping classification for the 4-inch line in question. 

Therefore, the staff‘s concern described in RAI 2.3.3.25-01 is resolved.

In RAI 2.3.3.25-02, dated April 3, 2009, the staff noted license renewal drawing LRM-394, 

location E-4, shows valve SW(T)242 as within the scope of license renewal for 

10 CFR 54.4(a)(2). However, the same valve on license renewal drawing LRM-202-2, 

location E-8, is shown to be within the scope of license renewal for 10 CFR 54.4(a)(1).

In its response dated April 27, 2009, the applicant stated that valve SW(T)242 is within the 

scope of license renewal for 10 CFR 54.4(a)(3), in support of 10 CFR 50.48 fire protection 

regulations, and that valve SW(T)242 on license renewal drawing LRM-394 is incorrectly shown 
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as within scope for 10 CFR 54.4(a)(2) and should be highlighted to be shown as within the 

scope of license renewal for 10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.25-02 acceptable 

because the applicant clarified the scoping classification for valve SW(T)242. Therefore, the 

staff‘s concern described in RAI 2.3.3.25-02 is resolved.

2.3.3.25.3 Conclusion

The staff reviewed the LRA, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the service water pretreatment system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the service water pretreatment system mechanical components subject to 

an AMR, in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.26 Miscellaneous Drains and Sumps System

2.3.3.26.1 Summary of Technical Information in the Application

LRA Section 2.3.3.26 describes the miscellaneous drains and sumps system. The applicant 

stated that this system consists of separate drains and sumps requiring physical separation due 

to radiological, chemical, environmental, or toxicological reasons. The system is described as 

having pumps and sumps that collect drainage from various locations; the pumps are for 

transferring the liquid wastes for processing and/or disposal.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides containment vessel pressure boundary integrity and isolation 

● provides RHR pump room flood control

● provides a pressure boundary against additional radiological releases during plant 

accidents

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes EQ components 

LRA Table 2.3.3-26 contains the components subject to an AMR.
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2.3.3.26.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.26 and USAR Sections 6.2.5, 6.5.1, and 11.1.2, and the 

license renewal drawings using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3. The staff 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 2.3.3.26-01, dated April 3, 2009, the staff noted license renewal drawing LRM-350, 

locations D-5, D-6, and D-10, show nonsafety-related piping connected to safety-related piping 

components at valves MD(R)-250A&B, MD(R)-251A&B, MD(R)-260, MD(R)-261, MD(R)-270, 

MD(R)-271, MD(R)-272, MD(R)-273, and MD(R)-262. The applicant was requested to provide 

the location of the seismic restraint for the nonsafety-related 1-inch lines connected to the 

safety-related heat exchangers, 1A and 1B, the letdown exchanger, and seal water heat 

exchanger piping. 

In its response dated April 27, 2009, the applicant clarified that the bounding scoping 

methodology was applied, wherein the sludge interceptor tank was used as an equivalent 

anchor.

Based on its review, the staff found the applicant‘s response to RAI 2.3.3.26-01 acceptable for 

the piping to the sludge interceptor tank, but the response was incomplete as described in 

RAI 2.3.3.26-01(a). Therefore, the staff‘s concern described in RAI 2.3.3.26-01 was not 

resolved.

In RAI 2.3.3.26-01(a), dated July 7, 2009, the staff noted the response to RAI 2.3.3.26-01 did 

not identify the seismic anchor for the branch piping continued to the waste area sump pumps. 

The applicant was requested to provide the location for the seismic anchor for the 

nonsafety-related branch piping continued to the waste area sump pumps.

In its response dated August 6, 2009, the applicant stated the bounding methodology described 

in LRA Section 2.1.3.6.2 was applied to the subject piping, and the piping should have been 

included within the scope of license renewal for 10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.26-01(a) acceptable 

because the applicant stated that the subject piping is within the scope of license renewal for 

10 CFR 54.4(a)(2).

In RAI 2.3.3.26-02, dated April 3, 2009, the staff noted license renewal drawing LRM-350, 

locations H-6 and H-7, shows 3-inch and 2-inch lines, downstream of the RHR pump flushing 

outlets, as within the scope of license renewal for 10 CFR 54.21(a)(2). However, part of the 

2-inch line is shown as not within the scope of license renewal. The 2-inch line upstream of 

valve MD(R)-280B, location H-7, is continued to license renewal drawing LRM-539, 

location H-5, where it is shown as within the scope of license renewal while it is shown as not 

within the scope of license renewal on license renewal drawing LRM-350. The applicant was 

asked to provide additional information to establish the license renewal boundary for the 3-inch 

and 2-inch lines shown as not within the scope of license renewal.

In its response dated April 27, 2009, the applicant confirmed that valve MD(R)-280B and the 

associated 2-inch line on license renewal drawing LRM-539 are within the scope of license 

renewal for 10 CFR 54.4(a)(2). This same valve and a portion of the associated 2-inch line were 
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incorrectly not highlighted on license renewal drawing LRM-350 and are within the scope of 

license renewal for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.3.26-02 acceptable 

because the applicant clarified the scoping classification for the 2-inch line. Therefore, the staff‘s 

concern described in RAI 2.3.3.26-02 is resolved.

2.3.3.26.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the miscellaneous drains and sumps system mechanical components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the miscellaneous drains and sumps system mechanical components 

subject to an AMR, in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.3.27 Miscellaneous Gas System

2.3.3.27.1 Summary of Technical Information in the Application

LRA Section 2.3.3.27 describes the miscellaneous gas system. The applicant stated that this 

system supplies nitrogen, hydrogen, propane, and CO2 gases to various plant equipment and 

systems. Systems listed include the following:

● safety injection system

● waste gas decay system

● CVCS

● pressurizer relief system

● spent fuel pool components

● main electrical generator

● fire protection system

● gases for chemical analysis and post-accident sampling

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides containment volume pressure boundary integrity and isolation 

● provides a pressure boundary for the RCS, safety injection system, and CVCS

● provides nitrogen backup to the spent fuel pool inflatable seals and oxygen supply to the 

containment hydrogen analyzers

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes components that support fire protection and SBO
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LRA Table 2.3.3-27 contains the components subject to an AMR.

2.3.3.27.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the miscellaneous gas system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.28 Potable Water System

2.3.3.28.1 Summary of Technical Information in the Application

LRA Section 2.3.3.28 describes the potable water system. The applicant stated that this system 

provides domestic water for plant personnel and for some plant equipment. The LRA states the 

system‘s water source is a pair of onsite deep wells located outside the protected area. 

The applicant classified this system as within scope because the system has nonsafety-related 

components that are part of the control room pressure boundary, and because it contains 

spatially-oriented, nonsafety-related components whose failure could impact safety-related 

SSCs.

LRA Table 2.3.3-28 contains the components subject to an AMR.

2.3.3.28.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the potable water system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.29 Primary Sampling System

2.3.3.29.1 Summary of Technical Information in the Application

LRA Section 2.3.3.29 describes the primary sampling system. The applicant stated that this 

system, which consists of two parallel subsystems, provides the ability to sample and analyze 

the RCS, the containment vessel atmosphere, the containment vessel sumps, and other 

supporting locations. Each subsystem contains heat exchangers, valves, and associated piping 

and directs samples to either the auxiliary building sample room or to the auxiliary building high 

radiation sample room. 

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides containment volume pressure boundary integrity and isolation 
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● provides a pressure boundary for the component cooling system

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes EQ components 

LRA Table 2.3.3-29 contains the components subject to an AMR.

2.3.3.29.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the primary sampling system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4 Steam and Power Conversion Systems

LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of these systems in the 

following LRA sections:

● Section 2.3.4.1, ―Turbine System‖

● Section 2.3.4.2, ―Main Steam and Steam Dump System‖

● Section 2.3.4.3, ―Bleed Steam System‖

● Section 2.3.4.4, ―Feedwater System‖

● Section 2.3.4.5, ―Condensate System‖

● Section 2.3.4.6, ―Steam Generator Blowdown Treatment System‖

● Section 2.3.4.7, ―Auxiliary Feedwater System‖

● Section 2.3.4.8, ―Air Removal System‖

● Section 2.3.4.9, ―Heater and Moisture Separator Drains System‖

● Section 2.3.4.10, ―Heating Steam System‖

● Section 2.3.4.11, ―Main Generator (Mechanical) and Auxiliaries System‖

● Section 2.3.4.12, ―Secondary Sampling System‖

● Section 2.3.4.13, ―Turbine Oil Purification System‖

● Section 2.3.4.14, ―Turbine Room Traps and Drains System‖

2.3.4.1 Turbine System

2.3.4.1.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the turbine system. The applicant stated that this system, 

composed of one high-pressure turbine and two low-pressure turbines, converts thermal energy 
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from the main steam system into mechanical energy to rotate the main (electrical) generator. 

The LRA indicates also that several auxiliary subsystems monitor, control, provide lubrication 

and cooling, and improve turbine system efficiency. 

The applicant classified this system as within scope because it provides safety-related 

protection; provides indication and controls; contains spatially-oriented, nonsafety-related 

components whose failure could impact safety-related SSCs; and includes components that 

support safe shutdown following an ATWS.

LRA Table 2.3.4-1 contains the components subject to an AMR.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1 and USAR Sections 10.2.2, B.9, Table 7.2-1, and 

Table B.2-1, and the license renewal drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 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 2.3.4.1-01, dated April 03, 2009, the staff noted license renewal drawing LRM-202-3, 

location H-7, shows a continuation of in-scope 2-inch 10 CFR 54.4(a)(2) pipe from license 

renewal drawing LRM-204, location A-5. Review of license renewal drawing LRM-204 found a 

continuation (i.e., 2 inches to stand pipe) at A-5, however, this line is included within the scope 

of license renewal for 10 CFR 54.4(a)(1). The applicant was requested to confirm that the 

located continuation is correct and provide additional information to explain the different criteria 

for this section of pipe.

In its response dated April 27, 2009, the applicant confirmed that the continuation of the 2-inch 

auxiliary feedwater pump recirculation line to the standpipe on license renewal drawing 

LRM-202-3 is within the scope of license renewal for 10 CFR 54.4(a)(2). The applicant also 

stated this line continues from the 2-inch line downstream of valve AFW-120 on license renewal 

drawing LRM-204 (location A-5) and is also within the scope of license renewal for 

10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.1-01 acceptable 

because the applicant confirmed the continuation location, and also stated the mismatch in 

scoping criterion is a highlighting error. Therefore, the staff‘s concern described in 

RAI 2.3.4.1-01 is resolved.

2.3.4.1.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the turbine system mechanical components within the scope of license 

renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified the 

turbine system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.4.2 Main Steam and Steam Dump System

2.3.4.2.1 Summary of Technical Information in the Application

LRA Section 2.3.4.2 describes the main steam and steam dump system. The applicant stated 

that this system transports dry, saturated steam from the SGs to the main turbine. The LRA 

states that the steam dump portion functions as an artificial steam load by sending steam to the 

condenser or to the atmosphere. The system also supplies steam to several plant auxiliaries 

and components. The LRA further states that the system contains main steam isolation valves, 

turbine stop and control valves, steamline code safeties, atmospheric power-operated relief 

valves, steam flow nozzles at the outlet of the SGs, and associated piping, as well as other 

valves and components.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides a steam flowpath for RCS heat removal

● provides steam motive power to the turbine-driven auxiliary feedwater pump

● provides overpressure protection for the RCS and for the SGs

● limits RCS cooldowns from main steamline breaks (thus limiting positive reactivity 

insertion to the reactor core)

● provides containment volume pressure boundary integrity and isolation 

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes components that support safe shutdown, fire protection, and SBO

● includes EQ components 

LRA Table 2.3.4-2 contains the components subject to an AMR.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2 and USAR Section 10.2, Table 10.3-1, Table B.2-1, 

Chapter 10A, and Figure 10.2-1, and the license renewal drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 

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 2.3.4.1-01, dated April 03, 2009, the staff noted license renewal drawing LRM-203, 

location H-3, shows a section of safety-related 10 CFR 54.4(a)(1) pipe connecting a tachometer 

element readout and the turbine driven auxiliary feedwater pump, both of which are within scope 

for 10 CFR 54.4 a (1), however, the connecting pipe section is not within scope. The applicant 

was requested to provide information explaining why this section of safety-related piping is not 

within the scope of license renewal.

In its response dated April 27, 2009, the applicant stated that the line joining the tachometer 

element and readout instrument and the auxiliary feedwater pump is not a pipe section but a 

shaft, joining the turbine to pump, that does not penetrate the system pressure boundary. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.2-01 acceptable 

because this drawing line represents a shaft that does not penetrate the system pressure 

boundary. Therefore, the staff‘s concern described in RAI 2.3.4.2-01 is resolved.

2.3.4.2.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has

appropriately identified the main steam and steam dump system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the main steam and steam dump system mechanical components subject 

to an AMR, in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.4.3 Bleed Steam System

2.3.4.3.1 Summary of Technical Information in the Application

LRA Section 2.3.4.3 describes the bleed steam system. The applicant stated that this system 

provides high-pressure turbine exhaust and extraction steam to the low- and high-pressure 

feedwater heaters to improve overall steam cycle efficiency. The LRA states that the system 

contains moisture separator reheaters, as well as interconnecting and associated piping and 

vents to and from the moisture separators, heater drain tank, and the various feedwater heaters.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs.

LRA Table 2.3.4-3 contains the components subject to an AMR.

2.3.4.3.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the bleed steam system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.4.4 Feedwater System

2.3.4.4.1 Summary of Technical Information in the Application

LRA Section 2.3.4.4 describes the feedwater system. The applicant stated that this system 

takes water flow from the condensate system and from drains of certain portions of the 

feedwater heaters, increases the pressure of the water, and sends the flow via its two 

motor-driven feedwater pumps through high-pressure feedwater heaters to the SGs. The 

system also contains pump lubricating oil subsystems, associated feedwater piping and valves, 

as well as flow measurement, indications, and protective controls. Finally, the LRA states that 

the system provides a flowpath for the auxiliary feedwater system pumps.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides the flowpath for auxiliary feedwater to the SGs

● provides isolation of feedwater flow to the SGs during main steam breaks to limit RCS 

cooldowns and energy release to the containment vessel

● provides containment volume pressure boundary integrity and isolation 

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes components that support safe shutdown and fire protection 

● includes EQ components 

LRA Table 2.3.4-4 contains the components subject to an AMR.

2.3.4.4.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the feedwater system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the system components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.5 Condensate System

2.3.4.5.1 Summary of Technical Information in the Application

LRA Section 2.3.4.5 describes the condensate system. The applicant stated that this system 

stores condensate water for secondary system makeup, acts as the supply to the auxiliary 
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feedwater pumps, and provides the flowpath and motive force to transfer water from the 

condenser hotwell to the feedwater system. The LRA also states that the system provides 

cooling for various secondary steam components and supplies seal water or makeup water to 

certain components. Finally, the applicant included portions of the chemical injection system in 

the condensate system scope.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs; contains 

nonsafety-related piping that is attached to safety-related piping, seismically designed, and 

supported up to the first structural anchoring point beyond the safety/nonsafety pipe boundary;

and includes components that support fire protection and SBO.

LRA Table 2.3.4-5 contains the components subject to an AMR.

2.3.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.5 and USAR Sections 6.6.2, 8.2.4, 10.2, Table B.2-1, and 

Figure 10.2-2, and the license renewal drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 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 2.3.4.5-01, dated April 3, 2009, the staff noted license renewal drawing LRM-204, 

locations B-1 and B-2, show a partially highlighted 10 CFR 54.4(a)(3) sampling line downstream 

from the condensate storage tanks 1A/1B to valves MU40A/B. This drawing does not match the 

partially highlighted 10 CFR 54.4(a)(3) section of piping on license renewal drawing LRM-219, 

location B-1. The applicant was requested to provide additional information to clarify the scoping 

classification for this pipe section.

In its response dated April 27, 2009, the applicant stated the valves and associated upstream 

piping on license renewal drawing LRM-204 were incorrectly not highlighted, but are within the 

scope of license renewal for 10 CFR 54.4(a)(3).

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.5-01 acceptable 

because the applicant clarified that the piping in question was within the scope of license 

renewal. Therefore, the staff‘s concern described in RAI 2.3.4.5-01 is resolved.

2.3.4.5.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the condensate system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the condensate system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.4.6 Steam Generator Blowdown Treatment System

2.3.4.6.1 Summary of Technical Information in the Application

LRA Section 2.3.4.6 describes the SGBD treatment system. The applicant stated that this 

system, which consists of the SGBD subsystem and the SGBD treatment subsystem, helps to 

maintain secondary chemistry for the SGs and the main steam and steam dump system. The 

LRA states that it provides the means to monitor SG tube integrity and has the capability to treat 

radioactively contaminated water from SGs following an SG tube rupture. 

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● isolates SGBD from the SGs during accidents and SG faults

● provides containment volume pressure boundary integrity and isolation 

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● includes components that support safe shutdown, fire protection, and SBO

● includes EQ components

LRA Table 2.3.4-6 contains the components subject to an AMR.

2.3.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and USAR Sections 10.2.3, 11.1.2, 11.2.3, Table B.2-1, 

Chapter 10A, Figure 11.1-3, and Figure 11.1-4, and the license renewal drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff 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 2.3.4.6-01, dated April 3, 2009, the staff noted license renewal drawing LRM-368, 

location H-7, shows 2-inch piping downstream of valve WD41 as within the scope of license 

renewal for 10 CFR 54.4(a)(2). The scoping classification on this drawing does not match the 

same section of piping on license renewal drawing LRXK-100-131, location H-10. The applicant 

was requested to provide additional information to clarify the scoping classification for this pipe 

section.

In its response dated April 27, 2009, the applicant stated the piping on license renewal drawing 

LRXK-100-131 was incorrectly not highlighted, but is within the scope of license renewal for 

10 CFR 54.4(a)(2). 
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Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.6-01 acceptable 

because the applicant clarified that the piping in question was within the scope of license 

renewal. Therefore, the staff‘s concern described in RAI 2.3.4.6-01 is resolved.

2.3.4.6.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the SGBD treatment system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the SGBD treatment system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.4.7 Auxiliary Feedwater System

2.3.4.7.1 Summary of Technical Information in the Application

LRA Section 2.3.4.7 describes the auxiliary feedwater system. The applicant stated that this 

system provides feedwater to remove sensible and decay heat from the RCS through the SGs 

when the main feedwater pumps are not available. The LRA describes the system as comprised 

of one turbine-driven pump; two motor-driven pumps; a normal supply from two condensate 

storage tanks; an emergency supply from the service water system; interconnections from 

auxiliary feedwater piping to the main feedwater piping; lubricating oil subsystems; and

associated valves, piping, indications, and controls. The LRA also states that parts of the 

chemical injection system are included in the auxiliary feedwater scope for license renewal.

The applicant classified this system as within scope for several reasons, some of which are 

summarized as follows:

● provides cooling water to the SGs to remove heat from the RCS and reactor core during 

accident conditions

● ensures an adequate fission product barrier by maintaining water inventory in the SGs 

during an SG tube rupture

● provides containment vessel pressure boundary integrity and isolation 

● contains spatially-oriented, nonsafety-related components whose failure could impact 

safety-related SSCs

● contains nonsafety-related piping that is attached to safety-related piping, seismically 

designed, and supported up to the first structural anchoring point beyond the 

safety/nonsafety pipe boundary

● contains components required for safe shutdown following a HELB

● includes components that support fire protection, SBO, and ATWS

● includes EQ components 
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LRA Table 2.3.4-7 contains the components subject to an AMR.

2.3.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.6 and USAR Sections 6.6, 10.3.1, Table 7.2-1, 

Table 10.1-1, Table 10.3-1, Table B.2-1, Chapter 10A, and Figure 10.2-3, and the license 

renewal drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff 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 2.3.4.7-01, dated April 3, 2009, the staff noted license renewal drawing LRM-204, 

location A-5, shows a 10 CFR 54.4(a)(1) pipe line continued to 2-inch ―Standpipe‖ on license 

renewal drawing LRM-202, location H-7. The continuation on LRM-202-3, location H-7, shows 

this section of pipe as within the scope of 10 CFR 54.4(a)(2). The applicant was requested to 

provide additional information to clarify the scoping classification for this pipe section.

In its response dated April 27, 2009, the applicant stated that the continuation of the 2-inch 

auxiliary feedwater pump recirculation line to the standpipe on license renewal drawing 

LRM-202-3 was correctly shown as within the scope of license renewal for 10 CFR 54.4(a)(2), 

and this line is continued from the 2-inch line downstream of valve AFW-120 on license renewal 

drawing LRM-204, location A-5, which is also within the scope of license renewal for 

10 CFR 54.4(a)(2), and should be highlighted within scope for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.7-01 acceptable 

because the mismatch in scoping criterion is a highlighting error. Therefore, the staff‘s concern 

described in RAI 2.3.4.7-01 is resolved.

In RAI 2.3.4.7-02, dated April 3, 2009, the staff noted license renewal drawing LRM-205, 

location G-6, shows a 10 CFR 54.4(a)(1) pipe line continued to 11⁄2-inch ―Recirc Line (typ)‖ on 

license renewal LRM-204, location A-6. The continuation on license renewal drawing LRM-204, 

location A-6, shows this section of pipe as not within scope. The applicant was requested to 

provide additional information to clarify the scoping classification for these pipe sections.

In its response dated April 27, 2009, the applicant stated the pipe line in question is a marker 

that is not intended to indicate a pipe line. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.7-02 acceptable 

because the line in question was a continuation marker, not a pipe line. Therefore, the staff‘s 

concern described in RAI 2.3.4.7-02 is resolved.

2.3.4.7.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the auxiliary feedwater system mechanical components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the auxiliary feedwater system mechanical components subject to an AMR, in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).
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2.3.4.8 Air Removal System

2.3.4.8.1 Summary of Technical Information in the Application 

LRA Section 2.3.4.8 describes the air removal system. The applicant stated that this system 

removes non-condensible gases from the main condenser, the gland steam condenser, the 

turbine oil reservoir, and the turbine oil loop seal tank. The LRA states that the system also 

includes a vacuum breaker valve to lower condenser vacuum and rapidly slow the turbine rotor 

in cases such as loss of turbine oil pressure. 

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs.

LRA Table 2.3.4-8 contains the components subject to an AMR.

2.3.4.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.8 and USAR Section 10.2.2, Table B.2-1, and 

Figure 10.2-6, and the license renewal drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 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 2.3.4.8-01, dated April 3, 2009, the staff noted license renewal drawing LRM-204, 

location G-1, shows a section of air removal system 3-inch piping, not included within scope, 

continuing from license renewal drawing LRM-212, location D-6, where it was included within 

the scope of license renewal for 10 CFR 54.4(a)(2). The applicant was requested to provide 

additional information to clarify the scoping classification for this pipe section.

In its response dated April 27, 2009, the applicant stated the continuation of this drain line on 

license renewal drawing LRM-204 was incorrectly not highlighted up to the check valve MD10, 

but is within the scope of license renewal for 10 CFR 54.4(a)(2). Valve MD10 and the 

downstream piping are not within the scope of license renewal because they are separated from 

the safety-related components by major plant equipment. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.8-01 acceptable 

because the applicant clarified which part of the piping in question was within the scope of 

license renewal and adequately explained why part of the piping in question was not within the 

scope of license renewal. Therefore, the staff‘s concern described in RAI 2.3.4.8-01 is resolved.

2.3.4.8.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the air removal system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the air removal system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.4.9 Heater and Moisture Separator Drains System

2.3.4.9.1 Summary of Technical Information in the Application

LRA Section 2.3.4.9 describes the heater and moisture separator drains system. The applicant 

stated that this system collects condensate drains from the main steam and steam dump 

system, the bleed steam system, four feedwater heaters, and the reheat portions of the 

moisture separator reheaters, in order to return them to the condensate/feedwater streams 

flowing to the SGs.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs.

LRA Table 2.3.4-9 contains the components subject to an AMR.

2.3.4.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.9 and USAR Section 10.2.2, Table B.2-1, and 

Figure 10.2-5, and the license renewal drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 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 2.3.4.9-01, dated April 3, 2009, the staff noted license renewal drawing LRM-207, 

locations C-1 and D-1, shows two instrument lines (DPS 16431 and DPS 16432) as not within 

scope that are continued to instrument lines on feedwater heater 15B on license renewal 

drawing LRM-206, location H-2. The continuation on license renewal drawing LRM-206, location 

H-2, shows these sections of the instrument lines as within scope for 10 CFR 54.4(a)(2). The 

applicant was requested to provide additional information to clarify the scoping classification for 

these pipe sections.

In its response dated April 27, 2009, the applicant stated the continuation of this tubing on 

license renewal drawing LRM-207 was incorrectly not highlighted, but is within the scope of 

license renewal for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.9-01 acceptable 

because the piping in question was incorrectly not highlighted and is within the scope of license 

renewal. Therefore, the staff‘s concern described in RAI 2.3.4.9-01 is resolved.

2.3.4.9.3 Conclusion

The staff reviewed the LRA, USAR, RAI response, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the heater and moisture separator drains system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 

applicant has adequately identified the heater and moisture separator drains system mechanical 

components subject to an AMR, in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.4.10 Heating Steam System

2.3.4.10.1 Summary of Technical Information in the Application

LRA Section 2.3.4.10 describes the heating steam system. The applicant stated that this system 

supplies steam and hot water to various plant areas, for heating purposes, through certain unit 

heaters, reheat coils, and preheat coils for various ventilation systems. The LRA states that the 

system‘s process steam is condensed in four hot water converters to provide hot water heat for 

some areas of the plant. 

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs, and because its 

system piping provides control room pressure boundary integrity.

LRA Table 2.3.4-10 contains the components subject to an AMR.

2.3.4.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.10 and USAR Sections 9.6.4, 10.1.4, 10A.1.2, and 

Table B.2-11, and the license renewal drawings using the evaluation methodology described in 

SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff 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 2.3.4.10-01, dated April 3, 2009, the staff noted license renewal drawing LRM-605-1,

location A-1, shows a section of heating steam pipe after control valve (31105/HS476) within 

scope for 10 CFR 55.4(a)(2). However, the same section of pipe is not included within scope on 

license renewal drawing LRXK-100-38, location D-8. The applicant was requested to provide 

additional information to clarify the scoping classification for this pipe section.

In its response dated April 27, 2009, the applicant stated that license renewal drawing 

LRM-605-1 incorrectly shows a heating steam line to/from the actuator for control valve 

TCV-100 (31105/HS-476). The configuration on license renewal drawing LRXK-100-38 correctly 

shows the instrument air control signal line to HS-476. 

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.10-01 acceptable 

because the applicant stated the line on license renewal drawing LRM-605-1 does not represent 

actual plant configuration. The configuration is correctly shown on license renewal drawing 

LRXK-100-38. Therefore, the staff‘s concern described in RAI 2.3.4.10-01 is resolved.

In RAI 2.3.4.10-02, dated April 3, 2009, the staff noted license renewal drawing LRM-605-1, 

location E-8, shows the caustic dilution water heat exchanger as not within scope. The applicant 

was asked to provide additional information explaining why the caustic dilution water heat 

exchanger is not included within scope for 10 CFR 54.4(a)(2).

In its response dated April 27, 2009, the applicant stated that the caustic dilution heat 

exchanger is located in an area of the auxiliary building where there is no potential for spatial 

interaction with safety-related SSCs.

Based on its review, the staff finds the applicant‘s response to RAI 2.3.4.10-02 acceptable 

because the caustic dilution heat exchanger is located in an area of the auxiliary building where 
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there is no potential for spatial interaction with safety-related SSCs. Therefore, the staff‘s 

concern described in RAI 2.3.4.10-02 is resolved.

2.3.4.10.3 Conclusion

The staff reviewed the LRA, USAR, RAI responses, and applicable license renewal drawings to 

determine whether the applicant failed to identify any components within the scope of license 

renewal. In addition, the staff determined if the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes the applicant has 

appropriately identified the heating steam system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the heating steam system mechanical components subject to an AMR, in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.4.11 Main Generator (Mechanical) and Auxiliaries System

2.3.4.11.1 Summary of Technical Information in the Application

LRA Section 2.3.4.11 describes the main generator (mechanical) and auxiliaries system. The 

applicant stated that this system provides support functions for operation of the main generator 

in production of electricity. The main generator converts mechanical energy into electrical 

energy and supplies electrical power to plant auxiliaries and to the electrical grid. The LRA 

states the system is comprised of several subsystems, which are described as follows:

● The main generator hydrogen cooling subsystem uses four heat exchangers (hydrogen 

coolers) located inside the generator housing to reject heat from inside the generator 

housing to the service water system.

● The seal oil subsystem provides oil at a higher pressure than main generator hydrogen 

pressure to glands at each end of the main generator shaft to ensure hydrogen does not 

leak out from the main generator and that air does not leak into the main generator.

● The isophase bus duct cooling subsystem removes heat from generator output electrical 

buswork due to electrical resistance. Its two heat exchangers reject the heat to the 

service water system.

● The exciter air cooler cools the air inside the exciter housing, rejecting the heat to the 

service water system.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs.

LRA Table 2.3.4-11 contains the components subject to an AMR.

2.3.4.11.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the main generator (mechanical) and auxiliaries system mechanical 

components within the scope of license renewal, as required by 10 CFR 54.4(a), and that the 
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applicant has adequately identified the system components subject to an AMR, in accordance 

with the requirements stated in 10 CFR 54.21(a)(1).

2.3.4.12 Secondary Sampling System

2.3.4.12.1 Summary of Technical Information in the Application

LRA Section 2.3.4.12 describes the secondary sampling system. The applicant stated that this 

system monitors water purity and chemical components of various secondary systems: 

condensate, feedwater, main steam and steam dump, SGBD treatment, and heating steam. The 

LRA states that samples can be obtained from various locations, either through the system‘s 

analytical instrumentation panel or via local grab samples, and then cooled, conditioned, 

monitored, analyzed, and recorded for trending purposes.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs and it contains 

nonsafety-related piping attached to safety-related piping, seismically designed, and supported 

up to the first structural anchoring point beyond the safety/nonsafety pipe boundary.

LRA Table 2.3.4-12 contains the components subject to an AMR.

2.3.4.12.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the secondary sampling system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4.13 Turbine Oil Purification System

2.3.4.13.1 Summary of Technical Information in the Application

LRA Section 2.3.4.13 describes the turbine oil purification system. The applicant stated that this 

system uses an oil conditioning unit to remove water and particulate contamination from turbine 

oil in the turbine oil reservoir. The LRA states that the removed water is discharged to a sump in 

the turbine building basement.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs.

LRA Table 2.3.4-13 contains the components subject to an AMR.

2.3.4.13.2 Conclusion

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the turbine oil purification system mechanical components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 
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identified the system components subject to an AMR, in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4.14 Turbine Room Traps and Drains System

2.3.4.14.1 Summary of Technical Information in the Application

LRA Section 2.3.14 describes the turbine room traps and drains system. The applicant stated 

that this system collects condensate from steam piping and from turbine casing drains, returning 

it to the condenser for reuse. The LRA states that the system collects the accumulations of 

water in order to prevent damage to steam equipment and piping.

The applicant classified this system as within scope because it contains spatially-oriented,

nonsafety-related components whose failure could impact safety-related SSCs and because it 

contains nonsafety-related piping attached to safety-related piping, seismically designed, and 

supported up to the first structural anchoring point beyond the safety/nonsafety pipe boundary.

LRA Table 2.3.4-14 contains the components subject to an AMR.

Based on the results of the staff evaluation discussed in SER Section 2.3 and on a review of the 

LRA, USAR, and applicable license renewal drawings, the staff concludes that the applicant has 

appropriately identified the turbine rooms traps and drain system mechanical components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified the system components subject to an AMR, in accordance with the 

requirements stated in 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 describes the following structures:

● reactor containment vessel

● structures and structural components

● shield building

● administration building

● auxiliary building

● screenhouse access tunnel

● TSC

● turbine building

● yard structures

● discharge structure

● discharge tunnel and pipe

● intake structure

● screenhouse

● component supports

● miscellaneous structural commodities

● NSSS supports
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In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed 

passive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To 

verify that the applicant properly implemented its methodology, the staff focused its review on 

the implementation results. This approach allowed the staff to confirm that there were no 

omissions of structural components that meet the scoping criteria and are subject to an AMR.

The staff‘s evaluation of the information provided in the LRA was performed in the same manner 

for all structures. The objective of the review was to determine whether the structural 

components that appeared to meet the scoping criteria specified in the Rule were identified by 

the applicant as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, 

the staff evaluated the applicant‘s screening results to verify that all long-lived, passive SCs 

were subject to an AMR, in accordance with 10 CFR 54.21(a)(1).

To perform its evaluation, the staff reviewed the applicable LRA sections, focusing its review on 

components that had not been identified as within the scope of license renewal. The staff 

reviewed the USAR for each structure to determine whether the applicant had omitted 

components with intended functions delineated under 10 CFR 54.4(a) from the scope of license 

renewal. The staff also reviewed the USAR to determine whether all intended functions 

delineated under 10 CFR 54.4(a) were specified in the LRA. When omissions were identified, 

the staff requested additional information to resolve the discrepancies.

Once the staff completed its review of the scoping results, the staff evaluated the applicant‘s 

screening results. For those components with intended functions, the staff sought to determine: 

(1) whether the functions are performed with moving parts or a change in configuration or 

properties, or (2) whether they are subject to replacement based on a qualified life or specified 

time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these 

criteria, the staff sought to confirm that these structural components were subject to an AMR as 

required by 10 CFR 54.21(a)(1). As stated previously, when discrepancies were identified, the 

staff requested additional information to resolve them.

2.4.1 Reactor Containment Vessel

2.4.1.1 Summary of Technical Information in the Application

LRA Section 2.4.1 describes the reactor containment vessel as a Class I cylindrical steel 

structure with a hemispherical dome roof and ellipsoidal bottom. It is completely enclosed by the 

shield building, but has an annular space between the reactor containment vessel and the 

shield building; except at the lower portion that is embedded in the concrete fill. The major 

concrete components are the reactor cavity shield wall, refueling pool, compartment vaults, and 

the floors at various elevations. The reactor cavity concrete shield wall surrounds the reactor 

vessel, all its nozzles and immediate piping, and also provides biological shielding and structural 

support. The top of the shield wall forms the refueling cavity pool. The shield wall also acts as a 

missile barrier.

The reactor containment vessel section also includes penetrations and internal concrete and 

steel structures. The listed penetrations include piping, electrical, heating and ventilation, 

equipment hatch, emergency and personnel airlocks, fuel transfer tubes, and internal structures.

Its purpose is to house the reactor pressure vessel and NSSS equipment, as well as various 

safety-related and nonsafety-related components.
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LRA Table 2.4.1-1 identifies the components subject to an AMR for the reactor containment 

vessel by component type and intended function.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.1, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the reactor containment vessel.

In RAI 2.4-1, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of additional structural components 

that support the intended functions of the penetration assemblies (i.e., welds between the 

canister and the nozzle and canister support) not listed in LRA Table 2.4.1-1.

In its response dated August 6, 2009, the applicant stated that the structural components that 

support the intended functions of the penetration assemblies (i.e., welds between the canister 

and the nozzle and canister support) were within the scope of license renewal and subject to an 

AMR. 

The applicant also stated that the nozzle with the integral welds and canister support was 

classified under the title ―Electrical Penetration Nozzles,‖ in LRA Table 2.4.1-1, and that the 

intended functions listed for this entry in LRA Table 2.4.1-1 are ―EQ Barrier, Fire Barrier, 

Pressure Boundary, and Structural Support.‖

Based on its review, the staff finds the response to RAI 2.4-1 acceptable because the structural 

components that support the intended functions of the penetration assemblies have been 

designated as within the scope of license renewal and subject to an AMR. Therefore, the staff‘s 

concern described in RAI 2.4-1 is resolved.

In RAI 2.4-2, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of concrete/grout fill supporting the 

reactor containment vessel not listed in LRA Table 2.4.1-1.

In its response dated August 6, 2009, the applicant stated that the concrete/grout fill is an 

integral part of the common foundation basemat that provides support to the reactor 

containment vessel; therefore, it is within the scope of license renewal and subject to an AMR. 

The applicant also stated that the concrete/grout fill was classified under the structural 

component ―Reactor Containment Vessel Basemat,‖ in LRA Table 2.4.1-1. The intended 

function listed for this entry in LRA Table 2.4.1-1 is ―Structural Support.‖

Based on its review, the staff finds the response to RAI 2.4-2 acceptable because the structural 

concrete/grout fill that supports the reactor containment vessel and its intended functions has 

been designated as within the scope of license renewal and subject to an AMR. Therefore, the 

staff‘s concern described in RAI 2.4-2 is resolved.
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In RAI 2.4-3, dated July 16, 2009, the staff requested that the applicant provide additional 

information to clarify the intended function of the masonry block walls since they were listed as 

enclosures for equipment in LRA Section 2.4.1 and listed as ―Structural Support,‖ in 

LRA Table 2.4.1-1. 

In its response dated August 6, 2009, the applicant stated that the intended function of the 

masonry block walls located inside the reactor containment vessel is ―Enclosure Protection,‖ 

and that they were incorrectly indicated as ―Structural Support,‖ in LRA Table 2.4.1-1.

Based on its review, the staff finds the response to RAI 2.4-3 acceptable because the intended 

function of the masonry block walls located inside the reactor containment vessel has been 

clarified. Therefore, the staff‘s concern described in RAI 2.4-3 is resolved.

2.4.1.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

reactor containment vessel 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).

2.4.2 Structures and Component Supports

2.4.2.1 Shield Building

2.4.2.1.1 Summary of Technical Information in the Application

LRA Section 2.4.2.1 describes the shield building as a Class I reinforced concrete cylindrical 

shell structure with a shallow dome roof, that completely encloses the reactor containment 

vessel. Both the shield building and the reactor containment vessel are supported on a common 

concrete foundation basemat. 

The purpose of the shield building is to protect the reactor containment vessel from external 

missiles and provide biological shielding; additionally, it releases annulus atmosphere under 

accident conditions and provides environmental protection for the reactor containment vessel. 

Adjacent and exterior structures to the shield building walls are specially designed with 

provisions to allow movement of the shield building during an earthquake. Such features are 

flexible expansion joints at the separation spaces in walls and floors.

The shield building evaluation also includes access openings and penetrations, annulus 

concrete, and steel structures.

LRA Table 2.4.2-1 identifies the components subject to an AMR for the shield building by 

component type and intended function.
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2.4.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.1 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.1, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the shield building.

In RAI 2.4-4, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the double interlocked doors for 

the shield building personnel access openings since they are mentioned in LRA Section 2.4.2.1 

as being evaluated for an AMR with the ―Miscellaneous Structural Commodities,‖ but are not 

included in LRA Table 2.4.2-13.

In its response dated August 6, 2009, the applicant stated that the double interlocked doors for 

the shield building personnel access openings are within the scope of license renewal and 

subject to an AMR. 

The applicant also stated that the double interlocked doors for the shield building personnel 

access openings were classified under the structural member ―Doors,‖ in LRA Table 2.4.2-13. 

The intended functions listed for this entry in LRA Table 2.4.2-13 are ―Enclosure Protection, EQ 

Barrier, Fire Barrier, Flood Barrier, Pressure Boundary, and Structural Support.‖

Based on its review, the staff finds the response to RAI 2.4-4 acceptable because the double 

interlocked doors for the shield building personnel access openings that support the intended 

function of the shield building have been designated as within the scope of license renewal and 

subject to an AMR. Therefore, the staff‘s concern described in RAI 2.4-4 is resolved.

In RAI 2.4-5, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the personnel airlock precast 

concrete panel and support framing for the shield building since they appear in USAR 

Figure 9.5-2, but have not been included in LRA Table 2.4.2-1.

In its response dated August 6, 2009, the applicant stated that the removable personnel airlock 

precast concrete panel and support framing are within the scope of license renewal and subject 

to an AMR. 

The applicant also stated that the removable personnel airlock precast concrete panel forms the 

wall at the shield building airlock cubicle opening and was classified under the structural 

member ―Structural Reinforced Concrete (Cubicles for Airlocks),‖ in LRA Table 2.4.2-3 titled 

―Auxiliary Building.‖ The intended functions listed for this entry in LRA Table 2.4.2-3 are 

―Enclosure Protection, EQ Barrier, Fire Barrier, Flood Barrier, Jet Impingement Shield, Missile 

Barrier, Pressure Boundary, and Structural Support.‖

Additionally, the applicant stated that the support framing for the precast concrete panel was 

classified under the structural member ―Miscellaneous Steel,‖ in LRA Table 2.4.2-3, and that the

intended function listed for this entry in LRA Table 2.4.2-3 is ―Structural Support.‖

Based on its review, the staff finds the response to RAI 2.4-5 acceptable because the personnel 

airlock precast concrete panel and structural support framing for the shield building that support 
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the intended functions of the shield building have been designated as within the scope of 

license renewal and subject to an AMR. Therefore, the staff‘s concern described in RAI 2.4-5 is 

resolved.

2.4.2.1.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the shield 

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).

2.4.2.2 Administration Building

2.4.2.2.1 Summary of Technical Information in the Application

LRA Section 2.4.2.2 describes the administration building as a structure with a reinforced 

concrete basemat founded on soil that consists of multiple levels that directly interface with the 

turbine building. The purpose of the structure‘s levels varies since the basement houses EDG 

rooms 1A and 1B and the upper levels consist of office space for plant personnel. The 

basement of the administration building is classified as Class I. The remaining areas are 

Class III. Regarding the EDG equipment, the air intake structures for rooms 1A and 1B, and the 

air outlet structure for room 1B are located outside, adjacent to the administration building. The 

air outlet for room 1A is through the screenhouse access tunnel. Also, the electrical power 

cables for two of the service water pumps and a fire pump are routed through an underground 

duct bank entrance area located at the southeast corner of the administration building.

There are additional safety-related components in the building that are within the scope of 

license renewal, such as doors and a trench to protect safety-related equipment from internal 

flooding due to a pipe break, as well as masonry walls that prevent the spread of a fire.

LRA Table 2.4.2-2 identifies the components subject to an AMR for the administration building 

by component type and intended function.

2.4.2.2.2 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

administration building 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).
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2.4.2.3 Auxiliary Building

2.4.2.3.1 Summary of Technical Information in the Application

LRA Section 2.4.2.3 describes the auxiliary building as a concrete and steel multi-story structure 

that interfaces with the shield building and turbine building. It is a Class I structure, except for 

the tank storage enclosure area and the cask handling area located on the south and west side 

of the auxiliary building, respectively. These areas are Class III* structures, which support SBO 

and fire protection. A steel frame structure which supports the auxiliary building crane and roof 

decking above the spent fuel pool is designed as Class I*. Additionally, other structural 

components such as flexible expansion joints are provided above the mezzanine floor between 

the auxiliary building and shield building exterior walls for lateral movement of the buildings 

during a seismic event. 

Other in-scope components provide equipment protection from various hazards, such as the 

doors and penetration seals that protect equipment from HELBs; the encapsulation sleeves and 

jet impingement shields; flood barriers, sumps, and trenches; hatch covers installed on the roof 

and floors for missile protection; and missile shields installed to protect the service water system 

piping from tornado generated missiles.

The Zone SV area of the auxiliary building is maintained at a negative pressure to ensure 

leak-tight integrity and provides a medium-leakage boundary, which confines leakage that could 

conceivably bypass the shield building annulus. The steam exclusion area is also included in 

the Zone SV area. The spent fuel pool and the fuel transfer canal are also in the auxiliary 

building and included within the scope of license renewal.

LRA Table 2.4.2-3 identifies the components subject to an AMR for the auxiliary building by 

component type and intended function.

2.4.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.3 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.3, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the auxiliary building.

In RAI 2.4-6, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the missile shields for the service 

water system piping and the fuel transfer canal stainless steel liner since it is not clear whether

they were included in LRA Section 2.4.2.3 or LRA Table 2.4.2-3 as being within the scope of 

license renewal and subsequently evaluated for an AMR.

In its response dated August 6, 2009, the applicant stated that both the missile shields for the 

service water system piping and the fuel transfer canal stainless steel liner are within the scope 

of license renewal and subject to an AMR. 

The response also stated that the missile shields for the service water system piping were 

incorrectly omitted from the screening results in LRA Table 2.4.2-3 and AMR Table 3.5.2-4. 

Their intended function is ―Missile Barrier‖ protection. They are exposed to ―air-indoor 
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uncontrolled‖ and ―borated water leakage‖ environments which cause the loss of material due to 

normal corrosion, as well as boric acid corrosion, respectively. The applicant further indicated 

that these aging effects will be analyzed in the Structures Monitoring Program and the Boric 

Acid Corrosion Program, respectively.

Additionally, the fuel transfer canal stainless steel liner is classified under the structural member 

―Spent Fuel Pool Liner,‖ in LRA Table 2.4.2-3. The intended functions listed for this entry in LRA 

Table 2.4.2-3 are ―Enclosure Protection, Pressure Boundary, and Structural Support.‖

Based on its review, the staff finds the response to RAI 2.4-6 acceptable because the missile 

shields for the service water system piping and the fuel transfer canal stainless steel liner that 

support the intended functions of the auxiliary building have been designated as within the 

scope of license renewal, and subject to an AMR. Therefore, the staff‘s concern described in 

RAI 2.4-6 is resolved. 

2.4.2.3.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 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).

2.4.2.4 Screenhouse Access Tunnel

2.4.2.4.1 Summary of Technical Information in the Application 

LRA Section 2.4.2.4 describes the screenhouse access tunnel as a Class I reinforced concrete 

rectangular tunnel, founded on soil and located below grade between the screenhouse and the 

administration building. Its purpose is to provide support and shelter for two service water 

supply headers and a fire supply header. Additionally, it provides support for the cables that 

provide power to two of the safety-related service water pumps and to one of the fire pumps 

located in the screenhouse. Also, the screenhouse access tunnel serves as an air outlet for 

EDG room 1A of the administration building.

LRA Table 2.4.2-4 identifies the components subject to an AMR for the screenhouse access 

tunnel by component type and intended function.

2.4.2.4.2 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

screenhouse access tunnel 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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2.4.2.5 Technical Support Center

2.4.2.5.1 Summary of Technical Information in the Application 

LRA Section 2.4.2.5 describes the TSC as being located adjacent to the turbine and auxiliary 

buildings. It is supported on a reinforced concrete mat foundation that is founded on soil and 

separated from adjacent buildings by a seismic gap that prevents interactions during a seismic 

event. The TSC basement level is classified as a Class I structure and has exterior walls 

constructed of reinforced concrete; the first and second floors are classified as Class III* 

structures and have exterior walls constructed of concrete masonry block.

Additionally, LRA Section 2.4.2.5 describes the TSC basement level as containing 

safety-related cables that are required for safe shutdown, as well as housing other 

administrative facilities. The TSC first floor includes the TSC diesel generator room, associated 

electrical equipment and battery rooms, additional equipment rooms, and administrative offices.

The TSC second floor level provides offices and working space for office personnel, and the 

roof provides support for a heat exchanger and an exhaust muffler for the TSC diesel generator.

2.4.2.5.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.5 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.5, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the TSC.

In RAI 2.4-7, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the Class III metal siding attached 

to the masonry block walls since LRA Section 2.4.2.5 states that it is not within the scope of 

license renewal, but LRA Section 2.1.3.6.3 states that it is included per 10 CFR 54.4(a)(2). 

There is no exception provided in USAR Table B.2-1 for metal siding classification.

In its response dated August 6, 2009, the applicant stated that the metal siding was evaluated 

per 10 CFR 54.4(a)(2); however, since the component is not credited for any load carrying 

capabilities in the TSC seismic analysis, it does not perform a license renewal function and,

therefore, this is consistent with the statement in LRA Section 2.4.2.5.

Based on its review, the staff finds the response to RAI 2.4-7 acceptable because the Class III 

metal siding attached to the masonry block walls does not support any of the scoping criteria 

presented in 10 CFR 54.4. Therefore, the staff‘s concern described in RAI 2.4-7 is resolved.

In RAI 2.4-8, dated July 16, 2009, the staff requested that the applicant provide additional 

information to clarify and further explain the TSC building configuration, since it is stated in 

USAR Table B.2.1 and Figure 1.2-11 that it is a one-story building and then stated in LRA 

Section 2.4.2.5 that it is a two-story building.

In its response dated August 6, 2009, the applicant stated that the configuration of the TSC in 

LRA Section 2.4.2.5 is correct since it is a two-story building.
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The response also stated that the basement and first floor were constructed in the 1980s and 

the second floor was added around 2004. However, the USAR, Revision 20, which was 

provided with the LRA, does not reflect the addition to the building. A subsequent revision has 

this addition incorporated in its review.

Based on its review, the staff finds the response to RAI 2.4-8 acceptable because the 

configuration of the TSC has been clarified and the building is included within the scope of 

license renewal, and thus subject to an AMR, since the TSC supports the scoping criteria 

presented in 10 CFR 54.4. Therefore, the staff‘s concern described in RAI 2.4-8 is resolved.

2.4.2.5.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the TSC 

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).

2.4.2.6 Turbine Building

2.4.2.6.1 Summary of Technical Information in the Application

LRA Section 2.4.2.6 describes the turbine building as a multi-story steel structure that interfaces 

with the auxiliary building, administration building, outdoor transformer bays, and TSC. It is 

founded on soil atop a reinforced concrete basemat. Additionally, the building is physically 

separated by seismic gaps from the TSC and outdoor transformer bays for seismic protection. 

The building is also equipped with flood barriers, a sump, a trench to protect safety-related 

equipment from internal flooding, and masonry walls for fire protection. The Class I areas of the 

building consist of the areas‘ housing safeguard batteries, safety features 480-volt switchgear, a 

station air compressor, and the auxiliary feedwater pumps. Also, the support system for the 

turbine building crane is Class I*. The rest of the structure is classified as Class III*. Finally, the 

turbine building houses the exhaust piping for the two EDGs; these exhaust pipes are routed 

through the building and their vents are located on the roof.

LRA Table 2.4.2-6 identifies the components subject to an AMR for the turbine building by 

component type and intended function.

2.4.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.6 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.6, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the turbine building.

In RAI 2.4-9, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the jet impingement barriers and 
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encapsulation sleeves located in the turbine building since they are shown in USAR 

Figure 10A.3-27 but not included in LRA Table 2.4.2-6.

In its response dated August 6, 2009, the applicant stated that the jet impingement barriers 

located in the turbine building are within the scope of license renewal and are subject to an 

AMR. The response also stated that the jet impingement barriers were included under the 

component type ―Piping Sleeves,‖ in LRA Table 2.3.4-2. The intended functions listed for this 

entry in LRA Table 2.3.4-2 are ―EQ Barrier, Jet Impingement Shield, and Pressure Boundary.‖ 

Based on its review, the staff finds the response to RAI 2.4-9 acceptable because the jet 

impingement barrier and encapsulation sleeves that support the intended functions of the 

turbine building have been designated as within the scope of license renewal and subject to an 

AMR. Therefore, the staff‘s concern described in RAI 2.4-9 is resolved.

2.4.2.6.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 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).

2.4.2.7 Yard Structures

2.4.2.7.1 Summary of Technical Information in the Application

LRA Section 2.4.2.7 describes the yard structures as being physically located throughout the 

yard and substation/switchyard area. They are within the scope of license renewal and are 

composed of the following structures:

● duct banks

● EDG fuel oil storage tanks foundation

● fire hose houses

● lighting poles (P2, P4, P5)

● manholes

● outdoor transformer bays

● substation/switchyard structures

● transmission towers

LRA Table 2.4.2-7 identifies the components subject to an AMR for the yard structures by 

component type and intended function.

Duct Banks. The duct banks are made of reinforced concrete, are soil supported, and are 

provided to route electrical cables underground. Their function is to support and protect 

electrical cables for safety-related equipment, SBO, and fire protection.

EDG Fuel Oil Storage Tanks Foundation. The EDG fuel oil storage consists of two underground 

tanks that are supported on compacted backfill material that is located between the tanks and a 
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common concrete mat foundation. The tanks are structurally equipped with steel bar straps that 

completely wrap around each tank and are anchored into the concrete mat foundation. The 

purpose of the bar straps anchored to the foundation is to resist any uplift forces from buoyancy 

that could occur within the tanks. 

Fire Hose Houses. The fire hose houses consist of small steel structures supported on concrete 

slabs that are provided at various locations throughout the yard area. Their purpose is to house 

fire protection equipment.

Lighting Poles. The security lighting in the yard area is provided by three steel lighting poles 

(Poles 2, 4, and 5) which are supported by a reinforced concrete caisson foundation.

Manholes. A total of four manholes located in the yard structures are within the scope of license 

renewal. Three of the four manholes provide access to underground fuel oil storage tanks and 

the remaining manhole supports electrical cables required for the restoration of offsite power for 

SBO. This fourth manhole is an enclosed underground reinforced concrete structure that is soil 

supported and is located near the tertiary auxiliary transformer. 

Two reinforced concrete access manholes are provided for the EDG fuel oil storage tanks and 

one reinforced concrete access manhole is provided for the TSC diesel generator fuel oil 

storage tank. These manholes rest directly on the tanks.

Outdoor Transformer Bays. There are a total of seven outdoor transformer bays that are located 

adjacent to the south and east sides of the turbine building. Construction for all the transformer 

bays consists of reinforced concrete for the side walls and the back wall is the exterior wall of 

the turbine building. The side walls are supported on a spread footing foundation and each bay 

has a reinforced concrete floor slab founded on soil. For each bay, the transformers located 

within are supported on a concrete mat foundation that is isolated by a construction joint from 

the concrete bay floor. Additionally, each transformer bay is built with firewalls and is fire 

protected with an automatic water spray system to extinguish and prevent the spread of fires. 

The reserve auxiliary transformer (RAT) and the tertiary auxiliary transformer (TAT) are required 

for the restoration of offsite power for SBO. The evaluation boundary for the outdoor transformer 

bays structural members subject to an AMR includes all of the bays since they support an 

automatic water spray system required for fire protection. However, only the foundations that 

support the RAT and TAT are within the scope of license renewal. 

Substation/Switchyard Structures. The structures within the scope of license renewal associated 

with the substation/switchyard are the steel structures and associated foundations for the 

138-kilovolt (kV) take-off tower, 13.8-kV take-off structure, and the 138-kV and 13.8-kV 

disconnect switches. The 13.8-kV take-off concrete structure and the concrete foundations for 

the 138-kV and 13.8-kV oil circuit breakers are also included within the scope of license 

renewal.

Transmission Towers. The transmission lines required for the restoration of offsite power for 

SBO are supported by three steel transmission towers (Towers 1, 3, and 4). These towers are 

single pole steel structures supported by a reinforced concrete caisson foundation and are 

installed from outside the substation/switchyard to the RAT. They support the 138-kV RAT 

circuit on one side and the main transformer 345-kV circuit on the other side. 
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2.4.2.7.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.7 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.7, the staff identified an area in which additional 

information was necessary to complete the evaluation of the applicant‘s scoping and screening 

results for the yard structures.

In RAI 2.4-15, dated July 16, 2009, the staff requested that the applicant clarify whether

additional foundations for other Class I and II transformers listed in USAR Table B.2-1 are 

included within the scope of license renewal since LRA Section 2.4.2.7 states that only the 

foundations that support the RAT and TAT are within the scope of license renewal.

In its response dated August 6, 2009, the applicant stated that USAR Table B.2-1 lists the RAT, 

the TAT, the start-up transformer, the transformer serving the pressurizer heater from the safety 

features bus, and the 4.16–.480-kV safety features transformers.

The applicant stated further that the start-up transformer is the same transformer as the RAT 

and is incorrectly listed in USAR Table B.2-1. Therefore, the applicant concluded that the RAT, 

TAT, the transformer that serves the pressurizer, and the 4.16–.480-kV safety features 

transformers are included within the scope of license renewal.

Finally, the response stated that the foundation for the pressurizer heater from the safety 

features bus is evaluated in the structural member ―Equipment pads/grout‖ in LRA 

Table 2.4.2-3, and that the foundations for the 4.16–.480-kV safety features transformers are 

included in LRA Table 2.4.2-6, ―Turbine Building.‖

Based on its review, the staff finds the response to RAI 2.4-15 acceptable because the 

transformers listed in USAR Table B.2-1 have been clarified and justified for inclusion within the 

scope of license renewal. The staff‘s concern described in RAI 2.4-15 is resolved. 

2.4.2.7.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the yard 

structures 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).

2.4.2.8 Discharge Structure

2.4.2.8.1 Summary of Technical Information in the Application

LRA Section 2.4.2.8 describes the discharge structure as a Class I reinforced concrete 

(onshore) structure that provides the termination for the circulating water discharge pipe, a 

transition from the pipe to the open discharge bay and the outlet to the lake.
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The discharge structure consists of reinforced concrete floors, walls, and a roof, as well as a 

concrete baffle that is provided to help dissipate the exit velocity and spread the discharge water 

into the open discharge basin, at the shoreline of Lake Michigan. Additionally, there is an 

interconnecting pipe between the discharge structure and the screenhouse forebay that 

provides an alternate source of service water, as well as warm recirculation water that helps 

dissipate the formation of frazil ice on the traveling water screens.

LRA Table 2.4.2-8 identifies the components subject to an AMR for the discharge structure by 

component type and intended function.

2.4.2.8.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.8 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.8, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the discharge structure.

In RAI 2.4-10, dated July 16, 2009, the staff requested that the applicant provide additional 

information to justify the exclusion of the riprap that paves the near shore portion of the basin 

and the riprap installed outside the sheet pile walls from the scope of license renewal. LRA 

Section 2.4.2.8 states that the purpose of the riprap in the structure is to dissipate the exit 

velocity of the discharge and does not perform a license renewal intended function. However, 

USAR Section 2.6.2 states that the riprap serves to protect the circulating water discharge.

In its response dated August 6, 2009, the applicant stated that the riprap that paves the near 

shore portion of the basin and the riprap installed outside the sheet pile wall are not within the 

scope of license renewal and thus not subject to an AMR. 

The response also stated that the riprap is provided as good engineering practice to help 

prevent shore erosion from storms or wave run-up. Also, the design of the discharge structure 

and the sheet pile wall is not based on riprap protection being installed outside the sheet pile 

wall. Additionally, the discharge water would not be prevented from returning to the lake if 

erosion of the riprap occurred.

Based on its review, the staff finds the response to RAI 2.4-10 acceptable because the reasons 

for excluding the riprap that paves the near shore portion of the basin and the riprap installed 

outside the sheet pile wall from the scope of license renewal have been justified. Therefore, the 

staff‘s concern described in RAI 2.4-10 is resolved.

2.4.2.8.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 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 the applicant has adequately identified the 

discharge structure 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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2.4.2.9 Discharge Tunnel and Pipe

2.4.2.9.1 Summary of Technical Information in the Application

LRA Section 2.4.2.9 describes the discharge tunnel and pipe as a reinforced concrete structure 

founded on soil and buried for the entire length. The discharge tunnel and pipe are classified as 

Class III structures.

The discharge tunnel is described as a reinforced concrete structure located beneath the turbine 

building at the condenser discharge. The discharge pipe is described as consisting of sections 

that are made of concrete encased steel pipe (underneath the turbine building and buried 

Y-section in the yard). The remaining sections are reinforced concrete pipe.

The purpose of the discharge tunnel and pipe is to route discharge water from the condenser 

outlets, drainage, and service water into the discharge structure. 

LRA Table 2.4.2-9 identifies the components subject to an AMR for the discharge structure by 

component type and intended function.

2.4.2.9.2 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 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 the applicant has adequately identified the 

discharge tunnel and pipe 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).

2.4.2.10 Intake Structure

2.4.2.10.1 Summary of Technical Information in the Application

LRA Section 2.4.2.10 describes the intake structure as a Class I structure consisting of vertical 

inlet cones, outlet pipes, and trash grilles. The structure is physically located approximately 

1,600 feet from the shore of Lake Michigan, in a water depth of 15 feet. The three 22-foot 

diameter vertical steel inlet cones are completely submerged and buried 12.5 feet below the 

lakebed, and discharge their water through 6-foot diameter outlet pipes into a 10-foot diameter 

steel intake pipe. Additionally, the trash grilles located at the top of each cone are anchored to a 

reinforced concrete ring foundation that is supported by the riprap laid below the lakebed.

The purpose of the intake structure is to provide a reliable source of lake water to the suction of 

two circulating water pumps, four service water pumps, and two fire pumps. 

LRA Table 2.4.2-10 identifies the components subject to an AMR for the intake structure by 

component type and intended function.

2.4.2.10.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.10 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 of LRA Section 2.4.2.10, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant‘s scoping and screening 

results for the intake structure.

In RAI 2.4-11, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the 6-foot diameter outlet pipes 

where the inlet cones of the intake structure discharge their water since they were not included 

in LRA Table 2.4.2-10.

In its response dated August 6, 2009, the applicant stated that the 6-foot diameter outlet pipes 

located in the intake structure are within the scope of license renewal and subject to an AMR.

The response also stated that the 6-foot diameter outlet pipes were included under the 

structural member ―Inlet Cones,‖ in LRA Table 2.4.2-10. The intended function listed for this 

entry in LRA Table 2.4.2-10 is ―Source of Cooling, Structural Support.‖ 

Based on its review, the staff finds the response to RAI 2.4-11 acceptable because the 6-foot 

diameter outlet pipes that support the intended functions of the intake structure have been 

included within the scope of license renewal and are subject to an AMR. Therefore, the staff‘s 

concern described in RAI 2.4-11 is resolved.

In RAI 2.4-12, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the two auxiliary water intake tees 

located in the plant intake since they were not included in LRA Table 2.4.2-10, nor LRA 

Section 2.4.2.10.

In its response dated August 6, 2009, the applicant stated that the two auxiliary water intake 

tees located in the intake structure are within the scope of license renewal and subject to an 

AMR. The response also stated that the two auxiliary water intake tees are spatially located 50 

and 100 feet shoreward of the intake crib and physically located in the 10-foot diameter steel 

intake pipe.

Both tees and the 10-foot diameter intake pipe were evaluated in the circulating water system 

and included under the component type ―Pipe,‖ in LRA Table 2.3.3-20. The intended function 

listed for this entry in LRA Table 2.3.3-20 is ―Pressure Boundary.‖ 

Based on its review, the staff finds the response to RAI 2.4-12 acceptable because the two 

auxiliary water intake tees that support the intended functions of the intake structure have been 

included within the scope of license renewal and subject to an AMR. Therefore, the staff‘s 

concern described in RAI 2.4-12 is resolved.

2.4.2.10.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the intake 

structure 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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2.4.2.11 Screenhouse

2.4.2.11.1 Summary of Technical Information in the Application

LRA Section 2.4.2.11 describes the screenhouse structure as soil-supported on a reinforced 

concrete mat foundation, mostly buried underground, and having a reinforced concrete roof 

deck located approximately 2.5 feet above grade. It is physically located 180 feet from the 

normal shoreline and is (for the areas housing service water facilities, piping and equipment) 

classified as a Class I structure.

The screenhouse structure includes a forebay area that allows overflow back into the lake in 

case of a water surge caused by tripping or starting of the circulating water pumps. Additionally, 

a 30-inch steel slotted pipe is installed in the forebay area that provides warm water from the 

circulating water discharge structure to the traveling screen inlet to prevent ice formation during 

cold weather operation. This line can also provide an alternate supply of service water if all 

other intakes are blocked. The purpose of the screenhouse structure is to house two circulating 

water pumps, four service water pumps, two fire pumps, and related auxiliaries. Additionally, 

power cables for two of the service water pumps and a fire pump are routed through an 

underground duct bank entrance area located at the southwest corner of the screenhouse. 

Additional features such as exterior bulkhead doors and bolted floor and manhole covers have 

been installed to prevent damage to safety-related equipment from external flooding due to the 

calculated maximum lake water level.

LRA Table 2.4.2-11 identifies the components subject to an AMR for the screenhouse by 

component type and intended function.

2.4.2.11.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2.11 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.2.11, the staff identified areas in which additional 

information was necessary to complete the evaluation of the applicant‘s scoping and screening 

results for the screenhouse.

In RAI 2.4-13, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the forebay overflow weir located 

in the screenhouse since it was not mentioned in LRA Table 2.4.2-11.

In its response dated August 6, 2009, the applicant stated that the forebay overflow weir is 

within the scope of license renewal and subject to an AMR.

The response also stated that the forebay overflow weir is included in the review under the 

structural member ―Structural Reinforced Concrete (foundation mat, walls, beams, columns, 

floor slabs, roof slab),‖ in LRA Table 2.4.2-11. 

The intended functions listed for this entry in LRA Table 2.4.2-11 include ―Enclosure Protection, 

Fire Barrier, Flood Barrier, Missile Barrier, and Structural Support.‖ 
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Based on its review, the staff finds the response to RAI 2.4-13 acceptable because the forebay 

overflow weir that supports the intended functions of the screenhouse has been included within 

the scope of license renewal and subject to an AMR. Therefore, the staff‘s concern described in 

RAI 2.4-13 is resolved.

2.4.2.11.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

screenhouse 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 Component Supports

2.4.3.1 Summary of Technical Information in the Application

LRA Section 2.4.3 describes the components/structural supports provided for the mechanical 

and electrical components.

Many of the supports are not uniquely identified with component identification numbers. 

However, since some of the characteristics of the supports such as design, materials of 

construction, environments, and anticipated stressors are similar, they are evaluated as 

commodities across system boundaries and within structures that are identified as being within 

the scope of license renewal. Some of the electrical/mechanical component supports addressed 

include piping, cable trays, HVAC, conduits, pumps, tanks, fans, and strainers. A complete list is 

provided in LRA Section 2.4.3 and Table 2.4.2-12.

2.4.3.2 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

component supports 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).

2.4.4 Miscellaneous Structural Commodities

2.4.4.1 Summary of Technical Information in the Application

LRA Section 2.4.4 describes the miscellaneous structural commodities as commodity groups 

that perform or support intended functions of in-scope SSCs.

The miscellaneous commodity groups include fire barriers, flood barriers, expansion 

joint/seismic gap materials, insulation, and electrical enclosure commodities. 
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LRA Table 2.4.2-13 identifies the components subject to an AMR for the miscellaneous 

structural commodities by component type and intended function.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review of LRA Section 2.4.4, the staff identified areas in which additional information 

was necessary to complete the evaluation of the applicant‘s scoping and screening results for 

the miscellaneous structural commodities.

In RAI 2.4-14, dated July 16, 2009, the staff requested that the applicant provide additional 

information to confirm the inclusion, or justify the exclusion, of the following components from 

LRA Table 2.4.2-13:

● grout pads for building structural column base plates

● vibration isolators

● waterproofing membrane

● waterstops

● anchor bolts and expansion anchors

● damper framing

In its response dated August 6, 2009, the applicant stated that the following components are 

within the scope of license renewal:

● grout pads for building structural column base plates

● vibration isolators

● anchor bolts and expansion anchor

● damper framing

The applicant also stated that the following components are not within the scope of license 

renewal:

● waterproofing membrane

● waterstops

Specifically, the applicant provided in its response the justification for inclusion or exclusion for 

each component. Additionally, the applicant stated that the components within the scope of 

license renewal are evaluated and included in the review as follows:

Grout Pads for Building Structural Column Base Plates. Included in the structural member 

―Structural reinforced Concrete,‖ in LRA Tables 2.4.1-1, 2.4.2-3, and 2.4.2-5. Grout pads for the 

turbine building are included in the structural member ―Foundation Basemat,‖ in LRA 

Table 2.4.2-6.

Vibration Isolators. Included in the component type/structural member ―Supports for Mechanical 

Equipment,‖ in LRA Table 2.4.2-12.
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Anchor Bolts and Expansion Anchors. The embedded portion of the anchor bolts and expansion 

anchors is evaluated as part of the concrete in which it exists. The section of the anchor bolts 

and expansion anchors that is not embedded is evaluated as part of the structural member it is 

supporting.

Damper Framing. Damper framing is identified under the component type ―Damper Housing,‖ in 

LRA Section 2.3, ―Mechanical Systems.‖

Based on its review, the staff finds the response to RAI 2.4-14 acceptable because the 

additional component types listed under RAI 2.4-14 for the miscellaneous structural 

commodities have been addressed as being within the scope of license renewal, or justified as 

excluded from the scope. Therefore, the staff‘s concern described in RAI 2.4-14 is resolved.

2.4.4.3 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the 

miscellaneous structural commodities 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 Nuclear Steam Supply System Structural Supports

2.4.5.1 Summary of Technical Information in the Application

LRA Section 2.4.5 describes the NSSS equipment supports as components that provide support 

and restraint to the following RCS equipment:

● reactor vessel

● reactor coolant pumps

● steam generators

● pressurizer

Reactor Vessel Supports. A total of six vertical steel H-columns are connected together at the 

top by means of a structural tee horizontal bracing system that is welded to a continuous outer 

steel band. The columns are embedded in concrete in order to provide a rigid anchorage 

system. Some of the design features of these columns are ventilated support pads, fitted key 

slot blocks, and machined keys.

Reactor Coolant Pumps Supports. A total of three vertical steel H-columns, hinged at each end 

for vertical support and uplift, are provided for support to each of the two reactor coolant pumps. 

They are designed to provide unrestrained movement laterally, in the direction of thermal 

expansion during heatup and cooldown.

Steam Generators Supports. A total of four steel vertical H-columns, hinged at each end, are 

provided for support to each of the two SGs. The hinges provide for unrestrained movement in 

the direction of thermal expansion and the column ends are anchored by embedded bolts at the 
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base to provide for uplift forces. Also, there are two lateral levels of support that are provided for 

the lateral seismic and pipe rupture loads. Additionally, two cable anchors fitted with yokes

welded to the pipe bends restrain the reactions of jet forces in the main steam line at the top of 

the SG.

Pressurizer Support. A support skirt anchored to the concrete floor by equally spaced, 

embedded anchor bolts is provided to support the pressurizer. The other end of the skirt is 

welded to the pressurizer.

LRA Table 2.4.2-14 identifies the components subject to an AMR for the NSSS supports by 

component type and intended function.

2.4.5.2 Conclusion

The staff followed the evaluation methodology discussed in SER Section 2.4 and 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 determined if 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 the applicant has adequately identified the NSSS 

supports 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 Systems/Commodity Groups

This section documents the staff‘s review of the applicant‘s scoping and screening results for 

electrical and I&C systems. Specifically, this section discusses:

● electrical and I&C component commodity groups

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SSCs 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 are 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 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 being within the scope of license renewal. The staff 

reviewed the USAR for each electrical and I&C system to determine if the applicant has omitted 

from the scope of license renewal components with intended functions delineated under 

10 CFR 54.4(a). 
Structures and Components Subject to Aging Management Review

2-132

After its review of the scoping results, the staff evaluated the applicant‘s screening results. For 

those SSCs 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 SSCs 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 SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5.1 Electrical and Instrumentation and Controls Systems

2.5.1.1 Summary of Technical Information in the Application

LRA Section 2.5 describes the electrical and I&C systems. The scoping method includes all 

plant electrical and I&C components. Evaluation of electrical systems includes electrical and 

I&C components in mechanical systems. The plantwide basis approach for the review of plant 

equipment eliminates the need to indicate each unique component and its specific location, and 

precludes improper exclusion of components from an AMR.

LRA Tables 2.5.1-1, 2.5.2-1, and 2.5.3-1 identify electrical and I&C systems component types 

and their intended functions within the scope of license renewal and subject to an AMR: 

● cable connections (metallic parts) - conducts electricity

● conductor insulation for electrical cables and connections - insulate

● conductor insulation for electrical cables and connections used in sensitive 

instrumentation circuits - insulate

● conductor insulation for inaccessible medium-voltage (2-kV to 35-kV) cables - insulate

● electrical equipment subject to 10 CFR 50.49 EQ requirements - conducts electricity, 

insulate

● fuse holders insulation - insulate

● transmission conductors and connections - conducts electricity

● fuse holders (not part of a larger assembly) metallic clamp - conducts electricity

● conductor insulation, metal-enclosed bus (MEB) - insulate

● metallic conductor, MEB - conducts electricity

● metallic conductor, switchyard bus - conducts electricity

● support insulation, high-voltage - insulate, structural support

● support insulation, MEB - insulate, structural support
Structures and Components Subject to Aging Management Review

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2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5 and USAR Sections 7 and 8 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 under 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).

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 addition, the staff 

noted that the guidance provided by letter, dated April 1, 2002 (ADAMS Accession No. 

ML020920464), ―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 SRP-LR 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 SSCs 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 [operation].

The applicant included the complete circuits between the onsite circuits and, up to and 

including, switchyard breakers (which includes the associated controls and structures) supplying 

the RAT and the TAT within the scope of license renewal. The RAT (which is the normal supply 

to emergency 4160-volt bus 1-6) is supplied from either of two 138-kV breakers in the 

switchyard and the TAT (which is the normal supply to emergency 4160-volt bus 1-5) is supplied 

from a 13.8-kV breaker in the switchyard which is fed from the secondary winding of a 

transformer which connects the 138-kV and 345-kV sections of the switchyard. Consequently, 

the staff concludes that the scoping is consistent with the guidance issued in the letter of April 1, 

2002, and was later incorporated in SRP-LR Section 2.5.2.1.1.

2.5.1.3 Conclusion

The staff reviewed the LRA and the USAR to determine whether the applicant failed to identify 

any SSCs within the scope of license renewal. The staff found no such omissions. In addition, 

the staff 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 adequately identified the electrical and I&C systems 
Structures and Components Subject to Aging Management Review

2-134

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).

2.6 Conclusion for Scoping 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.‖ The staff finds that the applicant‘s scoping and screening methodology 

is consistent with the requirements of 10 CFR 54.21(a)(1), and with the staff‘s position on the 

treatment of safety-related and nonsafety-related SSCs within the scope of license renewal and 

the SCs requiring an AMR are 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 that are within the scope of license renewal, as required by 

10 CFR 54.4(a), and those systems and components that are subject to an AMR, as required by 

10 CFR 54.21(a)(1).

With regard to these matters, the staff concludes, 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 54.21(a)(1), are in accordance with the Atomic 

Energy Act of 1954 and NRC regulations.
3-1

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 Kewaunee Power Station (KPS), by the 

staff of the U.S. Nuclear Regulatory Commission (NRC) (the staff). 

In Appendix B of its license renewal application (LRA), Dominion Energy Kewaunee, Inc., 

(Dominion, DEK, or the applicant) described the 34 AMPs 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, ―Generic Aging Lessons Learned 

(GALL) Report,‖ Revision 1, 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 SCs for license renewal without change. The GALL 

Report also contains recommendations concerning 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 the programs at its facility correspond to those reviewed and approved 

in the GALL Report.

The purpose of the GALL Report is to provide the staff with 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 used to review an 

applicant‘s LRA will be greatly reduced, thereby improving the efficiency and effectiveness of 

the license renewal review process. The GALL Report also serves as a reference for applicants 

and staff reviewers to quickly identify those 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 associated with 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.

The staff performed its review in accordance with the requirements of Title 10, Part 54 of the 

Code of Federal Regulations (10 CFR Part 54), ―Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants‖; the guidance provided in NUREG-1800, ―Standard Review 
Aging Management Review Results

3-2

Plan for Review of License Renewal Applications for Nuclear Power Plants‖ (SRP-LR), 

Revision 1, dated September 2005; and the guidance provided in the GALL Report.

In addition to its review of the LRA, the staff conducted onsite audits of selected AMPs to verify 

the applicant‘s claims of consistency with the GALL Report during the weeks of June 8, 2009, 

and October 20, 2009, as described in the ―AMP Audit Report Regarding the Kewaunee Power 

Station, License Renewal Application,‖ dated August 12, 2009, and in the ―Work Control 

Process Aging Management Program Audit Report Regarding the Kewaunee Power Station, 

License Renewal Application,‖ dated December 14, 2009, respectively. The onsite audits and 

reviews are designed to maximize the 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 followed the standard LRA format, as agreed to by 

the staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003. This LRA format 

incorporates lessons learned from the staff‘s reviews of previous 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. The AMR results 

information in LRA Section 3 is presented in the following two table types:

 (1) Table 3.x.1 (Table 1s) – where ―3‖ indicates the LRA section number, ―x‖ indicates the 

subsection number from the GALL Report, and ―1‖ indicates that this is the first table 

type in LRA Section 3.

 (2) Table 3.x.2-y (Table 2s) – where ―3‖ indicates the LRA section number, ―x‖ indicates the 

subsection number from the GALL Report, ―2‖ indicates that this is the second table type 

in LRA Section 3, and ―y‖ indicates the system table number.

The content of the GALL Report tables and the LRA tables are essentially the same. In its LRA, 

the applicant chose to modify the tables in Chapter 3 to provide additional information that 

would assist the staff in its review. In each Table 1, the applicant summarized the portions of the 

application with respect to consistency with the GALL Report. In each Table 2, the applicant 

identified the linkage between the scoping and screening results in Chapter 2 and the AMRs in 

Chapter 3.

3.0.1.1 Overview of Table 1s

Each of the Tables 3.x.1 (Table 1s) provides a summary comparison of how the facility aligns 

with the corresponding tables of the GALL Report. These tables are essentially the same as 

Tables 1 through 6 provided in the GALL Report, Volume 1, except that the ―ID‖ column has 

been replaced by an ―Item Number‖ column, the ―Type‖ column is removed, and the ―Related 

Generic Item‖ and ―Unique Item‖ columns have been replaced by a ―Discussion‖ column. The 

―Discussion‖ column is used by the applicant to provide clarifying and amplifying information. 
Aging Management Review Results

3-3

The following are examples of information that the applicant placed within this column:

 statements indicating that further evaluation is documented in subsection x

 statements indicating that subsection x contains information or evaluations related to the 

item

 exceptions to the GALL Report assumptions

 discussion of how the item is consistent with the corresponding line item in the GALL 

Report when this consistency may not be intuitively obvious

 discussion of how the item is different from the corresponding line item in the GALL 

Report (e.g., when there is exception taken to a GALL Report AMP)

The format of the Table 1s allows the staff to align a specific Table 1 row with the corresponding 

GALL Report table row so that the consistency can be easily checked. 

3.0.1.2 Overview of Table 2s

Each of the Tables 3.y.2-x (Table 2s) provides the detailed results of the AMRs for those 

components identified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for 

each of the systems or components ―x‖ within a system grouping ―y‖ (e.g., reactor coolant 

systems, engineered safety features, auxiliary systems, etc.). For example, the engineered 

safety features group (3.2.2-x) contains tables specific to the containment vessel spray system, 

safety injection system, and residual heat removal system. Each Table 2 consists of the 

following nine columns:

 (1) Component Type – The first column identifies the component types, commodity groups, 

structural members, or subcomponents from LRA Section 2 that are subject to an AMR. 

The component types are listed in alphabetical order.

 (2) Intended Function – The second column contains the license renewal intended functions 

for the listed component types. Definitions of intended functions are contained in LRA 

Table 2.0-1.

 (3) Material – The third column lists the particular materials of construction for the 

component type.

 (4) Environment – The fourth column lists the environment to which the component types 

are exposed. Internal and external service environments are indicated and a list of these 

environments is provided in LRA Table 3.0-1.

 (5) Aging Effect Requiring Management – The fifth column lists aging effects/aging 

mechanisms 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 used 

to manage the identified aging effects.

 (7) GALL Report Volume 2 Line Item – The seventh column lists the GALL Report item(s) 

that the applicant identified as corresponding to the AMR results in the LRA. The 
Aging Management Review Results

3-4

applicant compared each combination of component type, material, environment, AERM, 

and AMP in LRA Table 2 to the items in the GALL Report. If there were no 

corresponding items in the GALL Report, the applicant left the column blank. In this way, 

the applicant identified the AMR results in the LRA tables that corresponded to the items 

in the GALL Report tables.

 (8) Table 1 Item – The eighth column lists the corresponding summary item number from 

Table 1. If the applicant identified AMR results in Table 2 that are consistent with the 

GALL Report, then the associated Table 3.x.1 line summary item number should be 

listed in Table 2. If there is no corresponding item in the GALL Report, then column eight 

is left blank. That way, the information from the two tables can be correlated.

 (9) Notes – The ninth column lists the corresponding notes that the applicant used to 

identify how the information in Table 2 aligns with the information in the GALL Report. 

The notes identified by letters were developed by an NEI working group to be used in 

LRAs. Any plant-specific notes are identified by a number and provide additional 

information concerning the consistency of the line item with the GALL Report or other 

clarifying information.

3.0.2 Staff’s Review Process

The staff conducted the following three types of evaluations of the AMRs and associated 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 

and/or enhancements, the staff conducted either an audit or a technical review of the 

item to determine consistency with the GALL Report. In addition, the staff conducted 

either an audit or a technical review of the applicant‘s technical justification for the 

exceptions and the adequacy of the enhancements.

 (3) For other items, the staff conducted a technical review pursuant to 10 CFR 54.21(a)(3).

These audits and technical reviews determine whether the effects of aging on SCs can be 

adequately managed so that the intended functions can be maintained consistent with the 

plant‘s current licensing basis (CLB) for the period of extended operation, as required by 

10 CFR Part 54.

3.0.2.1 Review of AMPs

For those AMPs for which the applicant had claimed consistency with the GALL Report AMPs, 

the staff conducted either an audit or a technical review to confirm that the applicant‘s AMPs 

were consistent with the GALL Report. For each AMP that had one or more deviations, the staff 

evaluated each deviation to determine whether the deviation was acceptable and whether the 

AMP, as modified, would adequately manage the aging effect(s) for which it was credited. For 

AMPs that were not addressed in the GALL Report, the staff performed a full review to 

determine their adequacy. 
Aging Management Review Results

3-5

The staff evaluated the AMPs against the following 10 program elements defined in SRP-LR 

Appendix A:

 (1) Scope of the Program: The 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 including such aspects as method 

or technique (i.e., visual, volumetric, surface inspection), frequency, sample size, data 

collection, and timing of new/one-time inspections should occur before there is a loss of 

structure or component intended function(s).

 (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 and effective corrective actions have been completed.

 (9) Administrative Controls: Administrative controls should provide a formal review and 

approval process.

 (10) Operating Experience: Operating experience (OE) 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) and (10) are 

documented in the Aging Management Program Audit Report and summarized in SER 

Section 3.0.3.

The staff reviewed the applicant‘s corrective action program and documented its evaluations in 

SER Section 3.0.4. The staff‘s evaluation of the corrective action program included 

assessments of program elements (7), (8), and (9).

The staff reviewed the updated safety analysis report (USAR) supplement for each AMP to 

determine if it provided an adequate description of the program or activity, as required by 

10 CFR 54.21(d).
Aging Management Review Results

3-6

3.0.2.2 Review of AMR Results

Table 2 contains information concerning whether the AMRs align with the AMRs identified in the 

GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, 

environment, AERM, and AMP combination for a particular component type within a system. 

The AMRs that correlate between a combination in Table 2 and a combination in the GALL 

Report were identified by a referenced item number in column seven, ―NUREG-1801 Volume 2 

Reference.‖ The staff also conducted onsite audits to verify the correlation. A blank column 

seven indicates that the applicant was unable to locate an appropriate corresponding 

combination in the GALL Report. The staff conducted a technical review of these combinations 

not consistent with the GALL Report. The eighth column, ―Table 1 Item,‖ provides a reference 

number that indicates the corresponding row in Table 1.

3.0.2.3 USAR Supplement

Consistent with the SRP-LR for the AMRs and associated AMPs that it reviewed, the staff also 

reviewed the USAR supplement that 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 performing its review, the staff used the LRA, LRA supplements, SRP-LR, and the GALL 

Report. Also, during the onsite audits, the staff examined the applicant‘s justifications, as 

documented in the Audit Summary Report, 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 GALL Report AMP that the applicant claimed its AMP 

was consistent with, if applicable, and the SSCs for managing or monitoring aging. The section 

of the SER, in which the staff‘s evaluation of the program is documented, is also provided.
Aging Management Review Results

3-7

Table 3.0.3-1 KPS Aging Management Programs

Applicant AMP LRA 

Sections

New or 

Existing 

Program

Applicant 

Comparison to 

the GALL Report

GALL Report AMPs SER Section

ASME Section XI 

Inservice Inspection 

(ISI), Subsections IWB, 

IWC, and IWD 

A2.1.2, 

B2.1.2 Existing

Consistent with 

exceptions and 

enhancements

XI.M1, ―ASME 

Section XI Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD‖

3.0.3.2.1

ASME Section XI, 

Subsection IWE 

A2.1.3, 

B2.1.3 Existing Consistent

XI.S1, ―ASME 

Section XI, 

Subsection IWE‖

3.0.3.1.1

ASME Section XI, 

Subsection IWF 

A2.1.4, 

B2.1.4 Existing Consistent withexception

XI.S3, ―ASME 

Section XI, 

Subsection IWF‖

3.0.3.2.2

Bolting Integrity A2.1.5, 

B2.1.5 Existing Consistent with enhancements

XI.M18, ―Bolting 

Integrity‖ 3.0.3.2.3

Boric Acid Corrosion A2.1.6, 

B2.1.6 Existing Consistent XI.M10, ―Boric Acid Corrosion‖ 3.0.3.1.2

Buried Piping and 

Tanks Inspection 

A2.1.7, 

B2.1.7 Existing Consistent with enhancement

XI.M34, ―Buried 

Piping and Tanks 

Inspection‖

3.0.3.2.4

Closed-Cycle Cooling 

Water System 

A2.1.8, 

B2.1.8 Existing Consistent with exceptions

XI.M21, 

―Closed-Cycle 

Cooling Water 

System‖

3.0.3.2.5

Compressed Air 

Monitoring 

A2.1.9, 

B2.1.9 Existing

Consistent with 

exceptions and 

enhancement

XI.M24, ―Compressed 

Air Monitoring‖ 3.0.3.2.6

External Surfaces 

Monitoring 

A2.1.10, 

B2.1.10 Existing Consistent with enhancements

XI.M36, ―External 

Surfaces Monitoring‖ 3.0.3.2.7

Fire Protection A2.1.11, 

B2.1.11 Existing

Consistent with 

exception and 

enhancements

XI.M26, ―Fire 

Protection,‖ and 

XI.M27, ―Fire Water 

System‖

3.0.3.2.8

Flow-Accelerated 

Corrosion 

A2.1.12, 

B2.1.12 Existing Consistent with exception

XI.M17, 

―Flow-Accelerated 

Corrosion‖

3.0.3.2.9

Flux Thimble Tube 

Inspection 

A2.1.13, 

B2.1.13 Existing Consistent XI.M37, ―Flux Thimble Tube Inspection‖ 3.0.3.1.3

Fuel Oil Chemistry A2.1.14, 

B2.1.14 Existing Consistent with exceptions

XI.M30, ―Fuel Oil 

Chemistry‖ 3.0.3.2.10

Fuel Oil Tank 

Inspections 

A2.1.15, 

B2.1.15 Existing Consistent with enhancement

XI.M30, ―Fuel Oil 

Chemistry‖ 3.0.3.2.11

Inspection of Overhead 

Heavy Load and 

Refueling Handling 

Systems 

A2.1.16, 

B2.1.16 Existing Consistent with enhancement

XI.M23, ―Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to Refueling) 

Handling Systems‖

3.0.3.2.12

Lubricating Oil 

Analysis 

A2.1.17, 

B2.1.17 Existing Consistent XI.M39, ―Lubricating Oil Analysis‖ 3.0.3.1.4

Metal-Enclosed Bus A2.1.18, 

B2.1.18 Existing Consistent with enhancement

XI.E4, 

―Metal-Enclosed Bus‖ 3.0.3.2.13
Aging Management Review Results

3-8

Applicant AMP LRA 

Sections

New or 

Existing 

Program

Applicant 

Comparison to 

the GALL Report

GALL Report AMPs SER Section

Non-Environmental 

Qualification (EQ) 

Electrical Cables and 

Connections 

A2.1.19, 

B2.1.19 New Consistent

XI.E1, ―Electrical 

Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements‖

3.0.3.1.5

Non-EQ Electrical 

Cable Connections 

A2.1.20, 

B2.1.20 New Consistent

XI.E6, ―Electrical 

Cable Connections 

Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements‖

3.0.3.1.6

Non-EQ Inaccessible 

Medium-Voltage 

Cables 

A2.1.21, 

B2.1.21 New Consistent

XI.E3, ―Inaccessible 

Medium-Voltage 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements‖

3.0.3.1.7

Non-EQ 

Instrumentation 

Circuits Subject to 

Sensitive, 

High-Voltage, 

Low-Level Signals 

A2.1.22, 

B2.1.22 New Consistent

XI.E2, ―Electrical 

Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used 

in Instrumentation 

Circuits‖

3.0.3.1.8

Open-Cycle Cooling 

Water System 

A2.1.23, 

B2.1.23 Existing

Consistent with 

exception and 

enhancement

XI.M20, ―Open-Cycle 

Cooling Water 

System‖

3.0.3.2.14

Primary Water 

Chemistry 

A2.1.24, 

B2.1.24 Existing Consistent XI.M2, ―Water Chemistry‖ 3.0.3.1.9

Reactor Containment 

Leakage Testing 

10 CFR 50, Appendix J 

A2.1.25, 

B2.1.25 Existing Consistent XI.S4, ―10 CFR 50, Appendix J‖ 3.0.3.1.10

Secondary Water 

Chemistry 

A2.1.28, 

B2.1.28 Existing Consistent XI.M2, ―Water Chemistry‖ 3.0.3.1.11

Reactor Head Closure 

Studs 

A2.1.26, 

B2.1.26 Existing Consistent with exception

XI.M3, ―Reactor Head 

Closure Studs‖ 3.0.3.2.15

Reactor Vessel 

Surveillance 

A2.1.27, 

B2.1.27 Existing Consistent with exception

XI.M31, ―Reactor 

Vessel Surveillance‖ 3.0.3.2.16

Selective Leaching of 

Materials 

A2.1.29, 

B2.1.29 New Consistent

XI.M33, ―Selective 

Leaching of 

Materials‖

3.0.3.1.12

Steam Generator Tube 

Integrity 

A2.1.30, 

B2.1.30 Existing Consistent with exception

XI.M19, ―Steam 

Generator Tube 

Integrity‖

3.0.3.2.17
Aging Management Review Results

3-9

Applicant AMP LRA 

Sections

New or 

Existing 

Program

Applicant 

Comparison to 

the GALL Report

GALL Report AMPs SER Section

Structures Monitoring 

Program 

A2.1.31, 

B2.1.31 Existing Consistent with enhancements

XI.S5, ―Masonry Wall 

Program‖; XI.S6, 

―Structures 

Monitoring Program‖;

and XI.S7, 

―Inspection of 

Water-Control 

Structures Associated 

with Nuclear Plant‖

3.0.3.2.18

Environmental 

Qualification (EQ) of 

Electric Components

A4.1, 

B3.1 Existing Consistent

X.E1, ―Environmental 

Qualification (EQ) of 

Electric Components‖

3.0.3.1.13

Metal Fatigue of 

Reactor Coolant 

Pressure Boundary

A4.2, 

B3.2 Existing Consistent with enhancement

X.M1, ―Metal Fatigue 

of Reactor Coolant 

Pressure Boundary‖

3.0.3.2.20

Alloy 600 Inspections A2.1.1, 

B2.1.1 Existing Plant-Specific N/A 3.0.3.3.1

Work Control Process 

(WCP)

A2.1.32, 

B2.1.32

New (Refer to 

DEK RAI 

response 

Letter Serial 

No. 09-597, 

September 25, 

2009)

Consistent with the 

GALL Report with 

exceptions and 

enhancement

(1) GALL 

AMP XI.M32, 

―One-Time 

Inspection,‖ when 

WCP is used as a 

one-time inspection 

program for 

programmatic 

verification of 

designated preventive 

or mitigative 

monitoring programs. 

(2) GALL 

AMP XI.M38, 

―Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components,‖ when 

WCP is used as a 

periodic, condition 

monitoring program.

3.0.3.2.19 

(Previous 

plant-specific 

version 

deleted, as 

discussed in 

3.0.3.3.2)
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3.0.3.1 AMPs That Are Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as being consistent with the 

GALL Report:

● ASME Section XI, Subsection IWE Program

● Boric Acid Corrosion Program

● Flux Thimble Tube Inspection Program

● Lubricating Oil Analysis Program

● Non-EQ Electrical Cables and Connections Program

● Non-EQ Electrical Cable Connections Program

● Non-EQ Inaccessible Medium-Voltage Cables Program

● Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals 

Program

● Primary Water Chemistry Program

● Reactor Containment Leakage Testing 10 CFR 50, Appendix J Program

● Secondary Water Chemistry Program

● Selective Leaching of Materials Program

● Environmental Qualification (EQ) of Electric Components Program

3.0.3.1.1 ASME Section XI, Subsection IWE Program

Summary of Technical Information in the Application. LRA Section B2.1.3 describes the existing 

ASME Section XI, Subsection IWE Program as consistent with GALL AMP XI.S1, ―ASME 

Section XI, Subsection IWE.‖ The applicant stated that the program provides for condition 

monitoring, including periodic visual examinations of metal pressure boundary surfaces and 

welds, penetrations, integral attachments and their welds, moisture barriers, and 

pressure-retaining bolted connections. The applicant further stated that the program is 

implemented in accordance with the requirements of 10 CFR 50.55a and uses American 

Society of Mechanical Engineers (ASME) Code Section XI, Subsection IWE, 2001 Edition 

through the 2003 Addenda.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.S1. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S1. Based on its 
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audit and review, the staff finds that elements one through six of the applicant‘s ASME 

Section XI, Subsection IWE Program are consistent with the corresponding program elements 

of GALL AMP XI.S1 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.3 summarizes OE related to the ASME Section XI, 

Subsection IWE Program. In the LRA, the applicant stated that during an April 2003 walkdown, 

surface rust was noted on the exterior face of the reactor containment vessel (RCV), primarily at 

the vessel-concrete interface, which was subsequently corrected in accordance with the ASME 

Section XI, Subsection IWE Program. The LRA discusses surface rust that was discovered 

around the equipment hatch in October 2004. The rust was corrected via the work management 

system. The LRA further discusses caulk degradation at the joint between the personnel airlock 

and the concrete floor, which was subsequently repaired to its design condition.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff identified concerns regarding water leakage from the reactor cavity 

area, which could degrade the steel containment and associated coatings during the period of 

extended operation. The staff determined the need for additional clarification, which resulted in 

the issuance of requests for additional information (RAIs).

In RAI B2.1.3-2 dated July 13, 2009, the staff requested that the applicant identify any locations 

requiring augmented examinations per Subsection IWE, and the results of any required 

examinations.

By letter dated August 17, 2009, the applicant responded to RAI B2.1.3-2. The applicant stated 

that currently there are no RCV surface areas that are experiencing accelerated degradation, 

which would require augmented examinations based on the requirements of Subsection 

IWE-1241. The applicant‘s response is consistent with the staff‘s review of the OE database 

during the audit which found that, while the applicant had found local areas of concrete with 

leaching and cracks, no RCV areas were identified with accelerated corrosion or material loss in 

a local area exceeding 10 percent of the normal wall thickness that could not be accepted by 

engineering evaluation or repair. Therefore, the staff finds the applicant‘s response acceptable 

and the staff‘s concern described in RAI B2.1.3-2 is resolved. 

During the audit, based on its review of OE, the staff asked the applicant why KPS did not have 

an AMP for coatings. The applicant explained that an AMP was not needed for coatings 

because the coatings are not credited for aging management. Although the coatings are not 

credited for aging management, the staff believed their failure could result in the failure of a 

safety system to perform its intended function. In RAI B2.1.3-3 dated July 13, 2009, the staff 

requested that the applicant justify not having an AMP for coatings. (The staff‘s evaluation of the 

applicant‘s protective coatings program, which the applicant has in lieu of an AMP, is 

documented in SER Section 3.0.3.3.3.)

By letter dated August 17, 2009, the applicant responded to RAI B2.1.3-3. In its response, the 

applicant stated that the protective coatings are not relied upon to manage the effects of aging 

of the RCV. The applicant stated that coatings provide protection for the underlying base metal 

but do not perform an intended function as defined in 10 CFR 54.4(a)(1), (2), and (3). The 
Aging Management Review Results

3-12

applicant stated further that the ASME Section Xl, Subsection IWE Program manages the aging 

effect of loss of material due to corrosion for the RCV, and that the benefits of proper 

maintenance of the protective coatings on the RCV are being addressed by the action plan 

developed in response to Generic Letter (GL) 2004-02, ―Potential Impact of Debris Blockage on 

Emergency Recirculation During Design Basis Accidents at Pressurized-Water Reactors,‖ and 

GL 98-04, ―Potential for Degradation of the Emergency Core Cooling System and the 

Containment Spray System After a Loss-of-Coolant Accident Because of Construction and 

Protective Coating Deficiencies and Foreign Material In Containment.‖ The applicant also stated 

that the GL recommendations related to aging management will become part of the CLB and, 

therefore, will carry forward into the period of extended operation.

The staff reviewed the applicant‘s response to RAI B2.1.3-3 and found that additional 

information was needed regarding the proper maintenance of protective coatings at KPS. 

Therefore, in RAI XI.S8 dated August 28, 2009, the staff requested that the applicant describe, 

in detail, the coatings program at KPS. Specifically, the staff requested that the applicant: 

(1) explain how the coatings program will ensure that there will be proper maintenance of the 

protective coatings inside containment, and ensure operability of post-accident safety systems 

that rely on water recycled through the containment sump and drain system during the period of 

extended operation; and (2) describe the frequency and scope of the inspections, acceptance 

criteria, and the qualifications of the personnel who perform containment coatings inspections.

In its response to RAI XI.S8, dated September 28, 2009, the applicant stated that its protective 

coatings program conforms to the requirements identified in Regulatory Guide (RG) 1.54, 

―Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear 

Power Plants.‖ The applicant stated that the program, including inspections, incorporates 

guidance from American Society for Testing and Materials (ASTM) D5144, ―Guide for the Use of 

Protective Coating Standards in Nuclear Power Plants,‖ and ASTM D5163, ―Standard Guide for 

Establishing Procedures to Monitor the Performance of Safety-Related Coatings in an Operating 

Nuclear Power Plant.‖

The applicant also stated that its protective coatings program requires that a containment 

coating condition assessment be performed during each refueling outage, and that a condition 

assessment report be prepared to document the inspection findings. The applicant also stated 

that the personnel responsible for performing containment coatings inspections are qualified in 

accordance with approved station procedures. 

Based on a review of the applicant‘s responses to RAIs B2.1.3-3 and XI.S8, the staff 

determined that the applicant‘s protective coatings program implemented during the current 

licensing period ensures that coatings inside the RCV will be properly maintained during the 

period of extended operation because the protective coatings program conforms to the 

requirements identified in RG 1.54, Revision 0, and inspection procedures incorporate guidance 

from ASTM D5144 and ASTM D5163. (The staff‘s review of the applicant‘s Protective Coatings 

Monitoring and Maintenance Program is contained in SER Section 3.0.3.3.3.) The staff‘s 

concerns in RAIs B2.1.3-3 and XI.S8 are resolved. 

During the audit, the staff noted that the applicant had observed indications of water leaking 

from the refueling cavity. In RAI B2.1.3-1 dated July 13, 2009, the staff requested that the 

applicant provide a discussion of how the ASME Section XI, Subsection IWE Program is 

addressing the possible aging effects associated with the refueling cavity leakage.
Aging Management Review Results

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By letter dated August 17, 2009, the applicant responded to RAI B2.1.3-1. The applicant stated 

that the scope of the ASME Section XI, Subsection IWE Program is associated with the metal 

pressure-retaining boundary of the RCV. The applicant stated that moisture barriers that prevent 

intrusion of moisture into inaccessible areas of the containment shell at concrete-to-metal 

interfaces are also inspected as part of the ASME Section XI, Subsection IWE Program. The 

applicant also stated that, if moisture barrier degradation were observed, the condition would be 

documented in the corrective action program. The applicant also stated that, in the fall of 2006 

and again in 2008, during inspections performed under the Boric Acid Corrosion Program and 

the Structures Monitoring Program, the reactor cavity/refueling pool was identified as a potential 

source of leakage. The applicant stated that it identified the area below the reactor cavity and 

the A-RCS loop vault as the two most likely locations. The applicant stated that it evaluated the 

amount of leakage and categorized it as minimal (e.g., streaking of the walls). The applicant 

also stated that it determined that the leakage had not come into contact with the RCV and,

therefore, that the RCV was not required to be evaluated for this identified leakage by the ASME 

Section XI, Subsection IWE Program. 

The staff reviewed the applicant‘s response to RAI B2.1.3-1 and determined that further 

clarification was needed concerning the leakage volume and path since the information 

provided in responses to RAI B2.1.3-1 and RAI B2.1.31-4 (discussed in SER Section 3.0.3.2.18)

did not appear to be consistent. Therefore, the staff issued follow-up RAI B2.1.31-4a, dated 

November 20, 2009, requesting additional details about the reactor cavity/refueling pool 

leakage. 

Specifically, the staff requested that the applicant provide the following:

 (1) more details about the leakage volume and path observed in the 2003, 2004, 2006, and 

2008 outages 

 (2) details of any remedial actions or repairs performed during 2003 and 2004 to stop the 

leakage

 (3) plans to verify the structural integrity of the concrete and rebar at the cracked locations 

by core drills or other means 

 (4) plans for permanent remediation of reactor cavity/refueling pool leakage 

By a letter dated December 28, 2009, the applicant responded to RAI B2.1.31-4a. The applicant 

stated that there are three sites within the reactor containment that have been identified as 

potential indications of leakage from the reactor cavity. The applicant also stated that none of 

the leakage from these three sites had the potential for moisture contact with the steel 

containment vessel. The applicant‘s response to the RAIs concerning the effect of leakage on 

the concrete structures inside containment and commitment for identification and remediation of 

the leakage is described in SER Section 3.0.3.2.18. 

Based on its review, the staff finds the applicant‘s responses to RAIs B2.1.3-1, B2.1.31-4, and 

B2.1.31-4a acceptable because leakage from the reactor cavity at the three locations is unlikely 

to reach or come into contact with the RCV. The leakage observed was minimal and not 

quantifiable (a few drops of water), and water did not flow beyond the immediate vicinity of the 

three leakage locations. Therefore, the water from the leakage areas could not have travelled

and come into contact with the steel containment vessel. The applicant inspected concrete 

surfaces inside containment, including the basement elevation, and did not find any moisture 
Aging Management Review Results

3-14

except for a minimal amount at the leakage locations. Furthermore, the applicant did not find 

any water or moisture in sump ―B‖ (the sump nearest to the containment vessel), which would 

have been the primary source of water collection in case water comes into contact and flows 

along the steel containment vessel. The staff‘s evaluation concerning the effect of water leakage 

from the reactor cavity on the concrete structures inside containment is documented in SER 

Section 3.0.3.2.18. 

Based on its audit and review of the application, and review of the applicant‘s responses to 

RAIs B2.1.3-1 through B2.1.3-3, XI.S8, and B2.1.31-4a, the staff finds that OE related to the 

applicant‘s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the ―operating 

experience‖ program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable.

USAR Supplement. In LRA Section A2.1.3, the applicant provided the USAR supplement for the 

ASME Section XI, Subsection IWE Program. The staff notes that the USAR supplement 

description of the ASME Section XI, Subsection IWE Program conforms to the recommended 

USAR supplement for this type of program as described in SRP-LR Table 3.5-2. 

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 ASME Section XI, Subsection IWE 

Program, including the applicant‘s responses to RAIs, 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 functions 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 Boric Acid Corrosion Program

Summary of Technical Information in the Application. LRA Section B2.1.6 describes the existing 

Boric Acid Corrosion Program as consistent with GALL AMP XI.M10, ―Boric Acid Corrosion.‖

The applicant stated that the program includes visual inspections to identify boric acid leakage 

and encompasses those systems and components which are the potential sources and targets 

of borated water leakage. The applicant also stated that the program includes requirements for 

ensuring that in-scope SSCs are properly monitored and that loss of material due to boric acid is 

consistently identified, documented, evaluated, trended, and effectively repaired. The applicant 

stated that the program also provides systematic measures for ensuring that corrosion caused 

by leaking borated water does not lead to the degradation of systems or components from 

which the boric acid leaked or the adjacent SCs upon which it might leak. The applicant further 

stated that the program uses GL 88-05, ―Boric Acid Corrosion of Carbon Steel Reactor 

Components in PWR Plants,‖ and industry guidance for evaluating the severity of boric acid 

leakage and for determining the appropriate corrective actions.
Aging Management Review Results

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Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared program elements one through six of the applicant‘s program to the 

corresponding elements of GALL AMP XI.M10. As discussed in the Audit Report, the staff 

confirmed that these elements are consistent with the corresponding elements of GALL 

AMP XI.M10.

Based on its review, the staff finds that program elements one through six of the applicant‘s 

Boric Acid Corrosion Program are consistent with the corresponding program elements of GALL 

AMP XI.M10 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.6 summarizes OE related to the Boric Acid Corrosion 

Program. The staff reviewed this information and interviewed the applicant‘s technical personnel 

to confirm that the applicable aging effects and industry and plant-specific OE have been 

reviewed by the applicant. During the audit, the staff independently verified that the applicant 

had adequately incorporated and evaluated OE related to this program. The staff also confirmed 

that the applicant has addressed OE identified after the issuance of the GALL Report.

The staff reviewed the OE information in the application and during the audit to determine 

whether the applicable aging effects and industry and plant-specific OE were reviewed by the 

applicant. As discussed in the Audit Report, the staff conducted an independent search of the 

plant OE information to determine whether the applicant had adequately incorporated and 

evaluated OE related to this program. The staff reviewed the applicant‘s license renewal basis 

document and also a sample of condition reports, and confirmed that the applicant identified 

boric acid corrosion and implemented corrective actions. The staff noted several condition 

reports where adjacent SCs were also included in the evaluation of identified boric acid leakage. 

For the cases reviewed by the staff, actions were taken to stop the leakage, or monitoring 

activities were used to ensure no ongoing degradation until the leakage was stopped. The staff 

interviewed the applicant‘s technical personnel during the audit to confirm that plant-specific OE 

revealed no degradation not bounded by industry experience. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable. 

USAR Supplement. LRA Section A2.1.6 provides the USAR supplement for the Boric Acid 

Corrosion Program. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.1-2.

The staff 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 Boric Acid Corrosion 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 
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3-16

intended functions 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 the applicant has provided an adequate summary description of 

the program, as required by 10 CFR 54.21(d).

3.0.3.1.3 Flux Thimble Tube Inspection Program

Summary of Technical Information in the Application. LRA Section B2.1.13 describes the 

existing Flux Thimble Tube Inspection Program as consistent with GALL AMP XI.M37, ―Flux 

Thimble Tube Inspection.‖ The applicant stated that the program manages the aging effect of 

loss of material due to wear of the flux thimble tube wall. The applicant stated that the flux 

thimble tubes provide a path for the in-core neutron flux monitoring system detectors and form 

part of the reactor coolant pressure boundary (RCPB). The applicant also stated that flux 

thimble tubes are subject to loss of material where flow-induced fretting causes wear at 

discontinuities in the path from the reactor vessel instrument nozzle to the fuel assembly guide 

tube. The applicant further stated that its response to NRC Bulletin 88-09, ―Thimble Tube 

Thinning in Westinghouse Reactors,‖ established the program requirements, including 

inspection methodology, tube wear acceptance criterion, inspection frequency, corrective 

actions, and maintenance of program documents and test results. The applicant stated that 

program guidance was also developed from Westinghouse WCAP-12866, ―Bottom Mounted 

Instrumentation Flux Thimble Tube Wear,‖ (1991), and that beginning in 2004, a new 

acceptance/repair criterion was established and the calculation or prediction of future wall loss 

rates was implemented. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M37. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M37, with the exception of the ―monitoring and trending‖ and ―acceptance criteria‖ 

program elements. For these elements, the staff determined the need for additional clarification, 

which resulted in the issuance of RAIs.

The staff noted that the ―monitoring and trending‖ program element of GALL AMP XI.M37 states 

that the wall thickness measurements should be trended and wear rates should be calculated. 

During its audit, the staff noted in the applicant‘s program basis document that it did not clearly 

address how the program manages discrepancies between projected wear rates and measured 

wear rates. By letter dated July 13, 2009, the staff issued RAI B2.1.13-1 requesting that the 

applicant explain how its program manages discrepancies between projected wear rates and 

measured wear rates, especially for cases where the discrepancies are large and unexpected. 

In its response dated August 17, 2009, the applicant stated that the discrepancies between the 

projected wear rates and measurement-based wear rates are documented in the corrective 

action program. The applicant also confirmed that its corrective actions to manage the 

projection rate discrepancies from the measured wear rate include a review of nondestructive 

examination (NDE) data, a review of the causes of the unexpected wear, and a new projection 

of thimble tube thickness based on the current inspection frequency as well as potential 

isolation and repositioning of thimble tubes.
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3-17

Based on its review, the staff finds the applicant‘s response to RAI B2.1.13-1 acceptable 

because: (1) the applicant‘s approach, using the engineering evaluation and corrective actions, 

is adequate to manage the wear rate discrepancies and aging effects of the flux thimble tubes; 

(2) the engineering review and corrective actions can identify the cause of the unexpected wear 

and perform corrective actions to eliminate or mitigate the cause of the unexpected wear; (3) the 

corrective actions, which include potential isolation and repositioning of thimble tubes, are 

adequate to manage the aging effects by isolating and repositioning the wear scar and to 

ensure the pressure boundary integrity of the thimble tubes; and (4) the applicant‘s actions are 

consistent with the recommendations of GALL AMP XI.M37. The staff‘s concern described in 

RAI B2.1.13-1 is resolved.

The staff noted that the ―acceptance criteria‖ program element of GALL AMP XI.M37 states that 

acceptance criteria, such as percent through-wall wear, should be established and technically 

justified to provide an adequate margin of safety to maintain the integrity of the RCPB. This 

program element also states that acceptance criteria different from those previously 

documented in NRC acceptance letters for the applicant‘s response to Bulletin 88-09 and 

amendments thereto should be justified. During its audit, the staff noted that the applicant‘s 

program uses the acceptance criterion of 80 percent through-wall wear, above which

repositioning and isolation of the thimble tube is required. By letter dated July 13, 2009, the staff 

issued RAI B2.1.13-3 requesting that the applicant justify how the current acceptance criterion

provides an adequate margin of safety to ensure that the integrity of the RCPB is maintained. 

In its response dated August 17, 2009, the applicant clarified that the eddy current testing in the 

program provides actual or conservative estimates of the depth of the wear scars and that its

test data show that the tubes will retain their functional and structural integrity with up to an 

85 percent wall loss for all plant operating modes. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.13-3 acceptable 

because: (1) the applicant‘s evaluation concluded that the remaining 20 percent wall thickness 

will provide adequate structural integrity, (2) a thimble tube with a measured wall thickness of 

80 percent or higher will be repositioned and isolated, and (3) the corrective action is initiated at 

a 60 percent through-wall measurement by repositioning the thimble tube if the plant-specific 

through-wall wear of the thimble tube at the next inspection period is projected to be equal to or 

greater than 80 percent. The staff‘s concern described in RAI B2.1.13-3 is resolved.

During its audit, the staff noted that the applicant‘s work order instructions for thimble tube eddy 

current inspection indicated that the best approach to calculating future wall loss is to use the 

exponential equation, with an exponent value calculated using two previous cycle inspection 

results for a specific plant; and for plants which do not have two prior inspection points, a 

conservative exponent value may be used. However, a report and attached information from the 

applicant‘s work order on the thimble tube degradation forecast suggests that the applicant‘s 

wear projection methodology may use a non-plant-specific exponent rather than an exponent 

based on the previous two inspection results. The staff also noted that the applicant‘s response 

to Bulletin 88-09, dated November 7, 1988, states that the examination frequency after 1998 will 

be dependent on the results of the previous two tests. It was not clear to the staff whether the 

applicant‘s approach to define the exponent considers plant-specific inspection results. By letter 

dated July 13, 2009, the staff issued RAI B2.1.13-4 requesting that the applicant: (1) clarify what 

exponent is used for the wear projections, and (2) if the previous inspection results are not used 

to determine the exponent, demonstrate why this methodology on the exponent determination is 

in agreement with or conservative compared to the exponent determination based on the actual 

plant-specific inspection results. The staff also requested that the applicant describe how its 
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program considers and manages the potential effect of changes in flow rates and thimble or 

reactor hardware on the wear rates.

In its response dated August 17, 2009, the applicant clarified that the projection is based on 

plant-specific wear data obtained from the two previous inspection cycles. Additionally, the 

applicant stated that it performs analyses to confirm that the conservative projections bound the 

wear rate projections which are based on the plant-specific inspection data. The applicant also 

clarified that changes to the reactor coolant system (RCS) flow rate, thimble tube, or reactor 

hardware could only occur through a plant modification in accordance with the applicant‘s 

design control process. The applicant stated that this process is procedurally controlled,

includes the requirements for safety review in accordance with 10 CFR 50.59, and is reviewed

by affected plant organizations. The applicant also clarified that the design and hardware 

changes that can affect the thimble tube wear would be identified and addressed during the 

review process. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.13-4 acceptable 

because: (1) the applicant‘s methodology uses the measured plant-specific wear data to 

perform the wear rate projections and is adequate to manage the aging effects of the thimble 

tubes, (2) the projections are based on actual plant-specific experience and data so that the 

projections represent and evaluate the plant-specific conditions adequately in terms of the 

thimble tube wear, and (3) the applicant‘s program evaluates and manages the potential effects 

of design and hardware modifications on the thimble tube integrity in accordance with 

10 CFR 50.59 and with the applicant‘s controlled review procedures that will consider their 

impacts on the program and equipment. The staff‘s concern described in RAI B2.1.13-4 is 

resolved.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.13-1, B2.1.13-3, and 

B2.1.13-4, the staff finds that elements one through six of the applicant‘s Flux Thimble Tube 

Inspection Program are consistent with the corresponding program elements of GALL 

AMP XI.M37 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.13 summarizes OE related to the Flux Thimble Tube 

Inspection Program. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. The 

staff also confirmed that the applicant has addressed OE identified after the issuance of the 

GALL Report. As discussed in the Audit Report, the staff conducted an independent search of 

the plant OE information to determine whether the applicant had adequately incorporated and 

evaluated OE related to this program. 

During its review, the staff identified OE which could indicate that the applicant‘s program may 

not be effective in adequately managing aging effects during the period of extended operation. 

The staff determined the need for additional clarification, which resulted in the issuance of an 

RAI. 

The applicant stated that inspections were performed in 2000 and 2004; however, the staff 

noted that the LRA did not clearly indicate the results of these inspections and whether they 

demonstrated the adequacy of the program-defined inspection frequency and wear projection 

methodology. By letter dated July 13, 2009, the staff issued RAI B2.1.13-2 requesting that the 

applicant provide relevant inspection results, including the actual wear of the two inspection 
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periods which ended in 2000 and 2004, respectively, and to demonstrate that the applicant‘s 

inspection frequency and wear rate projection methodology are adequate to manage the aging 

effects of the thimble tubes.

In its response dated August 17, 2009, the applicant clarified that the eddy current testing of the 

flux thimble tubes repositioned in 1994 has confirmed that the wear scars are not actively 

wearing. The staff reviewed the 2000 and 2004 inspection results provided in the RAI response 

and found that: (1) the measured through-wall thickness data met the acceptance criteria of the 

applicant‘s program, and (2) the projected wall thickness values for the next inspection were

within the acceptance criteria.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.13-2 acceptable 

because: (1) the inspection frequency and associated wear rate projection methodology of the 

applicant‘s program are adequate to manage the wear of the flux thimble tubes, and (2) the 

applicant‘s OE demonstrates its program is effective to manage the aging effects of the flux 

thimble tubes. The staff‘s concern described in RAI B2.1.13-2 is resolved.

Based on its audit and review of the application, and review of the applicant‘s response to 

RAI B2.1.13-2, the staff finds that OE related to the applicant‘s program demonstrates that it can 

adequately manage the detrimental effects of aging on SSCs within the scope of the program, 

and that implementation of the program has resulted in the applicant taking corrective actions. 

The staff confirmed that the ―operating experience‖ program element satisfies the criterion in 

SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.13 provides the USAR supplement for the Flux Thimble 

Tube Inspection Program. The staff reviewed this USAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.1-2. The staff noted that the applicant‘s USAR supplement description did not include 

NRC Bulletin 88-09 as a reference. By letter dated July 13, 2009, the staff issued RAI B2.1.13-5 

requesting the USAR summary description include NRC Bulletin 88-09 as a technical reference. 

The staff also requested that the applicant clarify whether the program implements the 

recommendations of NRC Bulletin 88-09.

In its response dated August 17, 2009, the applicant stated that it will revise LRA 

Section A2.1.13 to confirm NRC Bulletin 88-09 as a technical reference for its program. The 

applicant stated that it will add the following to the end of the last paragraph of LRA 

Section A2.1.13:

The program implements the recommendations of NRC Bulletin 88-09, Thimble 

Tube Thinning in Westinghouse Reactors, as identified in WPSC letter, 

NRC-88-2 dated January 6, 1989.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.13-5 acceptable 

because the applicant amended LRA Section A2.1.13 to conform to the recommended 

description for this type of program as described in SRP-LR Table 3.1-2. The staff‘s concern 

described in RAI B2.1.13-5 is resolved.

The staff determines that the information in the USAR supplement, as amended, 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 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 functions 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 Lubricating Oil Analysis Program

Summary of Technical Information in the Application. LRA Section B2.1.17 describes the 

existing Lubricating Oil Analysis Program as being consistent with GALL AMP XI.M39, 

―Lubricating Oil Analysis.‖ The applicant stated that its program manages the aging effects of 

loss of material and reduction of heat transfer for aluminum, copper alloys, stainless steel, and 

steel mechanical system components when exposed to a lubricating oil environment. The 

applicant also stated that this is accomplished by maintaining oil system contaminants 

(i.e., primarily water and particulates) within acceptable limits, thus preserving an environment 

that is not conducive to loss of material or reduction of heat transfer. The applicant stated that 

the oil testing activities include sampling and analysis of lubricating oil for detrimental 

contaminants, such as water, particulates, and metals. The applicant further stated that the 

effectiveness of this program is verified by the WCP Program.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff noted in the applicant‘s ―acceptance criteria‖ program element that it is using the 

industry standard ISO 11500. The staff noted that this standard incorporates ISO 4406, which is 

a standard that GALL AMP XI.M39 recommends. The staff determined this to be acceptable 

because it is consistent with the recommendations of GALL AMP XI.M39 to use industry 

standards.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M39. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M39. Based on its 

audit, the staff finds that elements one through six of the applicant‘s Lubricating Oil Analysis 

Program are consistent with the corresponding program elements of GALL AMP XI.M39 and 

are, therefore, acceptable.

Operating Experience. LRA Section B2.1.17 summarizes OE related to the Lubricating Oil 

Analysis Program. 

During its June 2009 audit, the staff reviewed the applicant‘s OE reports, including a sample of 

condition reports. In June 2001, the applicant noted that, based on an oil analysis, the 1B heater 

drain pump thrust stand bearing had water in the lube oil. The applicant noted that the level of 

water was 1,588 parts per million (ppm), which was still below the allowable concentration of 

2,000 ppm of water. The applicant‘s report noted that a desiccant breather on the heater drain 

pump thrust stand would prevent reoccurrence of excess water. During its evaluation, the 

applicant noted that moisture from the air or moisture from packing leak-off spilling to the hot 

pump casing and flashing to steam may have entered the lube oil reservoir through the air 

breather. The staff noted that despite the applicant‘s corrective actions to prevent reoccurrence,
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in August 2005 there was excess water in the lube oil again. The applicant evaluated this 

excess water further and determined that the water in the lube oil was a result of packing gland 

leakage. The staff noted that the applicant took actions to remove the water in the lube oil 

reservoir and to correct the packing gland leakage. The applicant removed the source of water 

to the thrust stand oil reservoir. The staff finds that the applicant took corrective actions in both 

instances to prevent reoccurrence, ultimately determined the root cause for the water 

contamination, and corrected the packing gland leakage.

During its review of the applicant‘s condition reports, the staff noted that in January 2007, the 

applicant identified an adverse trend of sodium and boron in the technical support center (TSC) 

diesel generator lube oil. The applicant determined the baseline for sodium and boron in the 

lube oil from historical results and noted that there was a large increase in this sample 

compared to previous results. Based on its review, the applicant ultimately determined that the 

cause of the elevated sodium and boron was coolant leaking into the lubricating oil. The 

applicant located the leak to be between an injector tube and cylinder head. The staff finds that 

the applicant took corrective actions to identify the cause of the adverse trend and then replaced

the cylinder head to prevent reoccurrence.

During May 2009, the applicant noted that the oil sample from the 1B control room A/C chiller 

pump contained suspended particles. The applicant noted that the particles were reddish in 

color, non-metallic and of low-density, and appeared to be some type of sealant. After the oil 

was sampled, the applicant flushed the bearing bracket with new oil to remove additional debris 

that remained. The applicant sent this oil sample to Insight Services for a laboratory analysis to 

determine the composition of the suspended particles and the quality of the oil. The results were 

obtained in June 2009, and the applicant noted that results indicated the oil was ―normal‖ and 

within acceptance criteria. The applicant concluded that the suspended particles were sealant 

tape from the pipe plug. The staff noted that the applicant determined the presence of 

contaminants in the oil sample, took actions to remove any remaining debris, and obtained 

laboratory results to determine the composition of the particles and evaluate the need for further 

actions. The staff noted that the applicant intends to continue to obtain samples on a normal 

frequency and monitor for adverse trends.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.
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USAR Supplement. LRA Section A2.1.17 provides the USAR supplement for the Lubricating Oil 

Analysis Program. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2.

The staff 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 Lubricating Oil Analysis 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 functions 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 Non-EQ Electrical Cables and Connections Program

Summary of Technical Information in the Application. LRA Section B2.1.19 describes the new 

Non-EQ Electrical Cables and Connections Program as consistent with GALL AMP XI.E1, 

―Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.‖ The applicant stated that this program will manage the aging effects of reduced 

insulation resistance and electrical failure of accessible non-EQ electrical cables and 

connections within the scope of license renewal that are subject to adverse localized 

environments. The applicant also stated that a representative sample of accessible insulated 

cables and connections within the scope of license renewal will be visually inspected for cable 

and connection jacket surface anomalies, such as embrittlement, discoloration, cracking, or 

surface contamination.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.E1. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.E1, with the exception of the areas discussed below. For these areas, the staff 

determined the need for additional clarification, which resulted in the issuance of an RAI.

During its audit, the staff reviewed the applicant‘s method for identifying adverse localized 

environments. The applicant stated in the LRA that an adverse localized environment is a 

condition in a limited plant area that is significantly more severe than the specified service 

condition for the cable and connections. The applicant stated that should an adverse localized 

environment be observed, a representative sample of electrical cables and connections installed 

within that environment will be visually inspected for aging. However, the applicant did not 

address how the adverse localized environment is identified. The staff noted that an adverse 

localized environment should be based on the most limiting service environment for cables 

(i.e., power, control, and instrumentation) and connections. By letter dated July 13, 2009, the 

staff issued RAI B2.1.19-1 requesting that the applicant explain how an adverse localized 

environment is identified. 
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In its response dated August 17, 2009, the applicant stated that for structures other than 

containment, the normal operating temperature ranges between 60 °F and 120 °F. The 

applicant further stated that one exception is the auxiliary feedwater (AFW) pump room in the 

turbine building that has a maximum operating temperature of 139 °F. The applicant stated that 

for cumulative radiation exposure, the plant‘s 40-year radiation dose ranges between less than 

1E4 rads and 1.8E7 rads. The applicant also stated that the electrical cable and connection 

insulation material types installed in the plant have been reviewed based on the 60-year service 

limiting temperature range, which varies between 141 °F and 273 °F, and the 60-year service 

limiting radiation dose range, which varies between less than 1.5E4 rads and 2.7E7 rads 

(1.5 x 40-year value). The applicant stated that it considered the temperature rise due to ohmic 

heating in the review. Additionally, the applicant stated that there are no installed cables or 

connections with polyvinyl chloride (PVC) insulation, which has a 60-year service limiting 

temperature of 112 °F. The applicant also stated that the most common adverse localized 

environments are those created by elevated temperature and noted that steam generators, 

feedwater heater, main steam valves, uninsulated or unshielded hot process piping, steam or 

packing leaks, high-powered incandescent lighting, motor exhaust air vents, areas with 

equipment that operate at high temperature, areas with inadequate ventilation, etc., are sources 

of adverse localized environments. Furthermore, electrical cables and connections normally 

within 3 feet of these sources may be subjected to an adverse localized environment. The 

applicant further stated that it will identify adverse localized environments through plant OE 

reviews; communication with maintenance, operations, and radiation protection personnel; and 

the use of environmental surveys. Finally, the applicant stated that the identified adverse 

localized environment will be used as an input to the walkdown performed in support of the 

Non-EQ Electrical Cables and Connections Program.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.19-1 acceptable 

because the applicant adequately described how adverse localized environments will be 

established and incorporated in the Non-EQ Electrical Cables and Connections Program. The 

staff‘s concern described in RAI B2.1.19-1 is resolved.

Based on its audit and review of the applicant‘s response to RAI B2.1.19-1, the staff finds that 

elements one through six of the applicant‘s Non-EQ Electrical Cables and Connections Program 

are consistent with the corresponding program elements of GALL AMP XI.E1 and are, therefore, 

acceptable.

Operating Experience. LRA Section B2.1.19 summarizes OE related to the Non-EQ Electrical 

Cables and Connections Program. The applicant stated that its program is a new program. The 

applicant performed a review of the corrective action program for representative examples of 

internal OE related to this program and found no cases of reduced insulation resistance or 

electrical failure of accessible non-EQ electrical cables and connections within the scope of 

license renewal that are subject to an adverse localized environment. The applicant also stated 

that as OE is obtained, lessons learned will be used to adjust this program as needed.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.
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Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.19 provides the USAR supplement for the Non-EQ 

Electrical Cables and Connections Program. The staff reviewed this USAR supplement 

description of the program and notes that it conforms to the recommended description for this 

type of program as described in SRP-LR Table 3.6-2.

The staff also notes that the applicant committed (Commitment No. 14) to implement the new 

Non-EQ Electrical Cables and Connections Program prior to entering the period of extended 

operation for managing aging of applicable components.

The staff 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 Non-EQ Electrical Cables and 

Connections 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 functions 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 Non-EQ Electrical Cable Connections Program

Summary of Technical Information in the Application. LRA Section B2.1.20 describes the new 

Non-EQ Electrical Cable Connections Program as consistent with GALL AMP XI.E6, ―Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.‖ 

The applicant stated that this program will manage the aging effect of loosening of bolted 

connections for non-EQ electrical cable connections within the scope of license renewal. The 

applicant stated that its program will perform a one-time inspection, on a sampling basis, to 

confirm the absence of loosening of bolted connections due to thermal cycling, ohmic heating, 

electrical transients, vibration, chemical contamination, corrosion, and oxidation. The applicant 

also stated that a representative sample of non-EQ electrical cable connections (e.g., metallic 

parts) associated with cables, within the scope of license renewal, will be tested at least once 

prior to the period of extended operation. The applicant further stated that the representative 

sample of non-EQ bolted electrical cable connections will be identified for testing based on 

voltage level (medium- and low-voltage), circuit loading (high loading), and location (high 

temperature, high humidity, vibration, etc.). The applicant also stated that the technical basis for 

the sample selections will be documented.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.E6. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 
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AMP XI.E6, with the exception of the area discussed below. For this area, the staff determined a 

need for additional clarification, which resulted in the issuance of an RAI.

The staff noted that the applicant‘s ―scope of the program,‖ ―parameters monitored or 

inspected,‖ and ―detection of aging effects‖ program elements are not consistent with GALL 

AMP XI.E6; SRP-LR Section 3.6.2.1, ―AMR Results Consistent with the GALL Report‖; and 

SRP-LR Table 3.6-2, ―USAR Supplement for Aging Management of Electrical and 

Instrumentation and Control Systems.‖ The staff noted that the applicant incorporated a 

one-time test, limited the voltage level testing criteria, limited connections to active or passive 

device external connections, and implemented program element changes that are inconsistent 

with GALL AMP XI.E6. The staff noted that the changes proposed by the applicant were, 

however, consistent with proposed Interim Staff Guidance (ISG) LR-ISG-2007-02: Changes to 

Generic Aging Lessons Learned (GALL) Report Aging Management Program (AMP) XI.E6, 

―Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.‖ 

During its audit, the staff also noted that although the applicant referenced the above ISG in its 

program basis document, the ISG is not referenced in LRA Section B2.1.20, nor is justification 

for its use provided in the program basis document or in LRA Section B2.1.20. By letter dated 

July 13, 2009, the staff issued RAI B2.1.20-1 requesting that the applicant provide justification, 

including an acceptable basis, for the proposed changes to its program and why these changes 

are not considered either exceptions to GALL AMP XI.E6 or a plant-specific program. 

In its response dated August 17, 2009, the applicant stated that the description of the Non-EQ 

Electrical Cable Connections Program in LRA Appendix B, Section B2.1.20 is supplemented to 

include the following exceptions:

● The program will be a one-time inspection program which will be performed prior to the 

period of extended operation but not repeated every 10 years. The program element 

affected is ―detection of aging effects.‖

● The program will not include high-voltage connections. The program elements affected 

are ―scope of the program‖ and ―parameters monitored or inspected.‖

● The program will not include connections that are on the internal side of an active 

component. The program element affected is ―scope of the program.‖

Based on its review, the staff finds the applicant‘s response to RAI B2.1.20-1 acceptable 

because the applicant amended its LRA to identify an exception concerning the ―scope of the 

program,‖ ―parameters monitored or inspected,‖ and ―detection of aging effects‖ program 

elements. The staff‘s review of this newly identified exception and its acceptability is discussed 

below. The staff‘s concern described in RAI B2.1.20-1 is resolved.

The staff also reviewed the portions of the ―scope of the program,‖ ―parameters monitored or 

inspected,‖ and ―detection of aging effects‖ program elements associated with the exception, as 

amended by letter dated August 17, 2009, to determine whether the program will be adequate 

to manage the aging effects for which it is credited. The staff‘s evaluation of this exception 

follows.
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Exception. LRA Section B2.1.20 states an exception to the ―scope of the program,‖ ―parameters 

monitored or inspected,‖ and ―detection of aging effects‖ program elements, as amended by 

letter dated August 17, 2009. The applicant stated that its program will be a one-time inspection 

program which will be performed prior to the period of extended operation but not repeated 

every 10 years. The applicant further stated that its program will not include high-voltage 

connections and connections that are on the internal side of an active component.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.20-1 to be acceptable 

because the applicant amended its LRA to take exceptions to GALL AMP XI.E6, consistent with 

the staff guidance in LR-ISG-2007-02. The staff noted that LR-ISG-2007-02 addresses the 

applicant‘s proposed changes to GALL AMP XI.E6. 

Based on its review, the staff finds this exception acceptable because the applicant‘s program is 

now consistent with GALL AMP XI.E6, as modified by LR-ISG-2007-02.

Subsequent to the audit, a notice of availability of the final LR-ISG-2007-02 was published in the 

Federal Register on December 23, 2009. The staff, therefore, re-evaluated the AMP, LRA 

Sections B2.1.20 and A2.1.20, and the exception based on the staff‘s aging management 

recommendations provided by LR-ISG-2007-02. Based on its review, the staff confirmed that 

elements one through six of the applicant‘s program remain consistent with the corresponding 

elements of GALL AMP XI.E6, as modified by the final LR-ISG-2007-02 dated 

December 23, 2009.

Based on its audit and review of the applicant‘s response to RAI B2.1.20-1, the staff finds that 

elements one through six of the applicant‘s Non-EQ Electrical Cable Connections Program, with 

acceptable exceptions, are consistent with the corresponding program elements of GALL 

AMP XI.E6, as modified by the final LR-ISG-2007-02 dated December 23, 2009, and are, 

therefore, acceptable.

Operating Experience. LRA Section B2.1.20 summarizes OE related to the Non-EQ Electrical 

Cable Connections Program. The applicant‘s review of its corrective action program did not 

reveal any specific corrective action program examples of loose bolt connections attributable to 

the aging mechanisms applicable to LRA Section B2.1.20 and GALL AMP XI.E6. The applicant 

stated that its program is a new program. As indicated above, the applicant performed a review 

of the corrective action program and stated that although cases of loose bolted connections 

were identified, there were no conclusive examples that the loosening of bolted connections 

was due to aging mechanisms associated with thermal cycling, ohmic heating, electrical 

transients, vibration, chemical contamination, corrosion, and oxidation. The applicant further 

stated that as OE is obtained, lessons learned will be used to adjust this program as needed 

through the applicant‘s OE program. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.
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Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.20 provides the USAR supplement for the Non-EQ 

Electrical Cable Connections Program, as amended by letter dated August 17, 2009. The staff 

reviewed this USAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program, as described in the staff guidance in

LR-ISG-2007-02.

The staff also notes that the applicant committed (Commitment No. 15) to implement the new 

Non-EQ Electrical Cable Connections Program prior to entering the period of extended 

operation for managing aging of applicable components.

The staff determines that the information in the USAR supplement, as amended, 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 Non-EQ Electrical Cable 

Connections Program, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the GALL Report as modified by 

LR-ISG-2007-02 (December 23, 2009). The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended functions 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 Non-EQ Inaccessible Medium-Voltage Cables Program

Summary of Technical Information in the Application. LRA Section B2.1.21 describes the new 

Non-EQ Inaccessible Medium-Voltage Cables Program as consistent with GALL AMP XI.E3, 

―Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.‖ The applicant stated that this AMP will manage the aging effects of localized 

damage and breakdown of insulation leading to electrical failure of non-EQ inaccessible 

medium-voltage cables within the scope of license renewal that are subject to exposure to 

significant moisture simultaneously with significant voltage. The applicant also stated that the 

program will inspect the in-scope manhole for water collection and will remove water if required. 

The applicant further stated that testing will be performed to provide an indication of the 

condition of conductor insulation. The applicant stated that the specific test will be determined 

prior to the initial test, and the test will be a proven test for detecting deterioration of the 

insulation due to wetting. Additionally, the applicant stated that both inspection of the in-scope 

manhole and testing will be performed prior to the period of extended operation, with the 

inspections repeated every 2 years and testing repeated every 10 years thereafter.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.
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The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.E3. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.E3, with the exception of the ―detection of aging effects‖ program element. For this 

element, the staff determined a need for additional clarification, which resulted in the issuance 

of an RAI.

For the ―detection of aging effects‖ program element, the applicant stated that inspection for 

water collection should be performed prior to the period of extended operation and every 

2 years thereafter. GALL AMP XI.E3 states that the inspection for water collection should be 

based on actual plant experience with water accumulation in the manhole and an inspection 

frequency of at least every 2 years. The staff noted that the applicant did not reference its 

plant-specific OE to justify the fixed 2-year inspection frequency. In addition, the staff noted that 

the applicant‘s program does not provide for adjustment of the 2-year inspection frequency 

based on the possibility of subsequent significant water accumulation resulting in cable 

submergence. By letter dated July 13, 2009, the staff issued RAI B2.1.21-1 requesting that the 

applicant justify the difference between GALL AMP XI.E3 and its program, which does not 

specify that inspections for water collection be performed based on actual plant experience with 

water collection in the manhole. 

In its response dated August 17, 2009, the applicant stated that LRA Section A2.1.21 will be 

revised to replace the fifth paragraph in the program description with the following: 

Inspection of the in-scope manhole east of the tertiary auxiliary transformer for 

water collection will be performed prior to the period of extended operation, and 

the inspection will be repeated at least every two years thereafter. 

The applicant also stated that if significant water collection is observed during the inspections 

which may cause the in-scope cables to become submerged, the condition will be documented 

in the corrective action program. The applicant further stated that the corrective action program 

will evaluate the apparent cause and determine corrective actions, including adjustment of the 

2-year inspection frequency, as necessary. However, the staff noted that the applicant‘s 

response did not include the specific guidance in GALL AMP XI.E3 which states, ―In addition, 

inspection for water collection is performed based on actual plant experience with water 

accumulation in the manholes.‖ By letter dated December 28, 2009, the applicant supplemented 

its response to RAI B2.1.21-1 by revising LRA Section A2.1.21 to replace the fifth paragraph in 

the program description with the following:

Inspection of the in-scope manhole east of the tertiary auxiliary transformer for 

water collection will be performed based on actual plant experience with water 

accumulation in the manhole. However, the inspection will be performed at least 

every two years. The first inspection for license renewal will be performed prior to 

the period of extended operation.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.21-1, supplemented by 

a letter dated December 28, 2009, acceptable because the applicant revised LRA 

Section A2.1.21 so that it is consistent with GALL AMP XI.E3 and SRP-LR Table 3.6-2. The 

staff noted that the applicant‘s revision to its LRA in conjunction with its corrective action 

program, which provides for the evaluation of the inspection frequency should subsequent 

inspections find significant water accumulation in the manhole, is now consistent with GALL 

AMP XI.E3 and SRP-LR Table 3.6-2. The staff, therefore, considers RAI B2.1.21-1 resolved.
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Based on its audit and review of the applicant‘s response to RAI B2.1.21-1, as amended by 

letter dated December 28, 2009, the staff finds that elements one through six of the applicant‘s 

Non-EQ Inaccessible Medium-Voltage Cables Program are consistent with the corresponding 

program elements of GALL AMP XI.E3 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.21 summarizes OE related to the Non-EQ 

Inaccessible Medium-Voltage Cables Program. The applicant stated that its review of its 

corrective action program did not reveal any specific examples attributable to the aging 

mechanisms applicable to its program and GALL AMP XI.E3. The applicant‘s response to 

GL 2007-01 did not identify any failures of in-scope cables. In addition, the applicant‘s 

inspection and interviews with plant personnel concerning the in-scope manhole east of the 

tertiary auxiliary transformer did not identify water collection that would cause in-scope cables to 

be exposed to significant moisture.

During its audit, the staff walked down the in-scope manhole and confirmed the applicant‘s 

recent findings. The applicant further stated that as OE is obtained, lessons learned will be used 

to adjust this program as needed through the applicant‘s OE program. Therefore, the applicant 

has determined that its plant-specific OE did not reveal any degradation outside the bounds of 

industry experience. 

Subsequent to the audit, by letter dated August 9, 2010, the applicant submitted a second 

annual update to the LRA. The annual update described modifications to the substation, 

switchyard, and associated LRA sections. As a result of the modifications that spliced a new 

13.8-kilovolt (kV) feed to the existing 13.8-kV underground feeder cable to the in-scope tertiary 

auxiliary transformer at an underground pulling pit, the applicant added the pulling pit to the 

scope of license renewal. The pulling pit protects the new cable splice and is within the scope of 

license renewal because it supports inaccessible medium-voltage cables required for station 

blackout (SBO). The pulling pit is also within the program scope for the applicant‘s Non-EQ

Inaccessible Medium-Voltage Cables Program and will be included as part of the program‘s 

manhole inspection activities. The staff, as referenced in its inspection report ―Kewaunee Power 

Station NRC License Renewal Scoping, Screening, and Aging Management Inspection (Report 

05000305/2009007),‖ performed a walkdown of the pulling pit and observed it to be free of 

water. 

The GALL Report addresses inaccessible medium-voltage cables in GALL AMP XI.E3, 

―Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.‖ The purpose of this program is to provide reasonable assurance that the 

intended functions of inaccessible medium-voltage cables (2 kV to 35 kV) that are not subject to 

the EQ requirements of 10 CFR 50.49 and are exposed to adverse localized environments 

caused by moisture while energized will be maintained consistent with the CLB. The application 

of GALL AMP XI.E3 to medium-voltage cables by the applicant was based on the OE available 

at the time Revision 1 of the GALL Report was developed. However, recently identified industry 

OE indicates that the presence of water or moisture can be a contributing factor in inaccessible 

power cable failures at lower operating voltages (480 volts (V) to 2 kV). Applicable OE was 

identified in licensee responses to GL 2007-01, ―Inaccessible or Underground Power Cable 

Failures that Disable Accident Mitigation Systems or Cause Plant Transients,‖ which included 

failures of power cables operating at service voltages of less than 2 kV where water was 

considered a contributing factor. The staff has concluded, based on recently identified industry 

OE concerning the failure of inaccessible low-voltage power cables (480 V to 2 kV) in the 

presence of significant moisture, that these cables can potentially experience aging-related 
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degradation. The staff noted that the applicant‘s Non-EQ Inaccessible Medium-Voltage Cables 

Program did not address inaccessible low-voltage power cables.

By letter dated September 10, 2010, the staff issued RAI B2.1.21-1a requesting that the 

applicant:

 (1) Provide a summary of its evaluation of recently identified industry OE and any 

plant-specific OE concerning inaccessible low-voltage power cable failures within the 

scope of license renewal (not subject to 10 CFR 50.49 EQ requirements), and how this 

OE applies to the need for additional aging management activities at KPS for such 

cables. 

 (2) Provide a discussion of how it will manage the effects of aging on KPS‘s inaccessible 

low-voltage power cables within the scope of license renewal and subject to an AMR,

with consideration of recently identified industry OE and any plant-specific OE. The 

discussion should include assessment of its AMP description, program elements 

(i.e., ―scope of the program,‖ ―parameters monitored or inspected,‖ ―detection of aging 

effects,‖ and ―corrective actions‖), USAR, and updated summary description to 

demonstrate reasonable assurance that the intended functions of inaccessible 

low-voltage power cables subject to adverse localized environments will be maintained 

consistent with the CLB through the period of extended operation.

 (3) Provide an evaluation showing that its Non-EQ Inaccessible Medium-Voltage Cables 

Program test and inspection frequencies, including event-driven inspections, incorporate 

recent industry and plant-specific OE for both inaccessible low- and medium-voltage 

cables. Discuss how its Non-EQ Inaccessible Medium-Voltage Cables Program will 

ensure that future industry and plant-specific OE will be incorporated into the program 

such that inspection and test frequencies may be increased based on test and 

inspection results. 

The applicant responded by letter dated September 23, 2010, stating that, in response to 

GL 2007-01, ―Inaccessible or Underground Power Cable Failures That Disable Accident 

Mitigation Systems or Cause Plant Transients,‖ no failures of inaccessible, low-voltage power 

cables were identified at KPS. The applicant also stated that there have been no failures of 

inaccessible, low-voltage power cables at KPS since the GL 2007-01 review was completed. 

The applicant further stated that it will include the inaccessible, low-voltage power cables 

(i.e., cables with service voltages less than 2 kV) that are within the scope of license renewal

and are not subject to 10 CFR 50.49 EQ (non-EQ) with the Non-EQ Inaccessible 

Medium-Voltage Cables Program. 

The applicant stated that it performed a supplemental review and identified the additional 

in-scope, low-voltage cables to be included in the program. The cables identified include a 

power feed to the fire pump 1B control cabinet, a power feed to MCC 1-62D, and power to 

emergency diesel generator (EDG) fuel oil transfer pumps 1A and 1B. The addition of these 

cables also expanded the scope of underground duct banks and associated manholes to 

include EDG fuel oil storage tank access manholes. 

In addition, the applicant also removed the ―significant voltage‖ criterion in the Non-EQ 

Inaccessible Medium-Voltage Cables Program. The elimination of this criterion will no longer 

allow the program exclusion of inaccessible power cables that are energized less than 

25 percent of the time. 
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The applicant stated that testing of the in-scope, low-voltage cables will be performed prior to 

the period of extended operation and at least every 10 years during the period of extended 

operation. The applicant also stated that the EDG fuel oil storage tank access manhole

inspections will be performed based on actual plant experience with water accumulation in the 

manholes, but with the inspection performed at least every 2 years. The applicant further stated 

that the first inspection for license renewal will be performed prior to the period of extended 

operation, and that adverse conditions identified either through cable testing or manhole 

inspections will be evaluated through the applicant‘s corrective action program. 

The applicant also stated that the electrical manhole, the two EDG fuel oil tank access 

manholes, and the cable pulling pit have been inspected for accumulation of water. The 

applicant stated that only minimal indications of water accumulation were identified, and that 

there were no indications of cable wetting or submergence. The applicant also stated that 

grading in the vicinity of the manholes is sloped to aid in directing surface water flow away from 

the manholes, which prevents surface runoff from entering the manhole in the event of 

significant rainfall or other flooding event. The applicant further stated that the grade around the 

pulling pit is not sloped, but that the pulling pit is provided with drains and is located in an area 

with minimal water ponding or runoff. In addition, the applicant stated that the manholes and 

pulling pit are located above the groundwater table such that groundwater accumulation does 

not occur. The applicant concluded that, therefore, water accumulation in the manholes and 

pulling pit was not expected. 

The applicant revised LRA Section A2.1.21 and Section B2.1.21 (including the updated OE) to 

include in-scope inaccessible low-voltage power cables and associated in-scope manholes into 

its Non-EQ Inaccessible Medium-Voltage Cables Program. 

Based on the information provided in the applicant‘s RAI response, the staff finds that:

 (1) The applicant appropriately expanded the program scope to include inaccessible 

low-voltage power cables (480 V to 2 KV) and eliminated the criterion of ―exposure to 

significant voltage‖ consistent with industry OE.

 (2) For KPS, the proposed 10-year frequency for power cable insulation testing is 

acceptable because, as described in the applicant‘s RAI response: (a) review of 

plant-specific OE has not revealed any instance of inaccessible low- or medium-voltage 

power cable failures at KPS; and (b) the frequency of testing can increase based on 

testing and OE as evaluated through the applicant‘s 10 CFR 50, Appendix B corrective 

action program. The staff notes that this approach is consistent with the discussion of 

OE in SRP-LR Section A.1.2.3.10, which states that applicants should consider 

plant-specific and applicable industry OE for its AMPs. 

 (3) The applicant‘s inspection of manholes and pulling pit containing inaccessible in-scope 

power cables is acceptable for several reasons: (a) it takes into account the plant OE at 

KPS, (b) the applicant has performed inspections of the in-scope manholes and pulling 

pit and has found no indications of cable wetting or submergence, (c) the area around 

the manholes is graded to prevent surface water from entering the manholes due to

flooding or heavy rain, (d) the pulling pit is equipped with drains and is located in an area 

that has limited exposure to runoff, and (e) the manholes and cable pit are located above 

the water table so groundwater intrusion should not occur. Because plant-specific OE

has not shown significant water accumulation in the manholes and pulling pit, nor any

indications of cable wetting or submergence within the scope of this AMP, a 2-year 
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inspection frequency is acceptable. In addition, the applicant‘s program supports more 

frequent inspections should adverse water accumulation be identified.

The staff finds that, with the enhancements discussed above, the Non-EQ Inaccessible 

Medium-Voltage Cables Program will adequately manage the aging effects of inaccessible 

power cables consistent with industry OE, such that there is reasonable assurance that 

inaccessible power cables subject to significant moisture will be adequately managed during the

period of extended operation. The staff‘s concern described in RAI B2.1.21-1a is resolved.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During this review, the staff did not identify any OE to indicate that the 

applicant‘s program would not be effective in adequately managing aging effects during the 

period of extended operation. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.21 provides the USAR supplement for the Non-EQ 

Inaccessible Medium-Voltage Cables Program, as amended by the applicant‘s letters dated 

August 17, 2009, December 28, 2009, August 9, 2010, and September 23, 2010. The staff 

reviewed this revised USAR supplement description of the program and notes that, as revised, it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.6-2.

In its response to RAI B2.1.21-1, dated August 17, 2009, combined with its supplemental 

response to RAI B2.1.21-1 dated December 28, 2009, its letter dated August 9, 2010, and its 

response to RAI B2.1.21-1a dated September 23, 2010, the applicant stated that LRA 

Section A2.1.21 will be revised to replace the fifth and sixth paragraphs in the program 

description as discussed in the staff evaluation section above with the following:

Inspection of the in-scope manhole east of the tertiary auxiliary transformer, the pulling 

pit, and the EDG fuel oil storage tank access manholes for water collection will be 

performed based on actual plant experience with water accumulation in the pulling pit 

and manholes. However, the inspection will be performed at least every two years. The 

first inspection for license renewal will be performed prior to the period of extended 

operation.

Testing of the in-scope inaccessible low- and medium-voltage cables exposed to 

significant moisture will be performed prior to the period of extended operation, and the 

tests will be repeated at least every ten years thereafter.

The staff also notes that the applicant committed (Commitment No. 16) to implement the new 

Non-EQ Inaccessible Medium-Voltage Cables Program prior to entering the period of extended 

operation for managing aging of applicable components.
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The staff determines that the information in the USAR supplement, as amended, 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 Non-EQ Inaccessible Medium-Voltage 

Cables Program, the staff finds that all program elements are 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 functions 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).

3.0.3.1.8 Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level 

Signals Program

Summary of Technical Information in the Application. LRA Section B2.1.22 describes the new 

Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals 

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 applicant stated that this program will manage the aging effects of reduced insulation 

resistance and electrical failure for electrical cables and connections subject to sensitive, 

high-voltage, low-level signals installed in nuclear instrumentation and radiation monitoring 

circuits, within the scope of license renewal, that are subject to an adverse localized 

environment. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.E2. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.E2, with the exception of the area discussed below. For this area, the staff determined a

need for additional clarification, which resulted in the issuance of an RAI.

LRA Section B2.1.22 states that this program will manage the aging effects of reduced 

insulation resistance and electrical failure for electrical cables and connections subject to 

sensitive, high-voltage, low-level signals installed in nuclear instrumentation and radiation 

monitoring circuits within the scope of license renewal that are subject to an adverse localized 

environment. The applicant further stated that an adverse localized environment is a condition in 

a limited plant area that is significantly more severe than the specified service environment for 

the cables (power, control, and instrumentation) and connections. However, the applicant did 

not discuss how the adverse localized environments will be identified. The adverse localized 

environment should be based on the most limiting design environment of cables and 

connections. By letter dated July 13, 2009, the staff issued RAI B2.1.19-1 requesting that the 

applicant explain how an adverse localized environment is identified.

In its response dated August 17, 2009, the applicant stated that for structures other than 

containment, the normal operating temperature ranges between 60 °F and 120 °F. The 

applicant further stated that one exception is the AFW pump room in the turbine building that 

has a maximum operating temperature of 130 °F. The applicant stated that for cumulative 

radiation exposure, the plant‘s 40-year radiation dose ranges between 1E4 rads and 
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1.8E7 rads. The applicant also stated that the electrical cable and connection insulation material 

types installed in the plant have been reviewed based on the 60-year service limiting 

temperature range, which varies between 141 °F and 273 °F, and the 60-year service limiting 

radiation dose range, which varies between 1.5E4 rads and 2.7E7 rads (1.5 x 40-year value). 

The applicant stated that it considered the temperature rise due to ohmic heating in the review. 

Additionally, the applicant stated that there are no installed cables or connections with PVC 

insulation, which has a 60-year service limiting temperature of 112 °F. The applicant also stated 

that the most common adverse localized environments are those created by elevated 

temperature and noted that steam generators, feedwater heater, main steam valves, 

uninsulated or unshielded hot process piping, steam or packing leaks, high-powered 

incandescent lighting, motor exhaust air vents, areas with equipment that operate at high 

temperatures, areas with inadequate ventilation, etc., are sources of adverse localized 

environments. Furthermore, electrical cables and connections normally within 3 feet of these 

sources may be subjected to an adverse localized environment. The applicant further stated 

that it will identify adverse localized environments through plant OE reviews, communication 

with maintenance, operations, and radiation protection personnel, and the use of environmental 

surveys.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.19-1 acceptable 

because the applicant adequately described how adverse localized environments will be 

established. The staff‘s concern described in RAI B2.1.19-1 is resolved.

Based on its audit and review of the applicant‘s response to RAI B2.1.19-1, the staff finds that 

elements one through six of the applicant‘s Non-EQ Instrumentation Circuits Subject to 

Sensitive, High-Voltage, Low-Level Signals Program are consistent with the corresponding 

program elements of GALL AMP XI.E2 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.22 summarizes OE related to the Non-EQ 

Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals Program. The 

applicant stated that its program is a new program. The applicant stated that it performed a 

review of the corrective action program for representative examples of internal OE related to this 

program and identified no cases of reduced insulation resistance and electrical failure for 

electrical cables and connections subject to sensitive, high-voltage, low-level signals installed in 

nuclear instrumentation and radiation monitoring circuits, within the scope of license renewal, 

that are subject to an adverse localized environment. The applicant also stated that as OE is 

obtained, lessons learned will be used to adjust this program as needed. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.
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USAR Supplement. LRA Section A2.1.22 provides the USAR supplement for the Non-EQ 

Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals Program. The 

staff reviewed this USAR supplement description of the program and notes that it conforms to 

the recommended description for this type of program in SRP-LR Table 3.6-2.

The staff also noted that the applicant committed (Commitment No. 17) to implement the new 

Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals 

Program prior to entering the period of extended operation for managing aging of applicable 

components.

The staff 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 Non-EQ Instrumentation Circuits 

Subject to Sensitive, High-Voltage, Low-Level Signals Program, the staff finds that all program 

elements are 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 

functions 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 Primary Water Chemistry Program

Summary of Technical Information in the Application. LRA Section B2.1.24 describes the 

existing Primary Water Chemistry Program as consistent with GALL AMP XI.M2, ―Water 

Chemistry.‖ The applicant stated that this program relies on the periodic monitoring and control 

of known detrimental contaminants, such as chloride, fluoride, dissolved oxygen, and sulfate 

concentrations below the levels known to result in cracking, loss of material, and reduction of 

heat transfer, and that the program is based upon industry guidelines for primary water 

chemistry given in Electric Power Research Institute (EPRI) TR-1014986, ―Pressurized Water 

Reactor Primary Water Chemistry Guidelines,‖ Volume 1, Revision 6. The applicant also stated 

that the program includes specifications for chemical species, sampling and analysis 

frequencies, and corrective actions for control of the environment to which internal surfaces of 

systems and components are exposed. The applicant further stated that the program maintains 

water quality (i.e., pH and conductivity) in accordance with the EPRI guidance.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M2. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M2, with the exception of the ―preventive actions‖ and ―acceptance criteria‖ program 

elements. For these elements, the staff determined a need for additional clarification, which 

resulted in the issuance of RAIs.

During its audit, the staff reviewed the applicant‘s LRA and accompanying documentation, 

including relevant chemistry, system operating, and administrative procedures. The staff also 

reviewed condition reports related to the applicant‘s program. In its review, the staff noted a 
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contradiction in the applicant‘s identification of the EPRI report that forms the basis for its 

program. LRA Section B2.1.24 states that this program is based on EPRI TR-1002884, which it 

identifies as ―Pressurized Water Reactor Primary Water Chemistry Guidelines,‖ Volume 1, 

Revision 6. However, the staff noted that this report number actually refers to Revision 5 of the 

report, whereas Revision 6, which is the most recent edition of the report and the one currently 

in effect, is EPRI TR-1014986. By letter dated July 13, 2009, the staff issued RAI B2.1.24-1 

requesting a clarification of this contradiction.

In its response dated August 17, 2009, the applicant stated that its LRA Section B2.1.24 should 

have referenced EPRI TR-1014986, ―Pressurized Water Reactor Primary Water Chemistry 

Guidelines,‖ Volume 1, Revision 6 as the basis for its program. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.24-1 acceptable 

because LRA Section B2.1.24 has been revised to properly identify the technical basis for its 

program, which is a later revision of the guidelines recommended in GALL AMP XI.M2, 

consistent with the recommendations of GALL AMP XI.M2. The staff‘s concern described in 

RAI B2.1.24-1 is resolved.

The staff also noted an inconsistency between two of the applicant‘s documents concerning 

action level limits for dissolved oxygen. The applicant‘s primary water chemistry directive 

defines action level limits for dissolved oxygen for reactor critical conditions that are identical to 

those in EPRI TR-1014986. However, the applicant‘s primary chemistry sample specifications 

procedure defines a different set of limits. By letter dated July 13, 2009, the staff issued 

RAI B2.1.24-2 requesting clarification of this inconsistency. 

In its response dated August 17, 2009, the applicant stated that action level limits stated in its 

procedure require updating and that this condition has now been documented for action in its 

corrective action program. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.24-2 acceptable 

because the applicant has entered this inconsistency into its corrective action program to 

resolve the contradiction between two of its procedures, and its procedures will have consistent 

action level limits in accordance with EPRI TR-1014986. The staff‘s concern described in 

RAI B2.1.24-2 is resolved.

The staff further noted a discrepancy between two of the applicant‘s documents concerning 

limits of reactive silica in the boric acid storage tank. The applicant‘s primary water chemistry 

directive states that the limit on reactive silica for the boric acid storage tank is 5,000 parts per 

billion (ppb), with no further explanation. However, the applicant‘s primary chemistry sample 

specifications procedure states that this limit is 10,000 ppb, and that the limit has been 

increased proportionally for the higher boric acid level of approximately 8 percent, in accordance 

with EPRI TR-1014986. By letter dated July 13, 2009, the staff issued RAI B2.1.24-3 requesting 

clarification of this discrepancy.

In its response dated August 17, 2009, the applicant stated that its primary water chemistry 

directive does not specifically address limits on reactive silica for the boric acid tank. The 

applicable limits are contained in its Nuclear Fleet Administrative Procedure, ―Primary Water 

Chemistry,‖ which identifies limits that are in agreement with EPRI TR-1014986. The applicant 

also stated that its site-specific primary chemistry sample specifications procedure identifies the 

same limits. 
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Based on its review, the staff finds the applicant‘s response to RAI B2.1.24-3 acceptable 

because the applicant clarified that the chemistry limit is in accordance with EPRI TR-1014986, 

which is consistent with the recommendations in GALL AMP XI.M2. The staff‘s concern 

described in RAI B2.1.24-3 is resolved.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.24-1, B2.1.24-2, and 

B2.1.24-3, the staff finds that elements one through six of the applicant‘s Primary Water 

Chemistry Program are consistent with the corresponding program elements of GALL 

AMP XI.M2 and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.24 summarizes OE related to the Primary Water 

Chemistry Program. In the LRA, the applicant cited several instances of transients in water 

chemistry conditions dating back to 2001 and summarized the relevant circumstances and 

corrective actions taken. These included modifications to the Primary Water Chemistry Program 

to control release of corrosion products during mid-cycle shutdowns, the detection of 

contaminants in the boric acid storage tank due to component degradation, modification of 

program procedures to include monitoring the levels of zeolite-forming elements, and changes 

in procedures associated with lithium additions. The applicant stated that, for all of these 

occurrences, the Primary Water Chemistry Program had been effective in managing aging 

effects by monitoring chemistry control parameters and establishing limits for corrective actions. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.24 provides the USAR supplement for the Primary Water 

Chemistry Program. The staff reviewed this USAR supplement description of the program and 

noted that it did not conform to the recommended description for this type of program as 

described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2. 

The staff noted that the LRA lists a number of SCs for which the operating environment is 

primary water. The GALL Report states that no further AMR is necessary for these and similar 

components if the applicant provides certain component-specific commitments in the USAR 

supplement. The staff reviewed the applicant‘s USAR supplement and found that these 

commitments were not present. By letter dated July 13, 2009, the staff issued RAI B2.1.24-4 

requesting that this deficiency be addressed.

In its response dated August 17, 2009, the applicant stated that the two commitments identified 

in the GALL Report that are applicable are related to: (1) the management of cracking for nickel 
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(Ni)-alloy components, and (2) the management of degradation of reactor vessel internals (RVI) 

components. The applicant also stated that the required commitments are not contained in the 

USAR supplement for the Primary Water Chemistry Program, but are instead included in the 

USAR supplements for the plant-specific Alloy 600 Inspections Program and the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.24-4 acceptable 

because it identifies where the required commitments are contained and that the USAR 

supplement now conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2. The staff‘s concern described 

in RAI B2.1.24-4 is resolved.

The staff determines that the information in the USAR supplement, as amended, 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 Primary Water Chemistry 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 functions 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 Reactor Containment Leakage Testing 10 CFR 50, Appendix J Program

Summary of Technical Information in the Application. LRA Section B2.1.25 describes the 

existing Reactor Containment Leakage Testing 10 CFR Part 50, Appendix J Program as 

consistent with GALL AMP XI.S4, ―10 CFR 50, Appendix J.‖ The applicant stated that the 

program manages the aging effects of cracking, loss of leak tightness, loss of material, loss of 

sealing, and leakage through the RCV, including the systems penetrating the RCV, 

penetrations, isolation valves, fittings and access openings made of elastomers, stainless steel, 

and steel to detect degradation of the pressure boundary. The applicant also stated that the 

program uses Option B, the performance-based approach, to implement the requirement of 

containment leak rate monitoring and testing.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.S4. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S4. Based on its 

audit, the staff finds that elements one through six of the applicant‘s Reactor Containment 

Leakage Testing 10 CFR Part 50, Appendix J Program are consistent with the corresponding 

program elements of GALL AMP XI.S4 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.25 summarizes OE related to the Reactor 

Containment Leakage Testing 10 CFR Part 50, Appendix J Program. The applicant stated that it 

has a history of valves exceeding the administrative leak rate limits during Type B and C local 

leak rate tests. The applicant explained that this issue has been addressed by installing O-ring 

flanges and removing the valves from the penetration boundary. During its audit, the staff 
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reviewed samples of condition reports and interviewed the applicant‘s technical staff to verify 

that these conditions were properly corrected in a timely fashion. The staff‘s review confirmed 

that the plant-specific OE did not reveal an adverse trend in program performance or any 

unacceptable aging-related degradation.

The staff reviewed the OE in the application, and during the audit, to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant and 

are evaluated in accordance with the GALL Report. As discussed in the Audit Report, the staff 

conducted an independent search of the plant OE information to determine whether the 

applicant had adequately incorporated and evaluated OE related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.25 provides the USAR supplement for the Reactor 

Containment Leakage Testing 10 CFR Part 50, Appendix J Program. The staff reviewed this 

USAR supplement description of the program and notes that it conforms to the recommended 

description for this type of program as described in SRP-LR Table 3.5-2.

The staff 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 Containment Leakage Testing 

10 CFR Part 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 functions 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).

3.0.3.1.11 Secondary Water Chemistry Program

Summary of Technical Information in the Application. LRA Section B2.1.28 describes the 

existing Secondary Water Chemistry Program as consistent with GALL AMP XI.M2, ―Water 

Chemistry.‖ The applicant stated that this program relies on the periodic monitoring and control 

of known detrimental contaminants, such as chloride, dissolved oxygen, and sulfate 

concentrations below the levels known to result in cracking, loss of material, or reduction of heat 

transfer and that the program is based upon industry guidelines for secondary water chemistry 

given in EPRI TR-1008224, ―Pressurized Water Reactor Secondary Water Chemistry 

Guidelines,‖ Revision 6. The applicant also stated that the program includes specifications for 

chemical species, sampling and analysis frequencies, and corrective actions for control of the 

environment to which internal surfaces of systems and components are exposed. The applicant 

further stated that the program maintains water quality (pH and conductivity) in accordance with 

the EPRI guidance. In addition, the applicant stated that the effectiveness of the Secondary 
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Water Chemistry Program is verified by its ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program; Steam Generator Tube Integrity Program; and WCP Program.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M2. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M2. Based on its

audit, the staff finds that elements one through six of the applicant‘s Secondary Water 

Chemistry Program are consistent with the corresponding program elements of GALL 

AMP XI.M2 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.28 summarizes OE related to the Secondary Water 

Chemistry Program. In the LRA, the applicant cited several instances of transients in water 

chemistry conditions dating back to 2002 and summarized the relevant circumstances and 

corrective actions taken. These included high dissolved oxygen levels in the condensate and 

feedwater systems and low feedwater hydrazine levels. In addition, changes were made in 

equipment operator logs to reflect EPRI guidelines, and enhancements were added to various 

secondary water chemistry procedures. The applicant stated that, for all of these occurrences, 

the Secondary Water Chemistry Program had been effective in managing aging effects by 

monitoring chemistry control parameters and establishing limits for corrective actions. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.28 provides the USAR supplement for the Secondary 

Water Chemistry Program. The staff reviewed this USAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2.

The staff 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 Secondary Water Chemistry 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 
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intended functions 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).

3.0.3.1.12 Selective Leaching of Materials Program

Summary of Technical Information in the Application. LRA Section B2.1.29 describes the new 

Selective Leaching of Materials Program as consistent with GALL AMP XI.M33, ―Selective 

Leaching of Materials.‖ The applicant stated that the new Selective Leaching of Materials 

Program will manage the aging effects of loss of material on internal and external surfaces of 

in-scope components, such as piping, pumps, valves, heat exchanger components made of 

steel (cast iron), and copper alloys (brass, bronze, or aluminum-bronze). The applicant also 

stated that the program combines the use of a one-time visual inspection with a hardness test or 

qualitative examination, such as resonance when struck by another object, scraping, or 

chipping, as appropriate, on the external and internal surfaces of components made of materials 

susceptible to selective leaching, to determine whether the aging effect of loss of material due to 

selective leaching has occurred. The applicant further stated that the program will define a 

one-time examination methodology and acceptance criteria, will inspect a representative sample 

of selected components that may be susceptible to selective leaching, and if selective leaching 

is found, the program will provide for evaluation as to the effect leaching will have on the 

component‘s function as well as the need to expand the number and location of components in 

the inspection sample.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M33. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M33, with the exception of the ―scope of the program‖ and ―detection of aging effects‖ 

program elements. For these elements, the staff determined a need for additional clarification, 

which resulted in the issuance of RAIs, as discussed below.

GALL AMP XI.M33 states in the ―scope of the program‖ program element that the program 

includes a one-time visual inspection and hardness measurement of a selected set of sample 

components to determine whether loss of material due to selective leaching is not occurring for 

the period of extended operation. However, the LRA did not state how the selected set of 

sample components would be determined or the size of the sample of components that would 

be inspected. The staff noted that due to the uncertainty in determining the most susceptible 

locations and the potential for aging to occur in other locations, large sample sizes may be 

required in order to adequately confirm that selective leaching is not occurring. By 

teleconference on November 17, 2010, the staff issued RAI B2.1.29-2 requesting that the 

applicant provide specific information regarding how the selected set of components to be 

sampled will be determined and the size of the sample of components that will be inspected.

In its response dated November 23, 2010, the applicant stated that inspection locations will be 

developed to ensure that a representative sample of material and environment combinations is 

selected with a focus on inspecting leading indicator components. The applicant also stated that 

a sample size of 20 percent of the population (up to a maximum of 25 components) will be 
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established for each of the two material groups (gray cast iron and copper alloy) consistent with 

the methodology established in EPRI TR-107514, ―Age-Related Degradation Inspection Method 

and Demonstration in Behalf of Calvert Cliffs Nuclear Power Plant License Renewal 

Application,‖ Section 4, Sampling Program Description. The staff finds the applicant‘s response 

acceptable because the applicant‘s selected set of components to be sampled will be based on 

material and environment combinations, and the sample locations will focus on the leading 

indicator components and include a large sample size. The staff‘s concern described in 

RAI B2.1.29-2 is resolved.

GALL AMP XI.M33 recommends the use of a one-time visual inspection and hardness 

measurement of a selected set of sample components to determine whether loss of material 

due to selective leaching is occurring for the period of extended operation; however, during its 

review, the staff found that the applicant‘s Selective Leaching of Materials Program credits the 

use of qualitative examinations, such as resonance when struck by another object, scraping, or 

chipping, as appropriate. By letter dated March 11, 2010, the staff issued RAI B2.1.29-1 

requesting that the applicant provide justification for why the qualitative examination 

methodologies credited in the LRA AMP are an acceptable alternative to performing a hardness 

measurement, as recommended by the GALL Report.

In its response dated March 26, 2010, the applicant stated that it would take an exception to the 

―detection of aging effects‖ program element to use qualitative examination methods, such as 

resonance when struck by another object, scraping, or chipping, where a hardness 

measurement may not be feasible due to the component‘s form, configuration, or location. The 

applicant also stated that visual inspection will be used in conjunction with the qualitative 

examination methods. The staff finds the applicant‘s response acceptable because visible 

inspection is an appropriate method for detecting loss of material, and the qualitative 

examination methods proposed are appropriate for detecting the effects of selective leaching by 

providing indication of degradation in the base material. The staff‘s concern described in 

RAI B2.1.29-1 is resolved.

The staff also reviewed the portions of the ―detection of aging effects‖ program element 

associated with the exception taken in response to RAI B2.1.29-1 to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff‘s 

evaluation of this exception follows.

Exception. LRA Section B2.1.29 states an exception to the ―detection of aging effects‖ program 

element as a result of the response to RAI B2.1.29-1 discussed above. The exception states 

that the applicant will use qualitative examination methods, such as resonance when struck by 

another object, scraping, or chipping, where a hardness measurement may not be feasible due 

to the component‘s form, configuration, or location, in conjunction with a visible inspection to 

determine if selective leaching is occurring. The staff finds the exception acceptable because 

the qualitative examination methods proposed are acceptable methods to determine if selective 

leaching is occurring.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.29-1 and B2.1.29-2, the 

staff finds that elements one through six of the applicant‘s Selective Leaching of Materials 

Program are consistent with the corresponding program elements of GALL AMP XI.M33 and 

are, therefore, acceptable. 
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Operating Experience. LRA Section B2.1.29 summarizes OE related to the Selective Leaching 

of Materials Program. The applicant stated that the Selective Leaching of Materials Program is a 

new program for which there is no plant-specific OE. The applicant also stated that as the new 

program is implemented, OE will be evaluated and the actions, inspection, and testing will be 

modified accordingly. The applicant further stated that inspection methods will be consistent 

with accepted industry practices.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no OE to indicate that the applicant‘s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

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. 

The staff finds this program acceptable.

USAR Supplement. LRA Section A2.1.29 provides the USAR supplement for the Selective 

Leaching of Materials Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.1-2, 3.2-2, and 3.3-2. 

The staff also notes that the applicant committed (Commitment No. 21) to implement the new 

Selective Leaching of Materials Program prior to entering the period of extended operation for 

managing aging of applicable components, including a one-time visual inspection and hardness 

measurement or qualitative examination of selected components.

The staff 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 Selective Leaching of Materials 

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 functions of these components 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). 

3.0.3.1.13 Environmental Qualification (EQ) of Electric Components Program

Summary of Technical Information in the Application. LRA Section B3.1 describes the existing 

EQ of Electric Components Program as consistent with GALL AMP X.E1, ―Environmental 

Qualification (EQ) of Electrical Components.‖ The applicant stated that its program manages the 

effects of thermal, radiation, and cyclic aging through the use of aging evaluations based on 

10 CFR 50.49(f) qualification methods. The applicant also stated that, as required by 

10 CFR 50.49, EQ components are refurbished, replaced, or their qualification extended prior to 

reaching the aging limits established in the evaluation. The applicant further stated that aging 
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evaluations for EQ components that specify a qualification of at least 40 years are considered 

time-limited aging analyses (TLAAs) for license renewal. LRA Section B3.1 states that for the 

period of extended operation, the qualified life for equipment is an additional 20 years at the 

maximum normal plant service conditions to which the equipment is exposed. The applicant 

also stated that in cases where the component lifespan (for the period of extended operation or 

current operating term) may not be achieved due to aging limitations of the equipment, it is 

acceptable to determine the qualified life of less than the length necessary, as long as the 

equipment is replaced, refurbished, or requalified prior to the end of qualified life.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP X.E1. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP X.E1, with the exception of the ―parameters monitored or inspected,‖ ―detection of aging 

effects,‖ and ―monitoring and trending‖ program elements. For these elements, the staff 

determined a need for additional clarification, which resulted in the issuance of an RAI.

During its audit, the staff noted that the applicant‘s program has a specific reference to the use 

of ambient temperature monitoring to modify qualified life through reanalysis. The staff noted 

that GALL AMP X.E1 states that per RG 1.89, Revision 1, a condition or performance 

monitoring program is an acceptable basis to modify a qualified life through reanalysis. 

However, the applicant did not describe whether ambient temperature monitoring is performed 

and controlled consistent with GALL AMP X.E1, such that component qualified life remains 

bounded with respect to ambient temperature or as a means to modify the qualified life. By letter 

dated July 13, 2009, the staff issued RAI B3.1-2 requesting that the applicant explain how 

ambient temperature monitoring is or will be performed and controlled under its EQ of Electric 

Components Program. 

In its response dated August 17, 2009, the applicant stated that ambient temperature monitoring 

data used in its program is historical data obtained from a monitoring program that was 

performed during the 1991–1992 timeframe, but there is no ambient temperature monitoring 

currently being performed for its program. The applicant also stated that EQ component 

qualified life analyses generally uses plant design temperatures, which are higher, on average, 

than actual service temperatures. The applicant further stated that when service temperatures 

are used in the analyses, the historical temperature monitoring data is adjusted to account for 

plant modification or changes that could affect ambient temperatures since the temperature 

monitoring data was obtained. The applicant also stated that ambient temperature monitoring 

data from the warmest months of the year are typically used as inputs to the qualification 

analysis. The applicant concluded that component qualified life analyses are based on 

conservative bounding service temperature inputs with respect to ambient temperature.

Based on its review, the staff finds the applicant‘s response to RAI B3.1-2 acceptable because 

the applicant explained the use of the historical temperature monitoring data, and that it is 

adjusted based on plant modifications or changes affecting the ambient temperature data when 

used in EQ component qualified life analyses, which is consistent with GALL AMP X.E1. The 

staff‘s concern described in RAI B3.1-2 is resolved.
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Based on its audit and review of the applicant‘s response to RAI B3.1-2, the staff finds that 

elements one through six of the applicant‘s EQ of Electric Components Program are consistent 

with the corresponding program elements of GALL AMP X.E1 and are, therefore, acceptable.

Operating Experience. LRA Section B3.1 summarizes OE related to the EQ of Electric 

Components Program. The applicant stated that OE indicates the EQ of Electric Components 

Program is effectively implemented and that, where appropriate, corrective actions are identified 

and implemented to ensure program effectiveness. The applicant referenced a 2005 condition 

report related to high-energy line break (HELB) adverse environmental conditions not 

considered in the EQ, and a 2004 condition report concerning shield building filter assembly 

inlet damper solenoid valves not in compliance with its program classification. The applicant 

entered the recommended actions into the corrective action program for resolution and 

completed them. Additionally, the applicant stated that industry and applicant self assessments 

of its program effectiveness and implementation were performed in 2004, 2006, and 2007. The 

applicant stated that, despite identifying needed improvements and a backlog of unfinished EQ 

documentation updates, the assessments found the applicant‘s EQ program adequate. The 

applicant implemented a program to address the areas where improvement was needed and 

eliminate the EQ documentation backlog. 

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A3.3 provides the USAR supplement for the EQ of Electric 

Components Program. The staff reviewed this USAR supplement description of the program

and noted that it did not conform to the recommended description for this type of program as 

described in SRP-LR Table 4.4-2.

The staff noted that GALL AMP X.E1 states that reanalysis of an aging evaluation is normally 

performed to extend the qualification by reducing excess conservatism incorporated in the prior 

evaluation. Furthermore, important attributes of a reanalysis include analytical methods, data 

collection and reduction methods, underlying assumptions, acceptance criteria, and corrective 

actions (if acceptance criteria are not met). By letter dated July 13, 2009, the staff issued 

RAI B3.1-1 requesting that the applicant provide justification for not including the reanalysis 

attributes in the USAR supplement. 
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In its response dated August 17, 2009, the applicant stated that the following statement would 

be added to LRA Section A3.3:

Re-analysis of aging evaluations to extend the qualifications of components is 

performed on a routine basis as part of the program. Important attributes for the 

re-analysis of aging evaluations include analytical methods, data collection and 

reduction methods, underlying assumptions, acceptance criteria and corrective 

actions (if acceptance criteria are not met).

Based on its review, the staff finds the applicant‘s response to RAI B3.1-1 acceptable because 

the applicant revised LRA Section A3.3 to include reanalysis attributes and the USAR 

supplement now conforms to the recommended description for this type of program as 

described in SRP-LR Table 4.4-2. The staff‘s concern described in RAI B3.1-1 is resolved.

The staff determines that the information in the USAR supplement, as amended, 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 EQ of Electric Components 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 functions 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 AMPS That Are Consistent with the GALL Report with Exceptions or 

Enhancements

In LRA Appendix B, the applicant identified the following AMPs that were, or will be, consistent 

with the GALL Report, with exceptions or enhancements:

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

● ASME Section XI, Subsection IWF Program

● Bolting Integrity Program

● Buried Piping and Tanks Inspection Program

● Closed-Cycle Cooling Water System Program

● Compressed Air Monitoring Program

● External Surfaces Monitoring Program

● Fire Protection Program

● Flow-Accelerated Corrosion Program

● Fuel Oil Chemistry Program

● Fuel Oil Tank Inspections Program

● Inspection of Overhead Heavy Load and Refueling Handling Systems Program

● Metal-Enclosed Bus Program

● Open-Cycle Cooling Water System Program 

● Reactor Head Closure Studs Program

● Reactor Vessel Surveillance Program

● Steam Generator Tube Integrity Program

● Structures Monitoring Program
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● Work Control Process Program

● Metal Fatigue of Reactor Coolant Pressure Boundary Program

3.0.3.2.1 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

Summary of Technical Information in the Application. LRA Section B2.1.2 describes the existing 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program as consistent, with exception 

and enhancements, with GALL AMP XI.M1, ―ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD.‖ 

The applicant stated that its program manages the aging effects of changes in dimensions, 

cracking, loss of fracture toughness, loss of material, and loss of preload for the ASME Class 1, 

2, and 3 piping, including piping less than 4 inches nominal pipe size (NPS), and components 

fabricated of Ni alloys, stainless steel, and steel. The applicant further stated that its program 

manages the aging effect of cracking for the steel reactor coolant pump (RCP) motor flywheels.

The applicant stated that its program performs visual, surface, ultrasonic, and eddy current 

examinations based on the inspection extent, schedule, and techniques specified in 

Tables IWB-2500-1, IWC-2500-1, and IWD-2500-1. The applicant further stated that its program 

performs examinations of the RCP motor flywheels as augmented examinations. These 

augmented examinations are regulatory commitments outside the scope of the requirements of 

the ASME Boiler and Pressure Vessel (B&PV) Code Section XI.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M1. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M1, with the 

exception of program elements ―parameters monitored or inspected‖ and ―detection of aging 

effects.‖ For these program elements, the staff determined a need for additional clarification, 

which resulted in the issuance of RAIs.

The staff noted that the applicant did not provide a specific program to manage aging effects in 

Class 1 small-bore piping. The program description of LRA Section B2.1.2 states that the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program includes ―piping less than four inches 

nominal pipe size [NPS].‖ The SRP-LR recommends a specific program to address aging 

management of Class 1 small-bore piping up to 4 inches NPS. The staff noted that this program 

is provided in GALL AMP XI.M35, ―One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping.‖ The applicant does not have a program consistent with GALL AMP XI.M35, but instead 

uses its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to manage aging for 

Class 1 small-bore piping. The staff noted that the applicant‘s ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program does not fully address the recommendations of GALL 

AMP XI.M35. 

By letter dated July 13, 2009, the staff issued RAI B2.1.2-1 requesting that the applicant provide 

program information on the aging management of Class 1 small-bore piping up to 4 inches 

NPS.
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In its response dated August 17, 2009, the applicant stated that it will perform examinations in 

accordance with the staff-approved risk-informed ISI program. The applicant stated that welds 

are selected based on risk significance and the potential for aging or cracking, and that 8 of the 

96 Class 1 small-bore welds are scheduled for volumetric and surface examinations. 

During a conference call with the applicant on September 22, 2009, the staff stated that 

additional information was needed to address the adequacy of the sampling size of its Class 1 

small-bore welds.

By letter dated February 2, 2010, the applicant supplemented its response to RAl B2.1.2-1. The 

applicant clarified that based on its risk-informed ISI program, a total of 24 welds will be 

examined prior to the end of the period of extended operation. The applicant further stated that 

weld selection is based on susceptibility, inspectability, dose considerations, OE, and limiting 

locations of the total population of welds.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.2-1, as supplemented 

by letter dated February 2, 2010, acceptable because the information demonstrated that the 

applicant has selection criteria that are consistent with the recommendations of GALL 

AMP XI.M35. The staff‘s concern described in RAI B2.1.2-1 is resolved.

During the audit, the staff noted that no specific information was provided regarding examination 

of small-bore piping socket welds. The applicant indicated only that there were 450 Class 1

welds up to 4 inches NPS, some of which were socket welds. By letter dated July 13, 2009, the 

staff issued RAI B2.1.2-2 requesting that the applicant provide information regarding the 

examination of small-bore piping socket welds.

In its response dated August 17, 2009, the applicant stated that for Examination Category B-J, 

Item No. B9.40, there are 320 ASME Class 1 socket welds. The applicant further stated that 

during the fourth (current) 10-year inspection interval, the risk-informed ISI program selected 

20 small-bore ASME Class 1 socket welds to receive surface examinations, based on risk 

significance and the potential for aging mechanisms. The applicant stated that 12 of the 20 

examinations have been completed to date, and there have been no indications of cracking. 

The applicant also stated that visual inspections of the ASME Class 1 piping systems at nominal 

operating pressure are performed during each refueling outage. The applicant stated that the 

surface examination of selected small-bore socket welds and the visual inspection of the ASME 

Class 1 piping systems are consistent with the requirements of ASME Code Section XI. The 

applicant stated that the socket weld issue had been resolved and that the staff has accepted 

the use of visual testing (VT)-2 and surface examinations. 

The staff noted that its position has been that which is recommended in GALL AMP XI.M35, 

which recommends a one-time volumetric examination. The staff noted that a VT-2 or surface 

examination is only for leakage detection and since cracking in most cases starts from the 

inside surface, by the time leakage indication is detected by VT-2, the subject component would 

have already failed and lost its intended function. The staff noted that this is the reason GALL 

AMP XI.M35 recommends volumetric examinations of small-bore piping, including socket welds.

During a conference call with the applicant on September 22, 2009, the staff stated that 

additional information was needed to address the adequacy of sampling size of its Class 1 

small-bore welds. The staff discussed its concerns with the applicant regarding the limitations of 

VT-2 examinations, as described above. The applicant stated that there was no industry 

demonstrated means of performing volumetric examinations to detect cracking at the inside 
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diameter of a socket weld. The staff noted that: (1) VT-2 or surface examination is not useful in 

detecting cracking initiated from the inside of a socket weld, and (2) although there is not yet a

performance demonstration initiative (PDI)-qualified ultrasonic testing (UT) technique that would 

have the ability to size a crack in socket welds, the industry has developed UT techniques on 

socket welds which, although not qualified for sizing, do provide go/no-go results that are useful 

in detecting aging.

By letters dated February 2, 2010, and September 23, 2010, the applicant supplemented its 

response to RAl B2.1.2-2. The applicant committed (Commitment No. 43) to perform volumetric 

examinations on 5 Class 1 socket welds, ―using a demonstrated, nuclear-industry endorsed

inspection methodology that can detect cracking within the specified examination volume, if a 

methodology becomes available.‖ Furthermore, the applicant committed (Commitment No. 43) 

to perform one destructive examination consisting of at least two socket welds will be performed 

in lieu of the volumetric examination if a demonstrated inspection methodology is not available 

prior to the period of extended operation. The staff noted that PDI has a set of very strict 

qualification standards and that a PDI-qualified UT technique would accurately size a flaw, but 

may be difficult to develop. The staff further noted that several demonstrated UT techniques 

have been developed and used by the nuclear industry. They provide a go/no-go result that 

would be adequate in the examination of socket welds. Nonetheless, the staff understands that 

the applicant has options of performing PDI-qualified UT, industry-demonstrated UT, or 

opportunistic destructive examinations on the subject socket welds. 

Subsequent to the applicant‘s response to RAI B2.1.2-2 above, on November 5, 2010, the staff 

held a telephone conference with the applicant to discuss Commitment No. 43. The staff 

provided additional information regarding sample size guidance for a plant such as KPS, and 

indicated that an appropriate sample size for Class 1 small-bore piping socket welds could be 

as low as 3 percent for an applicant that has not experienced a failure in its Class 1 small-bore 

piping during an extensive operating history (e.g., over 36 years of operation).

By letter dated November 9, 2010, the applicant supplemented its response to RAl B2.1.2-2 and 

indicated that there are currently a total of 345 Class 1 socket welds. The applicant stated that 

10 of the welds (about 3 percent) will be volumetrically examined by a demonstrated volumetric 

technique. In case such a technique is not available, the applicant stated that destructive 

examination will be substituted for volumetric NDEs. The applicant indicated that it has an 

option of performing destructive examination in lieu of volumetric examination on a two-for-one 

basis. Because more information can be obtained from destructive examinations than from 

nondestructive examinations, the staff finds the applicant‘s option to perform destructive 

examination in lieu of volumetric examination on a two-for-one basis, acceptable. The staff also 

finds that the number of welds to be inspected is consistent with the staff‘s position of a 3 

percent sample size for plants with no operating experience of weld failures. Therefore, the staff 

finds the applicant‘s proposed inspection sample size acceptable. The staff determines that the 

sampling adequacy issue regarding socket weld inspection has been addressed. In addition, the 

applicant also provided information regarding its inspection schedule and stated the following:

A minimum of four volumetric examinations or two destructive examinations (or 

an equivalent combination of examinations) will be performed prior to the period 

of extended operation. To allow for orderly planning and scheduling of plant 

resources and outage workload, the remaining examinations will be performed 

within three years of entering the period of extended operation.
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Since the applicant will be entering the period of extended operation in December of 2013, the 

staff noted that the first inspections will be performed within 3 years, and all inspections will be 

completed within 6 years. The staff finds the applicant‘s proposal consistent with the 

recommendations of the GALL Report regarding timely implementation of the small-bore piping 

inspections and is, therefore, acceptable.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.2-2, as supplemented 

by letters dated February 2, 2010, September 23, 2010, and November 9, 2010, acceptable 

because the applicant committed (Commitment No. 43) to volumetric examinations of socket 

welds, consistent with GALL AMP XI.M35. The staff‘s concern described in RAI B2.1.2-2 is 

resolved.

The staff noted that the examinations will be implemented by the applicant‘s ASME Section XI 

ISI, Subsections IWB, IWC, and IWD Program and, therefore, the ASME Code Section XI 

acceptance criteria and examination expansion criteria are both applicable. The staff finds the 

applicant‘s commitment (Commitment No. 43) addressing examination of Class 1 socket welds 

to be consistent with the recommendations in GALL AMP XI.M35.

The staff determined that aging management of Class 1 small-bore piping is adequately 

addressed because the number of welds to be inspected, the selection methodology, and the 

timely implementation of the small-bore piping inspection are consistent with the 

recommendations in the GALL Report.

The staff also reviewed the portions of the ―scope of the program,‖ ―parameters monitored or 

inspected,‖ ―detection of aging effects,‖ ―monitoring and trending,‖ and ―acceptance criteria‖ 

program elements associated with the exceptions and enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff‘s 

evaluation of these exceptions and enhancements follows.

Exception. LRA Section B2.1.2 states an exception to the ―scope of the program,‖ ―parameters 

monitored or inspected,‖ ―detection of aging effects,‖ ―monitoring and trending,‖ and ―acceptance 

criteria‖ program elements. The applicant stated that the ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program is based on the ASME Code Section XI, 1998 Edition through 

2000 Addenda. The applicant stated that use of the 1998 Code Edition through 2000 Addenda 

is consistent with 10 CFR 50.55a, which requires use of the ASME Code Edition in effect 

12 months prior to the start of the inspection interval, and that, for KPS, this is the 1998 Edition 

though the 2000 Addenda. The applicant further stated that this is a different code edition and 

addenda than recommended in GALL AMP XI.M1, which specifies the use of the ASME Code

Section XI, 2001 Edition through the 2003 Addenda.

To justify this exception, the staff noted that the applicant has performed a comparison of the 

two code edition/addenda combinations and has concluded that there were no changes in the

scope of components. 

To ensure that the GALL Report conclusions will remain valid when future editions of the ASME 

Code are incorporated into NRC regulations by the 10 CFR 50.55a rulemaking, the staff will 

perform an evaluation of these later editions for their adequacy for license renewal using the 

10-element program evaluation described in the GALL Report as part of the 10 CFR 50.55a 

rulemaking. The staff will document this evaluation in the statements of consideration (SOCs) 

accompanying future 10 CFR 50.55a amendments, which will be published in the Federal 

Register notice (FRN) for each code edition or addendum. The applicant needs to examine the 
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FRN paragraph for a specific code edition or addendum for use in license renewal when 

updating its code of record in subsequent inspection intervals.

Based on its review, the staff does not consider the applicant‘s use of code edition as an 

exception, and finds it acceptable for the applicant to use the ASME Code Section XI,

1998 Edition through 2000 Addenda.

Enhancement 1. LRA Section B2.1.2 states an enhancement to the ―detection of aging effects‖ 

program element. The applicant stated that the ASME Section XI ISI, Subsections IWB, IWC, 

and IWD Program will be enhanced to: (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, submit 

an inspection plan for reactor internals to the staff for review and approval to augment the 

current inspections.

The staff noted that this enhancement incorporates the recommendations of GALL 

AMP XI.M16, ―PWR Vessel Internals,‖ which refers to Chapter IV of the GALL Report that 

states:

No further aging management review is necessary if the applicant provides a 

commitment in the FSAR [final safety analysis report] supplement to 

(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, submit an inspection plan for reactor internals to the NRC for review 

and approval.

The staff noted that the applicant committed (Commitment No. 1) in its USAR supplement to 

enhance its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to: (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, submit an inspection plan for reactor internals to the 

staff for review and approval to augment the current inspections.

Based on its review, the staff finds the applicant‘s enhancement acceptable because the 

applicant provided a commitment (Commitment No. 1) to enhance its ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program to manage the effects of aging for the RVIs 

consistent with the recommendations of the GALL Report and SRP-LR.

Enhancement 2. LRA Section B2.1.2 states an enhancement to the ―detection of aging effects‖ 

program element. The applicant stated that the ASME Section XI ISI, Subsections IWB, IWC, 

and IWD Program will be enhanced to include identification of the limiting susceptible cast 

austenitic stainless steel (CASS) RVI components from the standpoint of thermal aging 

susceptibility, neutron fluence, and cracking. The applicant further stated that for each identified 

component, a plan will be developed that accomplishes aging management through either a 

supplemental examination or a component-specific evaluation. Furthermore, the plan will be 

submitted for staff review and approval, not less than 24 months before entering the period of 

extended operation. The applicant further stated that the enhancement will ensure that the 
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inspections for the detection of aging effects on the CASS RVI components will implement the 

best industry practices.

In addition, the applicant stated in LRA Table 3.1.1, item 3.1.1-80 that the loss of fracture 

toughness due to thermal aging and neutron irradiation embrittlement of CASS RVI components 

is managed by this enhancement to the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program to include the recommendations of GALL AMP XI.M13, ―Thermal Aging and Neutron 

Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS),‖ following participation in 

the industry programs for investigating and managing aging effects on reactor internals. 

The staff noted that the applicant did not describe a specific program to manage the effects of 

loss of fracture toughness due to thermal and neutron irradiation embrittlement of CASS RVI 

components. The staff further noted that in LRA Table 3.1.1, item 3.1.1-80, the applicant stated 

that, following participation in the industry programs for investigating and managing aging 

effects on reactor internals, the program to manage loss of fracture toughness of CASS RVI 

components would be consistent with the recommendations of GALL AMP XI.M13. The staff 

also noted that the LRA, on page B-7, states that the recommendations of GALL AMP XI.M13 

will be an enhancement to the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program.

The applicant committed (Commitment No. 2) that its ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program will be enhanced to include identification of the limiting susceptible 

CASS RVI components from the standpoint of thermal aging susceptibility, neutron fluence, and 

cracking, and for each identified component to develop a plan which accomplishes aging 

management through either a supplemental examination or a component-specific evaluation. 

The plan will then be submitted for staff review and approval not less than 24 months before 

entering the period of extended operation. The staff finds this acceptable because the applicant 

has made a commitment to develop and submit for staff review and approval, a program to 

manage loss of fracture toughness of CASS RVI components that is consistent with the 

recommendations of GALL AMP XI.M13. 

Based on its audit and review of the applicant‘s responses to RAIs B2.1.2-1 and B2.1.2-2, the 

staff finds that elements one through six of the applicant‘s ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program, with acceptable enhancements and an exception, are consistent 

with the corresponding program elements of GALL AMP XI.M1 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.2 summarizes OE related to the ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program. The applicant provided examples of OE review 

related to the effectiveness of its ISI program. The applicant stated that, during the fall 2006 

refueling outage, the NDE examiner identified a moderate amount of dry boric acid on the 

interface of the valve body to the bonnet in the residual heat removal (RHR) system. The 

applicant also stated that the valve was repaired and returned to service.

The applicant stated that, in April 2003, during a liquid penetrant examination of a 2-inch socket 

weld in the RCS, a linear indication was recorded that was unacceptable in accordance with 

ASME Code Section XI 1989 Edition, Table IWB-3514-2. The engineering evaluation of the 

condition determined that it was a fabrication indication. The applicant further stated that the 

weld was repaired by light filing.

In another example provided by the applicant, it stated that during the spring 2003 refueling 

outage, the applicant performed visual examinations of its reactor vessel head and all the head 

penetrations. The applicant stated that this inspection stemmed from NRC Order EA-03-0091, 
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―Issuance of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel 

Heads at Pressurized Water Reactors.‖ The examinations performed by the applicant showed 

that there were no recordable indications and that the head was free of any evidence of 

corrosion, boric acid residue, or leakage.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.2 provides the USAR supplement for the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program, as amended by letter dated 

February 2, 2010. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.1-2.

The staff also notes that the applicant committed (Commitment No. 1 and No. 2) to enhance the 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program prior to entering the period of 

extended operation. 

Specifically, Commitment No. 1 states the following:

The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program will be enhanced to: (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, submit an inspection 

plan for reactor internals to the NRC for review and approval to augment the 

current inspections.

Specifically, Commitment No. 2 states the following:

The ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

program will be enhanced to include identification of the limiting susceptible cast 

austenitic stainless steel reactor vessel internals components from the standpoint 

of thermal aging susceptibility, neutron fluence, and cracking. For each identified 

component, a plan will be developed, which accomplishes aging management 

through either a supplemental examination or a component-specific evaluation. 
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The plan will be submitted for NRC review and approval not less than 24 months 

before entering the period of extended operation.

The staff notes that the applicant committed (Commitment No. 42) by letter dated February 2, 

2010, to the following:

For Examination Category B-J, Item No. B9.21, eight ASME Class 1 small-bore 

circumferential welds will receive volumetric and surface examinations during 

each 10-year ISI interval the during the period of extended operation. 

The staff also notes that the applicant committed (Commitment No. 43) by letters dated 

February 2, 2010, September 23, 2010, and November 9, 2010, to the following:

Ten volumetric examinations of ASME Class 1 small-bore socket welds will be 

performed using a demonstrated, nuclear-industry endorsed, inspection 

methodology that can detect cracking within the specified examination volume, if 

a methodology becomes available. In the event that a demonstrated, 

nuclear-industry endorsed, inspection methodology is not available, destructive 

examinations of socket welds will be substituted for volumetric non-destructive 

examinations. Each destructive weld examination will be considered equivalent 

to performing two volumetric weld examinations, such that a maximum of five 

destructive examinations will be performed.

The staff noted that regarding the inspection schedule, Commitment No. 43 further states the 

following: 

Four volumetric examinations or two destructive examinations, (or an equivalent 

combination of examinations) [will be performed] prior to the period of extended 

operation. 

[The] [R]emaining examinations [will be performed] within three years of entering the 

period of extended operation.

The staff determines that the information in the USAR supplement, as amended, 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 Section XI ISI, 

Subsections IWB, IWC, and IWD Program and Commitment No. 43, 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 the LRA credits 

it. Also, the staff reviewed the two enhancements and confirmed that their implementation 

through Commitment Nos. 1 and 2, prior to the period of extended operation, would make the 

existing AMP consistent with the GALL Report 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 functions 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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3.0.3.2.2 ASME Section XI, Subsection IWF Program

Summary of Technical Information in the Application. LRA Section B2.1.4 describes the existing 

ASME Section XI, Subsection IWF Program as consistent, with an exception, with GALL 

AMP XI.S3, ―ASME Section XI, Subsection IWF.‖ The applicant stated that the program 

performs visual examinations of Class 1, Class 2, and Class 3 component supports consistent 

with the examinations of ―Support Types Examined‖ in Table IWF-2500-1. The applicant further 

stated that the program is implemented in accordance with the requirements of 10 CFR 50.55a 

and uses ASME Code Section XI, Subsection IWF, 1998 Edition through the 2000 Addenda for 

the current inspection interval.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.S3. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.S3, with the 

exception of the ―scope of the program‖ program element. For this element, the staff determined 

the need for additional clarification, which resulted in the issuance of an RAI.

During its audit, the staff noted that the ―scope of the program‖ program element in the 

applicant‘s program basis document mentioned an augmented program for Class 1, Class 2, 

and Class 3 supports and hangers. The staff noted that the augmented program was 

implemented by the applicant‘s site-specific procedure, as documented in its audit report. 

During its audit, the staff reviewed this procedure and determined that additional information 

was required. By letter dated July 13, 2009, the staff issued RAI B2.1.4-1 requesting that the 

applicant explain how the additional examination requirements of IWF-2430 are satisfied by the 

applicant‘s ASME Section XI, Subsection IWF Program.

In its response dated August 17, 2009, the applicant stated that the surveillance procedure 

examines essentially 100 percent of all required accessible supports and hangers over the 

10-year interval, as compared to the ASME Code Section XI, Table IWF-2500-1 requirement to 

examine 25 percent of Class 1 piping supports, 15 percent of Class 2 piping supports, and 

10 percent of Class 3 piping supports during inspection intervals (i.e., every 10 years). The 

applicant further stated that this practice of an expanded number of examinations provides the 

opportunity to envelop any additional examinations that may be required by IWF-2430 (a), (b), 

(c), and (d). However, the applicant stated that if the examinations performed in accordance 

with the surveillance procedure do not encompass the requirements of IWF-2430 (a), (b), (c), 

and (d), additional examinations are incorporated into the program to satisfy IWF-2430 

requirements. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.4-1 acceptable because

the augmented program specified in the applicant‘s surveillance procedure does not supersede 

or modify the requirements to determine and perform additional examinations of supports 

required to satisfy ASME Code Section XI, IWF-2430. The staff‘s concern described in 

RAI B2.1.4-1 is resolved.

The staff also reviewed the portions of the ―scope of the program‖ program element associated 

with an exception to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff‘s evaluation of this exception follows.
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Exception. LRA Section B2.1.4 states an exception to the ―scope of the program‖ program 

element. The applicant stated that its program is based on the ASME Code Section XI, 

1998 Edition through 2000 Addenda. The applicant further stated that this code edition is 

different than the code edition identified in GALL AMP XI.S3, which specifies the use of the 

ASME Code Section XI, 2001 Edition through the 2003 Addenda. The applicant stated that the 

use of the ASME Code Section XI, 1998 Edition through 2000 Addenda is consistent with 

provisions in 10 CFR 50.55a to use the code that is in effect 12 months prior to the start of an 

inspection interval. Additionally, the applicant compared the 1998 Edition with the 2001 Edition 

and identified no technical differences. 

The staff noted that the ASME Code Section XI edition referenced by the applicant was 

previously approved under 10 CFR 50.55a for the 10-year interval. The staff further noted that 

the use of the 1998 Edition through the 2000 Addenda of the ASME Code is consistent with the 

provisions in 10 CFR 50.55a to use the code in effect 12 months prior to the start of the 

inspection interval. Based on its review, the staff finds this exception acceptable because: 

(1) the applicant follows the provisions of 10 CFR 50.55a, (2) no technical differences were 

identified between the requirements of the 1998 and 2001 Code Editions, and (3) the applicant 

is following a staff-approved ASME Code Section XI code edition and will update the code prior 

to the start of the next inspection interval, in accordance with 10 CFR 50.55a.

Based on its audit and review of the applicant‘s response to RAI B2.1.4-1, the staff finds that 

elements one through six of the applicant‘s ASME Section XI, Subsection IWF Program, with an 

acceptable exception, are consistent with the corresponding program elements of GALL 

AMP XI.S3 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.4 summarizes OE related to the ASME Section XI, 

Subsection IWF Program. The applicant stated that minor conditions, such as improper spring 

can settings and degraded pipe hangers, have been identified and corrected. During its audit, 

the staff had a difficult time verifying that the required additional examinations per IWF-2430 

were being conducted. By letter dated July 13, 2009, the staff issued RAI B2.1.4-1 in relation to 

this issue. The staff‘s review and acceptability of RAI B2.1.4-1 is documented above.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the OE related to the 

applicant‘s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program, and that implementation of the program has 

resulted in the applicant taking corrective actions. The staff confirmed that the ―operating 

experience‖ program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable.
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USAR Supplement. LRA Section A2.1.4 provides the USAR supplement for the ASME 

Section XI, Subsection IWF Program. The staff reviewed this USAR supplement description of 

the program and finds that it conforms to the recommended description for this type of program 

as described in SRP-LR Table 3.5-2.

The staff 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 Section XI, 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 the LRA credits it. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions 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 Bolting Integrity Program

Summary of Technical Information in the Application. LRA Section B2.1.5 describes the existing 

Bolting Integrity Program as consistent, with an enhancement, with GALL AMP XI.M18, ―Bolting 

Integrity.‖ The applicant stated that the Bolting Integrity Program manages the aging effects of 

cracking, loss of material, and loss of preload for bolting and fasteners by incorporating NRC 

and industry recommendations in NUREG-1339, ―Resolution of Generic Safety Issue 29: Bolting 

Degradation or Failure in Nuclear Power Plants‖; EPRI TR-104213, ―Bolted Joint Maintenance & 

Applications Guide‖; and EPRI NP-5769, ―Degradation and Failure of Bolting in Nuclear Power 

Plants.‖ The applicant also stated that the program addresses: (1) proper assembly of bolted 

joints; (2) procurement, receipt, and storage of bolting materials; and (3) training of plant 

personnel. The applicant further stated that the program addresses bolting associated with 

pressure boundary, mechanical, and high-strength applications for component supports.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M18. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding elements of GALL 

AMP XI.M18 with the exception of the ―preventive actions,‖ ―parameters monitored or 

inspected,‖ and ―detection of aging effects‖ program elements. For these elements, the staff 

determined the need for additional clarification, which resulted in the issuance of RAIs, as 

discussed below.

GALL AMP XI.M18 recommends that high-strength bolting used in nuclear steam supply system 

(NSSS) component supports be monitored for stress-corrosion cracking (SCC) under the 

―parameters monitored or inspected‖ program element description; however, the applicant‘s 

Bolting Integrity Program is not clear in how it monitors high-strength bolts for SCC. By letter 

dated July 13, 2009, the staff issued RAI B2.1.5-4 requesting that the applicant provide further 

justification regarding the applicability of SCC for high-strength bolts, and why exclusion of the 
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management of SCC for high-strength bolting is not identified as an exception to the GALL 

Report recommendation.

In its response dated August 17, 2009, the applicant stated that the high-strength bolting used in 

the RCP connections are hand tightened and, therefore, do not experience tensile stress 

required for SCC. The applicant also stated that the steam generator footbolts are manufactured 

with a material that is resistant to SCC, are not subject to a corrosive environment, and 

experience low tensile stress. The applicant concluded that these high-strength bolts are not 

susceptible to SCC and, therefore, do not require aging management. The staff reviewed the 

response to RAI B2.1.5-4 and determined that the applicant did not provide sufficient 

information for the staff to determine whether residual stresses existed from fabrication, 

installation, or operation that may contribute to the possibility for SCC. By letter dated 

August 28, 2009, the staff issued RAI B2.1.5-5 requesting that the applicant provide further 

justification regarding the residual and tensile stresses on the RCP connecting bolts. 

In its response dated September 28, 2009, the applicant stated that the susceptibility for SCC in 

the RCP connecting bolts could not be definitively ruled out and, therefore, the applicant would 

take an exception to GALL AMP XI.M18. The staff‘s evaluation of the exception is included in 

the ―exception‖ section below. 

GALL AMP XI.M18 recommends selection of bolting material and the use of lubricants and 

sealants, as well as proper torquing of the bolts and checking for uniformity of the gasket 

compression after assembly, under the ―preventive actions‖ program element. This degree of 

detail implies the need for proper training of service and maintenance personnel. The 

applicant‘s Bolting Integrity Program included a training program that is pertinent to proper 

bolting procedures; however, the applicant did not specifically state the frequency of such 

training. By letter dated July 13, 2009, the staff issued RAI B2.1.5-1 requesting that the 

applicant provide additional information on its training programs and frequency, pertinent to the 

Bolting Integrity Program.

In its response dated August 17, 2009, the applicant described the bolting related training for 

mechanical maintenance personnel. The applicant stated that all mechanical maintenance 

personnel receive specific instruction on proper bolting techniques as part of their initial 

qualification training, with continuing training on a quarterly basis and specific refresher training 

conducted on an as-needed basis when performance deficiencies are noted through job 

observations or the corrective action program. The applicant also stated that certain bolting 

issues, such as joint design, material, gasket, and lubricant selection, are completed by 

engineering personnel.

The staff finds the applicant‘s response acceptable because the applicant provided initial and 

continuing training, supplemented by its job observation program. The staff‘s concern described 

in RAI B2.1.5-1 is resolved.

GALL AMP XI.M18 recommends inspections be performed in accordance with the ASME Code 

Section Xl, Tables IWB 2500-1, IWC 2500-1, and IWD 2500-1 editions endorsed in 

10 CFR 50.55a(b)(2) and the recommendations of EPRI NP-5769 under the ―detection of aging 

effects‖ program element. In LRA Section B2.1.5, the applicant did not include which portions of 

the ASME Code Section XI would be used to perform the additional inspections. By letter dated 

July 13, 2009, the staff issued RAI B2.1.5-2 requesting that the applicant provide the specific 

ASME Code section numbers that would be used to perform the additional inspections. 
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In its response dated August 17, 2009, the applicant stated that the inspections would be 

performed in accordance with ASME Code Section XI, Subsections IWB 2500-1, IWC 2500-1, 

IWD 2500-1, and IWF 2500-1 of the 1998 Edition. The staff finds the applicant‘s response 

acceptable because it is consistent with the GALL Report. The staff‘s concern described in 

RAI B2.1.5-2 is resolved.

The staff also reviewed the portions of the ―preventive actions,‖ ―parameters monitored or 

inspected,‖ and ―detection of aging effects‖ program elements associated with an exception and 

enhancement to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff‘s evaluation of this exception and enhancement follows.

Exception. On September 28, 2009, in its response to RAI B2.1.5-5, the applicant stated that an 

exception to the Bolting Integrity Program would be taken. This exception affects the 

―parameters monitored or inspected‖ and ―detection of aging effects‖ program elements. The 

applicant revised the LRA to use only visual inspections, whereas GALL AMP XI.M18

recommends volumetric and visual examinations to detect aging of high-strength bolts. 

The staff noted that the GALL Report ―detection of aging effects‖ program element states that 

high-strength structural bolts and fasteners (actual yield strength greater than or equal to 

150 kilopounds per square inch (ksi)) for NSSS component supports may be subject to SCC, 

and recommends that a volumetric examination comparable to that of ASME Code Section XI 

Examination Category B-G-1 be performed in addition to a visual examination. However, the 

GALL Report further states that this requirement may be waived with adequate plant-specific 

justification. 

The staff noted that the applicant justified this exception by stating that the bolting in question is 

used to provide a connection between the top of the RCP support columns and the pump 

support brackets. The applicant stated that these bolts are hand tightened at each end and are 

not torqued. The staff noted, however, that the applicant could not definitively support the 

conclusion that residual stresses did not exist from the fabrication process. The applicant also 

justified this exception by stating that visual examinations will detect corrosion and conditions 

indicative of a corrosive environment which is a requirement of SCC in high-strength bolting. 

The applicant further justified this exception by stating that detection of corrosion or a corrosive 

environment would result in implementation of the plant‘s corrective action program, which 

would lead to corrective actions potentially including volumetric examination, hammer testing, or 

other appropriate measures. The staff noted, however, that the applicant did not provide the 

type of material being used for the threaded bar and its manufacturing process, so that the staff 

could evaluate the plant-specific justification. By letter dated November 20, 2009, the staff 

issued RAI B2.1.5-6 requesting that the applicant provide the type of material being used for the 

threaded bar and how it was manufactured. 

In its response dated December 28, 2009, the applicant stated that the material from which the 

fastener was manufactured is Vascomax 300 (CVM) maraging steel. The applicant also stated 

that specific processes were used to ensure minimization of residual stresses and defects 

including: (1) heat treatment by slow heating to 900 °F, holding at 3 hours and then air cooling; 

(2) stress equalizing and nitrogen baking after fabrication; (3) application and baking of first 

bonded coating; and (4) ultrasonic examination in the axial direction prior to machining.

The staff finds the applicant‘s response acceptable because it provided assurance that the 

material was manufactured in a manner which considered the potential for residual stresses and 
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SCC, and the materials used are moderately corrosion resistant and resist SCC. The staff‘s 

concerns described in RAIs B2.1.5-4, B2.1.5-5, and B2.1.5-6 are resolved.

However, the staff noted that the applicant‘s response to RAI B2.1.5-5 did not provide 

justification for why the steam generator footbolts are not susceptible to SCC. By letter dated 

March 11, 2010, the staff issued RAI B2.1.5-7 requesting that the applicant provide justification 

for why the steam generator footbolts are noted in LRA Table 3.5.2-15, footnote 4, as not 

subject to SCC, and why no AMP is credited to manage the effects of aging on the footbolts.

In its response dated March 26, 2010, the applicant stated that the steam generator footbolts 

are constructed of Carpenter Custom 455 stainless steel, which has good corrosion resistance 

to atmospheric conditions and has been tested in salt spray and chloride solution environments 

to maintain its resistance to SCC. The applicant also stated that the steam generator footbolts 

are located above the containment floor and exposed to containment atmosphere, which 

contains little or no corrosive contaminants. The applicant further stated that the steam 

generator footbolts have low preload because they are snug-tight and that it has no 

high-strength structural bolting with a diameter greater than 1 inch, other than the RCP support 

bolts and steam generator footbolts discussed above. 

The staff finds the applicant‘s response acceptable because: (1) the construction material for 

the steam generator footbolts has been tested in adverse environments and shown to maintain 

good resistance to SCC, (2) the footbolts are not in a corrosive environment, and (3) the 

footbolts are subject to low tensile stress. The staff‘s concern described in RAI B2.1.5-7 is 

resolved.

With the information provided in the applicant‘s RAI responses, the staff finds the program 

exception acceptable because the applicant‘s inspection process is consistent with the GALL 

Report recommendations, and the applicant‘s justification is an adequate plant-specific 

justification for a waiver of this recommendation. 

Enhancement. LRA Section B2.1.5 states an enhancement to the ―preventive actions‖ program

element to further incorporate applicable EPRI and industry bolting guidance, including proper 

joint assembly, torque values, gasket types, use of lubricants, and other bolting fundamentals.

The staff noted that the enhancement does not cite a specific EPRI document or the details of 

the specific changes that will be made. This raises the question of whether or not EPRI 

guidance relied upon by the applicant is consistent with the GALL Report. The staff determined 

that additional information was needed to complete its review. By letter dated July 13, 2009, the 

staff issued RAI B2.1.5-3 requesting that the applicant provide the specific EPRI document 

related to this enhancement so that the staff can complete its review.

In its response dated August 17, 2009, the applicant stated that information in EPRI NP-5067, 

―Good Bolting Practices Volume 1: Large Bolt Manual‖; EPRI NP-5067, ―Good Bolting Practices 

Volume 2: Small Bolt Manual‖; EPRI TR-104213, ―Bolted Joint Maintenance and Application 

Guide‖; EPRI 1015336, ―Bolted Joint Fundamentals‖; and EPRI 1015337, ―Assembling 

Gasketed, Flanged Bolted Joints,‖ will be included in the Bolting Integrity Program.

The staff noted that although EPRI NP-5067 is not specifically listed as a technical reference in 

GALL AMP XI.M18, the GALL Report does include EPRI NP-5769 as a technical reference. 

EPRI NP-5769 states, ―It is believed that the bolting reference manuals [EPRI NP-5067, 

Volumes 1 and 2] will satisfy the industry‘s need for guidance in this area [which is bolted 
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joints].‖ Additionally, the staff evaluated a comparison of the two documents dated April 1, 2005 

(Agencywide Document Access and Management System (ADAMS) Accession ML051020128), 

and finds that the two documents are very closely related and cross-reference one another, in 

addition to referencing NUREG-1339, with no contradictions. Furthermore, the staff noted that 

EPRI 1015336 and EPRI 1015337 are also not listed as technical references in the GALL 

Report AMP. These EPRI reports are consolidations of various bolting related EPRI reports 

including EPRI NP-5067, Volumes 1 and 2, which were previously evaluated for consistency, 

and EPRI TR-104213, which is specifically referenced in the GALL Report. The staff further 

compared EPRI 1015336 and EPRI 1015337 with the requirements of the GALL Report AMP 

and finds no contradictions.

The staff finds the applicant‘s response to RAI B2.1.5-3 and this enhancement acceptable 

because it is consistent with the recommendations of the GALL Report. The staff‘s concern 

described in RAI B2.1.5-3 is resolved.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.5-1, B2.1.5-2, B2.1.5-3, 

B2.1.5-4, B2.1.5-5, B2.1.5-6, and B2.1.5-7, the staff finds that elements one through six of the 

applicant‘s Bolting Integrity Program, with an acceptable exception and enhancement, are 

consistent with the corresponding program elements of GALL AMP XI.M18 and are, therefore, 

acceptable.

Operating Experience. LRA Section B2.1.5 summarizes OE related to the Bolting Integrity 

Program. The applicant cited three examples where corroded bolts were discovered during 

inspections, evaluated, and appropriately dispositioned as part of the corrective action program. 

In two of the instances, the applicant stated that although the requirements of the AMP and 

plant procedures found these worn and damaged studs acceptable, they were replaced as an 

enhanced measure to assure structural integrity. During the audit, the staff noted that a 

condition report indicated that in April 2008, one of four bolts was found missing from the 

support stand for a portion of one steam generator‘s flow instrument tubing. The staff also noted 

that the problem was identified as a potential compromise to the structural integrity of the stand; 

however, the structural integrity was re-examined by structural design engineers, who 

determined that the joint still satisfied applicable design criteria. The staff further noted that 

these reports and others like them confirmed that the plant-specific OE did not reveal any 

degradation not bounded by industry experience and demonstrated that proper corrective 

actions are taken to address bolting issues. 

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking 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 

and, therefore, the staff finds it acceptable.
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USAR Supplement. LRA Section A2.1.5 provides the USAR supplement for the Bolting Integrity 

Program. The staff reviewed this USAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Tables 3.1-2, 3.2-2, 3.3-2, 3.4-2, and 3.5-2.

The staff also notes that the applicant committed (Commitment No. 3) to enhance the Bolting 

Integrity Program prior to the period of extended operation. Specifically, the applicant committed 

to further incorporate applicable EPRI and industry bolting guidance by including information on 

proper joint assembly, torque values, gasket types, use of lubricants, and other bolting 

fundamentals. 

The staff 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 Program, 

including the applicant‘s response to the RAIs, the staff concludes that the applicant has 

demonstrated 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 

the LRA credits it. Also, the staff has reviewed the enhancement and confirmed that the 

implementation of the enhancement through Commitment No. 3, prior to the period of extended 

operation, would result in the existing AMP being consistent with the GALL Report 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 functions of these components 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).

3.0.3.2.4 Buried Piping and Tanks Inspection Program

Summary of Technical Information in the Application. LRA Section B2.1.7 describes the existing 

Buried Piping and Tanks Inspection Program as consistent, with exceptions and an 

enhancement, with GALL AMP XI.M34, ―Buried Piping and Tanks Inspection.‖ The applicant 

stated that the program manages the aging effect of loss of material from the external surfaces 

of buried steel piping and tanks. The applicant also stated that it has expanded the program to 

include stainless steel piping and tanks. The applicant further stated that the program manages 

the aging effect through the use of preventive measures, such as coating and/or wrapping the 

buried material, and through the use of condition monitoring measures, including opportunistic 

and deliberate visual inspections.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff compared 

elements one through six of the applicant‘s program to the corresponding elements of GALL 

AMP XI.M34. As discussed in the Audit Report, the staff confirmed that each element of the 

applicant‘s program is consistent with the corresponding element of GALL AMP XI.M34, with the 

exception of the ―scope of the program‖ and ―parameters monitored or inspected‖ program 

elements. For these elements, the staff determined the need for additional clarification, which 

resulted in the issuance of RAIs.
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The GALL AMP XI.M34 program description includes only buried steel piping and tanks; 

however, during its audit, the staff found that the applicant‘s Buried Piping and Tanks Inspection 

Program ―scope of the program‖ program element includes both steel and stainless steel piping 

and tanks. By letter dated July 13, 2009, the staff issued RAI B2.1.7-1 requesting that the 

applicant revise the LRA AMP to reflect that the inclusion of stainless steel in the scope of the 

LRA AMP constitutes an exception to the GALL Report AMP. The applicant was also requested 

to clarify whether the stainless steel piping present at the plant was coated or uncoated. 

In its response dated August 17, 2009, the applicant modified the LRA AMP ―scope of the 

program‖ program element to show the inclusion of stainless steel piping as an exception to the 

GALL Report AMP. The applicant stated that the stainless steel piping under consideration is a 

vent line which was installed in 2003, consisting of approximately 30 feet of 2-inch nominal 

ASTM A-312 schedule 80 coated and wrapped pipe, all of which is buried except for about 

3 feet. The applicant also stated its failure was highly unlikely due to the limited amount of 

buried piping, the design requirements of the piping (i.e., atmospheric service), the recent

installation, and the planned inspections.

The staff finds this response acceptable because the applicant has: (1) appropriately modified 

the LRA to reflect the inclusion of stainless steel piping as an exception to the GALL Report 

AMP; and (2) demonstrated that, through the design of the piping and the planned inspections, 

the LRA AMP will provide aging management which is at least equivalent to that provided by the 

GALL Report AMP, and thus the applicant‘s program is consistent with GALL AMP XI.M34. The 

staff‘s concern described in RAI B2.1.7-1 is resolved.

GALL AMP XI.M34 recommends the use of coatings and wrappings under the ―parameters 

monitored or inspected‖ program element description; however, during its audit, the staff found 

the program includes uncoated steel tank hold down straps. By letter dated July 13, 2009, the 

staff issued RAI B2.1.7-2 requesting that the applicant revise the LRA AMP to reflect that the 

inclusion of uncoated steel piping or tanks constitutes an exception to the GALL Report AMP.

In its response dated August 17, 2009, the applicant modified the LRA AMP ―scope of the 

program,‖ ―preventive actions,‖ ―parameters monitored or inspected,‖ and ―detection of aging 

effects‖ program elements to show the inclusion of uncoated steel. The applicant stated that the 

hold down straps for the EDG fuel oil tanks are the only uncoated steel material managed by 

this program. The applicant also stated that these straps are inspected when the exterior of the 

fuel tank is inspected. The applicant further stated that the straps will be inspected prior to 

entering the period of extended operation, and an engineering evaluation will be performed to 

determine whether additional periodic inspections will be required during the period of extended 

operation based on evidence of loss of material. 

The staff finds the applicant‘s response to this RAI acceptable because: (1) the applicant has 

appropriately identified the use of uncoated steel as an exception to the GALL Report AMP, 

(2) the straps will be inspected prior to entering the period of extended operation, and (3) an

engineering evaluation will be performed to determine appropriate inspection intervals based on 

loss of material. 

The staff also reviewed the portions of the ―scope of the program,‖ ―preventive actions,‖ 

―parameters monitored or inspected,‖ and ―detection of aging effects‖ program elements 

associated with exceptions and an enhancement to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff‘s evaluation of these 

exceptions and enhancement follows.
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Exception 1. LRA Section B2.1.7 states an exception to the ―scope of the program‖ program 

element. This exception and staff evaluation are discussed above in RAI B2.1.7-1.

Exception 2. LRA Section B2.1.7 states an exception to the ―scope of the program,‖ ―preventive 

actions,‖ ―parameters monitored or inspected,‖ and ―detection of aging effects‖ program 

elements. This exception and staff evaluation are discussed above in RAI B2.1.7-2.

Enhancement. LRA Section B2.1.7 states an enhancement to the ―parameters monitored or 

inspected‖ and the ―detection of aging effects‖ program elements. The applicant stated that an 

inspection of a representative sample of in-scope buried material and protective measure 

combinations will be accomplished through the use of opportunistic and deliberate inspections 

during the 10 years preceding, and the 10 years following, the beginning of the period of 

extended operation.

The staff reviewed this enhancement against the corresponding program elements in GALL 

AMP XI.M34. On the basis of its review, the staff finds this enhancement acceptable because 

when it is implemented prior to the period of extended operation, the program inspection 

frequencies will be consistent with the recommendations in GALL AMP XI.M34. 

Based on its audit and review of the applicant‘s responses to RAIs B2.1.7-1 and B2.1.7-2, the 

staff finds that elements one through six of the applicant‘s Buried Piping and Tanks Inspection 

Program, with acceptable exceptions and an enhancement, are consistent with the 

corresponding program elements of GALL AMP XI.M34 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.7 summarizes the OE related to the Buried Piping and 

Tanks Inspection Program. The applicant stated that it conducted an inspection of a fire water 

system header based on observed degradation in a potable water pipe that was of similar 

design and construction. The applicant also stated that it found the fire water system header 

was in generally good condition. 

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no plant OE to indicate that the 

applicant‘s program would not be effective in adequately managing aging effects during the 

period of extended operation; however, the staff noted a number of recent industry events 

involving radioactive fluid leakage from buried and underground piping and tanks. In light of this 

recent industry OE, the staff is concerned about the continued susceptibility to failure of 

in-scope buried or underground piping. In reviewing the applicant‘s Buried Piping and Tanks 

Inspection and the External Surfaces Monitoring programs, along with the applicable AMR items 

associated with them, the staff is not clear whether: (1) the components addressed by these

AMPs clearly include both buried and underground piping (piping which is below grade and 

contained in a vault or other structure where it is exposed to air and where access is limited),

and (2) whether these programs are being updated to incorporate lessons learned from these 

recent events as well as any OE from the applicant‘s own history.

By letter dated May 27, 2010, the staff issued RAI B2.1.7-3 requesting that the applicant 

address these issues. The staff identified this as Open Item 3.0.3.2.4-1. 
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In its response dated July 22, 2010, the applicant stated that no leaks have been discovered in 

in-scope buried or underground piping during the past 5 years, although an area of degraded 

piping with surface degradation and irregularities was found in the transition zone between the 

buried and aboveground portions of the diesel fuel oil day tank vent piping during modification 

work in the area. The applicant stated that this was caused by approximately 2 feet of the pipe 

in this zone not being coated or wrapped. The applicant also stated that an extent of condition

inspection of two similar locations demonstrated that coatings and wrappings were installed. 

The applicant further stated that: (1) components that are located below grade in a vault are 

inspected by the External Surfaces Monitoring Program; (2) cathodic protection is provided for 

buried portions of the circulating water system and 400 of the 500 feet of buried fuel oil piping, 

and National Association of Corrosion Engineers (NACE) surveys of the cathodic protection 

system are conducted; (3) with the exception of the one instance of the diesel fuel oil vent 

piping, coatings have been found to be in good condition; (4) during excavations, backfill in the 

vicinity of buried piping has been found to be a proper bedding of sand and gravel as specified;

(5) direct visual inspections of at least 10 linear feet of excavated piping will be conducted for 

the steel portions of the circulating water system, stainless steel portions of the circulating water 

system, steel portions of the diesel fuel oil piping, and three inspections of at least 10 linear feet 

of piping each for the ductile iron fire protection system; and (6) one of three of the fuel oil 

storage tanks along with its hold down straps will be inspected in each 10-year period of 

inspections. Based on its review, the staff determined that it did not have sufficient information 

to find the applicant‘s response acceptable. 

In a letter dated September 10, 2010, the staff issued follow-up RAI B2.1.7-3a requesting that 

the applicant: (1) provide a commitment to maintain the cathodic protection system available 

90 percent of the time; (2) provide a commitment to perform annual NACE cathodic protection 

surveys; (3) discuss any enhancements that may be developed for the 100 feet of buried fuel oil 

piping that are not cathodically protected and clarify that a buried piping inspection will occur in 

this portion of the system; and (4) clarify the program commitment to also include buried piping 

inspections in the 50–60 year period of plant operation.

In its response dated September 23, 2010, the applicant stated that: (1) the goal for availability 

of the cathodic protection system is 100 percent and that a minimum of 90 percent will be met; 

(2) cathodic protection surveys will be conducted on at least an annual basis; (3) it has no 

current plans to cathodically protect the 100 feet of buried fuel oil piping; however, an inspection 

of the non-cathodically protected pipe will be performed; and (4) the buried pipe inspections will 

be repeated during the second 10-year period of extended operation.

Based on a review of plant-specific OE, the staff notes that there have been no failures in the 

applicant‘s buried, in-scope piping. The staff also notes that the circulating water, fire protection, 

and diesel fuel oil systems have buried piping. The staff finds the applicant‘s responses 

acceptable because: (1) components that are located below grade in a vault are inspected by 

the External Surfaces Monitoring Program; (2) the applicant‘s cathodic protection system will be

available 90 percent of the time and annual NACE survey testing will be conducted during the 

period of extended operation; (3) coatings were applied on buried steel piping; 

(4) recently-conducted inspections of excavated fire protection and diesel generator fuel oil 

piping demonstrate that coatings are in very good condition; (5) during excavations, backfill has 

been found to be acceptable; (6) the applicant has committed to conduct direct visual 

inspections of at least 10 linear feet of excavated piping for the steel portions of the circulating 

water system, stainless steel portions of the circulating water system, steel portions of the diesel 

fuel oil piping, and three inspections of at least 10 linear feet of piping each for the ductile iron 

fire protection system each 10-year period starting 10 years prior to the period of extended 
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operation; (7) the non-cathodically protected 100 feet of buried diesel fuel oil piping will be 

inspected; and (8) one of three of the fuel oil storage tanks along with its hold down straps will 

be inspected in each 10-year period of extended operation.

The staff notes that the applicant has no current plans to cathodically protect the 100 feet of 

buried in-scope diesel fuel oil piping; however, the staff finds this acceptable because, based on 

information provided in the response to RAI B2.1.7-3, site-specific conditions and planned 

inspections are adequate to be consistent with paragraph 3.2, ―Determination of Need for 

External Corrosion Control,‖ from NACE Standard SP-169-2007, ―Control of External Corrosion 

on Underground or Submerged Metallic Piping Systems,‖ for the following reasons: 

 (1) Based on inspections of portions of the fire protection piping and 17 percent of the 

cathodically-protected diesel fuel oil piping, the coatings were in good condition. 

 (2) Backfill in the vicinity of buried piping has been found to be a proper bedding of sand 

and gravel as specified. 

 (3) Only surface degradation and irregularities were detected in the uncoated fuel oil vent 

piping at the soil-to-air interface. 

 (4) The applicant has committed to inspect 10 percent of the non-cathodically protected 

piping.

 (5) Based on staff walkdowns conducted during the audit, soil conditions are similar along 

the entire length (i.e., cathodically and non-cathodically protected) of the diesel fuel oil 

piping and, therefore, corrosion rates would be expected to be similar. 

The staff‘s concerns described in RAIs B2.1.7-3 and B2.1.7-3a are resolved, and Open 

Item 3.0.3.2.4-1 is closed.

USAR Supplement. LRA Section A2.1.7 provides the USAR supplement for the Buried Piping 

and Tanks Inspection Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2. The staff also notes that the applicant 

committed (Commitment Nos. 4 and 48) to enhance the Buried Piping and Tanks Inspection 

Program prior to entering the period of extended operation. Specifically, the applicant committed 

to enhance the program to: (a) maintain its cathodic protection system available 90 percent of 

the time and conduct annual NACE survey testing; (b) conduct direct visual inspections of at 

least 10 linear feet of the excavated steel portions of the circulating water system, stainless 

steel portions of the circulating water system, steel portions of the diesel fuel oil piping, and 

three inspections of at least 10 linear feet of piping each for the ductile iron fire protection 

system each 10-year period starting 10 years prior to the period of extended operation;

(c) inspect the non-cathodically protected 100 feet of buried diesel fuel oil piping; and (d) inspect 

one of three of the fuel oil storage tanks along with its hold down straps in each 10-year period. 

The staff 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 determines that the program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff also reviewed the two 

exceptions associated with the ―scope of the program,‖ ―preventive actions,‖ ―parameters 
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monitored or inspected,‖ and ―detection of aging effects‖ program elements, and their

justifications, and determines that the AMP, with the exceptions, is adequate to manage the 

aging effects for which the LRA credits it. In addition, the staff reviewed the enhancement and 

confirmed that its implementation through Commitment Nos. 4 and 48, prior to the period of 

extended operation, would make the existing AMP consistent with the GALL Report 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 functions 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 Closed-Cycle Cooling Water System Program

Summary of Technical Information in the Application. LRA Section B2.1.8 describes the existing 

Closed-Cycle Cooling Water System Program as consistent, with exceptions, with GALL 

AMP XI.M21, ―Closed-Cycle Cooling Water System.‖ The applicant stated that this program 

manages the aging effects of cracking, loss of material, and reduction of heat transfer for the 

steel, stainless steel, and copper alloys in the piping, heat exchangers, and other components in 

the component cooling system, EDG cooling water subsystems, and control room air 

conditioning system. The applicant stated that this program establishes appropriate corrosion 

strategies and chemistry specifications, including the use of inhibitors, for each of the 

closed-cycle cooling water systems in the plant, based on EPRI TR-1007820, ―Closed Cooling 

Water Chemistry Guideline,‖ Revision 1. The applicant also stated that performance monitoring,

including system operation monitoring, system testing, heat exchanger thermal performance 

testing, heat exchanger tube eddy current testing, and pump performance testing, is used to 

verify the effectiveness of the chemistry controls in this program. The applicant further stated 

that a plant-specific WCP Program is used to provide additional verification of the program‘s 

effectiveness. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M21. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M21, with the exception of the ―parameters monitored or inspected‖ and ―monitoring 

and trending‖ program elements. For these elements, the staff determined the need for 

additional clarification, which resulted in the issuance of an RAI.

During its audit, the staff reviewed the applicant‘s program basis document and accompanying 

documentation, including relevant chemistry, system operating, and administrative procedures. 

The staff noted that the ―parameters monitored or inspected‖ and ―monitoring and trending‖ 

program elements in the applicant‘s program did not specify a monitoring frequency for nitrate 

levels in the component cooling water system, which uses a nitrite-molybdate corrosion control 

program. The staff further noted that EPRI TR-1007820, ―Closed Cooling Water Chemistry 

Guideline,‖ Revision 1, specifies that nitrate levels for such systems be monitored on a monthly 

basis for both Tier 1 and Tier 2 systems. By letter dated July 13, 2009, the staff issued 

RAI B2.1.8-3 requesting that the applicant provide a justification for not performing monthly 

monitoring of the nitrate levels in the closed-cycle cooling water system. 
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In its response dated August 17, 2009, the applicant stated that as an alternative to the monthly 

monitoring of nitrate levels recommended by EPRI TR-1007820, the applicant monitors nitrite 

levels on a monthly basis and ammonia levels on a quarterly basis. The applicant also stated 

that these monitoring activities verify chemistry stability and verify that unacceptable levels of 

nitrites, which would be produced by nitrifying bacteria, are not present in the closed-cycle 

cooling water system. The staff noted that in nitrite-treated systems, nitrates are produced by 

nitrifying bacteria, while ammonia and nitrogen gas are produced by denitrifying bacteria. 

Furthermore, either or both of these bacteria types may be present in a closed water system, 

and the absence of one type does not necessarily indicate the absence of the other. The staff 

noted that the periodic sampling for ammonia may be used to verify the absence or control of 

denitrifying bacteria, but it provides no assurance that nitrifying bacteria are not present. For this 

reason, EPRI TR-1007820 recommends monitoring for both nitrates and ammonia on a monthly 

basis for Tier 1 and 2 systems.

Based on its review, the staff found the applicant‘s response to RAI B2.18-3 unacceptable. 

Therefore, by letter dated December 16, 2009, the staff issued follow-up RAI B2.1.8-3a 

requesting that the applicant justify how current monitoring procedures provide assurance that 

excessive levels of nitrifying bacteria are not present in the closed water system. In its response 

dated January 21, 2010, the applicant stated that, upon review of EPRI TR-1007820, it had 

determined that monitoring for nitrates through the Closed-Cycle Cooling Water System 

Program would provide improved ability to identify the presence of nitrifying bacteria in the 

component cooling system. The applicant stated that, as a result, nitrate monitoring will be 

implemented on a frequency consistent with the existing monitoring for ammonia. By letter 

dated January 21, 2010, the applicant committed (Commitment No. 40) to implement this 

change in its monitoring procedure.

Based on its review, the staff finds the applicant‘s responses to RAIs B2.1.8-3 and B2.1.8-3a 

acceptable because the applicant has committed (Commitment No. 40) to implement nitrate 

monitoring on a frequency consistent with the quarterly monitoring for ammonia. The staff finds 

that monthly monitoring for (decreases in) nitrites, along with quarterly monitoring for nitrates 

and ammonia, is acceptable in regards to EPRI TR-1007820 for the following reasons: 

(1) although the report recommends monthly samples for both nitrates and ammonia, Chapter 5 

of the report allows deviating from these recommendations as long as there is a technical basis; 

(2) Table 5-3 of TR-1008720 states that nitrate and ammonia concentrations are not control 

parameters but rather parameters used for trending; and (3) the applicant has demonstrated the 

ability to identify biological activity as indicated by plant-specific OE cited in LRA Section B2.1.8, 

which describes an October 2006 example where possible biological activity was detected by 

sampling for adenosine triphosphate (ATP) levels. The staff‘s concerns described in 

RAIs B2.1.8-3 and B2.1.8-3a are resolved.

The staff also reviewed the portions of the ―preventive actions‖ and ―parameters monitored or 

inspected‖ program elements associated with the exceptions to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff‘s evaluation of 

these exceptions follows.

Exception 1. LRA Section B2.1.8 states an exception to the ―preventive actions‖ program 

element. The applicant stated that corrosion inhibitors are not used in the control room air 

conditioning system because this system interconnects with the service water system, which 

provides an alternate safety-related cooling mode. The applicant stated that periodic testing of 

this mode would release any inhibitors to the environment. The applicant also stated that, in lieu 

of the use of corrosion inhibitors, the system is periodically sampled to verify system integrity. 
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The applicant further stated that periodic visual inspections of system components are 

performed under the WCP Program.

The staff noted that EPRI TR-1007820 allows for the operation of closed cooling water systems 

without the addition of inhibitors, provided proper water chemistry is maintained. Specifically, the 

staff noted that EPRI TR-1007820 states that control of dissolved oxygen is particularly 

important for systems containing copper or copper alloys. The report recommends that 

dissolved oxygen either be maintained at less than 100 ppb to stabilize the cuprous oxide film 

on component surfaces or that it be maintained at greater than 2,000 ppb to stabilize the cupric 

oxide film. The staff also noted that operation at dissolved oxygen levels between these two 

limits is specifically warned against, since it results in alternate formation and breakdown of the 

two oxides, resulting in the loss of the protective film. The staff noted that the applicant does not 

state the limits on dissolved oxygen levels in the control room air conditioning system or in 

which of the two EPRI-recommended dissolved oxygen level regimes this system operates.

By letter dated December 3, 2009, the staff issued RAI B2.1.8-4 requesting that the applicant 

clarify the limits on dissolved oxygen levels in the control room air conditioning system and 

specify in which of the two EPRI-recommended dissolved oxygen level regimes this system 

operates. The staff also requested that if the limits on dissolved oxygen in the control room air 

conditioning system are not maintained within the levels that are recommended by EPRI 

TR-1007820, the applicant needs to provide further details on how inspection procedures under 

the applicant‘s WCP Program are used to verify that corrosion of copper alloy components does 

not occur. The staff also requested that the applicant include information on water sampling for 

the presence of dissolved and/or suspended copper indicative of copper alloy corrosion. 

In its response dated January 21, 2010, the applicant stated that the dissolved oxygen level in 

the control room air conditioning system is not monitored. The applicant stated that the water 

chemistry parameters monitored for the system, in accordance with the Closed-Cycle Cooling 

Water System Program, include ATP, conductivity, copper, iron, pH, and suspended solids. The 

applicant stated that the acceptance criteria for these parameters are consistent with EPRI 

TR-1007820. The applicant stated that to verify that degradation of the copper alloy components 

is not occurring, the control room air conditioning system will be subject to inspection under the 

applicant‘s one-time inspections portion of its WCP Program as confirmation of the 

effectiveness of the Closed-Cycle Cooling Water System Program. The applicant also stated 

that this will include NDE techniques (e.g., visual and/or volumetric examinations) to detect the 

aging effects in the copper alloys in the system. The applicant further stated that this 

combination of routine monitoring for copper content in the control room air conditioning system 

cooling water and one-time inspection of the subject copper alloy components ensures that the 

system is not experiencing significant corrosion of copper alloy components. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.8-4 acceptable because 

the water chemistry parameters monitored by its Closed-Cycle Cooling Water System Program 

and the one-time inspection performed under its WCP Program are capable of ensuring 

significant corrosion of copper alloy components in the control room air conditioning system is 

not occurring. The staff‘s concern described in RAI B2.1.8-4 is resolved.

Exception 2. LRA Section B2.1.8 states an exception to the ―preventive actions‖ program 

element. The applicant stated that its program is implemented using EPRI TR-1007820, ―Closed 

Cooling Water Chemistry Guideline,‖ Revision 1 (2004), rather than the original revision of this 

report, EPRI TR-107396 (1997) as recommended by GALL AMP XI.M21. The applicant stated 

that the updated EPRI report provides for prescriptive guidance and has a more conservative 
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monitoring approach. The applicant also stated that EPRI TR-1007820 meets the same 

requirements as EPRI TR-107396 with respect to maintaining corrosion and microbiological 

growth in closed cooling water systems for effectively mitigating many aging effects. The 

applicant further stated that the use of the updated edition of the EPRI report resulted in more 

restrictive chemistry action levels. 

The staff noted that the ―acceptance criteria‖ program element is also impacted by the chemistry 

action levels being more restrictive. By letter dated July 13, 2009, the staff issued RAI B2.1.8-1 

requesting that this exception be revised to indicate that both the ―preventive actions‖ and 

―acceptance criteria‖ program elements are impacted.

In its response dated August 17, 2009, the applicant stated that the ―acceptance criteria‖ 

program element is also impacted by this exception. The applicant amended LRA 

Section B2.1.8, so that this exception states that the ―acceptance criteria‖ program element is 

also impacted and that the implementation of EPRI TR-1007820 results in specific chemistry 

action levels that are more restrictive than those allowed in EPRI TR-107396. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.8-1 acceptable because 

the LRA was amended to clearly and correctly identify the ―acceptance criteria‖ program 

element being impacted by this exception. The staff‘s concern described in RAI B2.1.8-1 is 

resolved.

Based on its review, the staff finds this exception acceptable because the applicant has justified 

the use of the updated report, EPRI TR-1007820, as the basis for its Closed-Cycle Cooling 

Water System Program and has properly identified the program elements impacted by the use 

of this report.

Exception 3. LRA B2.1.8 states an exception to the ―parameters monitored or inspected‖ 

program element. The applicant stated that differential pressure is not monitored as part of the 

thermal performance testing of the component cooling heat exchangers, as recommended by 

GALL AMP XI.M21. The applicant stated that periodic thermal performance and heat exchanger 

tube eddy current testing, and the frequent chemistry sampling of the closed-cycle cooling water 

systems, provide verification that the chemistry controls are preventing tube degradation that 

would affect differential pressure. The applicant further stated that monitoring shell-side inlet 

and outlet temperatures provide an indirect indication that heat exchanger differential pressure 

is not increasing. 

Based on its review, the staff finds this exception acceptable because the alternative 

parameters monitored and inspected by the applicant provide satisfactory verification of heat 

exchanger performance. 

Exception 4. LRA Section B2.1.8 states an exception to the ―parameters monitored or 

inspected‖ program element. The applicant stated that thermal performance testing is not 

performed for the heat exchangers included in the component cooling water system cooling loop 

that are part of the EDG cooling water subsystem heat exchangers and lube oil coolers. The 

applicant stated that previous testing had shown that valid results cannot be obtained due to the 

configuration of the heat exchangers. The applicant also stated that corrosion inhibitors prevent 

gross degradation of the heat exchangers and frequent chemistry sampling provides verification 

that these chemistry controls are effective. The applicant further stated that the performance of 

the EDG cooling water subsystem is monitored during the periodic testing of the EDG, and this 

monitoring includes recording heat exchanger inlet and outlet temperature, engine water 
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temperature, and cylinder temperatures. The applicant stated that these data provide adequate 

information to detect heat exchanger degradation. Finally, the applicant stated that the EDG 

cooling water subsystems are periodically drained and flushed, during which time the heat 

exchangers are visually inspected and the tubes cleaned. By letter dated July 13, 2009, the staff 

issued RAI B2.1.8-2 requesting that the applicant indicate the frequency for the periodic flushing 

and inspection and provide a basis for specifying this frequency. The staff also requested that 

the applicant provide information on OE to verify the effectiveness of its program. 

In its response dated August 17, 2009, the applicant stated that only the EDG cooling water 

subsystem heat exchangers and lube oil coolers are periodically inspected and flushed, since 

the remaining heat exchangers in the component cooling system cooling loop that are part of 

other systems are in continuous operation. For these latter heat exchangers, system 

performance, including system flow rates and temperatures, is monitored. The applicant also 

stated that the EDG cooling water subsystem heat exchangers and lube oil coolers are drained 

and flushed every 18 months during refueling outages. The applicant further stated that the raw 

water side of the EDG heat exchangers is cleaned and inspected at that time, and eddy current 

inspection of the tubes is performed. The applicant further stated that no significant performance 

or material degradation in these components has been identified, and that their thermal 

performance is consistent with their required functions. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.8-2 acceptable because 

the applicant provided the requested information, which describes an acceptable alternative to 

thermal performance testing of this portion of the component cooling water system and provides 

adequate assurance that potential component degradation in this portion of the component 

cooling water system is being adequately monitored. The staff‘s concern described in 

RAI B2.1.8-2 is resolved.

Based on its review, the staff finds this exception acceptable because the applicant has 

provided an acceptable alternative to thermal performance testing as a means of monitoring 

potential component degradation in this portion of the closed-cycle cooling water system.

Exception 5. LRA Section B2.1.8 states an exception to the ―parameters monitored or 

inspected‖ program element. The applicant stated that air handling units and pumps in the 

control room air conditioning system are not performance tested as recommended in GALL 

AMP XI.M21. The applicant stated that the control room air conditioning system is in continuous 

operation and system performance is monitored and alarmed in the control room. The applicant 

also stated that the air handling units and pumps are cleaned on a 12-month frequency. The 

applicant further stated that visual inspections of piping, valves, heat exchangers, and other 

component internals under the WCP Program provide a representative sample of the 

material-environment combinations in the systems within the scope of the program. 

Based on its review, the staff finds this exception acceptable because it provides assurance that 

potential component degradation in this portion of the component cooling water system is being 

adequately monitored.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.8-1 and B2.1.8-2, the 

staff finds that elements one through six of the applicant‘s Closed-Cycle Cooling Water System 

Program, with acceptable exceptions, are consistent with the corresponding program elements 

of GALL AMP XI.M21 and are, therefore, acceptable.
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Operating Experience. LRA Section B2.1.8 summarizes OE related to the Closed-Cycle Cooling 

Water System Program. The staff reviewed this information and interviewed the applicant‘s 

technical personnel to confirm that the applicable aging effects and industry and plant-specific 

OE have been reviewed by the applicant. During the audit, the staff independently verified that 

the applicant had adequately incorporated and evaluated OE related to this program.

In the LRA, the applicant cited examples, dating back to 2003, of modifications to procedures 

and possible indications of corrosion in the component cooling water system and EDG cooling 

water subsystem. The applicant summarized the relevant circumstances and corrective actions 

taken for these events. The applicant stated that, for all of these occurrences, the Closed-Cycle 

Cooling Water Program had been effective in managing aging effects by monitoring chemistry 

control parameters and establishing limits for corrective actions.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.8 provides the USAR supplement for the Closed-Cycle 

Cooling Water System Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2.

The staff also notes that the applicant committed (Commitment No. 40), by letter dated 

January 21, 2010, to implement nitrate monitoring for the component cooling system on a 

frequency consistent with the existing monitoring for ammonia.

The staff 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 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 the LRA credits it. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions 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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3.0.3.2.6 Compressed Air Monitoring Program

Summary of Technical Information in the Application. LRA Section B2.1.9, as amended by the 

applicant‘s letter dated November 13, 2009, describes the existing Compressed Air Monitoring 

Program as consistent, with exceptions and an enhancement, with GALL AMP XI.M24, 

―Compressed Air Monitoring.‖ The applicant stated that the program manages the aging effect 

of loss of material for the steel, stainless steel, and copper alloy components in the station and 

instrument air system and the air start subsystems for the EDGs. The program performs air 

quality sampling, visual inspections, and periodic testing to verify the adequacy of the air quality 

and to detect air leakage. The applicant also stated that the program addresses the 

requirements of GL 88-14, ―Instrument Air Supply System Problems Affecting Safety-Related 

Equipment.‖

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M24. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M24, with the exception of the ―scope of the program,‖ ―preventive actions,‖ 

―parameters monitored or inspected,‖ ―detection of aging effects,‖ ―monitoring and trending,‖ and 

―acceptance criteria‖ program elements. For these elements, the staff determined the need for 

additional clarification, which resulted in the issuance of RAIs.

During its audit, the staff noted that the technical basis references of the applicant‘s program did 

not include NRC Information Notice (IN) 81-38, IN 87-28, IN 87-28 Supplement 1, or Institute of 

Nuclear Power Operations Significant Operating Experience Report (INPO SOER) 88-01. The 

staff also noted that the GALL Report recommends that GL 88-14 be augmented by the 

references that were not included in the applicant‘s program. In addition, the staff noted that 

IN 87-28 Supplement 1 transmitted to the applicant by NUREG-1275, Volume 2, ―Operating 

Experience Feedback Report – Air Systems Problems,‖ addresses the concerns related to 

instrument air system failures and recommendations for corrective actions, and INPO 

SOER 88-01 describes the recommendations for operations, training, maintenance, design, and 

analysis to prevent and mitigate instrument air system failures.

By letter dated July 13, 2009, the staff issued RAI B2.1.9-1 requesting that the applicant clarify 

whether or not IN 81-38; IN 87-28; IN 87-28 Supplement 1; NUREG-1275, Volume 2; and INPO 

SOER 88-01 documents are applicable as technical basis references for its program. For 

reference(s) not applicable, the applicant should justify why its approach without the reference is 

adequate for aging management.

In its response dated August 17, 2009, the applicant clarified that the aforementioned technical 

references are applicable to its program and an effort has been initiated to include the 

references in its program basis document as part of the next revision to the program. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.9-1 acceptable because 

the applicant clarified that the technical references are applicable to the program and initiated 

actions to include the references in its program basis documents. The staff‘s concern described 

in RAI B2.1.9-1 is resolved.
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The staff noted that the applicant‘s chemistry procedure for air quality control states an 

inspection frequency of one per year for pressure dew point, but the applicant‘s procedure did 

not specify any ―Action Level‖ for hydrocarbon content or particulate size. In contrast, American 

National Standards Institute (ANSI)/ISA-7.0.01-1996, which is one of the applicant‘s technical 

references, recommends monitoring for pressure dew point each shift if a monitored alarm is not 

available. The staff also noted that the ―Action Level‖ for the dew point was greater than or 

equal to 22 °F in the applicant‘s procedure. By letter dated July 13, 2009, the staff issued 

RAI B2.1.9-2 requesting that the applicant clarify why its inspection frequency for pressure dew 

point is not consistent with the recommendation of ANSI/ISA-7.0.01-1996, although the 

applicant claimed consistency with ANSI/ISA-7.0.01-1996. The staff also requested that the 

applicant clarify why no ―Action Level‖ was specified for hydrocarbon content or particulate size 

in the chemistry procedure.

In its response dated August 17, 2009, the applicant clarified that the pressure dew point for the 

instrument air system is monitored and recorded each shift during plant operator rounds using 

the installed in-line dew point monitor. The applicant also clarified that a change has been 

initiated to add an action level specification for hydrocarbon and particulate content sample 

parameters in the chemistry procedure for compressed air quality control. The applicant also 

stated that the pressure dew point for the EDG air start subsystem is monitored annually. The 

applicant stated that the pressure dew point data have been within specification over the past 

several years and the air receivers have maintained a moisture-free condition. In its review of 

the RAI response, the staff noted that an air dryer is maintained in service on a continuous basis 

during compressor operation so as to remove moisture from the incoming compressed air, and 

the air receivers are checked daily for accumulation of condensation. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.9-2 acceptable 

because: (1) the applicant‘s pressure dew point monitoring frequency for the instrument air 

system is consistent with the recommendation of ANSI/ISA-7.0.01-1996 and GALL 

AMP XI.M24; (2) a change has been initiated to add an action level specification to the 

hydrocarbon and particulate content sample parameters in the chemistry procedure for 

compressed air quality control, consistent with the recommendations of GALL AMP XI.M24; 

(3) an air dryer is in service during the compressor operation; and (4) the applicant‘s daily check 

for accumulation of condensation is adequate to manage adverse effects of moisture on the 

EDG air start subsystem. The staff also finds that the applicant‘s OE demonstrates that the 

pressure dew point of the air start subsystem is adequately maintained within specification, and 

the EDG air start subsystem has minimal demand flow, except when an EDG start signal is 

generated. The staff‘s concern described in RAI B2.1.9-2 is resolved.

In its review, the staff noted that the ―parameters monitored or inspected‖ program element of 

GALL AMP XI.M24 recommends that ISI and testing be performed to confirm that maintenance 

practices, emergency procedures, and training are adequate to ensure that the intended 

function of the air system is maintained. The staff noted that in conjunction with GL 88-14, 

NUREG-1275, Volume 2 (Part I, Section 9.0) recommends that anticipated transient and system 

recovery procedures and related training for loss of air system events should be reviewed for 

adequacy and revised as necessary. NUREG-1275, Volume 2 recommends that plant 

personnel should be trained in the anticipated transient and system recovery procedures to 

respond to loss of air system events. The staff needed clarification as to whether the 

aforementioned recommendations for the emergency procedures and training are adequately 

implemented in the applicant‘s program. By letter dated July 13, 2009, the staff issued 

RAI B2.1.9-3 requesting that the applicant provide relevant references for the emergency 

procedures, training, and training schedules.
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In its response dated August 17, 2009, the applicant confirmed that an abnormal operating 

procedure is implemented to manage and recover from events that result in decreasing 

instrument air pressure, and licensed operators are required to be trained on loss of instrument 

air events in accordance with the applicant‘s training program for the licensed operator 

requalification training program. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.9-3 acceptable because

the applicant‘s program implements an emergency procedure for loss of instrument air and 

training of licensed plant operators for loss of instrument air events consistent with GALL 

AMP XI.M24. The staff‘s concern described in RAI B2.1.9-3 is resolved.

In its review, the staff noted that the ―acceptance criteria‖ program element of GALL 

AMP XI.M24 recommends that acceptance criteria be established for the system and for 

individual components that contain specific limits or acceptance ranges, based on design-basis 

conditions and/or component vendor specifications. The staff also found that the applicant‘s 

program documents did not clearly indicate that acceptance criteria were established for some 

parameters. Therefore, by letter dated July 13, 2009, the staff issued RAI B2.1.9-5 requesting

that the applicant clarify whether relevant acceptance criteria are established and documented 

for the parameters described in the RAI. The staff requested that if any of the parameters do not 

have an acceptance criterion, then the applicant should justify why lack of the acceptance 

criterion for the parameter is acceptable for the aging management or describe the actions for 

the applicant to take in relation to the acceptance criterion. The parameters addressed in 

RAI B2.1.9-5 are: (1) the compressor load and unload times, (2) the inlet and outlet coolant 

temperatures of the compressor intercoolers and aftercoolers, (3) the set pressures of 

compressors‘ and receivers‘ pressure-relief valves, (4) the differential pressure through the 

dryers, and (5) the minimum operational time for each special service air accumulator and its 

associated check valves upon loss of the main air system.

In its response dated August 17, 2009, the applicant provided the response regarding the load 

and unload times for the compressors. The applicant clarified that periodic leakage testing is 

performed on the EDG air start subsystem, although it is not possible to monitor load and 

unload times of the air start subsystem compressors by design, and that the compressors are 

designed to automatically cycle based on the air start tank pressure. The staff found that the 

conduct of periodic leakage testing on the compressors is consistent with the GALL Report and, 

therefore, acceptable to manage the aging effects. The staff also found that the applicant 

confirmed that the program monitors the unload times of the inservice compressors in the 

station and instrument air system each shift in accordance with approved procedures; therefore,

the staff finds that the monitoring of the unload times is adequate to detect and manage the 

degradation of the system due to aging effects. 

However, the staff noted that the applicant did not provide technical information on the load time 

of the compressors in its response. By letter dated November 20, 2009, the staff issued 

RAI B2.1.9-6 requesting that the applicant clarify whether the program enhancement regarding 

the implementation of ASME OM-S/G-1998, Part 17 includes the acceptance criteria for the load 

time of the station and instrument air system compressors. 

In its response dated December 28, 2009, the applicant stated that the establishment of specific 

acceptance criteria for load and unload time is not practical for the station and instrument air 

system compressors since the load and unload times vary based on the varying system air 

demand. The applicant also stated that as stated in the response to RAI B2.1.9-5, the unload 

times for the inservice compressors in the station and instrument air system are monitored each 
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shift in accordance with approved procedure. The applicant further stated that the system 

engineer performs monitoring and trending of the system in accordance with the established 

system monitoring plan and, as part of the system monitoring plan, the system engineer records 

the load and unload times during compressor walkdowns performed at least once a month. The 

applicant stated that the system engineer uses the load and unload times, in conjunction with 

other system parameters, to monitor the system performance and to evaluate long term issues.

Based on its review, the staff finds the applicant‘s responses to RAIs B2.1.9-5 and B2.1.9-6 

regarding the compressor load and unload times acceptable because: (1) the unload times of 

the inservice compressors in the station and instrument air system are monitored each shift in 

accordance with approved procedures; (2) the unload and load times of the station and 

instrument air system compressors are recorded according to the system monitoring plan, and 

analyzed to monitor the system performance and to evaluate long term issues; (3) the system 

engineer also performs the monitoring and trending of the station and air system in accordance 

with the established system monitoring plan; and (4) periodic leakage testing is performed on 

the EDG air start subsystem, although it is not possible to monitor load and unload times of the 

air start subsystem compressors by design, and the compressors are designed to automatically 

cycle based on the air start tank pressure. Therefore, the staff‘s concerns regarding the 

compressor load and unload times described in RAIs B2.1.9-5 and B2.1.9-6 are resolved.

In its response dated August 17, 2009, the applicant also provided the technical information 

regarding the inlet and outlet temperatures of the coolant in the compressor coolers. In its 

review, the staff noted that compressors F and G in the station and instrument air system, which 

are the normally-operating compressors, and the EDG air start subsystem compressors are air 

cooled. Therefore, the staff finds that the monitoring of coolant temperatures is not applicable to 

the air cooled compressors as addressed in the applicant‘s response to RAI B2.1.9-5. The staff 

also finds that the applicant‘s monitoring of the coolant temperatures of compressors A, B, and 

C during the routine testing is acceptable to ensure that the components are operating 

adequately on the basis that the compressors are not normally in operation, but are maintained 

and tested on a routine basis. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.9-5 regarding the 

coolant temperatures acceptable because the AMP monitors the coolant temperatures in 

accordance with approved test procedures and the monitoring of the coolant temperatures can 

ensure that the components are operating adequately. The staff‘s concern regarding coolant

inlet and outlet temperatures of the compressors described in RAI B2.1.9-5 is resolved.

In its response dated August 17, 2009, the applicant also provided the technical information 

regarding the set pressures of compressors‘ and receivers‘ pressure-relief valves. In its review 

of the response, the staff found that the set pressures for these compressed air system relief 

valves are routinely monitored, and that bench testing is performed to document the as-found 

set pressures. The staff also found that the applicant confirmed that if the acceptance criteria 

are not met, the relief valves are either adjusted or replaced. 

Based on its review, the staff finds that the applicant‘s response to RAI B2.1.9-5 regarding the 

set pressures is acceptable because the monitoring and bench testing of the set pressures can 

ensure that the set pressure values are within the acceptance criteria through relevant 

corrective actions that are performed, as required. The staff‘s concern regarding the set 

pressures of compressors‘ and receivers‘ pressure-relief valves described in RAI B2.1.9-5 is 

resolved.
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In its response dated August 17, 2009, the applicant also addressed its response to the concern 

described in RAI B2.1.9-5 regarding the differential pressure through the dryers. In its review of 

the RAI response, the staff noted that the differential pressure through the dryers is continuously 

monitored for the station and instrument air system, and the dryers are automatically bypassed 

in the event of high differential pressure across the dryer. The staff also noted that the applicant 

clarified that the setpoint at which dryer bypass occurs is established by approved procedures 

for the station and instrument air system. In an email exchange provided by the applicant 

(ADAMS Accession No. ML102700431), the applicant also indicated that a high differential 

pressure for the on-line drier is annunciated in the control room, procedures direct the 

applicant‘s staff to place a backup drier on line, and the expected time to have a backup drier in 

service is approximately 45 minutes. The staff finds that the applicant‘s procedure, including the 

establishment of the pressure setpoints to bypass the dryers, control room annunciation of the 

alarm, and actions directing the operators to place a backup drier on line, is adequate to 

manage the aging effects because the length of time the drier is bypassed due to high 

differential pressure is short and will not impact the overall quality of instrument air. 

The staff also noted that although the differential pressure through the dryers of the EDG air 

start subsystem is not monitored (due to the intermittent operation of its compressors), the 

dryers are cleaned on an annual basis in accordance with approved procedures. Based on its 

review, the staff finds the applicant‘s response to RAI B2.1.9-5 regarding the differential 

pressure through the dryers acceptable because: (1) the setpoint at which dryer bypass occurs 

is established by approved procedures for the station and instrument air system with prompt 

placement of a backup dryer in service in the case of dryer bypass, (2) the compressors of the 

EDG air start subsystem operate intermittently, and (3) periodic cleaning and maintenance 

activities are performed for the dryers in accordance with approved procedures. The staff‘s 

concern regarding the differential pressure through the dryers described in RAI B2.1.9-5 is 

resolved.

In its response dated August 17, 2009, the applicant stated that the minimum operational time 

for each special service air accumulator and its associated check valves is a design 

consideration for the station and instrument air system and is not related to plant aging. 

However, the staff noted that the minimum operational time for each special air accumulator and 

its associated check valves, upon loss of the main air system, is part of the baseline data 

against which the periodic leak-rate test results are compared, in order to identify adverse 

trends or system and component degradation due to aging effects, as delineated in ASME 

OM-S/G-1998, Part 17, Section 5.3 and in the ―monitoring and trending‖ program element of 

GALL AMP XI.M24. In addition, the staff noted that LRA Section B2.1.9 states that the 

Compressed Air Monitoring Program will be enhanced to incorporate the compressed air 

system testing and maintenance recommendations from ASME OM-S/G-1998, Part 17. 

In LRA Section B2.1.9, the applicant also stated that ASME OM-S/G-1998, Part 17, Section 5.3, 

―Inservice Performance Tests,‖ identifies periodic testing that should be performed for 

instrument air systems. In its review, the staff noted that ASME OM-S/G-1998, Part 17, 

Section 5.3 recommends leak tests of special service air accumulators and their associated 

check valves using pressure decay tests every refueling outage. The staff also noted that the 

concern regarding the minimum operational time for the air accumulators and their associated 

check valves is closely related to the conduct of leak tests. 

Therefore, by letter dated November 20, 2009, the staff issued RAI B2.1.9-7 requesting that the 

applicant clarify its aging management methodology in terms of the leak tests of special service 

air accumulators and their associated check valves. RAI B2.1.9-7 is also described in the safety 
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evaluation of Exception 1 because the safety evaluation is related to the concern regarding lack 

of the leak tests. In the RAI, the staff requested that the applicant clarify whether the applicant‘s 

program includes the leak tests for the special service accumulators and their associated check 

valves and whether the program compares the periodic leak test data with the minimum 

operational time for the accumulators and their associated check valves upon loss of the main 

air system. The staff also noted that lack of the leak tests and leak test data analysis affects the 

―scope of the program,‖ ―preventive actions,‖ ―parameters monitored or inspected,‖ ―detection of 

aging effects,‖ ―monitoring and trending,‖ and ―acceptance criteria‖ program elements.

In its response dated December 28, 2009, the applicant stated that the safety-related special 

service air accumulators and their associated check valves are leak tested each refueling 

outage consistent with the requirements of ASME OM-S/G-1998, Part 17, to meet design-basis 

requirements. The applicant further stated that this testing is not included in or credited by the 

Compressed Air Monitoring Program, since the testing is not required in order to adequately 

manage the effects of aging for the service and instrument air system components within the 

scope of license renewal; furthermore, the AMR for the special service air accumulators and 

their associated check valves, as stated in LRA Table 3.3.2-8, concluded that there are no 

AERMs for these accumulators and check valves due to exposure to the dried compressed air 

environment. The applicant also stated that the AMR results are consistent with the GALL 

Report, Volume 2, Section VII, items VII.J-3, VII.J-18, and VII.J-22, which indicate that piping, 

piping components, and piping elements fabricated from copper alloys, stainless steel, or steel 

materials are not subject to aging effects in a dried air environment.

Based on its review, the staff finds the applicant‘s responses to RAIs B2.1.9-5 and B2.1.9-7 

acceptable because: (1) the applicant stated that the environment for the components is dried 

air; (2) no aging effect is applicable to the components exposed to the dried air environment 

consistent with GALL Report items VII.J-3, VII.J-18, and VII.J-22; and (3) the monitoring and 

trending of the leak test results against the minimum operational time is not required for the 

aging management of the components. The staff‘s concern regarding the minimum operational 

time described in RAIs B2.1.9-5 and B2.1.9-7 is resolved.

Exception 1. LRA Section B2.1.9 states an exception to the ―detection of aging effects‖ program 

element. The applicant stated that leak testing is not performed for the station and instrument air 

system distribution network as recommended in GALL AMP XI.M24. Instead, LRA 

Section B2.1.9 states Enhancement 1 to the same program element incorporates the 

compressed air system testing and maintenance recommendations from ASME OM-S/G-1998, 

Part 17 and EPRI TR-108147 and identifies these documents as part of the program basis. In 

contrast with this program exception, ASME OM-S/G-1998, Part 17 and EPRI TR-108147 

recommend leak tests such as:

 (1) pressure decay test on the distribution network as one of recommended tests for the 

case that compressor loading indicates an increase in system leakage 

(ASME OM-S/G-1998, Part 17, Section 5.3.3; EPRI TR-108147, Section 8.9.2)

 (2) air leak test with a soap solution to piping joints and connections (EPRI TR-108147, 

Section 8.9.2)

In its review, the staff noted that the exception is directly related to Enhancement 1 and that a 

conflict exists between Exception 1 and Enhancement 1 in terms of the conduct of leak tests. By 

letter dated July 13, 2009, the staff issued RAI B2.1.9-4 requesting that the applicant clarify how 
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its program can identify the locations of air leakage without leak testing for the distribution 

network, and clarify whether leak tests for the distribution network will be performed as the 

technical basis references recommend and to which the applicant committed in the program 

enhancement. 

In its response dated August 17, 2009, the applicant stated that system walkdowns have been 

proven effective in identifying and locating air distribution system leakage, and that leak testing 

is used as a diagnostic tool when needed. The applicant further stated that although both 

ASME OM-S/G-1998, Part 17 and EPRI TR-108147 address leak testing, both documents 

advocate leak testing as part of a troubleshooting process when leakage is suspected and not 

as a periodic preventive maintenance activity, and that there is a technical difference between 

GALL AMP XI.M24 and the two industry documents. The applicant also stated that the 

exception regarding the leak testing does not imply that leak testing would not be performed 

when there are indications of leakage in the station and instrument air system, and the source of 

the leakage is not readily apparent. The applicant stated that this type of ―as-needed‖ rather 

than ―preventive‖ leak testing would be performed, when required, per ASME OM-S/G-1998, 

Part 17 and EPRI TR-108147.

In its review, the staff noted that Section 5.3.1(b)(1) and Table 1 of ASME OM-S/G-1998, 

Part 17 require that special service air accumulators and their associated check valves should 

be leak tested. Therefore, by letter dated November 20, 2009, the staff issued RAI B2.1.9-7 

requesting that the applicant clarify whether the applicant‘s program includes leak tests for the 

special service air accumulators and their associated check valves, and whether the program 

compares periodic leak test data with the minimum operational time for the accumulators and 

their associated check valves upon loss of the main air system. This RAI and the applicant‘s 

response to the RAI are also described above as part of the safety evaluation regarding the 

acceptance criteria for the minimum operational time of the special service air accumulators and 

their associated check valves.

In its response dated December 28, 2009, the applicant stated that it performs leak tests on the 

safety-related special service air accumulators and their associated check valves to meet 

design-basis requirements, but not to manage the aging effects because no aging effects are 

applicable to the special service air accumulators and their associated check valves in the dried 

air condition as stated in LRA Table 3.3.2-8.

Based on its review, the staff finds the applicant‘s responses to RAIs B2.1.9-4 and B2.1.9-7 and 

this exception acceptable because: (1) the applicant‘s system walkdowns have been proven 

effective in identifying and locating air distribution system leakage; (2) when there are 

indications of leakage in the station and instrument air system and the source of the leakage is 

not readily apparent, leak testing would be performed, as needed, consistent with 

ASME OM-S/G-1998, Part 17 and EPRI TR-108147; and (3) the special service air 

accumulators and their associated check valves are exposed to dried air such that no aging 

effects are applicable to the components, although the applicant performs the leak tests of the 

accumulators and check vales to meet design-basis requirements. The staff‘s concerns 

described in RAIs B2.1.9-4 and B2.1.9-7 are resolved. 

Exception 2. LRA Section B2.1.9 states an exception to the ―scope of the program‖ program 

element, as amended by letter dated November 13, 2009. The applicant stated that the station 

and instrument air system and the EDG air start subsystems are not sampled at various 

locations as recommended by the ―scope of the program‖ program element of GALL 

AMP XI.M24. The applicant also stated that the sample point for the station and instrument air 
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system is downstream of the system dryer tower, and that the sample points for the EDG air 

start subsystems are downstream of the dryer for each subsystem. 

The staff noted that the applicant‘s justification for the exception is that since the systems are 

normally pressurized, the only source for contaminants or moisture into the system would be via 

the respective compressors and, therefore, measuring the quality of the air as it enters the 

system provides an accurate representation of the quality of the air in the system.

In its review, the staff noted that the applicant correctly described the exception as the air quality 

sampling points in the applicant‘s program are downstream of the system dryer tower or 

downstream of the dryer, in contrast to the recommendation of the GALL Report that air quality 

be checked at various locations in the system. In comparison, the staff also noted that EPRI 

NP-7079, which is one of the technical references of GALL AMP XI.M24, states that the system 

should be sampled on the downstream side of the dryer as close to the outlet of the air filter as 

possible, and that this provides assurance of the quality of the air supplied to the system. The 

EPRI report also states that moisture content should be continuously monitored by the use of a 

permanent dew cell or moisture indicator installed on the downstream side of the dryer, and that 

this can be extremely useful in early detection of instrument air system problems.

Based on its review, the staff finds the applicant‘s exception acceptable because: (1) the 

locations of the air quality sampling in the applicant‘s program are consistent with the 

recommendation of EPRI NP-7079, which can assure the quality of the air supplied to the 

system; (2) the applicant‘s approach, which is consistent with one of the technical references of 

GALL AMP XI.M24, provides the assurance of the quality of the air supplied to the system and a 

reasonable representation of the quality of the air in the system based on the fact that the 

system is normally pressurized; and (3) in addition to the air quality control, the applicant 

performs inspections and testing as part of the AMP in order to ensure the integrity of the 

components and system. 

Exception 3. LRA Section B2.1.9 states an exception to the ―monitoring and trending‖ program 

element, as amended by letter dated November 13, 2009. The applicant stated that the sample 

data for the station and instrument air system and the EDG air start subsystems are not trended 

as recommended by GALL AMP XI.M24. In its justification, the applicant also stated that the 

sample data are related to air quality control parameters.

In its review, the staff noted that the applicant‘s justification is that specific chemistry parameter 

limits have been established for the station and instrument air system and the EDG air start 

subsystems in accordance with ANSI/ISA-7.0.01-1996. In addition, the measured chemistry 

parameters are compared to specific limits and an action is taken to restore the parameter 

within specification if an out-of-specification condition is identified. The staff also noted that the 

applicant stated that maintaining the compressed air system air quality in accordance with 

ANSI/ISA-7.0.01-1996 provides sufficient margins to ensure continued system functions, and 

that data trending of the [air quality] control parameter results would not provide information 

useful for aging management. In the applicant‘s letter, the applicant further clarified that 

chemistry procedures require that out-of-specification conditions are also documented in the 

corrective action program.

Based on its review, the staff finds the applicant‘s exception acceptable because: (1) the 

applicant takes adequate actions to restore the air quality parameters to the specific limits when 

parameters are identified as out-of-specification, and (2) the corrective actions can continue to 
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control the air quality in accordance with ANSI/ISA-7.0.01-1996 and provide assurance of 

acceptable air quality control. 

Enhancement. LRA Section B2.1.9 states an enhancement to incorporate the compressed air 

system testing and maintenance recommendations from ASME OM-S/G-1998, Part 17 and 

EPRI TR-108147, and to identify these documents as part of the program basis. The applicant 

also stated that the implementation of the enhanced testing and maintenance practices will 

ensure that the compressed air systems can perform their intended function. 

Based on its review, the staff finds the applicant‘s enhancement acceptable because the 

enhancement is consistent with the recommendation of GALL AMP XI.M24. 

Based on its audit and review of the applicant‘s responses to RAIs B2.1.9-1, B2.1.9-2, B2.1.9-3, 

B2.1.9-4, B2.1.9-5, B2.1.9-6, and B2.1.9-7, the staff finds that elements one through six of the 

applicant‘s Compressed Air Monitoring Program, with acceptable exceptions and an 

enhancement, are consistent with the corresponding program elements of GALL AMP XI.M24 

and are, therefore, acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.9. In the LRA, 

the applicant stated that in July 2005, a station and instrument air system air compressor was 

started and tripped on ―HP Air Outlet Temp High Trip.‖ The applicant stated that the cause of 

the elevated temperature was determined to be a leaking ―equalizing‖ line on the high pressure 

element, which involved a sufficient volume of leakage to cause elevated temperatures. The 

applicant also stated that the high pressure element was replaced as a unit. The staff found that 

the applicant took corrective action, identified the air leakage in the equalizing line as the root 

cause of the elevated temperatures, and replaced the high pressure element to manage the 

aging effect.

The applicant stated that in January 2007, during a plant tour, the intercooler pressure for one 

air compressor was outside the acceptance band, and the applicant cleaned the compressor 

intercooler to restore compressor performance. In the OE review, the staff found that the 

applicant responded to the situation with corrective action that restored system performance.

During its audit and review, the staff reviewed the onsite documents as well as the LRA. The 

staff also interviewed the applicant‘s technical staff. The staff confirmed that the plant-specific 

OE did not reveal any degradation not bounded by industry experience in relation to the 

Compressed Air Monitoring Program. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.9 provides the USAR supplement for the Compressed Air 

Monitoring Program. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.3-2. 
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The staff also notes that the applicant committed (Commitment No. 5) to enhance the 

Compressed Air Monitoring Program prior to entering the period of extended operation. 

Specifically, the applicant committed to incorporate the compressed air system testing and 

maintenance recommendations from ASME OM-S/G-1998, Part 17 and EPRI TR-108147, and 

to identify these documents as part of the program basis. 

The staff 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 Compressed Air Monitoring 

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 the LRA credits it. Also, the staff reviewed the enhancement 

and confirmed that its implementation through Commitment No. 5, prior to the period of 

extended operation, would make the existing AMP consistent with the GALL Report 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 functions 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 External Surfaces Monitoring Program

Summary of Technical Information in the Application. LRA Section B2.1.10 describes the 

existing External Surfaces Monitoring Program as consistent, with enhancements, with GALL 

AMP XI.M36, ―External Surfaces Monitoring.‖ The applicant stated that through this program, 

during walkdowns, it visually inspects and monitors the external surfaces of piping, its 

components and supports, ducting, structural members and other components, materials, and 

commodities for loss of material and changes in material properties, including cracking, 

delamination, hardening, and loss of strength. The applicant stated that monitored materials and 

commodities include carbon steel, stainless steel, aluminum, copper and its alloys, and selected 

elastomers. The applicant also stated that this program provides support to the Bolting Integrity 

and Boric Acid Corrosion programs. The applicant further stated that the program takes an 

areas approach, where representative samples of materials in SSCs and in selected 

environments are monitored. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M36. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M36, with the exception of the ―scope of the program‖ and ―detection of aging effects‖ 

program elements. For these elements, the staff determined the need for additional clarification, 

which resulted in the issuance of RAIs. 
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The ―program description‖ and ―scope of the program‖ program elements of GALL AMP XI.M36 

recommend the use of periodic visual inspections during walkdowns, to monitor and inspect 

external surfaces of steel components, such as piping, piping components, and ducting, for loss 

of material, leakage, discoloration, and coating degradations. In the LRA program description, 

the applicant included, in addition to monitoring steel components, visual monitoring of 

aluminum, copper alloys, stainless steel components, and selected elastomers. By letter dated 

July 13, 2009, the staff issued RAI B2.1.10-1 requesting that the applicant: (1) justify why the 

inclusion of other than carbon-steel based metal commodities and elastomers to the ―scope of 

the program‖ program element does not constitute an exception, (2) provide details of how the 

inspecting personnel visually recognize corrosion in stainless steel and aluminum components 

during walkdowns, and (3) clarify how the aging effects of elastomers are identified, since visual 

observations are normally inadequate to identify aging of elastomer properties, such as 

hardness and flexibility.

In its response dated August 17, 2009, the applicant agreed with the staff for part one of the 

RAI, that the included metal commodities constitute an exception to GALL AMP XI.M36. The 

applicant responded to parts two and three of the RAI by providing details of how it will conduct 

visual inspections of the added metals during the walkdowns and assess the integrity of the 

selected elastomers. Since the applicant considered this an exception to the GALL Report, it is 

discussed below. The staff‘s evaluation of this exception concluded that the exception was 

acceptable, as stated below. The staff‘s concern described in RAI B2.1.10-1 is resolved.

The ―program description,‖ ―scope of the program,‖ ―preventive actions,‖ ―detection of aging 

effects,‖ and ―monitoring and trending‖ program elements of GALL AMP XI.M36 articulate this 

program to be a visual inspection program. In the LRA ―program description‖ program element, 

the applicant stated that this program will identify changes in material properties of piping, 

supports, structural members, and structural commodities, whether they are constructed of the 

included metals or elastomers. The applicant further stated that its External Surfaces Monitoring 

Program, after enhancements, is consistent with that of the GALL Report. By letter dated 

July 13, 2009, the staff, concerned with the inability of the applicant to visually identify changes 

in material properties during walkdowns, issued RAI B2.1.10-2 requesting that the applicant 

identify how it can visually detect changes in material properties, as these may require 

inspection techniques other than visual. 

In its response dated August 17, 2009, the applicant referenced the portion of its response to 

RAI B2.1.10-1 regarding compliance to the recommendations of GALL AMP XI.M36 on 

elastomers. The applicant stated that this AMP manages aging effects related to changes in 

material properties for the flexible connections in the ventilation system ducting and the shield 

building penetration seals, by employing the ―scratch, sniff, and stretch‖ technique as described 

in the EPRI ―Aging Assessment Field Guide.‖ The staff reviewed the concept of ―scratch, sniff, 

and stretch‖ and concluded that it is an acceptable technique promoting close physical 

inspection and manipulation of elastomers beyond the visual inspection recommended by the 

GALL Report. The staff reasoned that such close physical manipulation of elastomers is bound 

to reveal material degradation and changes in properties due to various aging mechanisms, be 

they physical, chemical, thermal, or weather related. The staff, therefore, accepts the applicant‘s 

approach in managing aging of elastomers because the EPRI approach and technique 

constitutes an acceptable industry practice. The staff‘s concern described in RAI B2.1.10-2 is 

resolved.
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SRP-LR Section A.1.2.3.4, ―detection of aging effects‖ program element, states that sampling is 

allowed for the inspection of a group of SCs, but that a rationale must be established for 

selection of the population and sampling size. The SRP-LR also states that samples should be 

biased toward locations most susceptible to the specific aging effect of concern during the 

period of extended operation, with provisions established to expand the size when degradation 

is detected in the initial sample. In LRA Section B.2.1.10, External Surfaces Monitoring Program 

―program description,‖ the applicant stated that it takes an ―areas approach‖ to monitoring the 

condition of plant equipment for loss of material. The applicant also stated that the plant is 

divided into areas that contain the equipment or structural commodities being evaluated, and 

that the inspectors look at a representative sample of the material and environment 

combinations in that area. The staff noted that the applicant did not include the basis for how it 

determines the population and size of the sampling of components inspected by the External 

Surfaces Monitoring Program. By letter dated July 13, 2009, the staff issued RAI B2.1.10-3 

requesting that the applicant provide its sampling basis.

In its response dated August 17, 2009, the applicant stated that the phrase ―representative 

sample‖ was used incorrectly in the ―program description‖ of the LRA. The applicant also stated 

that its External Surfaces Monitoring Program is consistent with GALL AMP XI.M36, and that 

personnel performing the inspections inspect material and environment combinations in a 

designated area, looking for indications of aging, such as loss of material, loss of sealing, or 

leakage of components in that area. The applicant further stated that the inspections ensure that 

a sufficient number of commodities are examined such that an overall assessment of 

component aging can be determined. The staff also noted that the LRA states that system 

engineers perform comprehensive visual inspections at least once per refueling cycle, which is 

consistent with the recommendations in GALL AMP XI.M36.

Based on its review, the staff finds the applicant‘s response acceptable because: (1) the 

applicant‘s program is based on a combination of periodic system inspections and walkdowns 

conducted by operations, health physics, and engineering personnel; (2) the inspections and 

walkdowns in an area are based on material and environment combinations, looking for loss of 

material, loss of sealing, or leakage; and (3) comprehensive visual inspections are performed at 

least once per refueling cycle. The staff finds that this approach is consistent with GALL 

AMP XI.M36. The staff‘s concern described in RAI B2.1.10-3 is resolved.

The staff also reviewed the portions of the ―scope of the program,‖ ―monitoring and trending,‖ 

and ―detection of aging effects‖ program elements associated with exceptions and 

enhancements to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff‘s evaluation of these exceptions and enhancements follows.

Exception. In its response to RAI B2.1.10-1, the applicant recognized an exception to the 

program because its program includes aluminum, copper alloys, stainless steel, and selected 

elastomers. The applicant revised the LRA and took an exception to the ―scope of the program‖ 

and ―detection of aging effects‖ program elements. In the exception, the applicant stated that the 

program has been extended beyond the GALL Report‘s restriction to manage aging effects of

just steel, to also manage the aging effects of stainless steel, aluminum, copper, and 

elastomers. The applicant further stated that the personnel performing inspections visually 

monitor external surface irregularities and localized discolorations for the included metal 

commodities. The inspectors also look for other relevant indicators, such as boric acid buildup, 

poor material conditions, coating degradations, accumulation of dirt and debris, and evidence of 

leakage. For aging management of elastomers, the inspectors use EPRI-developed techniques 
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that include physical manipulation of elastomers and are identified as ―scratch, sniff, and 

stretch.‖ 

The staff reviewed the applicant‘s revisions to the LRA and justification for the exception as 

presented in its response to RAI B2.1.10-1. The staff determined the exception to be acceptable 

because the applicant will use: (1) relevant indicators for timely identification of corrosion, and 

(2) the WCP Program to supplement the External Surfaces Monitoring Program to supplement 

aging management of SCs in environments and materials and commodities combinations. In 

addition the staff noted: (1) that aluminum, copper alloys, and stainless steel in an 

indoor-uncontrolled air environment do not exhibit aging effects (see Technical Bases for 

Revision to the License Renewal Guidance Documents, NUREG-1833); and (2) the location of 

the plant is in a colder climate which inhibits aggressive corrosion rates. The staff also finds the 

exception to use ―scratch, sniff, and stretch‖ detection techniques, to assess the integrity of 

elastomers, acceptable because the technique includes physical manipulation and is recognized 

by EPRI and the industry.

Enhancement 1. LRA Section B2.1.10 states an enhancement to the ―scope of the program‖ 

and ―parameters monitored or inspected‖ program elements in that the applicant will enhance 

the External Surfaces Monitoring Program with inspections of infrequently accessed plant areas. 

The applicant stated that it will enhance and augment the ―scope of the program‖ and 

―parameters monitored or inspected‖ program elements by having operators, engineers, and 

health physicists inspect the external surfaces of infrequently inspected commodities in SSCs, 

in accordance with GALL AMP XI.M36 recommendations. The staff finds this enhancement 

acceptable because: (1) it provides an increased surveillance of inaccessible plant areas‘ 

relevant commodities, (2) it is accompanied by a commitment (see Commitment No. 6, 

Table A6.0-1), and (3) it reinforces the ―scope of the program‖ program element, supporting it 

with the ―parameters monitored or inspected‖ program element, thus rendering it consistent with 

the GALL Report AMP recommendations. 

Enhancement 2. LRA Section B2.1.10 also states an enhancement to the ―monitoring and 

trending‖ program element. The applicant stated that it will enhance the External Surfaces 

Monitoring Program by providing training of the operations, engineering, and health physics 

plant personnel to better perform the program inspections and walkdowns. The applicant also 

stated that the enhancement will satisfy the need to document the identified material states or 

conditions with sufficient detail to support predictability of the extent of degradations, and 

provide background for timely corrective actions in accordance with the recommendation of 

GALL AMP XI.M36. The applicant‘s intent to adequately monitor material conditions was 

reinforced by its responses to RAIs B2.1.10-1 and B2.1.10-2. In the case of elastomers, during 

inspection, the applicant intends to physically manipulate the materials to ensure that they 

continue to maintain their functionality, assuring the operability of SSCs. For metallic materials 

other than (carbon) steel included in the scope of the program (i.e., stainless steel, copper, 

aluminum), the applicant plans to educate the inspectors to look for specific clues identifying 

corrosion and to pursue a comprehensive visual examination of these commodities (see also 

the staff‘s disposition of the RAIs, above). Following the additional input from the applicant, the 

staff finds this enhancement acceptable to reinforce the ―monitoring and trending‖ program 

element, rendering it consistent with the GALL Report AMP recommendations.

Based on its audit and review of the applicant‘s responses to RAIs B.2.1.10-1, B.2.1.10-2, and 

B.2.1.10-3, the staff finds that elements one through six of the applicant‘s External Surfaces 

Monitoring Program, with acceptable exception and enhancements, are consistent with the 

program elements of GALL AMP XI.M36 and are, therefore, acceptable.
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Operating Experience. LRA Section B.2.1.10 summarizes OE related to the External Surfaces 

Monitoring Program. Under OE, the applicant stated the External Surfaces Monitoring Program 

to be ―...effective in identifying change in material properties, cracking, delamination, loss of 

material, and hardening and loss of strength, evaluating the degradation, and implementing 

corrective actions.‖ The applicant further stated that when degradation was ―...identified, 

corrective actions have been implemented to ensure that the intended functions of the affected 

SSCs are maintained.‖ The staff also interviewed the applicant‘s technical personnel to confirm 

that the plant-specific OE did not reveal any aging effects not bounded by the GALL Report and 

confirmed that applicable aging effects and industry and plant-specific OE have been reviewed 

by the applicant. The staff also confirmed that the applicant has addressed the plant‘s OE 

identified after the issuance of the GALL Report.

The staff reviewed the OE information in the application during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no OE to indicate that the applicant‘s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. 

Specifically, the staff, through an independent search of the applicant‘s condition report 

database and through an in-person interview of its onsite personnel, concluded that the 

applicant maintains a high awareness in visually identifying the presence of rust and corrosion 

in carbon steel SSCs. The staff extended the search to see if the applicant was capable of 

visually identifying corrosion for all metallic materials and elastomer degradations. The database 

search included both current and historical records. The staff was satisfied with the applicant‘s 

rust and corrosion tracking of carbon steel and copper material commodities. For example, in 

December of 2001, the applicant‘s inspection personnel found a leak at the shaft of a mixing 

pump. The plant assessed the situation, confirmed that the pump functionality in mixing and 

transferring contents remained, and advised timely repairs. After completion of the repairs, the 

pump was back at its design configuration. The staff, however, expressed concerns in the 

applicant‘s ability to visually monitor stainless steel and aluminum rust and loss of performance 

of elastomers; these concerns were evaluated and resolved in the subsection for Exception 1, 

as noted above. 

The staff confirmed that the applicant repairs or replaces SSCs and commodities before they 

lose their capacity to perform their intended functions. Some work orders were completed well 

before loss of functionality with decisions based on cost/benefit analyses. If, however, a function 

of an SSC or commodity was lost, then the applicant took a contingency action. For example, in 

January 2002, the staff confirmed that the applicant‘s operations personnel identified a 

non-functional penetration seal located in the wall separating the two component cooling 

pumps. Since the penetration seal affected a fire barrier, the applicant took an immediate 

contingency action to establish a fire watch within one hour of this identification. Subsequently, 

the penetration seal was repaired and returned to its design configuration. 

However, subsequent to the audit, the staff noted a number of recent industry events involving 

radioactive fluid leakage from buried and underground piping and tanks. In light of this recent 

industry OE, the staff is concerned about the continued susceptibility to failure of buried and/or 

underground piping that are within the scope of 10 CFR 54.4 and subject to aging management 

for license renewal. In reviewing the applicant‘s External Surfaces Monitoring and Buried Piping 

and Tanks Inspection programs, along with the applicable AMR items associated with them, the 
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staff is not clear whether: (1) the components addressed by these AMPs clearly include both 

buried and underground piping (piping which is below grade and contained in a vault or other 

structure where it is exposed to air and where access is limited) and (2) these programs are

being updated to incorporate lessons learned from these recent events as well as any OE from 

the applicant‘s own history.

In a letter dated May 27, 2010, the staff issued RAI B2.1.7-3 requesting that the applicant 

address these issues. The staff identified this as Open Item 3.0.3.2.4-1. The staff‘s evaluation 

and closure of RAI B2.1.7-3 and Open Item 3.0.3.2.4-1 is documented in LRA Section 3.0.3.2.4.

USAR Supplement. LRA Section A2.1.10 provides the USAR supplement for the External 

Surfaces Monitoring Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2.

The staff also notes that the applicant committed (Commitment Nos. 6 and 7) to enhance the 

program prior to entering the period of extended operation. Specifically, the applicant committed 

to: (1) inspect the accessible external surfaces of in-scope components, piping, supports, 

structural members, and structural commodities, in the infrequently accessed areas, consistent 

with the criteria used in other plant areas; and (2) provide training for operations, engineering, 

and health physics personnel performing the program inspections and walkdowns that will 

address the requirements of the External Surfaces Monitoring Program for license renewal, 

including the need to document the identified conditions with sufficient detail to support 

monitoring and trending the aging effects, and the aging effects monitored by the program and 

how to identify them.

The staff 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 determines 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 determined that the AMP, with the exception, is adequate to manage the 

aging effects for which the LRA credits it. The staff also reviewed the enhancements and 

confirmed that their implementation through Commitment Nos. 6 and 7, prior to the period of 

extended operation, would make the existing AMP consistent with the GALL Report AMP to 

which it was compared. 

The staff 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).

The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.0.3.2.8 Fire Protection Program

Summary of Technical Information in the Application. LRA Section B2.1.11 describes the 

existing Fire Protection Program as consistent, with an exception and enhancements, with 

GALL AMPs XI.M26, ―Fire Protection,‖ and XI.M27, ―Fire Water System.‖ The applicant stated 

that its Fire Protection Program manages the aging effects of change in material properties, 
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cracking, delamination, increased hardness, loss of material, loss of sealing, loss of strength, 

shrinkage, and spalling for the fire protection components and features. The applicant also 

stated that its Fire Protection Program performs: (1) chemical treatment and periodic flushing of 

the water-based fire suppression system; (2) periodic inspection and testing of the water-based, 

carbon dioxide (CO2), and Halon fire suppression systems; and (3) visual inspections of fire 

barriers, fire barrier penetrations and seals, fire barrier expansion joints, doors, fire wraps, and 

the RCP oil collection system to detect degradation. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M26. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M26. The staff noted 

that GALL AMP XI.M26 recommends that the diesel-driven fire pump be periodically tested to 

ensure the fuel supply line can perform its intended function. The staff also noted that the 

applicant does not have a diesel-driven fire pump and, therefore, has no fire protection pump 

fuel supply line which requires aging management. Hence, the staff further noted that this 

recommendation in GALL AMP XI.M26 is not applicable.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M27. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M27.

The staff also reviewed the portions of the ―parameters monitored or inspected,‖ ―detection of 

aging effects,‖ and ―monitoring and trending‖ program elements associated with the exception 

and three enhancements to determine whether the program will be adequate to manage the 

aging effects for which it is credited. The staff‘s evaluation of the exception and three 

enhancements follows.

Exception. LRA Section B2.1.11 states an exception to the ―monitoring and trending‖ program 

element of GALL AMP XI.M26, ―Fire Protection.‖ In this exception, the applicant stated that the 

Halon system is functionally tested annually and Halon cylinder level measurements are taken 

on a 6-month frequency. The applicant further stated that the relay room and turbine bearing 

CO2 fire suppression subsystems are inspected and tested every 18 months, during the 

refueling outage; while the remaining CO2 systems are tested semi-annually. 

The GALL Report recommends that a visual and functional test be performed on the Halon and 

CO2 fire suppression systems at least once every 6 months. The staff noted that the applicant‘s 

CLB for the Halon and CO2 systems is based on the 1973 editions of National Fire Protection 

Association (NFPA) Standard 12 A, ―Standard on Halon 1301 Fire Extinguishing Systems,‖ and 

Standard 12, ―Standard on Carbon Dioxide Extinguishing Systems,‖ respectively. The 1973 

editions of NFPA Standards 12 A and 12 did not specify any testing frequency for the Halon and 

CO2 fire suppression systems. The 6-month surveillance and testing frequency for the Halon 

and CO2 fire suppression systems in the GALL Report is consistent with the current NFPA 

Standard 12 A (2009), but is more frequent than the current NFPA Standard 12 (2008), which 

stipulates an annual testing frequency for CO2 systems. 

By letter dated July 13, 2009, the staff issued RAI B2.1.11-1 requesting that the applicant 

provide operating history to justify why the longer timeframe is sufficient to protect the Halon 
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and CO2 fire suppression systems from the effects of aging. In its response dated August 17, 

2009, the applicant stated the following:

Based on the results of inspections and testing performed since 1973, there has 

been no significant aging-related degradation identified in these gaseous fire 

suppression systems. Therefore, the extended functional testing cycle provides 

adequate opportunity to observe system performance degradation prior to loss of 

intended function and the inspection and testing frequency is justified.

The staff reviewed the applicant‘s response and noted that the applicant‘s CLB is to functionally 

test the gaseous fire suppression system consistent with the NFPA standards. The staff noted 

that, with the exception of the relay room and turbine bearing subsystems, the applicant‘s CO2

system is tested at a frequency consistent with the GALL Report recommendation and is tested 

more frequently than that of the current NFPA Standard 12 requirement. The staff also noted 

that the applicant‘s Halon systems are tested less frequently than both the GALL Report 

recommendation and the current NFPA Standard 12 A recommendation of a 6-month 

frequency. The applicant stated that the two CO2 subsystems that are not consistent with the 

GALL Report are tested on an 18-month frequency. The staff‘s independent OE review 

indicated no aging-related effect that has adversely affected the operation of the Halon and CO2

fire suppression systems. The staff further noted that the externals of the applicant‘s fire 

suppression systems and components are exposed to an inside air environment where 

corrosive agents (e.g., excessive salt or sulfur) are not expected to attack the fire suppression 

systems during the period of extended operation. The staff finds that the testing frequencies of 

the Halon and relay room and turbine bearing CO2 subsystems, even though less frequent than 

the GALL Report recommendation, are sufficient to ensure that the systems will perform their 

intended functions, as evidenced by the operating history of the systems. The staff‘s concern 

described in RAI B2.1.11-1 is resolved.

Enhancement 1. LRA Section B2.1.11 states an enhancement to the ―detection of aging effects‖ 

program element. The applicant committed (Commitment No. 8) to either test or replace a 

sample of sprinkler heads, in accordance with NFPA Standard 25. NFPA Standard 25 (2002), 

Section 5.3.1.1.1 states, in part, ―Where sprinklers have been in service for 50 years, they shall 

be replaced or representative samples from one or more sample areas shall be tested.‖

The GALL Report recommends replacing or testing the sprinkler heads after they have been in 

service for 50 years, in accordance with NFPA Standard 25 (1998, 2002). In reviewing this 

enhancement, the staff noted that the applicant‘s sprinkler heads had been in service since the 

start of the plant‘s operation. The staff finds the applicant‘s enhancement acceptable because it 

will make the applicant‘s program consistent with the GALL Report recommendation.

Enhancement 2. LRA Section B2.1.11 states an enhancement to the ―parameters monitored or 

inspected‖ and the ―detection of aging effects‖ program elements. The applicant committed 

(Commitment No. 9) to include the elastomer shield building fire boots in the fire barrier 

penetration seal inspection program.

The GALL Report recommends visually inspecting approximately 10 percent of the seals for 

signs of degradation at least once every refueling outage. The staff noted that the applicant 

regularly inspected these silicone-impregnated neoprene fire boots. However, the boot type 

seals are not specifically included in the plant fire barrier inspection procedure. The staff also 

noted that visual inspection of penetration seals is an integral part of the fire barrier inspection in 

GALL AMP XI.M26, ―Fire Protection.‖ The staff finds the applicant‘s enhancement acceptable 
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because it will make the applicant‘s Fire Protection Program consistent with the GALL Report 

recommendation.

Enhancement 3. LRA Section B2.1.11 states an enhancement to the ―parameters monitored or 

inspected‖ program element. The applicant committed (Commitment No. 10) to: (1) add one 

more criterion (i.e., inspecting for corrosion) to the current RCP oil collection system receiver 

inspection program and (2) perform a visual inspection of the internal surfaces of the oil 

collection tank prior to entering the period of extended operation. 

The oil collection system collects any leaking lubricating oil from the RCPs, through the RCP oil 

collection system receiver, into a tank, as required by 10 CFR Part 50, Appendix R. To manage 

loss of material for steel in a lubricating oil environment, the GALL Report recommends using 

GALL AMPs XI.M39, ―Lubricating Oil Analysis,‖ and XI.M32, ―One-Time Inspection.‖ By letter 

dated July 7, 2009, the staff issued RAI B2.1.11-2 requesting that the applicant provide 

justification as to why the Lubricating Oil Analysis Program was not credited to protect the RCP 

oil collection system. In its response dated August 17, 2009, the applicant provided the following 

discussion:

Since the lubricating oil environment for the tank is from oil leakage from reactor 

coolant pump bearings, it was determined that management of tank aging by the 

Lubricating Oil Analysis Program described in LRA Appendix B, Section B2.1.17 

would not be effective. In addition, although the AMR conservatively concluded 

that loss of material due to corrosion is a potential aging effect, the internal air 

environment with the potential for minimal amounts of oil is not expected to be 

aggressive to the tank material and result in significant aging, Therefore, a 

specific visual inspection of the tank prior to the period of extended operation is 

provided as an enhancement to the Fire Protection Program, as described in 

LRA Appendix B, Section B2.1.11, ―Fire Protection,‖ Enhancement 3, in order to 

confirm that significant aging is not occurring. A visual inspection of the tank is 

adequate to identify signs of loss of material due to corrosion.

The staff finds the applicant‘s response acceptable because: (1) the applicant plans to enhance 

the program with additional inspection criteria for the RCP oil collection system and a one-time 

internal inspection of the oil collection tank prior to the period of extended operation, and 

(2) only minimal amounts of oil that leak from the RCP are expected to accumulate in the tank.

The staff finds the one-time inspection of the internal surfaces affords the applicant an 

opportunity to assess internal material condition of the tank prior to the period of extended 

operation. The staff also finds the additional inspection criteria provide assurance that the 

effects of aging will be adequately managed. 

Based on its audit and review of the applicant‘s responses to RAIs B2.1.11-1 and B2.1.11-2, the 

staff finds that elements one through six of the applicant‘s Fire Protection Program, with 

acceptable exception and enhancements, are consistent with the corresponding program 

elements of GALL AMPs XI.M26, ―Fire Protection,‖ and XI.M27, ―Fire Water System,‖ and are, 

therefore, acceptable.

Operating Experience. LRA Section B2.1.11 summarizes OE related to the Fire Protection 

Program. The applicant stated that a degraded penetration seal was discovered during a 

preventive maintenance activity in 2002. The applicant also stated that a fire barrier impairment 

was issued, a work request was generated, and the fire barrier was repaired. The applicant 

further stated that use of a valve not designed to slowly bleed off fire system header pressure 
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caused an unexpected auto start of the fire pumps during surveillance testing in 2005. The 

applicant revised the surveillance procedure to use a different valve more suitable for throttling 

to bleed off system header pressure. 

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no OE to indicate the applicant‘s 

program would not be effective in adequately managing aging effects during the period of 

extended operation. 

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on fire

protection system components within the scope of the program, and that implementation of the 

program has resulted in the applicant taking corrective actions. The staff confirmed that the 

―operating experience‖ program element satisfies the criterion in SRP-LR Section A.1.2.3.10 

and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.11 provides the USAR supplement for the Fire Protection 

Program. The staff reviewed this USAR supplement description of the program and notes that it 

conforms to the recommended description for this type of program as described in SRP-LR 

Table 3.3-2. 

The staff also notes that the applicant committed (Commitment Nos. 8, 9, and 10) to enhance 

the existing Fire Protection Program prior to entering the period of extended operation. 

Specifically, the applicant committed to: (1) either test or replace a sample of sprinkler heads, in 

accordance with NFPA Standard 25; (2) include the elastomer shield building fire boots in the 

fire barrier penetration seal inspection program; (3) include an additional criterion (inspecting for 

corrosion) to the current RCP oil collection system receiver inspection program; and (4) perform 

a one-time inspection of the internal surfaces of the RCP oil collection system tank.

The staff 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 justification 

and determines that the AMP, with the exception, is adequate to manage the aging effects for 

which the LRA credits it. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment Nos. 8, 9, and 10, prior to the period of extended 

operation, would make the existing AMP consistent with the GALL Report 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 functions 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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3.0.3.2.9 Flow-Accelerated Corrosion Program

Summary of Technical Information in the Application. LRA Section B2.1.12 describes the 

existing Flow-Accelerated Corrosion Program as consistent, with an exception, with GALL 

AMP XI.M17, ―Flow-Accelerated Corrosion.‖ The applicant stated that the program manages the 

aging effect of wall thinning for all carbon and low-alloy steel piping and components containing 

high-energy fluids for both safety-related and nonsafety-related applications. The applicant also 

stated that the program is based on EPRI Report 1011838, ―Recommendations for an Effective 

Flow Accelerated Corrosion Program‖ (NSAC-202L, Revision 3), and predicts, detects, and 

monitors flow-accelerated corrosion in plant piping and other pressure-retaining components.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M17. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M17.

The staff also reviewed the portions of the ―scope of the program‖ and ―detection of aging 

effects‖ program elements associated with the exception to determine whether the program will 

be adequate to manage the aging effects for which it is credited. The staff‘s evaluation of the 

exception follows.

Exception. LRA Section B2.1.12 states an exception to the ―scope of the program‖ and 

―detection of aging effects‖ program elements. The applicant‘s Flow-Accelerated Corrosion 

Program is based on EPRI Report NSAC-202L, Revision 3, instead of Revision 2, as 

recommended in the GALL Report. The applicant stated that NSAC-202L, Revision 3 contains 

updated recommendations with recent developments in detection, modeling, and mitigation 

technology. The applicant also stated that NSAC-202L, Revision 3 is equivalent to NSAC-202L,

Revision 2, since these recommendations refine and enhance the earlier versions, to ensure the 

continuity of existing flow-accelerated corrosion programs. 

As discussed in the Audit Report, the staff determined that the differences between 

NSAC-202L, Revision 2 and Revision 3 include enhanced sample selection, inspection 

guidance, and additional guidance for use of OE. The staff finds the use of EPRI NSAC-202L, 

Revision 3 acceptable because the later revision provides enhancements and additional 

guidance that strengthens the Flow-Accelerated Corrosion Program.

Based on its review, the staff finds that program elements one through six of the applicant‘s 

Flow-Accelerated Corrosion Program, with an acceptable exception, are consistent with the 

corresponding program elements of GALL AMP XI.M10 and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.12 summarizes OE related to the Flow-Accelerated 

Corrosion Program. The applicant stated that prior to the 2006 refueling outage, wall thickness 

inspections performed on the condensate supply to the 14B feedwater heater revealed wall 

thinning. The applicant also stated that the data was analyzed using the CHECWORKS 

computer code, and the projected wall thickness was determined to remain above the minimum 

required wall thickness over the next operating cycle. The applicant further stated that in 2006, 

wall thinning was identified in the shells of feedwater heaters 14A and 14B, evaluated using the 
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CHECWORKS computer code, and entered into the corrective action program for subsequent 

repair.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant.

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no OE to indicate that the applicant‘s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the OE related to the 

applicant‘s program demonstrates that it can adequately manage the detrimental effects of 

aging on SSCs within the scope of the program, and that implementation of this program has 

resulted in the applicant taking corrective actions. The staff confirmed that the ―operating 

experience‖ program element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, 

therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.12 provides the USAR supplement for the 

Flow-Accelerated Corrosion Program. The staff reviewed this USAR supplement description of 

the program and notes that it conforms to the recommended description for this type of program 

as described in SRP-LR Tables 3.1-2, 3.2-2, and 3.4-2.

The staff 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 justification and determines that the AMP, with the exception, is adequate to manage the 

aging effects for which the LRA credits it. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions 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 Fuel Oil Chemistry Program

Summary of Technical Information in the Application. LRA Section B2.1.14 describes the 

existing Fuel Oil Chemistry Program as being consistent, with exceptions, to the fuel oil 

chemistry portion of GALL AMP XI.M30, ―Fuel Oil Chemistry.‖ The staff noted that the remaining 

portion of GALL AMP XI.M30, fuel oil tank inspection, is documented in LRA Section B2.1.15. 

The applicant stated that this program is credited to manage the aging effect of loss of material 

for piping and components that supply fuel oil from storage tanks to the EDGs and to the TSC 

diesel generator by maintaining potentially harmful contaminants at low concentrations. The 

applicant further stated that the fuel oil quality is monitored and controlled in accordance with 

the guidelines from ASTM Standards D975, D4057, D2709, and D6217. Furthermore, the 

applicant stated that the effectiveness of this program will be verified by the Fuel Oil Tank 

Inspections Program and the WCP Program.
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Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff noted that GALL AMP XI.M30 is comprised of a chemistry portion and a tank 

inspection portion. The staff further noted that the chemistry portion of GALL AMP XI.M30 

includes periodic sampling and analysis of fuel oil to ensure that contaminants are maintained 

within acceptable levels. Furthermore, the tank inspection portion of GALL AMP XI.M30 

includes periodic draining, cleaning, and inspection of fuel oil tanks to confirm the effectiveness 

of the chemistry control. The staff noted that the applicant has an individual program for each 

portion. The applicant‘s Fuel Oil Chemistry Program addresses only the chemistry portion of 

GALL AMP XI.M30. The applicant‘s Fuel Oil Tank Inspections Program addresses only the tank 

inspection portion of GALL AMP XI.M30. The staff‘s evaluation of the Fuel Oil Tank Inspections 

Program is documented in SER Section 3.0.3.2.11.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M30. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M30.

The staff also reviewed the portions of the ―scope of the program,‖ ―preventive actions,‖ 

―parameters monitored or inspected,‖ ―detection of aging effects,‖ and ―acceptance criteria‖ 

program elements associated with exceptions to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff‘s evaluation of these 

exceptions follows.

Exception 1. LRA Section B2.1.14 states an exception to the ―scope of the program‖ program 

element. The applicant stated that its technical specifications (TSs) do not include requirements 

for fuel purity as noted in GALL AMP XI.M30 and that the fuel oil purity and testing requirements 

are included in the applicable plant procedures.

The applicant stated that the recommendations in the GALL Report reference NUREG-1430 

through NUREG-1433. The applicant further stated it is a Westinghouse design plant but has 

not adopted NUREG-1431, ―Standard Technical Specifications Westinghouse Plants.‖ The staff 

noted that LRA Section B2.1.14 states that the plant fuel oil specifications and procedures have 

requirements that are ―similar‖ to NUREG-1431 for fuel oil purity and testing. By letter dated 

July 13, 2009, the staff issued RAI B2.1.14-1 requesting that the applicant provide a direct 

comparison between NUREG-1431 and its fuel oil specifications, along with a justification for 

any difference in fuel oil purity and testing parameters. 

In its response dated August 17, 2009, the applicant compared its fuel oil sampling procedure 

with NUREG-1431. The applicant identified that the only difference is that the kinematic 

viscosity is not verified in new fuel oil deliveries prior to offloading the diesel fuel oil into the 

storage tanks. However, the applicant further stated that kinematic viscosity is included as part 

of the new fuel oil testing that is performed by an offsite laboratory. The applicant stated that the 

OE to-date has not revealed problems associated with the kinematic viscosity for fuel oil. The

staff noted that if the results from the laboratory analysis indicate that the fuel oil parameters, 

including kinematic viscosity, were not within specifications, then corrective actions would be 

initiated. The applicant also stated that NUREG-1431 specifies a frequency of 31 days for 

determining the particulate concentration of fuel oil to be less than or equal to 10 milligrams per 

liter (mg/L). The applicant further stated that its fuel oil sampling procedure test for particulate 

concentration less than or equal to 10 mg/L is consistent with NUREG-1431; however, the test 
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frequency is quarterly. The staff noted that this frequency is consistent with the ―monitoring and 

trending‖ program element of GALL AMP XI.M30, which states that quarterly monitoring and

analysis of fuel oil provides for timely detection of conditions conducive to corrosion. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.14-1 and this exception 

acceptable because: (1) the applicant provided a direct comparison between its fuel oil sampling 

procedures with NUREG-1431; (2) the applicant‘s fuel oil sampling procedures are consistent 

with NUREG-1431 and the GALL Report, except for verification of kinematic viscosity prior to 

the new fuel oil being offloaded to the storage tanks; (3) the applicant provided an acceptable 

justification for not verifying the laboratory results for kinematic viscosity prior to the new fuel oil 

being offloaded into the storage tanks; (4) the applicant‘s OE through August 2009 (the date of 

its RAI response) has not indicated problems related to kinematic viscosity; and (5) the 

applicant will initiate corrective actions if the monitored fuel oil parameters, including kinematic 

viscosity, are not within the specified acceptance criteria in ASTM D975. The staff‘s concern 

described in RAI B2.1.14-1 is resolved.

Exception 2. LRA Section B2.1.14 states an exception to the ―preventive actions‖ program 

element. The applicant stated that its program does not include the use of biocides to minimize 

biological activity, stabilizers to prevent biological breakdown of the diesel fuel, or corrosion 

inhibitors to mitigate corrosion.

The staff noted that the applicant does not use biocides. The applicant stated that new fuel oil is 

sampled before it is added into the storage tank to ensure that the fuel or the truck container 

does not contain excessive contaminants that would be introduced to the fuel oil storage tanks. 

The staff noted that the applicant performs periodic multilevel sampling, in which oil samples are 

taken from the top, middle, and bottom of the storage tanks, to ensure that there are no 

indications of deteriorating fuel oil, water, sediments, or biological growth. The staff further noted 

that the program is focused on limiting the potential for microbiologically-influenced corrosion 

(MIC) by minimizing the water concentration of the fuel, since microbiological growth would 

occur in the water/fuel interface. The applicant stated that results and operating history have not 

indicated microbiological growth in the fuel oil storage tanks. The staff noted that the applicant 

will consider the addition of biocides into its fuel oil if future plant OE provides indications of fuel 

oil degradation or corrosion. 

Based on its review, the staff finds this portion of the exception acceptable because: (1) the 

applicant will be performing a multilevel sample of the fuel oil which will provide indications of 

contaminants including microbiological growth, (2) the applicant‘s operating history has not 

indicated that there is microbiological growth, and (3) if future plant-specific OE indicates 

microbiological growth, the applicant will consider the use of biocides as corrective actions.

The staff noted that the applicant does not use fuel stabilizers because of the frequent use of 

the diesel generators. The applicant stated that since the diesel generators are used so 

frequently, the fuel oil in the storage tank is mixed with new fuel being added in just as 

frequently. The applicant also stated that the day tanks, which are supplied by the storage 

tanks, experience a much higher turnover rate compared to the storage tanks because they are 

smaller in volume. The staff required additional information on the term ―frequent basis,‖ the 

volume of the fuel oil storage and day tanks, and the yearly fuel consumption of fuel oil from the 

tanks within the scope of license renewal. By letter dated July 13, 2009, the staff issued 

RAI B2.1.14-2 requesting that the applicant clarify what is meant by a ―frequent basis‖ and to 

clarify the volume and fuel consumption of the fuel oil storage and day tanks within the scope of 

license renewal. 
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In its response dated August 17, 2009, the applicant described that each EDG is served by one 

fuel oil storage tank (35,000 gallons) and two fuel oil day tanks (850 gallons each), and the TSC 

diesel generator is served by one fuel oil storage tank (10,000 gallons) and one fuel oil day tank 

(275 gallons). The applicant described the frequency of operation of the EDGs and stated that 

the fuel consumption over an 18-month period is approximately 37 percent of the maximum 

capacity of the EDG fuel oil storage tank, and the fuel turnover for each day tank is over seven 

times the maximum capacity. The applicant described the frequency of operation of the TSC 

diesel generator and stated that the fuel consumption over an 18-month period is approximately 

14 percent of the maximum capacity of the TSC fuel oil storage tank, and the fuel turnover for 

the day tank is over five times the maximum capacity. The staff noted that this information about 

fuel oil turnover supports this exception; however, it is not the sole basis and is also supported 

by the fuel oil analysis that is performed to ensure that the fuel oil quality is maintained and that 

biological breakdown and activity does not occur. The applicant stated that the frequency of 

sampling in the fuel oil storage tanks and fuel oil day tanks will be performed quarterly, 

consistent with GALL AMP XI.M30. The applicant further stated that the specific fuel oil 

parameters that will be monitored for fuel oil instability or breakdown are particulate 

contamination, kinematic viscosity, and distillation temperature. The staff noted that the 

applicant does not have OE to support fuel oil breakdown. The staff noted in LRA 

Section B2.1.14 that the applicant will consider the addition of fuel stabilizers if future plant OE 

provides indications of fuel oil instability or breakdown. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.14-2 and this portion of 

the exception acceptable because: (1) quarterly fuel oil analysis of particulate contamination, 

kinematic viscosity, and distillation temperature will provide indications of fuel oil breakdown or 

instability that would support the use of fuel stabilizers; (2) the applicant‘s OE has not supported 

the need for fuel stabilizers; and (3) if future plant-specific OE indicates fuel oil breakdown or 

instability, the applicant will consider the use of fuel stabilizers as corrective actions. The staff‘s 

concern described in RAI B2.1.14-2 is resolved.

The applicant stated corrosion inhibitors are not added to the diesel fuel oil and that the fuel oil 

meets the ASTM D975, which includes specifications and acceptance criteria for a copper strip 

corrosion test. The staff noted that the copper strip corrosion test is used to evaluate the 

corrosive tendencies and corrosiveness of distillate fuel oils to copper. The staff reviewed 

ASTM D130, ―Standard Test Method for Corrosiveness to Copper from Petroleum Products by 

Copper Strip Test,‖ which is the referenced test in ASTM D975, and noted that Section 10.3.1 is 

the test procedure for distillate fuel oil. The applicant stated that this test is performed as part of 

new fuel oil specifications and the fuel oil sample is tested as part of the receipt acceptance test 

by an outside laboratory. The staff noted that the applicant‘s plant-specific OE of this test for the 

last 10 years has shown that results meet the ASTM standard of the corrosiveness of distillate 

fuel oil to copper. The staff further noted that contaminants and particulates will settle to the 

bottom of the tank and will be detected during the periodic sampling of fuel oil or by periodic 

draining and inspection of the fuel oil storage tanks. The staff noted that the applicant will 

consider the addition of corrosion inhibitors into its fuel oil if future plant OE provides indications 

of fuel oil degradation or corrosion. 

Based on its review, the staff finds this portion of the exception acceptable because: (1) the 

applicant‘s test results have indicated that fuel oil used by the applicant has met the standards 

of ASTM for corrosiveness of distillate fuel oil to copper; (2) contaminants will normally settle to 

the bottom of the tank, which will be removed and detected upon the periodic sampling and 

analysis of the fuel oil storage tanks and day tanks; and (3) the applicant will consider the use of 

corrosion inhibitors as part of corrective actions if future OE indicates a need for this additive.
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Based on its review, the staff finds this exception acceptable in its entirety, as described above.

Exception 3. LRA Section B2.1.14 states an exception to the ―parameters monitored or 

inspected‖ program element. The applicant stated its program uses ASTM D975, ―Standard 

Specification for Diesel Fuel Oils,‖ for determination of water and sediment levels in fuel oil in 

lieu of ASTM D1796, which is recommended by GALL AMP XI.M30.

The applicant stated that ASTM D975 references the test method included in ASTM D2709, 

which is appropriate specifically for Grade 2-D fuel oil, for measuring water and sediment in fuel 

oil. The staff noted that ASTM D2709 is a standard that is recommended by GALL AMP XI.M30. 

The applicant stated that the test method in ASTM D1796 is meant for higher viscosity fuel oils. 

The staff reviewed ASTM D975-06b and confirmed in Section 4.1.3 that the test method in 

ASTM D1796 is meant for Grade 4-D fuel oil. The staff compared ASTM D1796 and D2709 and 

noted that both test methods are performed by the centrifuge method. 

Based on its review, the staff finds this exception acceptable because: (1) the applicant is using 

the appropriate test method, ASTM D2709, which is referenced in the GALL Report, for 

Grade 2-D fuel oil, and (2) both tests determine the water and sediment content by a centrifuge 

test method.

Exception 4. LRA Section B2.1.14 states an exception to the ―parameters monitored or 

inspected‖ and ―acceptance criteria‖ program elements. The applicant stated its program uses 

ASTM D6217, ―Standard Test Method for Particulate Contamination in Middle Distillate Fuels by 

Laboratory Filtration,‖ for the determination of particulates in lieu of ASTM D2276, which is 

recommended by GALL AMP XI.M30.

The staff reviewed ASTM D6217 and D2276 and noted that these standards are meant for 

different types of fuel oil. More specifically, the staff noted that ASTM D6217 is meant for diesel 

fuel oil, while ASTM D2276 is meant for aviation fuel. The applicant stated that since ASTM 

D6217 is meant specifically for diesel fuel oil, its program uses this standard, which is also a 

standard that is recommended by the GALL Report. The staff also noted that GALL 

AMP XI.M30 recommends a modified ASTM D2276, Method A, in which the modification is the 

use of a filter with a pore size of 3.0 micrometers (μm). The staff reviewed ASTM D6217 and 

noted that this test method uses a filter with a pore size of 0.8μm, which is more conservative 

because the 0.8μm filter will be capable of capturing particulates that a 3.0μm filter cannot 

capture. 

Based on its review, the staff finds this exception acceptable because: (1) the applicant is using 

ASTM D6217, which is meant for the type of fuel oil used by the applicant; (2) ASTM D6217 is a 

standard that is recommended by the GALL Report; and (3) ASTM D6217 uses a smaller filter 

size of 0.8μm compared to the GALL AMP XI.M30 recommendation of 3.0μm.

Exception 5. LRA Section B2.1.14 states an exception to the ―detection of aging effects‖ 

program element. The applicant stated that its program drains and visually inspects a sample of 

the fuel oil obtained from the bottom of the day tanks on a monthly basis in lieu of taking 

multilevel samples of day tanks, as recommended by GALL AMP XI.M30.

The applicant stated that the EDG fuel oil day tanks and the TSC fuel oil day tank are supplied 

by their respective diesel fuel oil storage tanks. The applicant further stated that each day tank 

is sampled monthly by having approximately 1 gallon of fuel removed near the tank bottom and 

then visually inspected for water and sediments. By letter dated July 13, 2009, the staff issued 
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RAI B2.1.14-3 requesting that the applicant justify why multilevel sampling is not performed for 

the fuel oil day tanks and to justify why a visual inspection is sufficient compared to sending the 

fuel oil sample to a laboratory for testing, as stated in ASTM D4057. 

In its response dated August 17, 2009, the applicant amended its LRA to remove Exception 5. 

By letter dated November 13, 2009, the applicant clarified its response to RAI B2.1.14-3 and 

amended its LRA to add Exception 5, which states the following:

The Fuel Oil Chemistry program provides for monthly visual inspections and will 

be enhanced to provide quarterly laboratory analysis of fuel oil samples obtained 

from the bottom of the day tanks in lieu of taking multilevel samples of the day 

tanks as recommended by NUREG-1801, Section XI.M30.

The applicant stated that laboratory analysis of fuel oil for water, sediment, and particulates from 

the four EDG fuel oil day tanks and the one TSC fuel oil day tank will be performed consistent 

with the quarterly surveillance frequency for the respective fuel oil storage tanks. The applicant 

further stated that multilevel sampling is not warranted based on the relatively small volume of 

the day tanks (850 gallons for each EDG fuel oil day tank and 275 gallons for the TSC fuel oil 

day tank) and the relatively high turnover rate with respect to the capacity of the tanks (over 

seven times the capacity of each EDG fuel oil day tank and over five times the capacity of the 

TSC fuel oil day tank over an 18-month period). The staff noted that the sample points are 

tapped off the respective supply lines; therefore, the samples are representative of the fuel 

being drawn or used by the diesel generators. The applicant stated that the EDG fuel oil day 

tanks have a 3-inch riser from the tank bottom to the sample point, and the TSC fuel oil day tank 

has a true bottom sample. The staff noted that particulates, water, and contamination will settle 

toward the bottom of the tanks; therefore, the samples being drawn from the tanks in these 

configurations will represent a conservative sample. The applicant stated that it will perform a 

confirmatory one-time inspection of the fuel oil day tanks, as discussed in SER 

Section 3.0.3.2.11. 

Based on its review, the staff finds the applicant‘s amended response to RAI B2.1.14-3 and 

exception acceptable because: (1) the applicant will be performing quarterly laboratory analyses 

of the fuel oil samples from the fuel oil day tanks, consistent with the recommendations in GALL 

AMP XI.M30; (2) the fuel oil samples that are being taken from the tanks provide the worst-case 

fuel oil sample, since contaminants and particulates will settle at the bottom of the tank, in 

comparison to a multilevel sample; and (3) the applicant will perform a confirmatory one-time 

inspection of the fuel oil day tanks to verify the condition of tank interiors. The staff‘s concern 

described in RAI B2.1.14-3 is resolved.

The applicant provided Commitment No. 30 to perform quarterly laboratory testing of the EDG 

and TSC diesel generator day tank fuel oil samples prior to the period of extended operation, 

which is consistent with the recommendations of GALL AMP XI.M30. 

Based on its audit and review of the applicant‘s responses to RAIs B2.1.14-1, B2.1.14-2, and 

B2.1.14-3, as amended by November 13, 2009, the staff finds that elements one through six of 

the applicant‘s Fuel Oil Chemistry Program, with acceptable exceptions, are consistent with the 

corresponding program elements of GALL AMP XI.M30 and are, therefore, acceptable. The 

staff‘s determination of consistency for the tank inspection portion of GALL AMP XI.M30 is 

documented in SER Section 3.0.3.2.11.
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Operating Experience. LRA Section B2.1.14 summarizes OE related to the Fuel Oil Chemistry 

Program. The staff noted that in November 2006, during a tank sampling of the 1B EDG fuel oil 

storage tank, the applicant discovered an unusual amount of particulates. Although the 

applicant determined that the amount of particulates discovered was below the acceptable 

limits, the applicant chose to evaluate the condition to establish the source and cause of the 

unusual amount of particulates. The staff noted that the applicant concluded that the excess 

particulate was from maintenance work performed during the refueling outage to replace four 

flexible hoses. The staff noted that the applicant has planned for the corrosion to be removed 

from the inlet flange with a method to minimize or eliminate the potential for the corrosion 

products from falling into the tank during the cleaning process. During its audit, the staff noted 

that the applicant has completed the actions to remove the excess corrosion from the inlet 

flange and considered the potential that corrosion products may fall into the tank during the 

cleaning process. The staff noted that the applicant took corrective actions by: (1) identifying the 

source of the excess corrosion, (2) performing an evaluation to determine if the 1A fuel oil 

storage tank was also affected, and (3) removing the excess corrosion.

The staff noted that the applicant performed an evaluation in February 2007 on the acceptable 

use of ultra-low-sulfur diesel (ULSD) fuel oil in the EDGs and TSC diesel generator after the 

issuance of NRC IN 2006-22, ―New Ultra-Low-Sulfur Diesel Fuel Oil Could Adversely Impact 

Diesel Engine Performance.‖ The applicant stated that in June 2007, its evaluation concluded 

that there were no operability concerns with the use of ULSD in its EDGs. The applicant later 

performed a subsequent evaluation for the use of ULSD in the TSC diesel generator and 

concluded that the use of ULSD was appropriate. The applicant‘s condition report directed that 

the long-term issues (e.g., compatibility with lube oil, elastomers, storage tank interior surfaces, 

and long-term fuel storage) and short-term issues (e.g., heat content and lubricity) be evaluated. 

The staff reviewed the applicant‘s evaluation and noted that the conclusion was made that 

ULSD is acceptable for use in the EDG and TSC diesel generator after consideration of the 

long-term and short-term issues with using ULSD. The staff determined that after the issuance 

of IN 2006-22, the applicant took actions to evaluate the potential long and short-term issues 

with using ULSD and determined its acceptable use.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. The 

staff also confirmed that the applicant has addressed OE identified after the issuance of the 

GALL Report. As discussed in the Audit Report, the staff conducted an independent search of 

the plant OE information to determine whether the applicant had adequately incorporated and 

evaluated OE related to this program. 

During its review, the staff identified OE which could indicate that the applicant‘s program may 

not be effective in adequately managing aging effects during the period of extended operation. 

The staff determined the need for additional clarification, which resulted in the issuance of an 

RAI. 

The staff noted that after the issuance of Revision 1 of the GALL Report, the staff issued 

IN 2009-02, ―Biodiesel in Fuel Oil Could Adversely Impact Diesel Engine Performance.‖ The 

staff further noted this IN discusses potential issues that may occur with the use of B5 blend fuel 

oil, such as suspended water particles, biodegradation of B5, and material incompatibility. By 

letter dated July 13, 2009, the staff issued RAI B2.1.14-4 requesting that the applicant

summarize the actions that were taken to determine the impact of IN 2009-02 and the use of 

biodiesel fuel oil, and if actions have not been taken yet, describe the actions that will be taken 

to determine the impact of IN 2009-02 and the acceptable or unacceptable use of biodiesel. The 
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staff further requested that the applicant clarify any problems encountered with the use of 

biodiesel and the associated corrective actions to prevent reoccurrence in the future, if biodiesel 

is currently being used. Finally, the staff requested that the applicant clarify the actions that 

were taken and/or will be taken to prevent the addition of biodiesel into the fuel oil supply, and to 

describe actions that will be taken if it is determined that biodiesel has been added into the fuel 

oil supply, if biodiesel has been determined to be not acceptable for use. 

In its response dated August 17, 2009, the applicant stated that the applicability of IN 2009-02 

has been evaluated and the conclusion from this evaluation is introduction of B5 blend fuel oil is 

controlled by purchasing only Amoco Premier diesel fuel with a purchase order that specifically 

prohibits biodiesel. The applicant stated that the current purchase order was reviewed to 

confirm that this controlling provision is still in place. The staff noted that in addition to this 

purchase order, the applicant does verify the absence of B5 blend fuel oil as part of the 

laboratory analysis performed for the quarterly fuel oil samples. However, the applicant stated 

that the results of the laboratory analysis are not received prior to the addition and mixing of the 

new fuel oil into the storage tanks. The applicant indicated that if the presence of biodiesel fuel 

oil is identified by the laboratory analysis, this will be entered into their corrective action program 

which will include an operability evaluation of the diesel generators along with the 

implementation of appropriate corrective actions. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.14-4 acceptable 

because the applicant: (1) has evaluated the applicability of recent OE, (2) has taken measures 

to prevent the addition of potentially harmful biodiesel fuel oil, (3) performs a laboratory analysis 

in order to verify that biodiesel fuel oil is absent, and (4) will implement corrective actions and 

perform an operability evaluation for the diesel generators if biodiesel is introduced to the fuel oil 

supply. The staff‘s concern described in RAI B2.1.14-4 is resolved.

Based on its audit and review of the application and review of the applicant‘s response to 

RAI B2.1.14-4, the staff finds that OE related to the applicant‘s program demonstrates that it can 

adequately manage the detrimental effects of aging on SSCs within the scope of the program, 

and that implementation of the program has resulted in the applicant taking corrective actions. 

The staff confirmed that the ―operating experience‖ program element satisfies the criterion in 

SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.14 provides the USAR supplement for the Fuel Oil 

Chemistry Program. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.3-2. The staff‘s review of the tank inspection portion of the USAR supplement 

is documented in SER Section 3.0.3.2.11.

By letter dated August 17, 2009, the applicant committed (Commitment No. 30) to perform 

quarterly laboratory analyses of fuel oil samples from all fuel oil day tanks. In its commitment, 

the staff noted that the applicant referenced the incorrect ASTM standard (ASTM D4057). By 

letter dated November 13, 2009, the applicant amended Commitment No. 30 to state that the 

acceptance criteria of laboratory testing will be consistent with requirements in ASTM D975-06b, 

for water and sediment, and ASTM D6217, for particulates. The staff noted that the amended 

ASTM standards referenced in Commitment No. 30 are correct and consistent with the 

recommendations provided in GALL AMP XI.M30 and are, therefore, acceptable.

The staff determines that the information in the USAR supplement, as amended, 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 Fuel Oil Chemistry Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent for the sampling and analysis for fuel oil to mitigate 

corrosion. The staff‘s evaluation and conclusion for the tank inspections is documented in SER 

Section 3.0.3.2.11. 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 the LRA credits it. The staff reviewed and confirmed that the implementation of 

Commitment No. 30 prior to the period of extended operation would make the existing AMP 

consistent with the GALL Report 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 functions 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 Fuel Oil Tank Inspections Program

Summary of Technical Information in the Application. LRA Section B2.1.15 describes the 

existing Fuel Oil Tank Inspections Program as being consistent, with an enhancement, to one 

component of GALL AMP XI.M30, ―Fuel Oil Chemistry.‖ The staff noted that the remaining 

component is documented in LRA Section B2.1.14. The applicant stated that this program is 

credited to manage the aging effect of loss of material for the internal surfaces of underground 

diesel generator fuel oil storage tanks. The applicant further stated that this program periodically 

drains, cleans, and inspects the internal surfaces of the tanks, and the schedule for cleaning 

and inspection is consistent with the recommendations of RG 1.137, Revision 1, ―Fuel-Oil 

Systems for Standby Diesel Generators.‖ Furthermore, the applicant stated that its program has 

provisions to perform an ultrasonic test of the fuel oil storage tank bottom plate to ensure that 

the minimum wall thickness requirements are satisfied and that degradation is not occurring.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff noted that GALL AMP XI.M30 is comprised of a chemistry portion and a tank 

inspection portion. The staff further noted that the chemistry portion of GALL AMP XI.M30 

includes periodic sampling and analysis of fuel oil to ensure that contaminants are maintained 

within acceptable levels. Furthermore, the tank inspection portion of GALL AMP XI.M30 

includes periodic draining, cleaning, and inspection of fuel oil tanks to confirm the effectiveness 

of the chemistry control. The staff noted that the applicant has an individual program for each 

portion. The applicant‘s Fuel Oil Chemistry Program addresses only the chemistry portion of 

GALL AMP XI.M30. The applicant‘s Fuel Oil Tank Inspections Program addresses only the tank 

inspection portion of GALL AMP XI.M30. The staff‘s evaluation of the Fuel Oil Chemistry 

Program is documented in SER Section 3.0.3.2.10.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M30. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M30, with the exception of the program description. For the program description, the 

staff determined the need for additional clarification, which resulted in the issuance of an RAI.
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During its review of the applicant‘s program description, the staff noted that the EDG day tanks 

and the TSC diesel generator day tank are not included in the scope of this program. The staff 

noted from LRA Table 3.3.2-19 that these day tanks credit the WCP Program. By letter dated 

July 13, 2009, the staff issued RAI B2.1.15-1 requesting that the applicant clarify if the WCP 

Program will periodically drain, clean, and visually inspect the interior of the tank and perform an 

ultrasonic test of the bottom plate to determine minimum wall thickness for the EDG day tanks 

and the TSC diesel generator day tank, consistent with the recommendations of GALL 

AMP XI.M30. Furthermore, the staff requested that if the WCP Program does not perform these 

activities, the applicant should justify the basis for not performing these activities for these tanks. 

Also, the staff requested that the applicant clarify how it will ensure that the internal surfaces of 

these day tanks are adequate if some type of inspection is not performed to assess the 

condition of the interior, including the tank bottom where contamination, water, and particulates 

are likely to settle and accumulate. 

In its response dated August 17, 2009, the applicant stated that the WCP Program will perform 

a one-time inspection for all four EDG fuel oil day tanks and the one TSC diesel generator day 

tank to confirm the effectiveness of the Fuel Oil Chemistry Program on the internal surfaces of 

these tanks. The applicant further explained that this inspection will consist of an exterior 

surface ultrasonic inspection of all the fuel oil day tanks and then, based on the results, the EDG 

fuel oil day tank that has the most limiting results will be drained, cleaned, and visually 

inspected as the leading indicator for the remaining tanks. The staff noted that the ultrasonic 

inspection from the exterior surface will be capable of detecting material wastage that may be 

occurring on the internal surface of these tanks. The applicant stated that if ultrasonic inspection 

results indicate loss of material that may affect the intended function of the fuel oil day tanks, 

then those tanks will also be drained, cleaned, and inspected. The applicant stated that an 

internal visual inspection will be performed on an EDG fuel oil day tank because the sample 

points are not true-bottom, but rather, these tanks have a 3-inch riser above the tank bottom. 

The staff noted that because these tanks have a 3-inch riser and have been in service for 

approximately 10 years longer than the TSC diesel generator day tank, there is a potential that 

there is a build-up of contaminants in comparison to the one TSC diesel generator day tank. 

The staff also noted that the TSC diesel generator day tank has a true-bottom sample point so 

that fuel oil samples will provide indication of the worst case scenario for contaminants and 

build-up since they will settle toward the bottom of the tank. Furthermore, the applicant 

explained that the TSC diesel generator day tank design does not have a manway to allow 

access for internal cleaning and inspection. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.15-1 and the applicant‘s 

use of a one-time inspection for the fuel oil day tanks acceptable because: (1) the applicant will 

perform exterior ultrasonic inspection of all fuel oil day tanks and internal cleaning and visual 

inspection of the most limiting EDG fuel oil day tank, (2) the applicant has included an 

inspection expansion based on the one-time inspection results, and (3) quarterly sampling and 

laboratory analysis from all fuel oil day tanks will determine the quality of the fuel oil. The staff‘s 

concern described in RAI B2.1.15-1 is resolved.

The staff also reviewed the portions of the ―preventive actions‖ and ―detection of aging effects‖ 

program elements associated with the enhancement to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff‘s evaluation of this 

enhancement follows.
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Enhancement. LRA Section B.2.1.15 states an enhancement to the ―preventive actions‖ and 

―detection of aging effects‖ program elements. The applicant stated its program will be 

enhanced to provide guidance for the periodic draining, cleaning, and inspection activities. The 

applicant described the details of this enhancement, which will include a visual inspection of the 

in-scope tanks for loss of material or other signs of degradation, such as coating degradation, 

abnormal rust, sludge, biological growth, and metal damage. Furthermore, thickness 

measurements for the EDG fuel oil storage tanks‘ bottoms and the TSC diesel generator fuel oil 

storage tank bottom will also be performed. The applicant stated that these inspections will be 

performed prior to entering the period of extended operation, and subsequent visual inspections 

and volumetric examinations will be performed on a frequency consistent with scheduled tank 

internals inspection activities.

The applicant stated in LRA Section B2.1.15 that this enhancement will proceduralize the 

requirements to drain, clean, and inspect the in-scope fuel oil storage tanks, and the 

requirement to visually inspect the internal surfaces and to measure the thickness of tank 

bottom surfaces of the in-scope tanks. During its audit, the staff noted that the applicant only 

has a preventive maintenance work order to inspect and clean the EDG fuel oil storage tanks 

and the TSC diesel generator fuel oil storage tank. The staff determined that since there 

currently are no formalized procedures to clean and inspect the fuel oil storage tanks, this 

enhancement is required to proceduralize the current preventive maintenance work order, the 

requirement to visually inspect the internal surfaces, and the measurement of the thickness of 

tank bottom surfaces of the in-scope fuel oil storage tanks.

Based on its review, the staff finds this enhancement acceptable because the applicant will be 

formalizing procedures for the activities to periodically drain, clean, and perform inspection 

activities, which include thickness measurements of the bottom plate to determine wall 

thickness, consistent with the recommendations of GALL AMP XI.M30.

Based on its audit and review of the applicant‘s response to RAI B2.1.15-1, the staff finds that 

elements one through six of the applicant‘s Fuel Oil Tank Inspections Program, with an 

acceptable enhancement, are consistent with the corresponding program elements of GALL 

AMP XI.M30 and are, therefore, acceptable. The staff‘s determination of consistency for the 

chemistry portion of GALL AMP XI.M30 is documented in SER Section 3.0.3.2.10.

Operating Experience. LRA Section B2.1.15 summarizes OE related to the Fuel Oil Tank 

Inspections Program. During its audit, the staff noted that in October 2001, the applicant 

performed a cleaning and inspection of the EDG fuel oil storage tanks. The staff reviewed the 

results of these inspections and noted that the ―A‖ EDG fuel oil storage tank had seven gouge 

locations on the shell and that eight gouge locations were on the shell of the ―B‖ EDG fuel oil 

storage tank. The applicant entered the discovery of these gouges in its corrective action 

program. The results of the inspection noted that these gouges were left during original 

construction. The applicant evaluated the gouges in the shells of the EDG fuel oil storage tanks 

and concluded that the maximum increased stress from the gouges does not exceed the 

allowable stress limit; therefore, these tanks are acceptable for continued operation. The staff 

noted that the applicant initiated corrective actions and determined that these tanks were 

suitable for continued use. The staff noted these tanks will be inspected on a 10-year frequency, 

consistent with RG 1.137.

The staff noted that the applicant also performed a tank inspection of the TSC diesel generator 

fuel oil storage tank. The results of this inspection concluded that the tank was in ―excellent 

condition‖ and that it was suitable for continued operation. During its inspection, the applicant 
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noted one area of coating discoloration but the base metal was still protected. The applicant 

determined that the tank was acceptable for continued service. The staff noted that the 

applicant will perform a tank inspection of the TSC diesel generator fuel oil storage tank on a 

10-year frequency, consistent with RG 1.137.

The staff reviewed the OE in the application and during the audit to determine whether the 

applicable aging effects and industry and plant-specific OE were reviewed by the applicant. As 

discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. 

During its review, the staff found no OE to indicate that the applicant‘s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.15 provides the USAR supplement for the Fuel Oil Tank 

Inspections Program. The staff reviewed this USAR supplement description of the program and 

notes that it conforms to the recommended description for this type of program as described in 

SRP-LR Table 3.3-2. The staff‘s review of the chemistry analysis portion of the USAR 

supplement is documented in SER Section 3.0.3.2.10.

The staff also notes that the applicant committed (Commitment No. 11) to enhance the Fuel Oil 

Tank Inspections Program prior to entering the period of extended operation. Specifically, the 

applicant committed to formalize guidance for the periodic draining, cleaning, and inspection 

activities for the fuel oil storage tanks prior to the period of extended operation. By letter dated 

August 17, 2009, the applicant committed (Commitment No. 31) to enhance the WCP Program

prior to entering the period of extended operation. Specifically, the applicant committed to 

perform ultrasonic inspections of the fuel oil day tanks prior to the period of extended operation.

The staff determines that the information in the USAR supplement, as amended, 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 Tank Inspections 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent for the tank inspections that confirm the 

effectiveness of the fuel oil chemistry. The staff‘s evaluation and conclusion for the sampling 

and analysis for fuel oil is documented in SER Section 3.0.3.2.10. Also, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 11, prior to the 

period of extended operation, would make the existing AMP consistent with the GALL Report 

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 functions 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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3.0.3.2.12 Inspection of Overhead Heavy Load and Refueling Handling Systems Program

Summary of Technical Information in the Application. LRA Section B2.1.16 describes the 

existing Inspection of Overhead Heavy Load and Refueling Handling Systems Program as 

consistent, with an enhancement, with GALL AMP XI.M23, ―Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems.‖ The applicant stated that this 

program manages the aging effect of loss of material due to general corrosion and rail wear for 

steel heavy load and refueling handling cranes, trolleys, bridges, and rails within the scope of 

license renewal by performing periodic visual inspections of the heavy load and refueling 

handling crane, trolley, bridge, and rail structural members. The applicant also stated that this 

program visually inspects structural bolting that is associated with structural members for 

general corrosion and tightness. The applicant further stated that overhead heavy load cranes 

are controlled in accordance with the guidance provided in NUREG-0612, ―Control of Heavy 

Loads at Nuclear Power Plants.‖

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. 

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M23. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M23 with the 

exception of the ―scope of the program‖ program element. For this element, the staff determined 

the need for additional clarification, which resulted in the issuance of an RAI, as discussed 

below.

GALL AMP XI.M23 recommends that the program manage the effects of general corrosion on 

the crane and structural components and the effects of wear on the rails in the rail system under 

the ―scope of the program‖ program element description; however, during its review, the staff 

found that the applicant‘s Overhead Heavy Load and Refueling Handling Systems Program 

includes visual inspection of the structural bolting associated with structural members for 

general corrosion and tightness. By letter dated March 11, 2010, the staff issued RAI B2.1.16-1 

requesting that the applicant justify how a visual inspection will verify tightness of bolting. 

Additionally, the staff requested that the applicant verify if this bolting is also managed by the 

Bolting Integrity Program, and if not, whether it conducts volumetric examinations on bolting 

larger than 1 inch with a yield strength greater than or equal to 150 ksi.

In its response dated March 26, 2010, the applicant stated that visual inspection of bolting for 

tightness is performed by observation of cracks in coatings, visible gaps between bolts and 

structural members, lack of full thread engagement of nuts, and excessive flexing of structural 

members. The applicant also stated that the two plant-specific OE examples included in LRA 

Section B2.1.16 were examples of loose bolting that were identified by visual inspection. The 

applicant further stated that it has no high-strength structural bolting greater than 1 inch in 

diameter associated with the structural members of cranes, and that bolting associated with 

crane structural members is not managed by the Bolting Integrity Program. 

The staff finds this response acceptable because: (1) the methods used to perform the visual 

inspection for tightness of bolting are appropriate for and have been effective at identifying 

loosened bolting, and (2) the applicant has no high-strength bolting with a diameter greater than 

1 inch associated with crane structural members that would require management in accordance 

with the Bolting Integrity Program. The staff‘s concern described in RAI B2.1.16-1 is resolved.
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The staff also reviewed the portions of the ―parameters monitored or inspected‖ program 

element associated with the enhancement to determine whether the program will be adequate 

to manage the aging effects for which it is credited. The staff‘s evaluation of this enhancement 

follows.

Enhancement. LRA Section B.2.1.16 states an enhancement to the ―parameters monitored or 

inspected‖ program element. The applicant stated that the inspection criteria of the Inspection of 

Overhead Heavy Load and Refueling Handling Systems Program will be enhanced to clarify the 

requirements of visual inspection of structural members, including structural bolting, of the 

in-scope heavy load and refueling handling cranes and associated equipment.

The staff noted that the ―parameters monitored or inspected‖ program element of GALL 

AMP XI.M23 states the program evaluates the effectiveness of the maintenance monitoring 

program and the effects of past and future usage on the structural reliability of cranes. The 

applicant stated in LRA Section B2.1.16 that this enhancement will clarify the requirements of 

visual inspection of structural members, including structural bolting, of the in-scope heavy load 

and refueling handling cranes and associated equipment. The staff noted that the applicant 

considered plant-specific OE, as described in the ―operating experience‖ program element, 

when evaluating the effectiveness of this program. The staff also noted that the applicant will 

appropriately incorporate its plant-specific OE when enhancing its program to clarify the 

requirements of visual inspection of structural members, including structural bolting, of in-scope 

components. The staff further noted that the applicant committed (Commitment No. 12) to 

implement this enhancement prior to the period of extended operation. On the basis of its 

review, the staff finds this enhancement acceptable because the applicant‘s actions associated 

with this enhancement considered plant-specific OE and evaluated the effectiveness of its 

program consistent with the recommendations of the GALL Report.

Based on its audit, the staff finds that elements one through six of the applicant‘s Inspection of 

Overhead Heavy Load and Refueling Handling Systems Program, with an acceptable 

enhancement, are consistent with the corresponding program elements of GALL AMP XI.M23 

and are, therefore, acceptable.

Operating Experience. LRA Section B.2.1.16 summarizes OE related to the Inspection of 

Overhead Heavy Load and Refueling Handling Systems Program. The applicant included two 

instances of applicable OE in the LRA. The applicant stated that in June 2001, it observed 

excessive flexing of an I-beam that supports the trolley drive system for the auxiliary building 

crane. The applicant also stated that it performed an inspection of the beam support system and 

discovered that the bolts in the cross-plate support at the center of the I-beam had loosened. 

The applicant further stated that these bolts were inspected and then re-torqued. In order to 

prevent a reoccurrence of loosened bolts from structural members, the applicant took corrective 

actions to periodically inspect bolts for all structural members of the crane. The staff noted that 

the applicant identified the loosened bolts, initiated corrective actions to re-torque the bolts, and 

performed inspections to ensure the components were in satisfactory condition, and then 

considered this OE for enhancing this program.

The applicant stated a similar incident occurred in August 2002, when the applicant identified a 

loose bolted connection on a cross plate connection for the trolley drive system of the auxiliary 

building crane. The applicant took corrective actions to replace and re-torque the fastener and 

to revise the procedures to include cross-plate bolt inspections, as well as an increase in the 

frequency of the inspections. The staff noted that the applicant identified the loosened bolts, 
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initiated corrective actions to replace and re-torque the fastener, and then considered this OE 

for enhancing this program.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff found no OE to indicate that the applicant‘s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.

USAR Supplement. LRA Section A2.1.16 provides the applicant‘s USAR supplement for the 

Inspection of Overhead Heavy Load and Refueling Handling Systems Program. The staff 

reviewed this USAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Table 3.3-2. 

The staff also notes that the applicant committed (Commitment No. 12) to enhance the 

Inspection of Overhead Heavy Load and Refueling Handling Systems Program prior to entering 

the period of extended operation. Specifically, the applicant committed to clarify the 

requirements of visual inspection of structural members, including structural bolting, of the 

in-scope heavy load and refueling handling cranes and associated equipment.

The staff 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 and audit of the applicant‘s Inspection of Overhead 

Heavy Load and 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 enhancement and confirmed that its implementation, through 

Commitment No. 12 prior to the period of extended operation, would make the existing program 

consistent with the GALL Report 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 functions 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 Metal-Enclosed Bus Program

Summary of Technical Information in the Application. LRA Section B2.1.18 describes the 

existing Metal-Enclosed Bus Program as consistent, with an enhancement, with GALL 

AMP XI.E4, ―Metal-Enclosed Bus.‖ The applicant stated that its program manages the aging 

effects of reduced insulation resistance, electrical failure, and loosening of bolted connections 

for non-segregated metal-enclosed bus and internal components within the scope of license 
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renewal. The applicant stated the program: (1) performs visual inspections, using a sampling 

methodology, of sections of the in-scope metal-enclosed bus looking for cracks, corrosion, 

foreign debris, excessive dust build up, and evidence of water intrusion; and (2) performs a 

visual inspection of component insulation surface anomalies, such as discoloration, cracking, 

chipping, or surface contamination. The applicant also stated that its program is supported by 

the Structures Monitoring Program, which performs visual inspection of portions of the 

metal-enclosed bus enclosure assemblies. The applicant further stated that the inspection of the 

metal-enclosed bus will be completed prior to the period of extended operation and performed 

every 5 years thereafter.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.E4. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.E4, with the exception of the area discussed below. For this area, the staff determined

the need for additional clarification, which resulted in the issuance of an RAI.

During its audit, the staff noted that LRA Sections B2.1.18 and A2.1.18, and the applicant‘s 

program basis document state that the program performs visual inspections, using a sampling 

methodology of sections of the in-scope metal-enclosed bus. The staff further noted that the 

program description of GALL AMP XI.E4 states that the purpose of the program is to provide an 

inspection of the metal-enclosed bus. GALL AMP XI.E4 recommends inspecting all internal 

portions of metal-enclosed bus and limits the application of sampling to accessible 

metal-enclosed bus bolted connections only. By letter dated July 13, 2009, the staff issued 

RAI B2.1.18-1 requesting that the applicant provide justification for specifying that selected 

sections of metal-enclosed bus will be sampled for visual inspections. 

In its response dated August 17, 2009, the applicant stated that consistent with GALL 

AMP XI.E4, its program, described in LRA Section B2.1.18, includes the inspection of all 

in-scope metal-enclosed buses. In addition, the applicant revised the scope of the 

metal-enclosed bus inspection, as stated in LRA Section A2.1.18, by replacing the third 

paragraph with:

The program performs visual inspections of the in-scope MEB [metal-enclosed 

bus] for cracks, corrosion, foreign debris, excessive dust buildup, and evidence 

of water intrusion, and performs visual inspections of the component insulation 

for surface anomalies, such as discoloration, cracking, chipping, or surface 

contamination.

The program performs visual inspections of a sample of accessible MEB bolted 

connections that are covered with heat shrink tape, sleeving, insulated boots, 

etc., for surface anomalies, such as discoloration, cracking, chipping, or surface 

contamination.
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The applicant also stated that it will also clarify the frequency of the metal-enclosed bus and 

bolted connection inspections in LRA Section A2.1.18 by replacing the fourth paragraph of the 

program description, as shown below:

The inspection of all metal enclosed bus will be completed prior to the period of 

extended operation and will be repeated every 10 years thereafter.

The inspection of the sample of bolted connections will be completed prior to the 

period of extended operation and will be repeated every 5 years thereafter.

Furthermore, the applicant stated that it will revise the frequency of the metal-enclosed bus and 

bolted connection inspections in Commitment No. 13, as described below:

Thereafter, the inspection of all metal enclosed bus will not exceed a 10-year 

interval and the inspection of the sample of bolted connections will not exceed a 

5-year interval.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.18-1 acceptable 

because: (1) the applicant revised LRA Section A2.1.18 to clarify that the applicant‘s sampling 

methodology will visually inspect all in-scope metal-enclosed bus, consistent with GALL 

AMP XI.E4, and (2) the applicant also revised the metal-enclosed bus and bolted connection 

inspection frequencies, consistent with GALL AMP XI.E4. The staff, therefore, considers 

RAI B2.1.18-1 resolved.

The applicant‘s metal-enclosed bus bolted connection sampling methodology is referenced in its 

program basis document which states that a sample of metal-enclosed bus connections will be 

inspected. Furthermore, the staff noted the applicant has procedures that implement the 

metal-enclosed bus bolted connection sampling methodology based on a joint selection matrix 

that uses completed inspection information to determine the next set of connections for 

inspection and in conjunction with the inspection frequency of the Metal-Enclosed Bus Program, 

which is consistent with GALL AMP XI.E4.

The program description of LRA Section B2.1.18 states that the program is supported by the 

Structures Monitoring Program, which performs a visual inspection of portions of the 

metal-enclosed bus enclosure assemblies. The staff reviewed the applicant‘s Structures 

Monitoring Program and noted that it does not specify visual inspection for the metal-enclosed 

bus enclosure assemblies. By letter dated July 13, 2009, the staff issued RAI B2.1.18-2

requesting the applicant confirm that the Structures Monitoring Program visually inspects the 

exterior portions of the metal-enclosed bus, consistent with GALL Report Table VI, items 

VI.A-12 and VI.A-13. 

In its response dated August 17, 2009, the applicant stated that Commitment No. 22, associated 

with the Structures Monitoring Program, will be enhanced to clearly define structures, structural 

elements, and miscellaneous structural commodities that are in-scope. The applicant also 

stated that the defined scope includes the metal-enclosed bus enclosure assemblies, structural 

supports, and enclosure seals. The applicant further stated that as enhanced, the Structures 

Monitoring Program supports inspections of the metal-enclosed bus consistent with GALL 

Report Table VI, items VI.A-12 and VI.A-13 by requiring visual inspection of portions of the 

metal-enclosed bus enclosure assemblies. 
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Based on its review, the staff finds the applicant‘s response to RAI B2.1.18-2 acceptable 

because: (1) the applicant will enhance the Structures Monitoring Program to include visual 

inspections of the metal-enclosed bus consistent with GALL Report Table VI, items VI.A-12 and 

VI.A-13, and (2) the applicant‘s program is consistent with GALL AMP XI.E4 with respect to 

visual inspection of metal-enclosed bus enclosure assemblies. The staff, therefore, considers 

RAI B2.1.18-2 resolved.

The staff also reviewed the portions of the ―parameters monitored or inspected,‖ ―detection of 

aging effects,‖ ―acceptance criteria,‖ and ―corrective actions‖ program elements associated with 

enhancement to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff‘s evaluation of this enhancement follows.

Enhancement. LRA Section B2.1.18 states an enhancement to the ―parameters monitored or 

inspected,‖ ―detection of aging effects,‖ ―acceptance criteria,‖ and ―corrective actions‖ program 

elements. The applicant stated that the existing program will be augmented to include periodic 

visual inspections of the metal-enclosed bus internal surfaces, bus supports, bus insulation, 

taped joints, and boots (e.g., bus connections) for signs of degradation or aging. The applicant 

stated that the Metal-Enclosed Bus Program will visually inspect internal surfaces for cracks, 

corrosion, aging degradation of insulation material, foreign debris, excessive dust build up, and 

evidence of moisture intrusion. The applicant also stated that bus insulation, taped joints, and 

boots will be visually inspected for signs of embrittlement, chipping, cracking, melting, swelling 

surface contamination, or discoloration, which may indicate overheating or aging degradation. 

The applicant stated that the internal bus supports will be visually inspected for structural 

integrity and signs of cracks. Finally, the applicant stated that corrective actions will be initiated 

for any observed aging degradation. 

The applicant stated the enhancement will require the use of visual inspection of internal 

portions of the metal-enclosed bus, bus insulation, and internal bus supports, which impacts the 

―parameters monitored or inspected‖ program element. The applicant stated the enhancement 

will require the inspection of the metal-enclosed bus internal surfaces, accessible covered 

bolted connections, bus insulation, and internal bus supports, which impacts the ―detection of 

aging effects‖ program element. In addition, the applicant‘s program basis document clarifies 

that it has only accessible bolted connections covered with heat shrink tape, sleeving, insulated 

boots, etc. Based on this, the staff noted that the inspections will be completed prior to the 

period of extended operation and every 5 years thereafter, consistent with GALL AMP XI.E4. In 

addition, the applicant stated in its program basis document that should degradation be 

observed and further evaluation required, the program allows for removal of the bus bolted 

connection insulation, inspection of the connection, and a resistance measurement to be 

performed. The applicant further stated that the resistance value will be specified in its 

implementing procedure. The applicant stated the enhancement will require further investigation 

and evaluation should unacceptable visual inspection of the metal-enclosed bus internal 

surfaces, bus supports, or internal component insulation be observed, which impacts the 

―acceptance criteria‖ program element. The applicant stated that this enhancement will require 

that aging degradation that is observed during visual inspections, including that which requires

corrective action, will be entered into the applicant‘s corrective action program, which impacts 

the ―corrective actions‖ program element.

Based on its review, the staff finds this enhancement acceptable because: (1) the actions that 

will be taken prior to the period of extended operation will make the applicant‘s existing program 

consistent with the recommendations in GALL AMP XI.E4, and (2) the applicant has committed 

(Commitment No. 13) to implementing these actions prior to the period of extended operation.
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Based on its audit and review of the applicant‘s responses to RAIs B2.1.18-1 and B2.1.18-2, the 

staff finds that elements one through six of the applicant‘s Metal-Enclosed Bus Program, with an 

acceptable enhancement, are consistent with the corresponding program elements of GALL 

AMP XI.E4 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.18 summarizes OE related to the Metal-Enclosed Bus

Program. The applicant stated that metal-enclosed bus failures due to degradation of bus 

insulation and accumulation of dust and debris occurred in the late 1980s. The applicant stated 

that the existing Metal-Enclosed Bus Program was created to manage non-segregated 

metal-enclosed bus joint connections. The applicant further stated that its program considered 

NRC INs 89-64, 98-36, and 2000-14. These INs document industry metal-enclosed bus failures, 

including those failures at the applicant‘s site that involved insulation failure and accumulation of 

water and debris. The applicant stated that its existing program was created to address the 

above failures and has been updated to include additional maintenance activities, testing, and 

program elements since original issue.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant. 

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff identified OE which could indicate that the applicant‘s program may 

not be effective in adequately managing aging effects during the period of extended operation. 

The staff determined the need for additional clarification, which resulted in the issuance of RAIs. 

The ―operating experience‖ program element of the applicant‘s program states that the existing 

inspection program is designed to maintain the tightness of metal-enclosed bus joints and that 

joints were torque-checked for proper tightness. The staff noted that re-torquing is not 

recommended in EPRI TR-104213 (Sections 7.2.1 and 8.2) for electrical bolted connection 

maintenance. The EPRI document states the following:

[T]he bolts should not be re-torqued unless the joint requires service or the bolts 

are clearly loose. Verifying the torque is not recommended. The torque required 

to turn the fastener in the tightening direction (restart torque) is not a good 

indicator of the preload once the fastener is in service. Due to relaxation of the 

parts of the joint, the final loads are likely to be lower than the installed loads.

By letter dated July 13, 2009, the staff issued RAI B2.1.18-3 requesting the applicant provide 

justification for not following the EPRI guidance for bus connection re-torquing.

In its response dated August 17, 2009, the applicant stated that when bolted connections are 

made accessible, current plant procedures incorrectly specify performance of a torque check on 

the bolted joints and re-torque of the joint if the as-found torque value is less than the 

manufacturers required torque value. The applicant also stated that the discrepancy was 

documented in the corrective action program to determine the necessary revisions to the 

procedures to provide consistency with the EPRI guidance.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.18-3 acceptable 

because the applicant has entered the condition in its corrective action program to determine 
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the procedure changes needed to be consistent with the EPRI guidance. The staff, therefore, 

considers RAI B2.1.18-3 resolved.

LRA Section B2.1.18 states that OE indicates that the Metal-Enclosed Bus Program is effective 

in identifying degradation, evaluating the degradation, and implementing corrective actions. The 

staff noted that corrective action examples included the discovery during preventive 

maintenance of foreign material on top of the bus insulation. The staff further noted that the bus 

insulation was cleaned and the applicant determined that the insulation remained intact with no 

sign of degradation. The applicant provided a second example that involved cracked insulation 

discovered during maintenance. The staff noted that the bus bars were removed, reinsulated 

and re-torqued. LRA Section B2.1.18 also states that no age-related metal-enclosed bus 

failures have occurred since the program was revised to include bus cleaning and enhanced 

visual inspection. 

Based on its audit and review of the application, and review of the applicant‘s response to 

RAI B2.1.18-3, the staff finds that OE related to the applicant‘s program demonstrates that it can 

adequately manage the detrimental effects of aging on SSCs within the scope of the program,

and that implementation of the program has resulted in the applicant taking corrective actions. 

The staff confirmed that the ―operating experience‖ program element satisfies the criterion in 

SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.18 provides the USAR supplement for the 

Metal-Enclosed Bus Program, as amended by letter dated August 17, 2009. The staff reviewed 

this USAR supplement description of the program and notes that it conforms to the 

recommended description for this type of program as described in SRP-LR Table 3.6-2.

In its response to RAI B2.1.18-1, dated August 17, 2009, the applicant amended LRA 

Section A2.1.18 to replace the third paragraph in the program description with the following:

The program performs visual inspections of the in-scope MEB for cracks, 

corrosion, foreign debris, excessive dust buildup, and evidence of water 

intrusion, and performs visual inspections of the component insulation for surface 

anomalies, such as discoloration, cracking, chipping or surface contamination.

The program performs visual inspections of a sample of accessible MEB bolted 

connections that are covered with heat shrink tape, sleeving, insulated boots, 

etc., for surface anomalies, such as discoloration, cracking, chipping or surface 

contamination.

The applicant also stated that it will clarify the frequency of the metal-enclosed bus and bolted 

connection inspections in LRA Section A2.1.18 by replacing the fourth paragraph of the program 

description as shown below:

The inspection of all metal enclosed bus will be completed prior to the period of 

extended operation and will be repeated every 10 years thereafter.

The inspection of the sample of bolted connections will be completed prior to the 

period of extended operation and will be repeated every 5 years thereafter.
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Thereafter, the inspection of all metal enclosed bus will not exceed a 10-year 

interval and the inspection of the sample of bolted connections will not exceed a 

5-year interval.

The staff also notes that the applicant committed (Commitment No. 13), as amended by letter 

dated August 17, 2009, to enhance the Metal-Enclosed Bus Program prior to entering the period 

of extended operation and thereafter, the inspection of all metal-enclosed buses will not exceed 

a 10-year interval and the inspection of the sample of bolted connections will not exceed a 

5-year interval. Specifically, the applicant committed to include augmented periodic visual 

inspections of the metal-enclosed bus internal surfaces, bus supports, bus insulation, taped 

joints, and boots for signs of degradation or aging. 

The staff determines that the information in the USAR supplement, as amended, 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-Enclosed Bus 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 confirmed 

that its implementation through Commitment No. 13, prior to the period of extended operation, 

would make the existing AMP consistent with the GALL Report 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 functions 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 Open-Cycle Cooling Water System Program

Summary of Technical Information in the Application. LRA Section B2.1.23 describes the 

existing Open-Cycle Cooling Water System Program as consistent, with an exception and an 

enhancement, with GALL AMP XI.M20, ―Open-Cycle Cooling Water System.‖ The applicant 

stated that the program addresses loss of material and reduction in heat transfer of the 

open-cycle cooling water system, which includes service water piping and portions of the 

circulating water piping system that support the operation of the service water system, including 

its alternate source of service water. The applicant also stated that the system components are 

constructed from copper alloys, stainless steel, and steel. The applicant further stated that the 

program proposes to manage this aging effect through the use of preventive measures, such as 

chemical treatment and monitoring measures (e.g., visual inspections, NDEs, heat exchanger 

thermal performance testing, and other maintenance activities).

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated. The staff compared 

elements one through six of the applicant‘s program to the corresponding elements of GALL 

AMP XI.M20. As discussed in the Audit Report, the staff confirmed that each element of the 

applicant‘s program is consistent with the corresponding element of GALL AMP XI.M20, with the 

exception of the ―preventive actions‖ program element. For this element, the staff determined 

the need for additional clarification, which resulted in the issuance of an RAI.

GALL AMP XI.M20 recommends that the system components be lined or coated to protect the 

underlying metal surfaces from being exposed to aggressive cooling water environments under 
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the ―preventive actions‖ program element description; however, during its audit, the staff found 

that much of the service water piping is not lined. By letter dated July 13, 2009, the staff issued 

RAI B2.1.23-1 requesting that the applicant demonstrate that the proposed program is 

sufficiently robust to adequately manage aging in the absence of pipe linings.

In its response dated August 17, 2009, the applicant stated that its source of open-cycle cooling 

water is Lake Michigan and that it is fresh water, relatively free of chemicals and minerals, and, 

therefore, not considered to be an aggressive cooling water environment. The applicant also 

stated that its program includes internal visual inspections whenever the piping is open for 

maintenance or repair, routine UT which is performed on select piping segments, and periodic 

replacement of susceptible dead leg piping. While the staff does not agree with the applicant‘s 

assertion that the open-cycle cooling water from Lake Michigan is not aggressive, the staff does 

consider this water to be less corrosive to carbon steel piping than most water sources. It is the 

staff‘s position that any aerated water source is corrosive to carbon steel and, therefore, 

aggressive. The staff noted that the applicant‘s program includes routine UT and periodic 

replacement of dead leg piping. The staff also noted that UT is effective in detecting loss of 

material in piping and that dead legs are the type of piping generally considered most 

susceptible to loss of material by corrosion. The staff finds this program acceptable because 

even in the absence of internal coatings, the low corrosivity of the water, as well as the 

increased inspection and routine piping replacement included in the applicant‘s program, 

provides a reasonable level of assurance that the LRA AMP will provide aging management 

which is at least equivalent to that provided by the GALL Report AMP.

The staff also reviewed the portions of the ―detection of aging effects‖ and ―parameters 

monitored or inspected‖ program elements associated with exceptions and enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff‘s evaluation of the exception and enhancement follows.

Exception. LRA Section B2.1.23 states an exception to the ―detection of aging effects‖ program 

element. The applicant stated that the containment fan coil units and EDG cooling water 

subsystem heat exchangers will not be thermal performance tested. The applicant also stated 

that it will periodically inspect and flush these heat exchangers as an alternative to thermal 

testing, and additionally flow test the containment fan coil units and perform eddy current tube 

inspections on the EDG cooling water subsystem heat exchangers. The applicant further stated 

that the basis for this exception is its inability to obtain valid heat transfer results for these heat 

exchangers due to their configuration.

The staff reviewed this exception to the GALL Report in conjunction with GL 89-13. The staff 

noted that these heat exchangers constitute a small subset of the heat exchangers tested under 

this AMP. GL 89-13 indicates that there are heat exchangers for which obtaining valid heat 

transfer data is very difficult. GL 89-13 proposes that adequate heat transfer for these heat 

exchangers can be maintained through a combination of flushing and inspection. The staff finds 

the program exception acceptable because GL 89-13 specifically authorizes this technique for 

maintaining the heat transfer capabilities of heat exchangers. Despite the exception, the staff 

finds the ―detection of aging effects‖ program element consistent with the one described in 

GALL AMP XI.M20.

Enhancement. LRA Section B2.1.23 states an enhancement to the ―parameters monitored or 

inspected‖ program element. The applicant stated that the program will be enhanced to add 

piping corrosion and erosion inspection criteria to the circulating water underwater visual 
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inspections. The applicant also stated that the inspection criteria includes buildup of silt and 

zebra mussels.

The staff reviewed this enhancement against the corresponding program element in GALL 

AMP XI.M20. On the basis of its review, the staff finds this enhancement acceptable because 

when it is implemented prior to the period of extended operation, the program inspection 

procedures and frequencies will be consistent with the recommendations in GALL AMP XI.M20. 

Based on its audit and review of the applicant‘s response to RAI B2.1.23-1, the staff finds that 

elements one through six of the applicant‘s Open-Cycle Cooling Water System Program, with 

an acceptable exception and enhancement, are consistent with the corresponding program 

elements of GALL AMP XI.M20 and are, therefore, acceptable.

Operating Experience. LRA Section B2.1.23 summarizes OE related to the Open-Cycle Cooling 

Water System Program. The applicant stated that OE has been effective in detecting loss of 

material and loss of heat transfer, citing examples related to silting in elbows and eddy current 

testing of heat exchanger tubes. 

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant.

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 

information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program. During its review, the staff identified OE which could indicate that the 

applicant‘s program may not be effective in adequately managing aging effects during the 

period of extended operation. The staff determined the need for additional clarification, which 

resulted in the issuance of RAIs.

In LRA Section B2.1.23, the applicant stated that it had addressed OE related to open-cycle 

cooling water systems. However, the staff found that the applicant had not addressed OE 

related to the biocide injection system functioning less than fully reliable. Plant OE also indicates 

that zebra mussels are commonly found in various parts of the open-cycle cooling water 

system. By letter dated July 13, 2009, the staff issued RAI B2.1.23-2 requesting that the 

applicant demonstrate the sufficiency of the proposed program to address biofouling.

In its response dated August 17, 2009, the applicant stated that the poor availability of the 

biocide injection equipment had been identified by the Open-Cycle Cooling Water Program and 

entered into the corrective action program. The applicant also stated that as a result of actions 

initiated by these programs, the availability of the biocide injection equipment has increased 

from 40 percent in 2007 to approximately 93 percent in 2009. The applicant further stated that 

although mussel fragments have been found in the open-cycle cooling water system, no live 

mussels were routinely found, even during the period when the availability of biocide injection 

equipment was poor.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.23-2 acceptable 

because the program was: (1) sufficiently robust so as to be able to control zebra mussels even 

when the performance of the biocide injection was poor, (2) capable of identifying a weakness in 

the program and correcting it over a reasonably short period of time, and (3) capable of 

preventing loss of function of the system under conditions of poor operating reliability of the 

biocide injection equipment. The staff‘s concern described in RAI B2.1.23-2 is resolved.
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In LRA Section B2.1.23, the applicant stated that it had addressed OE related to open-cycle 

cooling water systems. However, the staff found that the applicant had not addressed OE 

related to several instances where small heat exchangers fouled under low flow conditions. In 

all instances, it was apparent that the LRA program was sufficient to initiate corrective action for 

the compromised exchanger. In some, but not all instances, it was apparent that lessons 

learned were extended to other heat exchangers or other components. By letter dated July 13, 

2009, the staff issued RAI B2.1.23-3 requesting that the applicant provide additional examples, 

particularly associated with low flow heat exchangers, demonstrating that OE from one 

component is used to modify the inspection program for other, similar components. 

In its response dated August 17, 2009, the applicant provided two examples demonstrating the 

manner in which lessons learned were utilized on other components. The applicant‘s first 

example dealt with low flow fouling of safety injection pump lube oil coolers. These coolers 

fouled in January 2004 due to lake weeds and low flow conditions. These heat exchangers were 

subsequently replaced by a different type of heat exchanger which is less prone to fouling. 

Additionally, the applicant inspected three other heat exchangers which were potentially subject 

to the same fouling method. Inspection results indicated that these heat exchangers were not 

subject to this type of fouling and that no further action was required. The applicant‘s second 

example addressed eddy current test results for heat exchanger tube pitting. In 2006, the 

applicant performed eddy current testing to determine loss of material from heat exchanger 

tubes and removed two tubes to confirm the eddy current analysis. The destructive analysis of 

the tubes indicated a shortcoming in the eddy current analysis. This data was used to correct 

the eddy current analysis for this heat exchanger, as well as all other heat exchangers subject 

to eddy current testing.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.23-3 acceptable 

because it demonstrates the ability of the program to appropriately apply lessons learned to 

other components. The staff‘s concern described in RAI B.2.1.23-3 is resolved.

Based on its audit and review of the application, and review of the applicant‘s responses to 

RAIs B2.2.23-2 and B2.1.23-3, the staff finds that OE related to the applicant‘s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program, and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the ―operating experience‖ program element 

satisfies the criterion defined in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable. 

USAR Supplement. LRA Section A2.1.23 provides the USAR supplement for the Open-Cycle 

Cooling Water System Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Tables 3.2-2, 3.3-2, and 3.4-2.

The staff also notes that the applicant committed (Commitment No. 18) to enhance the 

Open-Cycle Cooling Water System Program prior to entering the period of extended operation. 

Specifically, the applicant committed to enhance the program to add applicable aging effects as 

inspection criteria for the circulating water system underwater visual inspections. The staff 

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 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 the LRA credits it. Also, the staff reviewed the enhancement 

and confirmed that its implementation through Commitment No. 18, prior to the period of 

extended operation, would make the existing AMP consistent with the GALL Report 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 functions 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 Reactor Head Closure Studs Program

Summary of Technical Information in the Application. LRA Section B2.1.26 describes the 

existing Reactor Head Closure Studs Program as consistent, with an exception, with GALL 

AMP XI.M3, ―Reactor Head Closure Studs.‖ The applicant stated that this program manages the 

effects of cracking and loss of material for the reactor head closure stud assembly, including 

nuts, washers, and the threads in the reactor vessel flange. The applicant further stated that the 

program includes preventive measures identified in RG 1.65, and visual or volumetric 

examinations in compliance with the ASME Code Section XI, 1998 Edition through 2000 

Addenda to monitor the aging degradation. The preventive measures of RG 1.65 include the 

use of appropriate fabrication materials, coatings, and lubricants, and operating practices to 

reduce the potential for corrosion and contamination of the reactor head closure stud assembly 

(including nuts, washers, and reactor pressure vessel (RPV) flange threads).

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff reviewed the material specification sheet and confirmed that the closure studs and 

nuts meet the material limitations of RG 1.65: the maximum tensile strength is less than 

1,172 megapascal (MPa) (170 ksi) and to avoid material property degradation, the studs are not 

metal-plated. In addition, the staff confirmed that: (1) the studs have a manganese phosphate 

surface treatment to prevent SCC; (2) the lubricant does not include any unstable compounds 

identified in RG 1.65; and (3) when the head is removed, to avoid corrosion and contamination, 

the water level of the reactor cavity is 6 inches below the flange and the stud bolts and bolt 

holes are protected. The staff noted that these actions by the applicant are consistent with the 

―preventive actions‖ program element in GALL AMP XI.M3.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M3. As discussed in the Audit Report, the staff confirmed that these 

elements are consistent with the corresponding elements of GALL AMP XI.M3.

The staff also reviewed the portions of the ―scope of the program‖ program element associated 

with its exception to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff‘s evaluation of this exception follows.
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Exception. LRA Section B2.1.26 states an exception to the ―scope of the program‖ program 

element. The applicant stated its program is implemented using the guidance of the ASME 

Code Section XI, 1998 Edition through 2000 Addenda, instead of the ASME Code Section XI,

2001 Edition through 2003 Addenda recommended by the GALL Report. The applicant stated 

that use of the ASME Code Section XI, 1998 Edition through 2000 Addenda is consistent with 

the provisions in 10 CFR 50.55a, which requires licensees to use the ASME Code Section XI in 

effect 12 months prior to the start of the inspection interval. The applicant further stated that the 

1998 Code Edition allows surface or volumetric examinations of the reactor head closure studs 

when they are removed, whereas the 2001 Code Edition provided for a volumetric examination 

when the studs are in place or removed. Consequently, the staff noted that the change in 

examination provisions has no impact on the program because volumetric examination of the 

studs is performed when the studs are removed. 

Based on its review, the staff finds this exception acceptable because the applicant is complying 

with the inspection requirements of the ASME Code Section XI Edition 1998 through 2000

Addenda and is consistent with the recommendations of GALL AMP XI.M3. 

Based on its audit, the staff finds that elements one through six of the applicant‘s Reactor Head 

Closure Studs Program, with an acceptable exception, are consistent with the corresponding 

program elements of GALL AMP XI.M3 and are, therefore, acceptable. 

Operating Experience. LRA Section B2.1.26 summarizes OE related to the Reactor Head 

Closure Studs Program. The staff reviewed the OE in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific OE were 

reviewed by the applicant. As discussed in the Audit Report, the staff conducted an independent 

search of the plant OE information to determine whether the applicant had adequately 

incorporated and evaluated OE related to this program. 

During the audit, the staff reviewed the OE described in the applicant‘s program basis document 

and interviewed the applicant‘s technical staff to confirm that the plant-specific OE did not reveal 

any degradation not bounded by industry experience. The applicant stated that a review of its 

condition reports did not identify any reported cracking or loss of material for the closure studs. 

A review of the applicant‘s corrective action reports indicated two minor incidents: (1) exceeding 

elongation limit of one stud by 0.001 inch (2003) and (2) removal of a stud blemish (2006). The 

staff concluded that by complying with the guidelines identified in the RG 1.65 and by complying 

with the requirements of the ASME Code Section XI, the applicant demonstrated that it is 

capable of effectively managing the aging degradation of the reactor head closure stud 

assembly during the period of extended operation.

The staff found no OE to indicate that the applicant‘s program would not be effective in 

adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that OE related to the applicant‘s 

program demonstrates that it can adequately manage the detrimental effects of aging on SSCs 

within the scope of the program, and that implementation of the program has resulted in the 

applicant taking corrective actions. The staff confirmed that the ―operating experience‖ program 

element satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it 

acceptable.
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USAR Supplement. LRA Section A2.1.26 provides the USAR supplement for the Reactor Head 

Closure Studs Program. The staff reviewed this USAR supplement description of the program 

and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.2-2.

The staff noted the preventive measures implemented by its program are consistent with the 

measures identified in RG 1.65. The staff also noted that a volumetric examination of the studs 

is performed when the studs are removed, which is consistent with the requirements of the 

ASME Code Section XI, 2001 Edition through 2003 Addenda.

The staff 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 exception 

and its justification and determines that the AMP, with the exception, is adequate to manage the 

aging effects for which the LRA credits it. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions 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 Reactor Vessel Surveillance Program

Summary of Technical Information in the Application. In LRA Section B2.1.27, the applicant 

described its Reactor Vessel Surveillance Program, stating that this existing program is 

consistent with GALL AMP XI.M31, ―Reactor Vessel Surveillance,‖ with the exception to keep the

last RPV surveillance capsule in the vessel beyond 60 years of operation. The applicant also 

stated that this existing program will be enhanced to include: (1) the applicable limitations on 

operating conditions to which the surveillance capsules were exposed, and (2) requirements for 

storing, and possible recovery, of tested and untested capsules.

The Reactor Vessel Surveillance Program manages the aging effect of loss of fracture 

toughness due to irradiation embrittlement of the RPV low-alloy steel material. Monitoring 

methods are in accordance with 10 CFR Part 50, Appendix H, ―Reactor Vessel Material 

Surveillance Program Requirements.‖ This program includes surveillance capsule removal and 

specimen mechanical testing and evaluation, radiation analysis, development of 

pressure-temperature (P-T) limits, and determination of low-temperature overpressure 

protection (LTOP) set points. The program ensures the RPV materials meet the fracture 

toughness requirements of 10 CFR Part 50, Appendix G, ―Fracture Toughness Requirements,‖ 

and meet pressurized thermal shock (PTS) and upper-shelf energy (USE) requirements in 

10 CFR 50.60, ―Acceptance Criteria for Fracture Prevention Measures for Lightwater Nuclear 

Power Reactors for Normal Operation,‖ and 10 CFR 50.61, ―Fracture Toughness Requirements 

for Protection Against Pressurized Thermal Shock Events,‖ as modified by the exemption 

granted to utilize the Master Curve methodology throughout the period of extended operation.

Staff Evaluation. The staff reviewed the applicant‘s proposed Reactor Vessel Surveillance 

Program and confirmed the applicant‘s claim of consistency with the GALL Report with one 

exception and two enhancements. 
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Appendix H of 10 CFR Part 50 specifies surveillance program criteria for 40 years of operation.

GALL AMP XI.M31 specifies additional criteria for 60 years of operation. The staff determined 

that compliance with 10 CFR Part 50, Appendix H criteria for capsule design, location, 

specimens, test procedures, and reporting remains appropriate for this AMP because these items, 

which satisfy 10 CFR Part 50, Appendix H, will stay the same throughout the period of extended 

operation. LRA Section B2.1.27 proposed an exception to keep the last RPV surveillance 

capsule in the vessel beyond 60 years of operation. However, to ensure that the last capsule, if 

removed and tested during the period of extended operation for any reason, still meets the test 

procedures and reporting requirements of ASTM E 185-82, ―Standard Practice for Conducting 

Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels,‖ the staff plans to 

impose conditions to address this specific concern:

All capsules in the reactor vessel that are removed and tested must meet the test 

procedures and reporting requirements of ASTM E 185-82 to the extent practicable 

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

withdrawal schedule, including spare capsules, must be approved by the NRC 

prior to implementation. All capsules placed in storage must be maintained for 

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

NRC.

The 10 CFR 50, Appendix H capsule withdrawal schedule during the period of extended

operation is addressed according to the GALL Report‘s consideration of eight criteria for an 

acceptable reactor vessel surveillance program for 60 years of operation.

The staff reviewed the exception and enhancements and the associated justifications to 

determine whether this AMP remains adequate to manage the aging effects for which it is 

credited. 

Exception. The exception is to keep the last RPV surveillance capsule in the RPV beyond 

60 years of operation, as opposed to a capsule withdrawal at 60-years of operation 

recommended by Criterion 6 of GALL AMP XI.M31. This exception to GALL AMP XI.M31 is 

acceptable to the staff because it is consistent with the current position of the Division of 

Component Integrity (DCI) of the Office of Nuclear Reactor Regulation (NRR) regarding RPV 

capsule withdrawal schedules during the period of extended operation. The current position, 

which has been conveyed to industry through the ASME Code meetings and other occasions, 

was prompted by the need to have a set of evenly-distributed, instead of clustered, high fluence 

surveillance data for the entire fleet of pressurized water reactors (PWRs) when there is a 

steady increase of plants joining integrated surveillance programs sponsored by the industry. 

The staff is in the process of revising GALL AMP XI.M31 to reflect this current DCI position of 

modifying Criterion 6.

Enhancement 1. The first enhancement is to include in the AMP the applicable limitations on 

operating conditions to which the surveillance capsules were exposed. However, since LRA 

Section B2.1.27 does not specify these limitations, the staff could not verify that this 

enhancement will satisfy Criteria 2, 3, and 6 of GALL AMP XI.M31, as stated in the LRA. Hence, 

the staff issued RAI B2.1.27-1 by letter dated Oct. 13, 2009.

RAI B2.1.27-1:

LRA Section B2.1.27, ―Reactor Vessel Surveillance,‖ states under Enhancement 

1: ―The Reactor Vessel Surveillance Program will be enhanced to include the 
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applicable limitations on operating conditions to which the surveillance capsules 

were exposed (e.g., neutron flux, spectrum, irradiation temperature, etc.).‖ Please 

provide details regarding these applicable limitations. Further, demonstrate that 

with this Enhancement the Reactor Vessel Surveillance Program meet[s] the 

acceptance criteria 2, 3, and 6 that were listed in GALL Aging Management 

Program (AMP) XI.M31, ―Reactor Vessel Surveillance.‖

The applicant responded to RAI B2.1.27-1 in its letter dated November 13, 2009, that 

Enhancement 1 will ensure that: 

 (1) Changes in plant parameters (e.g., operating temperature, neutron fluence) to which 

reactor vessel materials are exposed, are evaluated for the effect on the applicability of 

RG 1.99, Revision 2, Radiation Embrittlement of Reactor Vessel Materials, Regulatory 

Position 1, as discussed in the GALL Report, Section XI.M31, item 2.

 (2) Plant parameters (e.g., cold leg temperature, neutron fluence) remain within the bounds 

defined for the surveillance data used as input to the embrittlement evaluations, as 

discussed in the GALL Report, Section XI.M31, item 3.

 (3) Reactor vessel exposure conditions (e.g., neutron flux, spectrum, irradiation 

temperature, etc.) are monitored to ensure that the actual exposure conditions remain 

consistent with those used to project the effects of embrittlement to the end of the period 

of extended operation, as discussed in the GALL Report, Section XI.M31, item 6.

The staff noted that the additional information clearly indicates Enhancement 1 is designed to 

address acceptance criteria 2, 3, and 6 in GALL AMP XI.M31. Hence, RAI B2.1.27-1 is 

resolved. Since Enhancement 1 is to upgrade the current Reactor Vessel Surveillance Program 

to meet the GALL AMP XI.M31 requirements, the staff considers Enhancement 1 acceptable. 

Enhancement 2. The second enhancement is to include requirements for storing, and possible 

recovery, of tested and untested capsules. Criterion 4 of GALL AMP XI.M31 recommends, ―[a]II 

pulled and tested capsules, unless discarded before August 31, 2000, are placed in storage. 

(Note: These specimens are saved for future reconstitution use, in case the surveillance 

program is reestablished.)‖ The emphasis of Criterion 4 of GALL AMP XI.M31 is tested 

specimens, not capsules. The staff, therefore, concludes that Enhancement 2 is acceptable 

because it expands the scope of Criterion 4 of GALL AMP XI.M31 to include requirements for 

storing tested and untested capsules. Through capsule retention, the overall task of irradiating 

archival or reconstituted specimens becomes easier to manage.

Hence, the exception and enhancements represent modifications to GALL AMP XI.M31, which 

are considered acceptable and credible as discussed above. The staff‘s review of the AMP 

addressing the remaining acceptable criteria in GALL AMP XI.M31 is presented below. 

Criterion 1 is automatically satisfied when RG 1.99, Revision 2 is appropriately used in the 

applicant‘s evaluation of USE, PTS, and P-T limits. Criterion 5 is for plants having a surveillance 

program that consists of capsules with a projected fluence of less than the 60-year fluence at the 

end of 40 years, and Criterion 6 is for plants having a surveillance program that consists of 

capsules with a projected fluence exceeding the 60-year fluence at the end of 40 years. LRA 

Section B2.1.27 states, ―Capsule N, the last remaining surveillance capsule, has currently 

accumulated a neutron fluence greater than that projected for 60 years of operation.‖ Therefore, 

instead of Criterion 5, Criterion 6 is applicable to the AMP. However, as discussed in the staff‘s 
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evaluation of the exception proposed in LRA Section B2.1.27, the current DCI position will modify 

Criterion 6. Hence, meeting the entire Criterion 6 is no longer needed.

Criterion 7 provides guidelines for applicants without surveillance capsules. The applicant has a 

capsule in the RPV to monitor neutron fluence during the period of extended operation. 

Therefore, Criterion 7 does not apply to the AMP. Criterion 8 relates to the need to include the 

RPV nozzle materials in the AMP. Based on the staff‘s evaluations and conclusions of SER 

Section 4.2.2 on Charpy USE and SER Section 4.2.3 on PTS, it is clear that the RPV nozzle 

materials are not controlling. Therefore, Criterion 8 is satisfied.

For the CLB and the period of extended operation, the applicant‘s Reactor Vessel Surveillance 

Program is different from other plants‘ surveillance programs in one aspect: the irradiated 

specimens for the circumferential weld metal are tested to obtain directly measured fracture 

toughness data in accordance with the Master Curve method as defined in an NRC safety 

evaluation dated May 1, 2001, which supported granting the applicant an exemption from the 

requirements of 10 CFR 50, Appendix G, Appendix H, and 10 CFR 50.61 (ADAMS Accession 

No. ML011210180). However, since the applicant‘s 2006 Master Curve test results support the 

period of extended operation, the applicant will not perform any additional surveillance specimen 

testing during the period of extended operation. The 2006 Master Curve test results are evaluated 

in SER Section 4.2.3.

Operating Experience. In LRA Section B2.1.27, the applicant stated that its Reactor Vessel 

Surveillance Program has provided material embrittlement and dosimetry data since plant 

startup and the test results have been reviewed for use in the current operating term. The LRA

also says that the applicant‘s 2006 self-assessment of the Reactor Vessel Integrity Program 

revealed no issues or findings that could impact the effectiveness of this program. 

The staff noted that this conclusion is reasonable because to date, the applicant has provided 

surveillance reports to the staff indicating no difficulty in obtaining fluence and embrittled 

material information from the surveillance specimens. The staff‘s acceptance of the applicant‘s 

TLAAs on PTS (SER Section 4.2.3) and P-T limits (SER Section 4.2.4) also supports the 

effectiveness of this AMP. Therefore, the staff determines that the applicant has provided an 

appropriate description of its plant-specific OE.

Based on the staff‘s evaluation of the proposed exception and enhancements of the applicant‘s

AMP and consistency of the AMP with the eight criteria of GALL AMP XI.M31, the staff considers 

the AMP acceptable.

USAR Supplement. The applicant provided its USAR supplement for the Reactor Vessel 

Surveillance Program in LRA Section A2.1.27. Appendix H of 10 CFR Part 50 requires licensees

to submit proposed changes to their Reactor Vessel Surveillance Program withdrawal schedules

to the staff for review and approval. To ensure that this reporting requirement will carry forward 

through the period of extended operation, the staff has imposed a license condition to the 

applicant‘s Reactor Vessel Surveillance Program as stated earlier in the staff‘s evaluation. The 

staff reviewed the USAR supplement and determines that the information in the supplement, 

with the license condition, provides 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 

and RAI responses, the staff determines that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent. The staff reviewed the exception and 

confirmed that the implementation of it is consistent with the current DCI position and meets the 
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objective of GALL AMP XI.M31. Also, the staff reviewed the enhancements and confirmed that 

the improvement labeled as ―Enhancement 1‖ will upgrade the existing AMP to meet the GALL 

AMP XI.M31 requirements, and Enhancement 2 will upgrade the existing AMP to exceed the 

GALL AMP XI.M31 requirements. The staff concludes that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended functions 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, with the license condition, it provides an adequate summary description of the program, as 

required by 10 CFR 54.21(d).

3.0.3.2.17 Steam Generator Tube Integrity Program

Summary of Technical Information in the Application. LRA Section B.2.1.30 describes the 

existing Steam Generator Tube Integrity Program as being consistent, with an exception, with 

GALL AMP XI.M19, ―Steam Generator Tube Integrity.‖ The applicant stated that the program 

manages the aging effects of cracking and loss of material for the primary and secondary-side 

steam generator components made of Ni alloy, stainless steel, and steel. The applicant also 

stated that the program is based on TS requirements and meets the intent of NEI 97-06, ―Steam 

Generator Program Guidelines.‖ The applicant credited its program for aging management of 

the tubes, tube plugs, tube sleeves, tube supports, and secondary-side components whose 

failure could prevent the steam generator from fulfilling its intended safety function. The 

applicant stated that the program manages aging effects by providing a balance of prevention, 

inspection, evaluation, repair, and leakage monitoring. The applicant explained that this 

program: (1) enables it to verify the effectiveness of the Primary Water Chemistry and 

Secondary Water Chemistry programs; (2) includes foreign material exclusion requirements; 

and (3) is able to detect flaws in tubes, tube plugs, tube sleeves, tube supports, and 

secondary-side components needed to maintain tube integrity by using degradation 

assessments, eddy current testing, and visual inspections. The applicant further stated that it 

―continually controls the primary-to-secondary leakage during operation.‖ 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

LRA Section B2.1.30 states that the Primary Water Chemistry and Secondary Water Chemistry 

programs provide preventive measures. During its review, the staff noted that the applicant is 

following water chemistry guidelines other than those recommended in GALL AMP XI.M19. The 

applicant stated in LRA Section B2.1.24 that primary water chemistry control is based on the 

industry guidelines for primary water chemistry, EPRI 1002884 (formerly TR-105714), 

―Pressurized Water Reactor Primary Water Chemistry Guidelines,‖ Revision 6. The applicant 

further stated in LRA Section B2.1.28 that secondary water chemistry control is based on the 

industry guidelines for secondary water chemistry, EPRI 1008224 (formerly TR-102134), 

―Pressurized Water Reactor Secondary Water Chemistry Guidelines,‖ Revision 6. The staff finds 

that the use of these more recent guidelines is consistent with GALL AMP XI.M2, which states 

that the water chemistry program for PWRs relies on monitoring and control of reactor water 

chemistry based on industry guidelines for primary water and secondary water chemistry, such 

as EPRI TR-105714, Revision 3 and TR-102134, Revision 3. Since the ―preventive actions‖ 

program element of GALL AMP XI.M19 refers to GALL AMP XI.M2 for monitoring and 

maintaining reactor water chemistry, the staff finds this aspect of GALL AMP XI.M19 ―preventive 

actions‖ program element acceptable.
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The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP XI.M19. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP XI.M19, with the exception of the ―scope of the program,‖ ―preventive actions,‖ 

―parameters monitored or inspected,‖ ―detection of aging effects,‖ ―monitoring and trending,‖ and 

―acceptance criteria‖ program elements. For these program elements, the staff determined the 

need for additional clarification, which resulted in the issuance of RAIs as discussed below.

During its audit, the staff identified one broad issue that affects all program elements and 

renders them inconsistent with GALL AMP XI.M19. The staff identified numerous 

inconsistencies between the applicant‘s program and its implementing documents and industry 

guidance documents. The staff noted that these inconsistencies can be categorized into three 

groups: (1) reference and document versions are inconsistent with guidance documents and 

among applicant procedures, (2) industry guidelines and/or plant TSs have been misinterpreted 

or misapplied in applicant implementing procedures, and (3) applicant implementing procedures 

are inconsistent both internally and between documents.

By letter dated July 13, 2009, the staff issued RAIs B2.1.30-1, B2.1.30-2, B2.1.30-4, and 

B2.1.30-11 to address the first category of inconsistencies (i.e., reference and document 

versions are inconsistent with guidance documents and among applicant procedures). The 

staff‘s evaluation of each RAI is discussed below.

In RAI B2.1.30-1 dated July 13, 2009, the staff requested that the applicant discuss its plans for 

modifying its program basis document for the Steam Generator Tube Integrity Program, which 

supports LRA Section B2.1.30, to be consistent with the updated references and provide the list 

of references. 

In its response dated August 17, 2009, the applicant stated that this document has been 

updated to reflect the revised references and the applicant provided the revised list of 

references. 

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-1 acceptable 

because the staff reviewed the updated references and the references provided are consistent 

with the applicant‘s other implementing procedures.

In RAI B2.1.30-4 dated July 13, 2009, the staff requested that the applicant address the 

inconsistency in the regulatory requirements section of its program document, ER-AP-SGP-101, 

―Steam Generator Program,‖ which does not appear to list all of the regulatory requirements 

identified in NEI 97-06.

In its response dated August 17, 2009, the applicant stated that this program section was not 

intended to include a complete listing of regulatory requirements identified in NEI 97-06, 

Revision 2, and the applicant took corrective actions to clarify this issue by relocating the 

documents listed in Section 3.1.9 to the reference section of this procedure.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-4 acceptable

because the applicant‘s actions to relocate the documents listed in Section 3.1.9 to the 

reference section of this procedure eliminates the prior ambiguity.

In RAI B2.1.30-2 dated July 13, 2009, the staff requested that the applicant confirm whether its 

program document, SP-36-084, ―Steam Generator Tube Inspection,‖ Revision 0, has been 
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updated to reflect the latest version of the EPRI guidelines and to provide its plan to ensure that 

future updates to the guidelines will be incorporated in a timely manner.

In its response dated August 17, 2009, the applicant confirmed that this procedure needs to be 

updated. The applicant also explained that the need to update this procedure has been 

documented in the corrective action program to ensure that it is revised in a timely manner. The 

applicant stated that, in order to ensure that future updates are incorporated in a timely manner, 

the procedure SP-36-084 will also be revised to reference fleet program document 

ER-AP-SGP-101, ―Steam Generator Program,‖ which implements the latest version of EPRI 

PWR Steam Generator Examination Guidelines.

Based on its review, the staff found the applicant‘s response to RAI B2.1.30-2 unacceptable 

because the staff could not verify that the modifications to be made to the procedure will be 

consistent with GALL AMP XI.M19. The resolution of this issue is discussed below during 

discussion of RAI B2.1.30-17.

In RAI B2.1.30-11 dated July 13, 2009, the staff requested that the applicant address whether

the secondary-side integrity plan references are current and, if not, to specify its plans for 

updating this document.

In its response dated August 17, 2009, the applicant stated that the secondary-side integrity 

plan has been reviewed and it was determined that it references outdated documents as 

identified during the staff‘s review. The applicant also stated that this condition has been 

documented in the corrective action program to ensure that the secondary-side integrity plan 

references are updated during the next revision of the plan.

Based on its review, the staff found the applicant‘s response to RAI B2.1.30-11 unacceptable 

because the staff could not verify that the modifications to be made to the procedure will be 

consistent with GALL AMP XI.M19. The resolution of this issue is discussed below during 

discussion of RAI B2.1.30-17.

By letter dated July 13, 2009, the staff issued RAIs B2.1.30-3, B2.1.30-5, and B2.1.30-6 through 

B2.1.30-10 to address the second category of inconsistencies (i.e., industry guidelines and/or 

applicant TSs that have been misinterpreted or misapplied in applicant implementing 

procedures). The staff‘s evaluation of each RAI is discussed below.

In RAI B2.1.30-6 dated July 13, 2009, the staff requested that the applicant discuss whether 

Section 3.2.5 of ER-AP-SGP-102 is sufficient for verifying tube integrity for loads other than that 

associated with differential pressure, and if it is not sufficient, to discuss its plans for modifying 

this section to reflect all the loads that must be considered per NEI 97-06 and the plant‘s TSs.

In its response dated August 17, 2009, the applicant stated that Section 3.2.5 of 

ER-AP-SGP-102 has been revised to state that in-situ pressure testing is performed in 

accordance with the EPRI Steam Generator In-situ Pressure Test guidelines and that 

Section 3.2.1 of ER-AP-SGP-101 includes the structural integrity performance criterion in 

NEI 97-06.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-6 acceptable 

because the applicant will consider all loads to determine the test pressure for verifying tube 

integrity in accordance with the EPRI Steam Generator In-situ Pressure Test Guidelines called 

for by NEI 97-06 and, therefore, with GALL AMP XI.M19.
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In RAI B2.1.30-8 dated July 13, 2009, the staff requested that the applicant discuss if the 

procedure ER-AP-SGP-103, ―Condition Monitoring and Operational Assessment,‖ is also 

applicable when steam generator tubes are plugged (without inspection), in accordance with 

NEI 97-06 and the plant‘s TSs. 

In its response dated August 17, 2009, the applicant stated that ER-AP-SGP-103, ―Condition 

Monitoring and Operational Assessment,‖ has been revised to include the applicability of the 

procedure when steam generator tubes are plugged.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-8 acceptable 

because the applicant‘s procedure is consistent with its TS requirements and NEI 97-06 and, 

therefore, with GALL AMP XI.M19.

In RAI B2.1.30-9 dated July 13, 2009, the staff requested that the applicant discuss how its 

program ensures the NEI 97-06 accident-induced leakage criteria will be met, given that there 

may be accident-induced leakage without observing operational leakage, and that Section 3.2.5 

of ER-AP-SGP-103, ―Condition Monitoring and Operational Assessment,‖ appears to only 

require an assessment of accident-induced leakage when operational leakage is observed.

In its response dated August 17, 2009, the applicant stated that ER-AP-SGP-103, ―Condition 

Monitoring and Operational Assessment,‖ has been revised to clarify that accident-induced 

leakage requires an assessment even if no operational leakage is observed.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-9 acceptable 

because it is consistent with NEI 97-06 and OE and, therefore, with GALL AMP XI.M19.

In RAI B2.1.30-10 dated July 13, 2009, the staff requested that the applicant discuss why only 

those conditions identified in the procedure as increasing the differential pressure across the 

tubes are required to be assessed, since there may be other conditions that result in an 

increase in the differential pressure across the tubes (e.g., fouling).

In its response dated August 17, 2009, the applicant stated that a revision to ER-AP-SGP-103 

relocates this information to ER-AP-SGP-101, ―Steam Generator Program,‖ and clarified that 

there may be other conditions resulting in increased differential pressure across the tubes 

requiring an operational assessment.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-10 acceptable 

because it is consistent with NEI 97-06 and OE and, therefore, with GALL AMP XI.M19.

During its audit, the staff reviewed the applicant‘s surveillance procedure for steam generator 

tube inspection and identified several discrepancies between the industry guidelines (referenced 

in NEI 97-06, Revision 2), the plant‘s TSs, and the plant procedure.

In RAI B2.1.30-3 dated July 13, 2009, the staff requested that the applicant address the 

discrepancies between the industry guidelines (referenced in NEI 97-06, Revision 2), the plant‘s 

TSs, and the plant procedure.

In its response dated August 17, 2009, the applicant stated that the discrepancies identified in 

RAI B2.1.30-3 have been documented in the corrective action program and the proposed 

changes for each issue are to be implemented in the next revision of the surveillance procedure

for steam generator tube inspection. 
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Based on its review, the staff found the applicant‘s response to RAI B2.1.30-3 unacceptable 

because the staff could not verify that the modifications to be made to the procedure will be 

consistent with GALL AMP XI.M19. The resolution of this issue is discussed below during 

discussion of RAI B2.1.30-17.

In RAI B2.1.30-5 dated July 13, 2009, the staff requested, in part, that the applicant clarify how it 

could ensure tube integrity prior to the inspection as discussed in ER-AP-SGP-102, ―Steam 

Generator Degradation Assessment.‖

In its response dated August 17, 2009, the applicant stated that Section 3.2.1.d of 

ER-AP-SGP-102 implements the requirement of EPRI Steam Generator Integrity Assessment 

Guidelines, Revision 2, Section 3.4.

Based on its review, the staff found the applicant‘s response to RAI B2.1.30-5 unacceptable 

because the response was incomplete, since the staff noted that, although it is acceptable to 

determine the repair limit prior to the inspection in order to ensure tube integrity for the operating 

interval between inspections, the adequacy of this repair limit (determined prior to the 

inspection) must be confirmed after the inspection once the inspection results are available. The 

resolution of this issue is discussed below during discussion of RAI B2.1.30-17.

In RAI B2.1.30-7 dated July 13, 2009, the staff requested that the applicant address how growth 

rates are considered in the condition monitoring evaluation and the need to reference the 

probability and confidence level for assessment of compliance with the accident-induced 

leakage performance criteria in ER-AP-SGP-103, ―Condition Monitoring and Operational 

Assessment.‖

In its response dated August 17, 2009, the applicant stated that Section 3.2.2 of 

ER-AP-SGP 103, ―Condition Monitoring and Operational Assessment,‖ reproduces the 

requirement of EPRI Steam Generator Integrity Assessment Guidelines, Section 7.6.

Based on its review, the staff found the applicant‘s response to RAI B2.1.30-7 unacceptable 

because staff did not have the initial text in Section 3.2.2 of ER-AP-SGP-103 or in 

ER-AP-SGP-101 to verify the adequacy of the applicant‘s response. The resolution of this issue 

is discussed below during discussion of RAI B2.1.30-17.

By letter dated July 13, 2009, the staff issued RAIs B2.1.30-5, B2.1.30-12, and B2.1.30-13 to 

address the third category of inconsistencies (i.e., applicant implementing procedures are 

inconsistent both internally and between documents). The staff‘s evaluation of each RAI is 

discussed below.

In RAI B2.1.30-5 dated July 13, 2009, the staff requested, in part, that the applicant clarify when 

its guidance documents would be updated since ER-AP-SGP-101 and ER-AP-SGP-102 

contained conflicting requirements.

In its response dated August 17, 2009, the applicant stated that Section 3.1.3 of 

ER-AP-SGP-102 was clarified to require compliance with the latest revision of the EPRI 

guidelines within the timeframe in the transmittal letter for the new guidelines.

Based on its review, the staff finds the applicant‘s response to this part of RAI B2.1.30-5

acceptable because this is consistent with NEI 97-06 and ER-AP-SGP-101 and, therefore, with 

GALL AMP XI.M19.
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In RAI B2.1.30-13 dated July 13, 2009, the staff requested that the applicant review 

ER-AP-SGP-10, ―Steam Generator Program Description,‖ and ER-AP-SGP-101, ―Steam 

Generator Program,‖ in order to clarify if the responsibilities of each person involved in the 

Steam Generator Program are identified correctly and consistently.

In its response dated August 17, 2009, the applicant stated that these procedures have been 

reviewed and revised, where necessary, to clarify the responsibilities of each person involved in 

the Steam Generator Program. The applicant also stated that all fleet Steam Generator 

Program procedures have been reviewed and revised, as necessary, to ensure responsibilities 

are identified consistently.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-13 acceptable 

because the applicant corrected the inconsistencies identified by the staff during the audit and 

widened its review and revision to all fleet Steam Generator Program procedures.

In RAI B2.1.30-12 dated July 13, 2009, the staff requested that the applicant address the 

discrepancy between Section 6.3 of the steam generator secondary-side integrity plan, which 

makes ―recommendations‖ on sludge lancing, and Section 3.3.6 of ER-AP-SGP-101, ―Steam 

Generator Program,‖ which requires a plan.

In its response dated August 17, 2009, the applicant stated that the steam generator 

secondary-side integrity plan had been reviewed for consistency with ER-AP-SGP-101, 

Section 3.6.6. The applicant stated that, as a result of this review, the steam generator 

secondary-side integrity plan has been determined to be consistent with Section 3.6.6 of 

ER-AP-SGP-101.

Based on its review, the staff found the applicant‘s response to RAI B2.1.30-12 unacceptable 

because staff did not have all the required information to confirm the adequacy of the applicant‘s 

response (i.e., that the applicant has plans for performing secondary-side inspections and 

maintenance). The resolution of this issue is discussed below during discussion of 

RAI B2.1.30-17.

The staff noted that for RAIs B2.1.30-2, B2.1.30-3, B2.1.30-5, B2.1.30-7, B2.1.30-11, and 

B2.1.30-12, the staff found the applicant‘s responses inadequate because the staff was not able 

to verify that the modifications to be made to the procedure and/or implementing documents will 

be consistent with GALL AMP XI.M19. By letter dated March 11, 2010, the staff issued the 

follow-up RAI B2.1.30-17 requesting that the applicant confirm that the modifications it will 

implement through its corrective action program, in its different documents, will be such that 

elements one through six of its Steam Generator Tube Integrity Program will be consistent with 

the corresponding program elements of GALL AMP XI.M19, before entering the period of 

extended operation for RAIs B2.1.30-2, B2.1.30-3, B2.1.30-5, B2.1.30-7, B2.1.30-11, and 

B2.1.30-12.

In its response dated March 26, 2010, the applicant stated that the modifications to the Steam 

Generator Tube Integrity Program and associated implementing documents discussed in the 

responses to RAls B2.1.30-2, B2.1.30-3, B2.1.30-5, B2.1.30-7, B2.1.30-11, and B2.1.30-12 

have been completed. The applicant further stated that no changes to the Steam Generator 

Tube Integrity Program are required and the program remains consistent with GALL 

AMP XI.M19, ―Steam Generator Tube Integrity.‖
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Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-17 acceptable 

because the applicant has confirmed that it has completed all the modifications discussed in its 

answers to RAls B2.1.30-2, B2.1.30-3, B2.1.30-5, B2.1.30-7, B2.1.30-11, and B2.1.30-12 in 

order to make its implementing documents consistent with its TSs, industry guidelines and, 

therefore, with all elements of GALL AMP XI.M19. The staff‘s concerns described in 

RAIs B2.1.30-2, B2.1.30-3, B2.1.30-5, B2.1.30-7, B2.1.30-11, B2.1.30-12, and B2.1.30-17 are 

resolved.

Exception. The staff also reviewed the portions of the applicant‘s program elements associated 

with the exception to determine whether the program will adequately manage the aging effects 

for which it is credited. The staff‘s evaluation of this exception follows.

LRA Section B.2.1.30 states an exception to the program in that the applicant‘s Steam 

Generator Tube Integrity Program is implemented using Revision 2 of NEI 97-06, whereas 

GALL AMP XI.M19 recommends the use of Revision 1 of NEI 97-06, ―Steam Generator 

Program Guidelines.‖ The applicant justified its use of Revision 2 based on the staff-approved 

KPS Technical Specification Amendment (ADAMS Accession Nos. ML061700091 and 

ML062430179) that incorporated Technical Specification Task Force Traveler 449, Revision 4, 

―Steam Generator Tube Integrity.‖

Since Revision 2 of NEI 97-06 is consistent with the applicant‘s TSs, the staff finds this 

exception to GALL AMP XI.M19 acceptable.

Based on its audit and review of the applicant‘s responses to the RAIs discussed above, the 

staff finds that elements one through six of the applicant‘s Steam Generator Tube Integrity 

Program, with an acceptable exception, are consistent with the corresponding program 

elements of GALL AMP XI.M19 and, therefore, acceptable.

Operating Experience. LRA Section B2.1.30 summarizes OE related to the Steam Generator 

Tube Integrity Program. The staff reviewed this information and interviewed the applicant‘s 

technical personnel to confirm that the applicable aging effects and industry and plant-specific 

OE have been reviewed by the applicant. During the audit, the staff independently confirmed 

that the applicant had adequately incorporated and evaluated OE related to this program.

The staff noted that due to tube degradation, the applicant replaced the original Westinghouse 

Model 51 steam generators with Westinghouse Model 54Fs in 2001. The applicant stated that, 

although similar in general design concept and capacity, the replacement steam generators 

incorporated a number of design improvements in response to OE with recirculating-type steam 

generators. The staff noted that the major improvements are based on the choice of corrosion 

resistant materials and on modifications of the upper part of steam generators.

In its LRA, the applicant also provided two examples of plant-specific OE, based on its review of 

corrective action program items that it considered in evaluating the effectiveness of the 

program:

In 2006, during implementation of a work order to visually inspect the annulus, 

tube lane, and a sample of in-bundle columns of its steam generators, five 

foreign objects were located in its ―A‖ Steam Generator and nine foreign objects 

were located in the ―B‖ Steam Generator. The retrieval efforts were 100 percent 

successful and all objects were removed from the steam generators. Eddy 

current inspection concluded that there were no indications that require repair.
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The applicant stated further that through the 2008 refueling outage, there were zero tubes 

plugged and zero sleeves installed in either steam generator. 

The staff also reviewed the OE documents provided by the applicant for the audit. During its 

audit, the staff interviewed the applicant‘s technical personnel to confirm that the plant-specific 

OE did not reveal any aging effects not bounded by the GALL Report. The staff confirmed that 

applicable aging effects and industry and plant-specific OE have been evaluated and 

incorporated into the Steam Generator Tube Integrity Program.

Based on its review, the staff finds that OE related to the applicant‘s program demonstrates that 

it can adequately manage the detrimental effects of aging on SSCs within the scope of the 

program, and implementation of this program has resulted in the applicant taking corrective 

actions. Therefore, the ―operating experience‖ program element satisfies the criterion in SRP-LR 

Section A.1.2.3.10 and the staff finds it acceptable.

USAR Supplement. LRA Section A2.1.30 provides the USAR supplement for the Steam 

Generator Tube Integrity Program. The staff reviewed this USAR supplement description of the 

program and notes that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.1-2. The staff 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 Steam Generator Tube 

Integrity 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 the LRA credits it. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions 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 Structures Monitoring Program

Summary of Technical Information in the Application. LRA Section B2.1.31 describes the 

existing Structures Monitoring Program as being consistent, with enhancements, to GALL AMPs 

XI.S5, ―Masonry Wall Program‖; XI.S6, ―Structures Monitoring Program‖; and XI.S7, ―RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants.‖ In the LRA, the 

applicant stated that the existing program manages the aging effects of:

● Concrete structural elements for cracking, loss of bond, loss of material, cracks and 

distortion, increase in porosity and permeability, loss of strength, and reduction in 

concrete anchor capacity due to local concrete degradation. The program performs 

opportunistic inspections of inaccessible concrete.

● Masonry walls for cracking.

● Structural steel elements and component supports, including anchoring system, bolts 

and fasteners, stainless steel, and aluminum for loss of material and loss of mechanical 

function. This includes structural steel for steel edge supports for masonry walls.
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● Non-metallic structural commodities for change in material properties, cracking, 

increased hardness, shrinkage and loss of strength, loss of sealing, and reduction or 

loss of isolation function for elastomers.

The applicant also stated in the LRA that the Structures Monitoring Program implements the 

requirements of 10 CFR 50.65, ―Requirements for Monitoring the Effectiveness of Maintenance 

at Nuclear Power Plants,‖ with the guidance of NUMARC 93-01, Revision 2, and RG 1.160, 

Revision 2, ―Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.‖ In the LRA, 

the applicant further stated that the program performs periodic visual inspections to monitor the 

condition of the structures, structural elements, miscellaneous structural commodities, water 

controlled structures, and masonry walls. 

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.

The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMPs XI.S5, XI.S6, and XI.S7. As discussed in the Audit Report, the staff 

confirmed that these elements are consistent with the corresponding elements of GALL 

AMP XI.S6. However, the staff needed further clarification to verify the consistency of program 

elements ―parameters monitored or inspected‖ and ―detection of aging effects‖ with GALL AMPs 

XI.S5 and XI.S7. Therefore, by letter dated July 13, 2009, the staff issued RAI B2.1.31-2 asking 

the applicant to include all the references for implementation in the element by element 

comparison. 

In its response dated August 17, 2009, the applicant stated that it had initiated a change to 

include the following references during the next update of the Structures Monitoring Program:

● Program Element: 3-Parameters Monitored or Inspected

[American Concrete Institute] ACI 349.3R-96 and ANSI/ASCE 11-90

● Program Element: 4-Detection of Aging Effects 

ACI 349.3R-96, ANSI/ASCE 11-90, and RG 1.127

During its review of the applicant‘s response, the staff issued follow-up RAI B2.1.31-2a by letter 

dated November 20, 2009, requesting that the applicant provide a list of applicable parameters 

of GALL AMP XI.S7, element 3, and indicate how those parameters will be monitored or 

inspected. In its response dated December 28, 2009, the applicant provided the list of the 

parameters that are applicable to its water-control structures within the scope of license 

renewal. The applicant further stated that it will use the Structures Monitoring Program to 

monitor those parameters.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.31-2 and follow-up 

RAI B2.1.31-2a acceptable because the applicant included the necessary references and 

provided the list of parameters that will be monitored for KPS water-control structures. The staff 

also confirmed that those parameters can be adequately monitored by the applicant‘s Structures 

Monitoring Program. The staff‘s concerns described in RAIs B2.1.31-2 and B2.1.31-2a are

resolved.
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Enhancement 1. In LRA Section B2.1.31, the applicant included an enhancement to ―Define 

In-Scope Structural Elements,‖ to enhance program element 1, ―scope of the program.‖ This 

enhancement clearly defines all the structures, structural elements, and miscellaneous 

structural commodities that are in scope. LRA Section 2.4 describes in detail the scoping and 

screening results for structures. Also, the staff reviewed the on-site document that provides 

information about the in-scope structures, including the components. The staff noted that LRA 

Section B2.1.31 and the program basis document state that structural elements, including 

bolting and fasteners, include such items as platforms, gratings, and component supports. 

Component supports are comprised of supports of the non-ASME Code piping; mechanical and 

electrical components (including their anchorage); heating, ventilation, and air conditioning 

(HVAC) ducts; and cable trays and conduits. Specialty items include sliding support surfaces 

and vibration isolation elements (non-metallic), base plate grout pads, and local concrete at 

expansion anchors. Miscellaneous structural commodities include such items as HELB barriers, 

flood barriers, electrical panels and cabinets, bus duct enclosures and gaskets, seals, and 

sealants. According to the onsite program basis documents, the masonry walls, including steel 

edged supports, identified in the response to IEB 80-11, are within the scope of the Structures 

Monitoring Program. The applicant confirmed that if the structure is within the scope of license 

renewal, then all masonry walls within that structure are in-scope.

On the basis of its review, the staff finds this enhancement acceptable because when it is 

implemented prior to the period of extended operation, it will be make the program consistent 

with the recommendations in GALL AMPs XI.S5, XI.S6, and XI.S7. 

Enhancement 2. In LRA Section B2.1.31, the applicant stated a further enhancement to 

program element 1, ―scope of the program.‖ This enhancement will periodically monitor 

groundwater to verify that the groundwater chemistry (e.g., pH, chlorides, and sulfates) remains 

non-aggressive during the period of extended operation. The staff reviewed the program basis 

document and found that the frequency of monitoring groundwater chemistry will be at least 

once every 5 years during the period of extended operation and will take into consideration 

seasonal variations. The staff also noted evidence of high chlorides and sulfates in LRA 

Section 3.5.2.2.1.1 and in condition reports, as stated in the audit report. 

Therefore, by letter dated July 13, 2009, RAI B2.1.31-3 was issued asking the applicant to:

 (a) describe past and present groundwater monitoring activities at KPS, including the results 

for sulfates, pH, and chlorides

 (b) provide the location(s) where test samples were or are taken relative to the 

safety-related and important-to-safety embedded concrete foundations

 (c) indicate seasonal variations

 (d) explain the technical basis and acceptance criteria

In its response by letter dated August 17, 2009, the applicant stated that the groundwater 

samples taken in June 2007; March, July, August, and October 2008; and March and June 2009 

indicate a chloride range from 34 ppm to 1,240 ppm. The applicant stated that average chloride 

readings from the eight wells selected for monitoring for license renewal varied from 120 ppm to 

640 ppm. The applicant also stated that use of de-icing salt is the most likely contributor to the 

elevated chloride concentration found in these wells, and that use of salt, instead of sand as a 

deicer, for the paved area began sometime between 1992 and 2000. Furthermore, the applicant 
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stated that a 40 mil thick (0.040 inch) PVC waterproofing membrane was installed over the 

concrete surface which minimizes direct contact between the concrete structures and the 

groundwater environment.

Based on its review of the applicant‘s response, the staff issued follow-up RAI B2.1.31-3a, by 

letter dated November 20, 2009, requesting that the applicant provide the following information:

 (a) Show the well locations with reference to the structures on the plant general 

arrangement plan drawing and indicate the maximum and average chloride content of 

the groundwater. This should identify the safety-related structures that are located in the 

areas where the chloride content has been found to be greater than 500 ppm.

 (b) Demonstrate that the current level of chloride in the groundwater is not causing any 

degradation to the structures.

 (c) Address the ability of the water proofing membrane to resist ingress of water in the 

concrete structure based on the plant-specific or/and industrywide experience.

The applicant responded to the follow-up RAI B2.1.31-3a by letter dated December 28 2009. 

During its review of the response, the staff noted that the maximum chloride content of six out of 

eight wells exceeded the GALL Report limit for chloride content (less than 500 ppm) and that 

these wells are located close to the safety-related structures. The staff noted that the 

groundwater table is 17 feet below grade level, and some parts of the structures are located 

below the groundwater level. The applicant has credited the water proofing membrane that was 

provided during initial construction to provide protection for the below-grade concrete structures. 

The applicant stated that it discontinued the use of sodium chloride-based de-icing products to 

reduce the possible mechanism, and is currently using pelletized calcium chloride mixed with 

sand. The applicant expects this new action will reduce the chloride content in the groundwater; 

however, the applicant provided no evidence that the below-grade concrete has not 

experienced degradation due to its exposure to groundwater with elevated chloride levels.

The staff held a conference call with the applicant on January 21, 2010, to discuss the 

aggressive groundwater and its effect on the below-grade structures. During the call, the staff 

explained that the applicant needed to provide evidence that the concrete has not degraded due 

to its exposure to an aggressive environment. The staff asked the applicant what actions would

be taken if, in the future, the chloride content in the groundwater does not drop below 

acceptable limits.

By letter dated February 15, 2010, the applicant submitted a supplemental response to address 

the staff‘s concerns discussed during the conference call. In its response, the applicant 

committed to take concrete core samples from the inside surface of a concrete wall, or from the 

foundation basemat, below the groundwater table elevation in the vicinity of groundwater wells 

for which the average sampling results have exceeded the chloride limit (Commitment No. 44). 

The applicant further explained that the cores will be tested to determine if the chloride content 

within the concrete could cause degradation due to corrosion of reinforcing steel. The applicant 

also committed to repeat the concrete core sampling prior to the end of the first 10 years of 

extended operation if the chloride content in the groundwater does not drop below the 500 ppm 

limit (Commitment No. 45).
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The staff reviewed the applicant‘s response and commitments and found them acceptable 

because they explain how concrete bore samples will be used to verify that exposure to an 

aggressive groundwater environment has not degraded the concrete. If the concrete samples 

reveal any degradation in the concrete or reinforcing steel, the results will be entered into the 

corrective action program and dealt with appropriately. The response also explains what actions 

would be taken during the period of extended operation if the groundwater chloride content does 

not drop below the acceptable 500 ppm limit. Since the applicant has committed to actions 

which will verify that the aggressive groundwater environment has not degraded the 

inaccessible concrete, the staff finds the applicant‘s approach acceptable and the staff‘s 

concerns in RAI B2.1.31-3a are resolved. 

On the basis of its review, including RAIs B2.1.31-3 and B2.1.31-3a, the staff finds this 

enhancement acceptable because when it is implemented prior to the period of extended 

operation, it will make the program consistent with the recommendations in GALL AMPs XI.S5, 

XI.S6, and XI.S7. 

Enhancement 3. In LRA Section B2.1.31, the applicant stated an enhancement to program 

element 3, ―parameters monitored or inspected‖; program element 5, ―monitoring and trending‖;

and program element 6, ―acceptance criteria,‖ by including provisions for underwater inspection. 

During the audit, the staff reviewed the onsite document that provides instructions for 

underwater inspection and repair. The staff also found that the program will be enhanced to 

require inspection of submerged structures in raw water on a frequency of 5 years. Inspection 

will be performed by a diver or by using remote video or other special safety equipment. During 

the audit, the staff reviewed the applicant‘s Preventive Maintenance Procedure for circulating 

water inlet and discharge structure inspection. This document provides instructions for diver 

inspection, cleaning, and repair, if required, of the circulating water inlet and discharge 

structures, forebay and screenhouse, as well as actions for zebra mussels and other organic 

macro-fouling as contained in GL 89-13 related to ―Service Water System Problem.‖

On the basis of its review, the staff finds this enhancement acceptable because when it is 

implemented prior to the period of extended operation, it will make the program consistent with 

the recommendations in GALL AMPs XI.S5, XI.S6, and XI.S7. 

Subsequent to the issuance of the SER on November 4, 2010, the staff identified three areas 

which required additional clarification from the applicant related to the inspection frequency of 

the Masonry Wall and Structures Monitoring programs, and to the acceptance criteria of the 

Structures Monitoring Program.

GALL AMP XI.S6, ―Structures Monitoring Program,‖ states that ACI 349.3R is an acceptable 

basis for selection of parameters monitored for detection of aging effects (i.e., inspection 

interval) and for acceptance criteria. The applicant had previously stated that it would list 

ACI 349.3R as a reference for its Structures Monitoring Program; however, it did not clearly 

state that the AMP‘s inspection interval and acceptance criteria would align with ACI 349.3R.

The staff discussed this issue with the applicant during a conference call on November 17, 

2010. By letter dated November 23, 2010, the applicant responded. In its response, the 

applicant stated that the inspection frequency for both the Structures Monitoring Program and 

the Masonry Wall Program was 5 years. The applicant also committed to include the 

acceptance criteria in ACI 349.3R as the criteria to be used when evaluating concrete structures 

(Commitment No. 54). The staff reviewed the applicant‘s response and found it acceptable 

because the applicant clarified that the inspection interval for both programs was at least as 
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conservative as the recommended interval in ACI 349.3R and committed to implement the 

quantitative acceptance criteria recommended in ACI 349.3R. The staff‘s concerns related to 

the inspection frequency for the Masonry Wall and Structures Monitoring Programs and the 

acceptance criteria for the Structures Monitoring Program are resolved.

Based on its audit and review of the applicant‘s responses to RAIs B2.1.31-2, B2.1.31-3, and 

the corresponding follow-up RAIs, as well as the additional clarifying information in the 

applicant‘s letter of November 23, 2010, the staff finds that elements one through six of the 

applicant‘s Structures Monitoring Program, with acceptable enhancements, are consistent with 

the corresponding program elements of GALL AMPs XI.S5, XI.S6, and XI.S7 and are, therefore, 

acceptable.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.31. The staff 

also searched and reviewed onsite documents, condition reports, and corrective action 

requests. The LRA states that during the 1997 periodic structure monitoring inspections of the 

screenhouse and tunnel, the applicant observed cracking with leaching. In March 2003, the 

applicant observed multiple concrete degradation mechanisms on a wall. The localized 

deficiencies and aging included cracking, leaching, patterned cracking, and a slight surface 

offset. Follow-up inspections by the applicant, in December 2004, revealed the condition of the 

affected area and overall wall to be stable, with no changes observed since the previous

inspection. The applicant re-examined the area in April 2008 and included it in the long-range 

rehabilitation plan. The structure status was evaluated as ―acceptable with deficiencies.‖ 

The LRA also states that in March 2003, during the periodic structure monitoring inspections of 

the turbine building, the applicant observed corrosion and chemical residue at the base of 

building column 1-A. Some localized material loss was observed at the outer flange, anchor 

bolts, and gussets. The area was re-inspected approximately 2 years later and the degradation 

had not progressed, so the normal inspection frequency was reinstated. 

The LRA further states that in March 2003, during the periodic structure monitoring inspections 

of the turbine building, the applicant observed deteriorating sealant (i.e., cracking and 

separation from adjoining concrete surfaces) in three vertical fire protection wall joints. The 

inspection noted that there was no active leakage observed or detected in the joints and the 

filler material appeared intact. The applicant stated it repaired the vertical wall joints to restore 

functionality. 

LRA Section B2.1.31 also states that in April 2003, leaching and cracking was observed on the 

outer concrete surface of the reactor refueling cavity wall (south side). According to the 

applicant‘s inspection, the noted indications were localized and the overall structural integrity of 

the wall appeared sound. The reactor refueling pool was flooded at the time of the observation. 

The hairline cracking was considered passive and did not affect the structural integrity of the 

concrete wall. Based on earlier inspection and chemistry sampling, a small amount of borated 

water found its way down the wall, followed the lip of the narrow crack, and deposited boric acid 

when it dried. The accessible wall area was cleaned. During a subsequent inspection in October 

2004, there was no change in appearance from 2003, nor any indication of an active leak or the 

presence of moisture.

The staff reviewed OE information in the application and during the audit to determine whether 

the applicable aging effects and industry and plant-specific OE were reviewed by the applicant.

As discussed in the Audit Report, the staff conducted an independent search of the plant OE 
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information to determine whether the applicant had adequately incorporated and evaluated OE 

related to this program.

During its review, the staff identified OE which could indicate that the applicant‘s program may 

not be effective in adequately managing aging effects during the period of extended operation. 

The staff determined the need for additional clarification, which resulted in the issuance of RAIs 

as discussed below.

The screenhouse and tunnel degradation discussed in the LRA was observed during the staff‘s 

walkdown on the audit. The wall was dry and the cracks were repaired and maintained in good 

condition. However, several instances of leaching were observed. By letter dated July 13, 2009, 

the staff issued RAI B2.1.31-6 asking that the applicant provide further explanation of its

―Long-range Rehabilitation Plan.‖ The staff also requested that the applicant explain its actions 

to manage the concrete aging effect and maintain integrity of the structure during the period of 

extended operation.

The applicant responded to this RAI by letter dated August 17, 2009, stating that LRA 

Appendix B, Section B2.1.31 incorrectly indicated that the ―status of the screenhouse structure 

following April 2008 inspection was acceptable with deficiencies‖ and that ―the screenhouse 

structure would be included in the long-range rehabilitation plan.‖ In its response to the RAI, the 

applicant stated that, as a result of the April 2008 inspection, the status of the screenhouse 

structure should have been identified as acceptable. In the response, the applicant also stated 

that the screenhouse wall currently indicates small hairline cracking with some leaching without 

any indication of spalling of concrete, and that moreover, inspection of screenhouse structures 

will continue during the period of extended operation to ensure intended functions and structural 

integrity. Additionally, the applicant stated that the circulating water pump room wall will be 

inspected during each refueling outage to manage concrete aging. The applicant confirmed that 

the inspection results will be entered into the corrective action program, evaluated, and, if 

required, will be repaired or additional corrective actions will be initiated. The staff finds the 

applicant‘s response acceptable on the basis that the applicant has identified adequate actions 

to manage the concrete aging, to maintain integrity of the screenhouse, and to ensure no loss of 

structure or structural component intended functions during the period of extended operation. 

The staff‘s concern described in RAI B2.1.31-6 is resolved.

By letter dated July 13, 2009, the staff also issued RAI B2.1.31-4 requesting more information 

about the reactor refueling cavity leakage. In the RAI, the staff requested that the applicant:

 (a) provide further information on what has been done to monitor the cracking, leaching, and 

leakage of boric acid after the last inspection in 2004

 (b) address what actions will be taken to manage the degradation during the period of 

extended operation to prevent any loss of intended function

 (c) address the adequacy of the current inspection interval considering the specific OE

In its response by letter dated August 17, 2009, the applicant stated that in October 2004, it

re-inspected the cracked location with the refueling pool flooded and did not find any active 

leakage through the crack. Based on the October 2004 inspection, the applicant concluded that 

no further action was required. The applicant further stated that during the fall 2006 refueling 

outage, regularly scheduled Boric Acid Corrosion Program inspections did not observe any 

leakage. The applicant stated that during the spring 2008 refueling outage, regularly scheduled 
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Structures Monitoring Program inspections did not identify any noticeable boric acid at the crack 

location. The applicant also stated that it would continue regular Structures Monitoring Program 

and Boric Acid Corrosion Program inspections. Furthermore, the applicant stated that during the 

period of extended operation, if the Structures Monitoring Program inspections observe 

degradation, an increased inspection frequency will be implemented to ensure the intended 

functions of the affected structures are maintained. However, the applicant also noted that other 

leak locations were identified during the 2006 and 2008 refueling outages. By letter dated 

November 20, 2009, the staff issued follow-up RAI B2.1.31-4a requesting the following 

information:

 (a) more details about the leakage volumes and paths observed in 2003, 2004, 2006, and 

2008 outages 

 (b) details of any remedial actions or repairs performed during 2003 and 2004 to stop the 

leakage

 (c) plans to verify the structural integrity of the concrete and rebar at the cracked locations 

by core drills or other means 

 (d) plans for permanent remediation of reactor cavity and refueling pool leakage

In its response dated December 28, 2009, the applicant responded to the request (a) by

describing three leakage indication sites. Leakage Site No. 1 is the one that is described in the 

previous RAI response. Leakage Site No. 2 was identified in October 2006. Leakage Site No. 3

was identified by the applicant in March 2008, and is located at the junction between the 

reinforced concrete biological shield wall and the base of the reactor refueling cavity.

The applicant provided details on Leakage Site No. 2 as follows: This leakage is at the 

construction joint of the ―A‖ RCS vault. The applicant observed residue streaking and staining 

and a small amount of moisture on the wall surface below the location of the construction joint. 

The applicant further noted that there was no measurable leakage or accumulation of boric acid 

crystals. This leakage site was again inspected during the next refueling outage in April 2008 

and the observation indicated wetting or moisture, a small amount of accumulation of residue, 

and some amount of wall staining and streaking at the ―A‖ RCS vault wall construction joint. This 

leakage site was re-inspected during the 2009 refueling outage, when multiple inspections were 

performed at different times during the outage. The initial inspection is noted as an ―as-found‖ 

inspection. In addition, a follow-up inspection was performed prior to filling the reactor refueling 

cavity pool, another inspection after filling the pool, and a final inspection at the end of the 

outage. After the ―as-found‖ inspection, the residue was removed from the leakage area and no 

further indication was noted until the final inspection, which was performed 17 days after filling 

the reactor refueling cavity. The applicant described this as small leakage; however, the 

frequency of inspection using the Structures Monitoring Program has been increased to each 

refueling in order to document and trend the observed conditions and assess the integrity of the 

concrete structure. 

The applicant provided details on Leakage site No. 3 as follows: This leakage also showed 

accumulation of residue, streaking, and staining on the wall surface. There was no quantifiable 

water flow from the junction and the applicant considered this as minor leakage. Similar to 

Leakage Site No. 2, Leakage Site No. 3 was further inspected multiple times during the 

refueling outage in 2009. Based on the long delay for leakage indication to reappear on the wall 

surface, potential reactor refueling cavity pool leakage at this location is also considered minor. 
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However, the applicant has increased the frequency of inspection using the Structures 

Monitoring Program to each refueling, in order to document and trend the observed conditions 

and assess the integrity of the concrete structure.

The applicant further stated that during the refueling outage in 2009, it performed additional 

inspections to check for the presence of other leakage and to verify that there was no moisture 

in contact with the RCV. The applicant inspected the containment basement and sump ―B,‖ 

which is located nearest to the containment vessel. From these inspections, the applicant could 

not find any leakage that would indicate potential for moisture in contact with the RCV. In 

addition, this inspection did not indicate any additional leakage indication sites that could have 

resulted from the reactor refueling cavity pool leakage.

In its response to request (b), the applicant determined that the leakage indication at Leakage 

Site No. 1 in 2003 was due to a small amount of borated water from a source external to the 

reactor refueling cavity pool. However, the applicant determined the leakage indication at 

Leakage Sites No. 2 and No. 3 to potentially originate from reactor refueling cavity pool liner 

leakage. The applicant further stated that the results of the inspections performed during the 

2009 refueling outage would be evaluated as an input to the determination of the necessary 

corrective actions related to the potential reactor refueling cavity pool liner leakage. The 

applicant also stated that it will add the following commitment to LRA Appendix A, USAR 

supplement, Table A6.0-1.

Item Commitment Source Schedule

33 Develop a plan for identification and remediation of 

reactor refueling cavity liner leakage to be 

implemented during the period of extended operation. 

Letter 09-760 

Response to 

RAI B2.1.31-4a

Prior to the period 

of extended 

operation

In response to request (c), the applicant determined the leakage at site No. 1 to be a passive 

condition and acceptable as-is, and that this leakage was from a source external to the reactor 

refueling cavity pool that flowed along the surface of the wall such that the concrete and 

reinforcing steel within the wall are not affected. Furthermore, the applicant stated that it 

performed follow-up inspections during the subsequent four refueling outages which confirmed 

the structural integrity of the concrete at Leakage Site No. 1.

According to the applicant‘s inspections and observations, Leakage Sites No. 2 and No. 3 are 

located at construction joints and originated from the reactor refueling cavity liner. The applicant 

concluded that the leakage rates at sites No. 2 and No. 3 are very small and the additional 

inspection within containment could not find any other leakage from the reactor refueling cavity 

pool. Furthermore, the applicant stated that, based on other nuclear plant evaluations, the 

effects of borated water on reinforced concrete structural integrity is considered minimal, and

that the identified leakages at these locations are very small. Consequently, the applicant 

concluded that the degradation of the reinforced concrete or the metal RCV is negligible. In 

order to confirm this conclusion, the applicant stated it will perform a reinforced concrete 

structural integrity examination for the concrete slab below the spent fuel pool (SFP) in the 

auxiliary building, as a representative location comparable to Leakage Sites No. 2 and No. 3, 

since the reinforced concrete material and the environments are the same for both locations.

In response to request (d), the applicant stated that as described in Commitment No. 33 above, 

it is developing an action plan to pursue additional methods for identification and remediation of 
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reactor refueling cavity pool liner leakage, which will include weld examinations, identification, 

and re-sealing of potential leakage sites at the liner penetrations.

The staff held a conference call with the applicant on January 21, 2010, to discuss Commitment 

No. 33, as well as the applicant‘s plans related to the refueling cavity leakage. During the call, 

the staff expressed its need to review the refueling cavity liner leakage action plan during the 

LRA review process. The staff also explained that wording needed to be added to the 

commitment which says a concrete sample will be taken from the refueling cavity concrete if the 

SFP core indicates degradation.

By letter dated February 15, 2010, the applicant submitted a supplemental response to address 

the staff‘s concerns discussed during the conference call. In the response, the applicant outlined 

a remediation plan for the refueling cavity liner leakage as summarized here. The outline 

explained that the current leakage sites will continue to be inspected during each refueling 

outage. Inspections will also be conducted during each refueling outage of containment internal 

structures with the objective of identifying any additional leakage indication sites. New leakage 

indications, or changes in existing leakage rates, will be documented in the corrective action 

program and evaluated. The outline also explained that a multi-discipline team will be formed to 

develop recommendations for inspection, testing, and repairs to remediate the liner leakage. 

The supplemental response also included a new commitment to take at least one core bore 

sample near at least one of the refueling cavity leakage indication sites, if the core sample 

below the SFP indicates degradation (Commitment No. 46). The core sample will be tested for 

compressive strength and will undergo a petrographic examination.

The staff reviewed the applicant‘s response and finds it acceptable because it outlines a

remediation plan which includes continued inspections of the existing leakage sites, inspections 

to identify possible additional leakage sites, as well as plans to ultimately repair the leakage. In 

addition, the concrete core bore discussed in Commitment No. 46 ensures that any degradation 

that may have been caused by the leakage will be captured and addressed prior to the period of 

extended operation. Since the applicant now has plans in place to stop the leakage and to 

address any concrete degradation that may have occurred as a result of the leakage, the staff‘s 

concerns in RAI B.2.3.31-4a are resolved. 

During the audit, while reviewing condition reports, the staff found that a white substance was 

observed on the wall and ceiling of the waste drumming room, below the SFP. The issue was 

discovered in December 2007. According to the condition report, it is boric acid-related. The 

staff conducted a walkdown during the audit and saw the white material; however, due to limited 

visibility, the staff was unable to arrive at any conclusion. The white substance indicates leakage 

of borated water through the concrete, which may be degrading the concrete and rebar. 

Therefore, by letter dated July 13, 2009, the staff issued RAI B2.1.31-5 asking the applicant to:

 (a) provide information regarding the source of the leakage and any plan to fix the leakage 

prior to entering the period of extended operation

 (b) if no plan exists to fix the leakage, provide the monitoring plan, inspection methods, and 

inspection schedule to ensure that degradation will be detected and quantified before 

there is a loss of intended functions

In its response dated August 17, 2009, the applicant stated that after the identification of white 

deposits on the wall and ceiling of the waste drumming room in December 2007, it held several 
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meetings to discuss fuel pool makeup, housekeeping and contamination, groundwater 

concerns, and the possibility of structural degradation. The applicant also stated that it cleaned 

the area, continued to observe, tried to find the cause of the condition, and established a 

corrective action plan. While monitoring, the applicant observed residue again in the cleaned 

area a little more than a month after the area was cleaned, but there was no active dripping. In 

June 2008, the applicant decided to: (1) monitor and troubleshoot as follow-up action; (2) add a 

monthly visual inspection to monitor the change in size, shape, and color of the deposit; and 

(3) photograph the leak location for comparative analysis. After 1 year of monitoring the wall and 

ceiling of the waste drumming room, the applicant observed that the residue formation remained 

constant. The applicant stated that the residue formation rate was slow and, therefore, there 

was no near-term concern for the integrity of the structure or potential loss of intended function. 

The applicant decided to take action if it observed any change in leakage trend or other signs of 

concrete distress.

Based on its review, by letter dated November 20, 2009, the staff issued follow-up 

RAI B2.1.31-5a to the applicant requesting the following information:

 (a) verification of the condition of the concrete and rebar at the crack locations by 

appropriate NDE

 (b) clarification of the applicant‘s basis for assuming the reinforcing bars will remain 

protected by concrete, even when they come in contact with boric acid water for a 

sustained period, since leakage of boric acid water could change the pH and could be a 

potential cause for corrosion of the rebar

 (c) a description of the applicant‘s plan for permanent remediation

 (d) a description of the functioning of leakchase channels and monitoring of water level in 

the SFP

In its response dated December 28, 2009, the applicant stated that it monitors groundwater and, 

to date, the result did not indicate any detectable level of tritium outside the auxiliary building or 

in the groundwater. The applicant confirmed that all the minor leakage from the SFP is 

contained within the auxiliary building or the radioactive waste disposal system because at KPS, 

the SFP is actually at an intermediate elevation in the auxiliary building. The SFP base is 7 feet 

thick concrete and it is 15 feet above the auxiliary building basement floor.

In response to items (a) and (b), the applicant referred to investigations, studies, and tests 

regarding the Salem SFP leakage in 2002, the liner leakage of the reactor cavity and SFP at 

Indian Point Units 2 and 3 (NUREG-1930), and the water seepage from the refueling cavity at 

Prairie Island Units 1 and 2 (―Safety Evaluation Report Related to the License Renewal of 

Prairie Island Nuclear Generating Plants‖). The applicant stated that industry data indicate that 

even in the presence of borated water, the conditions at the rebar remain sufficiently alkaline, 

resulting in negligible corrosion. In order to confirm that potential SFP liner leakage is not 

causing significant degradation of SFP reinforced concrete, the applicant will obtain a concrete 

core sample at the greatest leak location and perform a strength test and petrographic 

examination. After the test, the applicant will enter the results in the corrective action program, 

evaluate the impact on SFP structural integrity, and identify additional actions. 
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The applicant will add the following commitment to LRA Appendix A, USAR supplement, 

Table A6.0-1:

Item Commitment Source Schedule

34 At least one core bore sample will be taken from the 

waste drumming room reinforced concrete ceiling 

below the spent fuel pool. The core sample location 

and depth will be sufficient to validate the strength of 

the concrete and the extent of any degradation. The 

core sample will be tested for compressive strength 

and will be subjected to petrographic examination. 

Reinforcing steel in the core sample area will be 

exposed and inspected for material condition. 

Letter 09-760 

Response to 

RAI B2.1.31-5a

Prior to the period 

of extended 

operation

In response to item (c), the applicant stated that it will develop an action plan based on the 

observed leakage and in consideration of the available techniques to inspect for leaks, including 

leak testing of the accessible SFP liner pressure boundary weld seams. The applicant further 

noted that the presence of spent fuel in the storage pools makes inspection of a large part of the 

storage pool liners impractical due to access restrictions. The applicant will add the following 

commitment to LRA Appendix A, USAR supplement, Table A6.0-1: 

Item Commitment Source Schedule

35 Develop a plan for identification and remediation of 

spent fuel pool liner leakage to be implemented during 

the period of extended operation. 

Letter 09-760 

Response to 

RAI B2.1.31-5a

Prior to the period 

of extended 

operation

The applicant further added that if repair efforts to eliminate the SFP leakage in the waste 

drumming room are not successful, an additional core sample will be subjected to the same 

tests prior to the end of the first 10 years of extended operation, and this commitment will be 

added to the following commitment to LRA Appendix A, USAR supplement, Table A6.0-1. After 

the test, the applicant will enter the results in the corrective action program, evaluate the impact 

on SFP structural integrity, and identify additional actions.

Item Commitment Source Schedule

36 If SFP liner leakage persists during the period of 

extended operation, an additional concrete core 

sample will be taken from the waste drumming room 

reinforced concrete ceiling below the spent fuel pool. 

The core sample location and depth will be sufficient to 

validate the strength of the concrete and the extent of 

any degradation. The core sample will be tested for 

compressive strength and will be subjected to 

petrographic examination. Reinforcing steel in the core 

sample area will be exposed and inspected for material 

condition. 

Letter 09-760 

Response to 

RAI B2.1.31-5a

Prior to the end of 

the first ten years 

of extended 

operation

In response to item (d), the applicant described that the SFP and the fuel transfer canal are 

divided into 10 leak detection zones, five for the pools and five for the canal. The applicant also 

stated that, at present, three zones, zone nos. 1, 4, and 5, are indicating leakage of 

approximately 6, 3, and 9 ounces per day, respectively, which totals to one gallon per week. 

Furthermore, the applicant stated that plant auxiliary operator records the SFP water level each 

shift and the operating crews review all logs for trends or abnormal readings. In the control 
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room, there is an SFP high/low alarm and the SFP level is maintained in accordance with the 

normal operating procedure.

The staff held a conference call with the applicant on January 21, 2010, to discuss Commitment 

Nos. 34 and 35, as well as the applicant‘s plans related to the SFP leakage. During the call, the 

staff explained that it needs to review the SFP leakage action plan (Commitment No. 35) during 

the LRA review process. The staff also explained that the applicant needs to explain why 

scheduling the concrete core bore ―prior to the period of extended operation‖ is acceptable.

By letter dated February 15, 2010, the applicant submitted a supplemental response to address 

the staff‘s concerns discussed during the conference call. In the response, the applicant outlined 

a plan to identify and remediate the SFP liner leakage. The outline explained that the leakage 

indication sites would continue to be inspected monthly. Portions of the auxiliary building 

adjacent to the SFP will be inspected annually during the period of extended operation to 

identify any additional leakage indications. Any additional indications will be documented and 

entered into the corrective action program. The outline also explained that a multi-discipline 

team will be formed to develop recommendations for inspection, testing, and repairs to 

remediate the SFP liner leakage. In addition, the SFP liner seam weld leakage detection and 

collection system drain lines will be inspected and repaired, if required, to ensure a clear drain 

path. The applicant explained that this will minimize the potential for re-direction of liner leakage 

through the concrete structure due to clogged drain lines. The applicant further explained that a 

routine maintenance activity will be created to continue inspection of the drain lines through the 

period of extended operation.

The applicant‘s supplemental response also revised the timing of a previous commitment to 

take a concrete core sample from below the SFP. The schedule was changed from ―prior to the 

period of extended operation‖ to ―prior to the end of 2011‖ (Commitment No. 34). Due to the low 

safety significance of the leakage, as well as the necessary preparation, the applicant feels this 

timing is reasonable and adequately supports the objective of the commitment.

The staff reviewed the applicant‘s response and finds it acceptable because it outlines a

remediation plan which includes continued inspections of the existing leakage sites, inspections 

to identify possible additional leakage sites, as well as plans to ultimately identify and repair the 

leakage source. The plan also includes inspections, and any necessary repairs, of the drain line 

system. These inspections should reduce the likelihood of future leakage through the concrete 

by ensuring the drain lines are clear. In addition, the concrete core bore discussed in 

Commitment No. 34 ensures that any degradation that may have been caused by the leakage 

will be captured and addressed prior to the period of extended operation. Due to the minor 

amount of leakage, along with the relatively recent identification of the issue (2007), the staff 

finds that the schedule for the commitment is appropriate. Since the applicant has plans in place 

to stop the SFP leakage through the concrete and to address any concrete degradation that 

may have occurred as a result of the leakage, the staff‘s concern described in RAI B.2.3.31-5a 

is resolved.

Based on its audit and review of the application, and review of the applicant‘s response to 

RAIs B2.1.31-4, 4a, 5, and 5a, the staff finds that OE related to the applicant‘s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program, and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the ―operating experience‖ program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable. 
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USAR Supplement. LRA Section A2.1.31 provides the USAR supplement for the Structures 

Monitoring Program. The staff reviewed this USAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.5-2.

The staff noted that LRA Section A2.1.31 does not clearly describe the program summary with 

all necessary references for implementation as defined in SRP-LR, Revision 1. By letter dated 

July 13, 2009, the staff issued RAI B2.1.31-1 requesting that the applicant revise Appendix A, 

―Program Description,‖ to summarize the Structures Monitoring Program consistent with the 

level of detail provided in SRP-LR, Revision 1. By letter dated August 17, 2009, the applicant 

responded to this RAI stating that the LRA Appendix A, USAR supplement, Section A2.1.31, 

―Structures Monitoring Program,‖ will be revised to add:

The program implements the requirements of 10 CFR 50.65, ―Requirements for 

Monitoring the Effectiveness of NUMARC 93-01, Revision 2, Industry Guideline 

for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,‖ and 

Regulatory Guide 1.160, Revision 2, ―Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants.‖

The staff noted that the response covers GALL AMP XI.S6 only. By letter dated November 20, 

2009, the staff issued follow-up RAI B2.31-a asking the applicant to incorporate the summary 

description of the ―Masonry Wall‖ and ―Inspection of Water-Control Structure‖ program because 

the applicant has combined those programs in its Structures Monitoring Program. In its 

response dated December 28, 2009, the applicant stated that it will add the following description 

to LRA Section A2.1.31:

For masonry walls within the scope of license renewal, the Structures Monitoring 

Program manages aging effects based on guidance provided in IE Bulletin 80-11, 

―Masonry Wall Design,‖ and plant-specific monitoring proposed by NRC 

Information Notice 87-67, ―Lessons Learned from Regional Inspections of 

License Actions in response to NRC IE Bulletin 80-11.‖ For water-control 

structures within the scope of license renewal, the Structures Monitoring Program 

manages aging effects consistent with the guidelines of RG 1.127, ―Inspection of 

Water Control Structures associated with Nuclear Power plants.‖

The staff also noted that the applicant committed (LRA Table A6.0-1; Commitment Nos. 22, 23, 

and 24) to enhance the Structures Monitoring Program prior to entering the period of extended 

operation. Specifically, the applicant committed to: (1) Commitment No. 22, ―Define In-Scope 

Structural Elements: the Structures Monitoring Program will be enhanced to clearly define 

structures, structural elements, and miscellaneous structural commodities that are in scope‖;

(2) Commitment No. 23, ―Groundwater Monitoring: the Structures Monitoring Program will be 

enhanced to monitor groundwater quality and verify that it remains non-aggressive to 

below-grade concrete‖; and (3) Commitment No. 24, ―Underwater Inspections: the Structures 

Monitoring Program will be enhanced to improve criteria for detection of aging effects for the 

underwater visual inspections of the in-scope structures.‖

Additionally, the applicant added Commitment Nos. 44 and 45 related to aggressive 

groundwater, Commitment Nos. 33 and 46 for reactor refueling cavity leakage, and 

Commitment Nos. 34, 35, and 36 for SFP leakage. 
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The applicant also added Commitment No. 54 to include the evaluation criteria of ACI 349.3R 

as the criteria to be used when evaluating conditions or findings identified during concrete 

structure inspections.

The staff determines that the modified 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 and RAI responses, 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 confirmed that their implementation through Commitment Nos. 22, 23, 24, 

33, 34, 35, 44, and 46, prior to the period of extended operation, and Commitment Nos. 36 and 

45, prior to the end of the first 10 years of extended operation, would make the existing AMP 

consistent with the GALL Report AMPs 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 functions 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 Work Control Process Program

Summary of Technical Information in the Application. In the applicant‘s letter dated 

September 25, 2009, the applicant amended LRA Section B2.1.32, ―Work Control Process 

(WCP) Program,‖ from a plant-specific AMP to a new AMP that will be consistent with the 

program elements in GALL AMP XI.M32, ―One-Time Inspection,‖ with an enhancement, and 

with GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,‖ with noted exceptions and an enhancement. The applicant‘s exceptions to GALL 

AMP XI.M38 include exceptions on the ―scope of the program,‖ ―parameters monitored,‖ 

―detection of aging effects,‖ and ―acceptance criteria‖ program elements in GALL AMP XI.M38. 

Specifically, the applicant identified that these exceptions pertain to the applicant‘s use of this 

AMP to manage new component materials, environments, and aging effects beyond those cited 

in GALL AMP XI.M38 and on the acceptance criteria that will be used to assess those aging 

effects that are applicable to these component material-environment-aging effect combinations. 

The applicant provided the specific details for these exceptions in its letter dated September 25, 

2009. 

The applicant clarified that the WCP Program, with a noted enhancement, will be consistent with 

the program elements in GALL AMP XI.M32, ―One-Time Inspection,‖ for those GALL 

Report-based AMR items in the LRA in which the WCP Program will be used to verify the 

effectiveness of five AMPs: (1) the Primary Water Chemistry Program, (2) the Secondary Water 

Chemistry Program, (3) the Closed-Cycle Cooling Water Program, (4) the Fuel Oil Program, and 

(5) the Lubricating Oil Analysis Program.

The applicant also clarified that the WCP Program, with noted exceptions and an enhancement, 

will be consistent with the program elements in GALL AMP XI.M38, ―Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components,‖ when applied to those GALL 

Report-based and plant-specific AMR items in the LRA in which the WCP Program is credited 

as a periodic, condition monitoring program. The applicant further stated that the methodology 

in EPRI TR-107514 will be considered in the determination of the overall sample size, and that a 
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technical review of plant-specific inspection results and a plant-specific OE evaluation will be 

performed.

Staff Evaluation. During its audit and review, the staff confirmed the applicant‘s claim of 

consistency with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff reviewed the 

enhancement to determine whether the AMP, with the enhancement, is adequate to manage 

the aging effects for which the LRA credits it. The staff confirmed that all of the program 

elements claimed by the applicant to be consistent with program elements in GALL AMP XI.M32 

were consistent with those described in the GALL AMP, except for those program element 

aspects in which the staff felt that additional clarification was necessary, or for which the staff 

felt additional information was necessary and for which an RAI was issued. The staff‘s 

evaluation of these program element aspects is presented in the paragraphs that follow.

The staff noted that, for those components or commodity groups associated with AMR items 

crediting the Primary Water Chemistry Program, the Secondary Water Chemistry Program, the 

Closed-Cycle Cooling Water Program, the Fuel Oil Program, or the Lubricating Oil Analysis

Program to manage loss of material, cracking, or loss of heat transfer function in the 

components, the applicant will apply the WCP Program to verify that these preventive or 

mitigative monitoring AMPs are achieving their aging management functions and that the aging 

effects of concern either do not occur, are progressing at an extremely slow growth rate, or that 

the time for initiation of the applicable aging effects involves an extremely long incubation time. 

The staff confirmed that, for these AMR items, the applicant‘s intent to use the WCP Program 

conforms to the staff‘s guidance in GALL AMP XI.M32 on when a one-time examination can be 

applied as a condition-monitoring aging management basis. 

The staff also noted that, in the ―detection of aging effects‖ program element for the AMP, the 

applicant‘s one-time inspection methods for managing loss of material, cracking, and loss of 

heat transfer function inducing mechanisms were consistent with those listed in the inspection 

method table in GALL AMP XI.M32. As a result, the staff found the applicant‘s inspection 

techniques for the one-time examinations to be acceptable because they were in conformance 

with those recommended in GALL AMP XI.M32 to manage loss of material, cracking, and 

reduction of heat transfer capability. 

The applicant indicated that the sample of components inspected for the one-time examinations 

would be done on a representative sampling basis, and that the applicant‘s sampling basis was 

consistent with the sampling basis statement for one-time inspections, as given in the ―detection 

of aging effects‖ program element in GALL AMP XI.M32. However, the staff also noted that the 

applicant‘s representative sampling basis did not clearly establish how the sampling would be 

accomplished because the WCP Program is credited with aging management of a varied set of 

environments, materials, and aging effects. As a result, the staff identified that the applicant‘s 

sampling basis did not clearly establish whether one sample population would be selected to 

represent the entire set of material-environment-aging effect combinations the program 

manages, or whether a representative sample of components would be selected for each of the 

material-environment-aging effect combinations that the program manages. In addition, the staff 

identified that additional explanations were needed regarding the type of conditions that would 

be used to factor in which component locations would be inspected under the program‘s 

one-time, representative sampling basis (e.g., loss of material due to corrosion could be 

expected to occur more readily in stagnant areas or creviced regions, etc.).

In a letter dated December 3, 2009, the staff issued RAI B2.1.32-1 requesting that the applicant 

clarify whether the WCP Program would inspect a representative sample of the component or 
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structure populations for each of the material-environment-aging effect combinations that is 

managed, in accordance with one of the referenced preventative or mitigative monitoring 

programs, or whether some other type of sampling basis would be used. The staff also asked 

the applicant to clarify which type of engineering, design, operational, or OE considerations 

would be used to select the sample of components for the one-time examinations, and to 

explain why the considerations used for the selection process are considered to be adequate, 

particularly if a given sample of structures or components is used to represent more than one 

material-environment-aging effect combination.

In its response dated January 21, 2010, the applicant clarified that, for those inspections 

performed under the WCP Program for verification of the effectiveness of the implementation of 

the Primary Water Chemistry Program, Secondary Water Chemistry Program, Closed-Cycle 

Cooling Water Program, Fuel Oil Program, or Lubricating Oil Analysis Program, the WCP 

Program will establish a population set for each material for which the WCP Program is 

credited, and that this AMP will inspect a number (sample) of components for each environment 

to which the materials are exposed. 

The applicant stated that the total sample size and selection of locations for inspection will be 

based on an assessment of the materials of fabrication, operating environments, plausible aging 

effects, and OE relative to the components in the populations for the material sets, consistent 

with the methodology in EPRI TR-107514, ―Age-Related Degradation Inspection Method and 

Demonstration on Behalf of Calvert Cliffs Nuclear Plant,‖ for performing this type of assessment. 

More specifically, the applicant clarified that the locations selected for inspection will be based 

on identifying those locations that are most susceptible to aging, in light of the time in service, 

component design aspects (such as geometry), environmental factors, severity of operating 

conditions, and remaining component safety margins for the populations of components in the 

material sets.

The staff finds the applicant‘s basis for selecting component locations for inspection to be 

acceptable because it is in conformance with the ―monitoring and trending‖ program element in 

GALL AMP XI.M32, which identifies that the sample size and sample locations for inspection 

should be based on an assessment of the materials of fabrication, environment, plausible aging 

effects, and OE for the components that are within the component population sets.

However, the staff also noted that the applicant is crediting methodology in EPRI TR-107514 as 

the basis for selecting the sample sizes for the material-environment-aging effect combinations 

that will be managed using this one-time inspection basis, and that this report states that the 

sample sizes should achieve a desired confidence level. Thus, the staff also noted that the 

applicant‘s sampling basis left some uncertainty with respect to establishing the sample size for 

one-time inspections: the applicant did not exactly specify or provide a justification for the 

minimum sample sizes that would be used for these one-time inspections, or establish a limit, 

with justification, on when these one-time examinations would need to be completed to ensure 

appropriate and timely verification of preventive or mitigative program effectiveness. By letter 

dated April 14, 2010, the staff issued follow-up RAI B2.1.32-5, Parts 1 through 4. In Part 1 of the 

RAI, the staff asked the applicant to specify and justify the minimum percentage of components 

that would be used to establish the sample sizes for the one-time examinations of the stated 

component populations. The staff also asked the applicant to identify and justify when the 

one-time inspections for the WCP Program would be completed. The staff identified this as

Open Item B2.1.32-1, Part 1.
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The applicant responded to RAI B2.1.32-5, Part 1, by letter dated May 13, 2010. In its response 

to Part 1 of the RAI, the applicant stated it is using the engineering sample size criteria in EPRI 

Report TR-107514 to establish the sample size for one-time inspections that would be applied 

to those steel, stainless steel, and copper alloy components for which the WCP is being used to 

verify the effectiveness of either the Primary Water Chemistry Program, Secondary Water 

Chemistry Program, Closed-Cycle Cooling Water Program, Fuel Oil Program, or Lubricating Oil

Analysis Program in managing aging. The applicant stated that the sample sizes are as follows:

Table 3.0.3.2.19-1: Component Populations and Sample Sizes for WCP One-Time Inspections

Material Group Component Population Sample Size

Steel Components 200 25

Stainless Steel Components 200 25

Copper Alloy Components ~ 200 25

Aluminum Alloy Components 1 1

The applicant stated that the EPRI Report establishes a minimum sample size of 25 for 

component population sets containing 200 or more components. 

The staff noted that the applicant‘s program will perform a one-time inspection of the one 

aluminum component that is within the scope of the WCP‘s one-time examinations, and a 

one-time inspection of 25 components for each of steel, stainless steel, and copper alloy 

commodity groups that are within the scope of the programs‘ one-time examinations. The staff 

noted that it has previously approved the EPRI sampling methodology as an acceptable 

sampling basis methodology for past applications. As a result, the staff finds that the applicant‘s 

use of the EPRI sampling basis is acceptable because the applicant is applying a sampling 

methodology that has been approved by the staff for past applications, and because the 

applicant will inspect at least 25 components for the steel, stainless steel, and copper alloy 

component populations in the program, as well as the sole aluminum component that is within 

the scope of the program‘s one-time inspections. Staff‘s concerns in RAI B2.1.32-5, Part 1 and 

RAI B2.1.32-1, relative to establishing and justifying the component populations and samples 

sizes for the components that will be subject to the one-time inspections of the WCP, are 

resolved, and Open Item B2.1.32-1, Part 1 is closed.

Based on this assessment, the staff finds that the applicant has provided an acceptable 

one-time sampling basis for the WCP Program for each of the populations that will be managed 

in accordance with either the Primary Water Chemistry Program, Secondary Water Chemistry 

Program, Closed-Cycle Cooling Water Program, Fuel Oil Program, or Lubricating Oil Analysis 

Program, and that this aspect of the WCP Program is consistent with the recommendations in 

GALL AMP XI.M32, ―One-Time Inspection.‖ 

Consistency with GALL AMP XI.M38, Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components. During its audit and review, the staff confirmed the applicant‘s claim 

of consistency with GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous Piping 

and Ducting Components.‖ The staff reviewed the enhancement to determine whether the AMP, 

with the noted exceptions and the enhancement to the program, is adequate to manage the 

aging effects for which the LRA credits the WCP Program as a periodic, condition monitoring 

program. The staff confirmed that all of the program elements, claimed by the applicant to be 

consistent with program elements in GALL AMP XI.M38, were consistent with those described 
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in the GALL AMP, except for those program element aspects in which the staff identified that 

additional clarification or additional information was necessary and for which an RAI was issued. 

The staff also issued RAIs on the exceptions taken to GALL AMP XI.M38.

“Detection of Aging Effects” Program Element. The staff noted that the applicant provided its 

bases for applying the WCP Program as a periodic, condition monitoring (inspection-based) 

program in the applicant‘s letter of September 25, 2009. The staff noted that the ―detection of 

aging effects‖ program element in GALL AMP XI.M38 recommends that locations for inspection 

should be chosen to include conditions likely to exhibit the aging effects and that the inspection 

intervals should be established such that they provide for timely detection of degradation. The 

staff also noted that the applicant‘s ―detection of aging effects‖ program element basis did not 

specifically establish or justify what sample populations, sample sizes, and inspection 

frequencies would be used for the periodic examinations that are performed in accordance with 

the WCP Program when the program is credited as a periodic, condition monitoring program 

basis. In a letter dated December 3, 2009, the staff issued RAI B2.1.32-2 requesting that the 

applicant clarify which type of environmental, design, operational, or engineering factors will be 

used to select the specific sample populations, sample sizes, and inspection frequencies for 

those aging effects and mechanisms that the WCP Program will be used to manage on a 

periodic, condition monitoring program basis.

In its response dated January 21, 2010, the applicant clarified that, for each 

material-environment combination managed by the WCP Program on a periodic basis, the WCP 

Program will perform a review of the scheduled periodic surveillance and preventative 

maintenance activities to enable selection of specific activities to ensure that the sampled 

locations in the WCP Program will be representative of the components in the program. The 

applicant clarified that the review will consider material, environmental, and OE factors in 

selecting the locations for inspections, and will take other operational and design-based factors 

into account, such as time at service, remaining design margins, and severity of operating 

conditions. The applicant also clarified that selected scheduled, surveillance, and maintenance 

activities will be performed on a repetitive basis and that any evidence of aging detected during 

the activities will be documented and evaluated for applicability to other components with the 

same material-environment combination as the component for which the degradation was 

detected. The applicant clarified that an engineering review will be performed to evaluate the 

condition, extent of condition, and need for corrective actions.

The applicant also clarified that the implementation of the internal surfaces monitoring portion of 

the WCP Program will require engineering personnel at the site to perform the following 

activities: (1) review the program inspection results to identify any new degradation mechanisms 

not previously considered, (2) monitor and/or perform walkdown activities to verify adequate 

identification and documentation of aging effects and initiation of corrective actions, (3) perform 

trending of inspection results, and (4) review site OE through the plant‘s corrective action 

program to ensure that aging effects are addressed. 

The staff noted that the ―detection of aging effects‖ program element in GALL AMP XI.M38 

recommends that, for AMPs conforming to GALL AMP XI.M38, the applicant ―should identify 

and justify the inspection technique used for detecting the aging effects of concern,‖ and that the 

locations chosen for inspection should include those with conditions likely to exhibit these aging 

effects. The staff also noted that the ―monitoring and trending‖ program element in GALL 

AMP XI.M38 recommends that the visual examination activities of the program be qualified in 

accordance with site procedures and processes, that intervals for the examinations be based on 

the materials and environments for the components in the program, and that consideration be 
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given to both generic and plant-specific OE. Based on these program elements, the staff finds 

the applicant‘s inspection and monitoring and trending bases (as supplemented in the letters of 

September 25, 2009, and January 21, 2010) to be acceptable because: (1) they are in 

conformance with the GALL AMP XI.M38 recommendations for using material, environmental, 

operational, and OE considerations in the selection of the program‘s inspection intervals, 

sample size, and component locations for inspection, and (2) the applicant‘s bases are

consistent with GALL AMP XI.M38 recommendations that the program be directed at inspecting 

and detecting degradation in those components that have the highest probability of exhibiting 

the conditions and aging effects that are managed by the program. Therefore, the staff‘s 

concern described in RAI B2.1.32-2 is resolved.

Exceptions to GALL AMP XI.M38. The applicant took four exceptions to GALL AMP XI.M38.

Exception 1. In its letter dated September 25, 2009, the applicant took an exception to the 

―scope of the program‖ program element in GALL AMP XI.M38, which identifies that the scope 

of the program is applicable to management of loss of material in the internal surfaces of steel 

piping, piping elements, ducting, and components in internal environments (such as internal 

indoor uncontrolled air, condensation, or steam environments). The applicant identified that the 

scope of the WCP Program, as applied as a periodic, condition monitoring program, is being 

credited for additional materials, environments, and aging effect combinations that are not 

included in GALL AMP XI.M38.

The staff noted that the exception applies the scope of the WCP Program to the following 

additional material-environment-aging effect combinations:

● aluminum components – loss of material and reduction of heat transfer capability under 

exposure to moist air environments and loss of material in outdoor air environments

● copper alloy components – loss of material and reduction of heat transfer capability 

under exposure to uncontrolled indoor air environments, moist air environments, or raw 

water environments; loss of material under exposure to moist air environments and loss 

of material in outdoor air environments or closed-cycle cooling water environments

● stainless steel components – loss of material in uncontrolled indoor air environments, 

moist air environments, outdoor air environments, raw water environments, and 

closed-cycle cooling water environments; loss of material and cracking in diesel exhaust 

environments

● steel components – loss of material in uncontrolled indoor air environments, moist air 

environments, raw water environments, closed-cycle cooling water environments, and 

diesel exhaust environments

● elastomeric components – changes in material properties (hardening and loss of 

strength) in indoor uncontrolled air, indoor controlled air, moist air, and raw water 

environments; loss of material in indoor uncontrolled air and raw water environments; 

loss of sealing in indoor uncontrolled air and outdoor air environments; cracking in indoor 

uncontrolled air environments 

● non-metallic paper filters – loss of strength in dried air environments
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The staff finds the applicant‘s exception to use the WCP Program for the management of loss of 

material in steel, stainless steel, and copper alloy components under exposure to various air, 

treated water, or raw water environments acceptable because: (1) the applicant‘s basis is 

consistent with the criteria in GALL Table IX.C, which identifies that stainless steel, steel, and 

copper alloy (greater than 15 percent zinc (Zn) alloying content) materials may be susceptible to 

loss of material by pitting and crevice corrosion (and for steel by general corrosion); and 

(2) consistent with the AMR items of the GALL Report, the applicant‘s basis accounts for the 

fact that loss of material may occur in these materials as a result of MIC when the materials are 

exposed to a raw water source. The staff evaluated the periodic inspection methods used to 

detect loss of material in these steel, stainless steel, and copper components in the staff‘s 

evaluation of the applicant‘s exception on the ―detection of aging effects‖ program element for 

this AMP.

The staff finds the applicant‘s exception to apply the WCP Program to the management of loss 

of material in aluminum alloy components conservative because aluminum alloy components 

are normally resistant to significant corrosion due to the development of a protective surface

(thin aluminum oxide layer) that protects the underlying aluminum material from further 

corrosion by an oxidizing environment (such as sources of oxygenated water or uncontrolled air 

environments).

The staff finds the applicant‘s basis to use visual methods to monitor for aging (loss of strength) 

in the non-metallic filter papers conservative because, although the applicant is applying the 

WCP Program to monitor for and manage loss of strength in the filter paper components, the 

components are replaced when the differential pressure across the filter reaches a 

pre-described limit and thus, the filter papers represent consumable components for the 

application.

The staff finds the applicant‘s exception to apply the WCP Program to the management of 

changes in material properties (including drops in the strength modulus or elastomeric 

hardening) in elastomeric components acceptable because the applicant‘s basis is consistent 

with GALL Table IX.C, which identifies that loss of strength and hardening are applicable aging 

effect mechanisms for elastomeric components. The staff finds the applicant‘s exception to 

apply the WCP Program to the management of loss of sealing in elastomeric components 

acceptable because the applicant‘s basis is consistent with the GALL Report Table IX.E, which 

identifies that loss of sealing may be applicable in elastomeric components. The staff finds the 

applicant‘s exception to apply the WCP Program to the management of cracking in elastomeric 

components to be acceptable because the applicant‘s basis is consistent with the basis in the 

GALL Report Table IX.F, which identifies that degradation of elastomeric materials may include 

cracking (including crazing, which is a form of cracking).

The staff noted that the applicant was crediting the WCP Program to manage loss of material 

due to pitting and crevice corrosion and cracking due to SCC in the stainless steel piping, piping 

components, and piping elements of the diesel generator exhaust lines under internal exposure 

in a diesel exhaust environment. The staff noted that this specific environment is limited to only 

a small number of component locations, and that the staff‘s recommendations for managing loss 

of material and cracking in these lines is addressed in SRP-LR Sections 3.3.2.2.2.3 and 

3.3.2.2.7.3, respectively. In a letter dated December 3, 2009, the staff issued RAI 3.3.2.2.3.3-1, 

requesting that the applicant discuss whether the WCP Program would actually inspect the 

diesel generator exhaust lines to monitor loss of material and cracking.
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In its response to RAI 3.2.2.3.3-1, dated January 21, 2010, the applicant stated that the 

stainless steel diesel generator exhaust flexible connections would be components that are 

explicitly selected for periodic enhanced VT-1 inspections under the periodic, condition 

monitoring bases of the WCP Program to monitor for evidence of loss of material and cracking 

in the interior surfaces of the components. The staff finds this condition monitoring basis to be 

acceptable because: (1) it is in conformance with recommendations in SRP-LR 

Sections 3.3.2.2.3.3 and 3.3.2.2.7.3, which state that a plant-specific AMP (using either GALL 

Report-based elements or plant-specific program elements) be credited to manage cracking and 

loss of material due to pitting and crevice corrosion in stainless steel diesel engine exhaust 

piping components; (2) the applicant will be using enhanced VT-1 examinations to inspect the 

internal surfaces of the stainless steel diesel exhaust flexible connections; and (3) the ASME 

Code Section XI lists VT-1 visual methods (including enhanced VT-1) as being capable of 

detecting these types of aging effects. The staff‘s concern described in RAI 3.3.2.2.3.3-1 is 

resolved with respect to its relationship to the WCP Program.

The staff also noted that, with respect to the comparison that was made to the ―scope of the 

program‖ program element in GALL AMP XI.M38, the applicant identified that the program 

scope includes periodic examinations of the external surfaces of the electrical box gaskets, the 

spent fuel gate seals and hoses, and reactor cavity seal ring, which are made from elastomeric 

materials. The staff observed that these components are not piping or ducting components that 

would meet the scope of components in GALL AMP XI.M38. The staff also observed that the 

scope of GALL AMP XI.M38 does not apply to inspection of external surface locations. As a 

result, the staff noted that the applicant‘s letter, dated September 25, 2009, did not identify the 

inclusion of the electrical box gaskets, the spent fuel gate seals and hoses, and reactor cavity 

seal ring, or the proposal to inspect the external surfaces of these components, as exceptions 

that are applicable to the ―scope of the program‖ program element criteria in GALL AMP XI.M38. 

In addition, the staff noted the ―scope of the program‖ and ―parameters monitored or inspected‖ 

program element discussions in the applicant‘s license renewal basis document indicated that 

the WCP Program inspections would be performed only during periodic surveillance or 

preventative maintenance activities when the components are opened up and the internal 

surfaces of the components are made accessible for examination. 

The staff also noted that Commitment No. 25 in the applicant‘s letter, dated September 25, 

2009, clarifies that the visual examinations for monitoring for aging in the elastomeric electrical 

box gaskets, spent fuel gate seals and hoses, and reactor cavity seal ring will be performed 

when the external surfaces of the components are made available for examination during 

preventative maintenance activities or periodic surveillance activities performed on the 

components. Based on its review, the staff finds that the applicant has provided an acceptable 

basis for adding the elastomeric electrical box gaskets, spent fuel gate seals and hoses, and 

reactor cavity seal ring to the scope of the WCP Program inspections because they are within 

the scope of Commitment No. 25, and because it is clear from the commitment that the visual 

examinations of these components will be performed when the external surfaces of these 

elastomeric components are made accessible for examination during periodic surveillance or 

preventative maintenance activities.

Based on the considerations discussed in the previous paragraphs and the staff‘s bases for 

concluding that the stated additional materials and environments are acceptable materials and 

environments to add to the scope of the WCP Program, the staff finds that the applicant has 

provided an acceptable basis for adding stainless steel, aluminum, copper, and selected 

elastomeric and paper filter components to the scope of the program, and finds this exception to 

be acceptable.
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Exceptions 2 and 3. In its letter dated September 25, 2009, the applicant took an exception to 

the ―parameters monitored or inspected‖ element in GALL AMP XI.M38, which identifies that 

visual inspections of internal surfaces of plant components are performed during maintenance 

or surveillance activities, and that the parameters monitored or inspected include visible 

evidence of corrosion to indicate possible loss of material. The applicant also took an exception 

to the ―detection of aging effects‖ element in GALL AMP XI.M38, which states, in part, that 

applicants for renewal should identify and justify the inspection technique used for detecting the 

aging effects of concern, that the locations should be chosen to include conditions likely to 

exhibit these aging effects, and that the inspection intervals selected should be established such 

that they provide timely detection of degradation. In these exceptions, the applicant identified 

that the WCP Program will monitor the following conditions or parameters:

● loss of material in aluminum, copper alloy, steel and stainless steel components –

monitor for evidence of localized discoloration or surface irregularities that are caused by 

either rust, scale, deposits, surface pitting, discontinuities, and coating degradation using 

visual examination methods on the internal surfaces of the components

● cracking in stainless steel diesel exhaust components – monitor for localized corrosion, 

discoloration, linear discontinuities, or surface irregularities that may be indicative of 

cracking using enhanced VT-1 or equivalent examinations 

● reduction of heat transfer capability – monitor for evidence of fouling, deposits, or scale 

on heat exchanger tubes using visual examinations of the internal surfaces of the 

components 

● elastomeric component degradation – monitor for evidence of cracking and crazing, 

discoloration, distortion, swelling, tears, usual wear, or leaks using the visual 

examination methods of the program, and monitoring for signs of tackiness, resiliency, or 

abnormal indentation recovery using the supplement physical manipulation methods of 

the program

● loss of strength in non-metallic filter papers – monitor for evidence of tears, material 

degradation, discoloration, unusual wear, or loss of form using visual examination 

methods

The staff noted that the applicant was appropriately looking for evidence of linear surface 

discontinuities as its basis for monitoring for cracking in stainless steel components and that the 

applicant was crediting either VT-1 or enhanced VT-1 methods as visual inspection methods for 

the detection of cracking. The staff found these bases to be acceptable because they are 

consistent with bases in the ASME Code Section XI that indicate VT-1 methods are acceptable 

visual examination methods for the detection of linear surface discontinuities or cracks. Based 

on these findings, the staff concluded that the ―parameters monitored‖ and ―detection of aging 

effects‖ program elements exception bases for detection of cracking to be acceptable. 

The staff noted that, for the management of loss of material in aluminum, copper alloy, steel or 

stainless steel components, the applicant will use the visual examinations of the WCP Program 

to monitor for both localized discoloration in the components and for evidence of surface 

irregularities, such as rust, scale, deposits, surface pitting, surface discontinuities, or (for coated 

metallic components) coating degradation. The staff noted that, for the management of loss of 

heat transfer capability in aluminum and copper alloy heat exchanger components, the applicant 
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will use the visual examinations of the WCP Program to monitor for evidence of fouling, 

deposits, or scale on the heat exchanger/cooler tubes. The staff found the applicant‘s 

parameters for detecting loss of material in the aluminum, copper alloy, steel or stainless steel 

components and for reduction of heat transfer capability in aluminum or copper alloy heat 

exchanger tubes to be acceptable because they are consistent with the type of parameters 

mentioned in Article IWA-2000 of the ASME Code Section XI for providing evidence of abnormal 

surface conditions. Based on these findings, the staff concluded that the ―parameters 

monitored‖ program element exception basis on the parameters that will be monitored for 

indication of loss of material or reduction of heat transfer capability to be acceptable. 

However, the staff also noted that the exception to use visual examination methods for the 

detection of aging effect conditions or parameters that would be indicative of loss of material in 

a metallic component or that could reduce a heat exchanger component‘s heat transfer 

capability did not define which type of visual examination methods would be used for the 

component inspections. In contrast, the staff noted that the applicant did identify which visual 

examinations or non-visual inspection techniques would be used to monitor for loss of material 

or fouling for the aspects of the program that would be implemented in accordance with the 

one-time inspection criteria of GALL AMP XI.M32. 

In a letter dated December 3, 2009, the staff issued RAI B2.1.32-3 requesting that the applicant 

clarify whether the visual inspection techniques that have been specified for detecting loss of 

material (induced by corrosion, wear, erosion, etc.) or reduction of heat transfer capability 

(fouling), when the program is implemented in conformance with the criteria in GALL 

AMP XI.M32, are also applicable to the monitoring of these aging effects/mechanisms when the 

WCP Program is credited on a periodic, aging management basis (i.e., the inspections that will 

be performed in accordance with recommendations in GALL AMP XI.M38). 

In its response to RAI B2.1.32-3, dated January 21, 2010, the applicant clarified that the visual 

examinations for detecting loss of material due to wear, corrosion, or erosion or reduction of 

heat transfer, when the program is implemented on a periodic basis in conformance with GALL 

AMP XI.M38, will not be VT-1 or VT-3 visual inspection techniques. The applicant clarified that, 

instead, the visual examinations will be performed by KPS maintenance personnel who receive 

specific training and qualifications on detecting the parameters that are associated with these 

aging effects. The applicant clarified that, specifically, the maintenance workers will be trained 

and qualified to look for and detect localized surface discolorations and/or surface irregularities 

(such as rust, scale, corrosion deposits or products, or surfaces pits) that may be indicative of 

these aging effects. 

The staff noted that the scope of the ―detection of aging effects‖ program element in GALL 

AMP XI.M38 only covers the general visual inspection techniques that may be used to detect 

evidence of abnormal surface conditions that may be associated with loss of material or 

reduction of heat transfer capability aging effects. As a result of this determination, the staff 

observed that the applicant‘s visual ―detection of aging effects‖ program element basis for 

managing loss of material in metallic components and reduction of heat transfer capability in the 

copper and aluminum heat exchanger tubes was in conformance with the ―detection of aging 

effects‖ program element criterion in GALL AMP XI.M38, which states that personnel performing 

the visual examination activities of the program should be qualified for the examinations in 

accordance with site controlled procedures and processes. 

However, the staff also observed that under the applicant‘s amended WCP Program basis, as 

given in the applicant‘s letter of September 25, 2009, and supplemented with information in the 
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letter of January 21, 2010, the WCP Program lends itself to being a program that monitors for 

abnormal surface conditions, such as rust, discoloration, deposits, scale, or abnormal surface 

conditions, or for evidence of cracking or changes in the material properties for elastomeric 

components (except for the visual techniques that the applicant credited for detection of 

cracking in metallic components: the applicant‘s letter dated September 25, 2009, states that 

these will be enhanced VT-1 techniques or their equivalent). As a result, the staff noted that the 

applicant‘s amended ―detection of aging effects‖ and ―monitoring and trending‖ program 

elements bases still did not establish its criterion for establishing and justifying the sample size 

that would be applied to the material-environment-aging effect populations being managed by 

the AMP on a periodic basis, or for establishing and justifying a minimum inspection frequency 

for the components being managed by the WCP Program on a periodic basis (i.e., specifying 

the maximum time that could elapse before an inspection of the components in the sample 

would actually have to be scheduled and performed). As a result, the staff concluded that the 

applicant‘s ―detection of aging effects‖ program element exception basis would need to be 

supplemented to provide additional details on: (1) clarifying and justifying the minimum 

percentage of components in the component samples that would be inspected to be 

representative of the component populations that the samples are representative of, and 

(2) defining and justifying a maximum limit on the time that could elapse before components in 

samples being examined would, with certainty, need to be scheduled for inspection. 

By letter dated April 14, 2010, the staff issued RAI B2.1.32-5, Part 2, to resolve this issue. In 

RAI B2.1.32-5, Part 2, the staff asked the applicant to provide additional details on how the 

WCP Program would be applied as a period inspection program as made relative to the 

management of loss of material and reduction of heat transfer capability in metallic components, 

and implemented in a manner consistent with the ―parameters monitored or inspected‖ and 

―detection of aging effects‖ program elements of GALL AMP XI.M38 (with noted exceptions). 

Specifically, the staff asked the applicant to: (1) specify and justify the minimum percentage of 

components that will be used to establish the sample sizes for the component populations that 

are associated with these material-aging effect combinations and will be managed on a periodic 

WCP-inspection basis, and (2) specify and justify the maximum frequency for the periodic 

examinations of the components in these samples. Resolution of RAI B2.1.32-3 is pending 

acceptable resolution of RAI B2.1.32-5, Part 2. The staff identified this as Open Item B2.1.32-1, 

Part 2.

The staff also noted that the applicant did not specify the minimum percentage of components 

that would be used to establish the sample size of elastomeric components that will be 

inspected on a periodic inspection basis or the maximum time limit that could elapse before 

inspections of the elastomer components in the sample would have to be, with certainty, 

scheduled for examination. As a result, the staff noted that the same issues raised in 

RAI B2.1.32-5, Part 2 and Open Item B2.1.32-1, Part 2, for managing loss of material and loss 

of heat transfer capability in metallic components, are also applicable to the applicant‘s 

―detection of aging effects‖ program element basis for elastomeric components. Thus, the issue 

raised in RAI B2.1.32-5, Part 2 and Open Item B2.1.32-1, Part 2 are also applicable to the 

―detection of aging effects‖ program element basis for managing cracking and changes in 

material properties in elastomeric components.

The applicant responded to RAI B2.1.32-5, Part 2 by letter dated May 13, 2010. In its response, 

the applicant restated its initial basis for the sample sizes and inspections that would be used to 

manage loss of material and reduction of heat transfer capability in the metallic components that 

would be managed under the WCP Program‘s periodic visual examinations and to manage 

cracking and changes in the material properties for the elastomeric components that are within 
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the scope of these periodic examinations. Specifically, the applicant clarified that the WCP 

Program historically performs enough periodic surveillance or preventive maintenance activities 

such that a sample of the population of components in each material/environment population set 

would be made available and accessible for inspection under the program elements of the WCP

Program.

However, the staff also noted that, in the applicant‘s response to RAI B2.1.32-2 (contained in

applicant‘s letter dated January 21, 2010), the applicant had indicated that:

For each material-environment combination, sufficient internal surfaces 

inspections will be performed during scheduled surveillance and maintenance 

activities to provide an overall assessment of any aging degradation that may be 

occurring. A review of the scheduled surveillance and maintenance activities will 

be performed to select activities that will provide a set of inspections that will be 

representative of the components in the program. The review will consider 

component materials; operating environments; industry and plant-specific 

operating experience; engineering evaluations of equipment performance; and 

susceptibility to aging due to time in service, severity of operating conditions, and 

lowest design margins.

Based on the response to RAI B2.1.32-2, the staff noted that the applicant had previously 

identified that it would define a sample set of component inspections that would be 

representative of the components in the material/environment populations of the program that 

would be inspected on a periodic basis. Thus, the staff noted that the applicant‘s response to 

RAI B2.1.32-5, Part 2 did not resolve the staff‘s issue on having assurance that the components 

selected for these material/environment sets would actually be scheduled for inspection on a 

periodic basis during the period of extended operation. Specifically, the staff noted that the 

applicant would need to provide further assurance that each of the lead-indicator components‘

material/environment sample sets would be inspected at least once prior to the period of 

extended operation to set a baseline set of results for these lead indicator components, and at 

least twice during the period of extended operation to conform to the definition of a periodic

condition monitoring program. By letter dated September 10, 2010, the staff issued 

RAI B2.1.32-5a, requesting that the applicant provide a description on how the WCP Program 

would be modified to ensure that a limit is placed on the maximum amount of time that could 

elapse before the lead indicator components in the sample sets would need to inspected.

The applicant responded to RAI B2.1.32-5a by letter dated September 23, 2010. In its response,

the applicant stated the program will be supplemented to include the following amended 

―detection of aging effects‖ and ―monitoring and trending‖ program element bases to ensure that 

the components selected for the sample sets would be inspected:

Prior to the period of extended operation, the inspections performed in 

accordance with the Internal Surfaces Monitoring portion of the Work Control 

Process program will be audited. The audit will confirm that inspections have 

been performed for each material/environment combination credited in the Work 

Control Process program for the inspection of internal surfaces. If a 

material/environment combination has not been inspected prior to the period of 

extended operation, supplemental inspections will be planned. Any identified 

supplemental inspections will be performed within 5 years from completion of the 

audit.
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Additionally, to confirm that the Internal Surfaces Monitoring portion of the Work 

Control Process program continues to adequately manage aging of the 

components for which it is credited; this audit will be repeated during each 10 

years of the period of extended operation. As with the initial audit, additional 

supplemental inspections will be performed if any material/environment 

combinations have not been inspected at least once during the 10-year period.

The staff noted that the applicant included these amended periodic ―detection of aging effects‖ 

and ―monitoring and trending‖ program element bases as license renewal Commitment No. 50 

in LRA Appendix A (USAR supplement) Table A6.0-1. In this commitment, the applicant 

committed to performing the stated audit of inspected components and material/environment 

combinations for these components a first time as a baseline inspection audit at least once 

within 5 years prior to entering the period of extended operation, and subsequently at least once 

within each 10-year interval scheduled for the 20-year period of extended operation. By letter 

dated October 20, 2010, the applicant amended Commitment No. 50 to clarify that the stated 

audits would be to confirm that the components in the lead material/environment sample sets 

had been inspected, or else to schedule them for inspection.

The staff noted that the applicant‘s amended bases, as committed to in the letter of 

September 23, 2010, resolve the staff‘s concern regarding frequency and number of periodic 

inspections performed on each of the components that will be selected for material/environment 

sample sets because it will ensure that the components will be inspected at least once prior to 

the period of extended operation and at least twice during the period of extended operation. 

Staff concerns in RAIs B2.1.32-2, B2.1.32-3, and B2.1.32-5a are resolved, and Open 

Item B2.1.32-1, Part 2 is closed.

The staff finds the applicant‘s exception, to apply the WCP Program and use visual examination 

methods to monitor for and manage loss of strength in the non-metallic filter papers, to be an 

acceptable and conservative aging management basis because: (1) the applicant will replace 

these filters when the differential pressure across the filter exceeds a pre-defined threshold; 

(2) under the provisions of 10 CFR 54.21(a)(1), these components do not need to be within the 

scope of an AMR because they are consumable components (i.e., the filters will be replaced on 

a specified frequency when the differential pressure threshold is achieved); (3) under this AMP, 

the applicant will conservatively monitor for loss of strength-related degradation in the filters, 

even though the requirements in 10 CFR 54.21(a)(1) do not require these consumable 

components be within the scope of an AMR; and (4) the parameters that the applicant will 

monitor for as providing for indications of loss of strength (i.e., monitor for evidence of tears, 

material degradation, discoloration, unusual wear, or loss of form in the filter papers) are easily 

detected in the papers using general visual examination methods. 

Based on its review, the staff finds the exceptions on the ―parameters monitored or inspected‖ 

and ―detection of aging effects‖ program elements on GALL AMP XI.M38, as made relative to 

the various materials and aging effects that the program manages, to be acceptable. 

Exception 4. In its letter dated September 25, 2009, the applicant took an exception to the 

―acceptance criteria‖ program element in GALL AMP XI.M38, which identifies that indications of 

various corrosion mechanisms or fouling will be reported and evaluated, and that the 

acceptance criteria are established in the maintenance and surveillance procedures or other 

established plant procedures. 
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In this exception, the applicant clarified that the scope of the WCP Program, as applied as a 

periodic, condition monitoring program, is being credited for additional materials, environments, 

and aging effect combinations that are not included in GALL AMP XI.M38. Therefore, the 

acceptance criteria for the program includes additional acceptance criteria for the additional 

aging effects that the program manages (i.e., the program includes additional acceptance 

criteria for cracking in stainless steel components; for loss of material, cracking, loss of sealing, 

changes in material properties, including hardening and loss of strength, in elastomeric 

components; and for loss of strength in the non-metallic filter papers). The applicant also 

clarified that the appropriate acceptance criteria are contained in applicable design standards, 

design codes, and manufacturer information, or vendor manuals, and that in the event that the 

acceptance criteria are not available in applicable source documents, an engineering evaluation 

would be performed to establish the specific acceptance criteria. The staff found this basis to be 

acceptable because it meets the staff acceptance criteria position in SRP-LR Section A.1.2.3.6, 

which states, in part, that acceptance criteria could be specific numerical values, or that 

acceptance criteria from available references may be cited.

The staff noted, however, that in this exception, the applicant indicated that the acceptance 

criteria will be established in the license renewal trailer when the program is implemented and 

that the acceptance criteria are no unacceptable wear, corrosion, cracking, change in material 

properties (for materials and non-metallics) or significant fouling. The staff noted that the 

statement, ―no unacceptable wear, corrosion, cracking, change in material properties (for 

materials and non-metallics) or significant fouling,‖ is vague and ambiguous. 

In a letter dated December 3, 2009, the staff issued RAI B2.1.32-4 requesting that the applicant 

clarify the intent of the phrase, ―no unacceptable wear, corrosion, cracking, change in material 

properties (for materials and non-metallics) or significant fouling.‖ Specifically, the staff asked 

the applicant to clarify whether the intent was to establish a go/no-go acceptance criterion for 

the GALL AMP XI.M38 aspects of the program (meaning that no evidence of aging would be 

acceptable and any evidence was unacceptable), or whether a certain amount of wear, 

corrosion, cracking, change in material properties, or significant fouling could be permitted in the 

components as long as it is within the bounds of the acceptance criteria for the detected aging 

effect mechanism (as established in implementing procedures).

In its response to RAI B2.1.32-4, dated January 21, 2010, the applicant clarified that the intent 

of the phrase, ―no unacceptable wear, corrosion, cracking, change in material properties (for 

materials and non-metallics) or significant fouling,‖ was to indicate that a certain amount of 

degradation could be permitted as long as it was within the acceptance criteria bounds 

established in the plant implementing procedures. The staff found that the applicant‘s exception 

basis taken on the ―acceptance criteria‖ program element of GALL AMP XI.M38, as 

supplemented by this clarification, to be acceptable because it is in conformance with the 

―acceptance criteria‖ program element recommendation in GALL AMP XI.M38, which states 

that:

Indications of various corrosion mechanisms or fouling that would impact 

component intended function are reported and will require further evaluation. The 

acceptance criteria are established in the maintenance and surveillance 

procedures or other established plant procedures. If the results are not 

acceptable, the corrective action program is implemented to assess the material 

condition and determine whether the component intended function is affected.
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Based on its review, the staff finds the exception taken on the ―acceptance criteria‖ program 

element in GALL AMP XI.M38 to be acceptable. Therefore, the staff‘s concern described in 

RAI B2.1.32-4 is resolved. 

Enhancement. In the applicant‘s letter of September 25, 2009, the applicant stated that the 

WCP Program is a new AMP and that the program will be enhanced to make it consistent with 

the program elements in GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖

The staff confirmed that the applicant included this enhancement of the program in LRA 

Commitment No. 25, which was amended in the letter of September 25, 2009, and placed in 

LRA Appendix A, USAR Supplement, Table A6.0-1 as follows:

The work control process will be established. The program will perform one-time 

inspections as a verification of the effectiveness of chemistry control programs. 

The program will also perform visual inspections of component internal surfaces, 

and external surfaces of selected components, to manage the effects of aging 

when the surfaces are made available for examination through surveillance and 

maintenance activities.

The staff‘s evaluation of this enhancement is given in the staff‘s evaluation of the USAR 

supplement for the WCP Program, which follows later on in this evaluation.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.32. The 

applicant stated that the WCP Program is a new program and that, therefore, there is currently 

no documentation of programmatic OE that had been obtained and is available through 

implementation as an AMP. The applicant clarified that, as OE is obtained, lessons learned will 

be used to adjust this program as needed. 

However, the applicant stated that inspections have been performed and documented during 

the performance of applicable surveillance and preventive maintenance procedures, and as a 

result of this, the following OE discussions represent examples of the type of OE that will be 

obtained when the WCP Program is implemented as an AMP during the period of extended 

operation:

In April 2002, Maintenance personnel were replacing the fire protection jockey 

pump discharge relief valve and identified the adjacent piping was approximately 

90% blocked with rust-like debris. Additionally, it was identified that a nearby pipe 

nipple was corroded and required replacement. The work order instructions were 

revised, the piping was cleaned, and the welded nipple was replaced.

In April 2008, a detailed inspection of a service water valve revealed that the disc 

guides in the valve body were eroded. The inspection was performed in response 

to a work order written in 2006 when poor valve seat contact was visually noted 

during service water pipe replacement. It was noted in 2006 that the seat 

conditions would probably cause the valve to weep. Visual inspection of the valve 

at that time indicated the valve would continue to perform its isolation function. 

As a result of the 2008 inspection, it was determined that the guides could not be 

repaired and the valve was replaced.
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In April 2008, during an overhaul of the ―B‖ Component Cooling Water pump, the 

lower pump casing was found to have an area of material loss on the outboard 

wear ring casing groove land. It was determined that the condition appeared to 

have developed over a long period of time, most likely since the pump was 

installed in October 2001. A review of operating experience did not identify any 

horizontal pumps with similar conditions. As part of the extent of condition review, 

the historical operating performance of the ―A‖ and ―B‖ Component Cooling Water 

pumps was reviewed. The results indicated that these pumps were operating at 

or near the reference vibration levels and hydraulic performance values that were 

established when the pumps were initially installed. Periodic performance testing 

(vibrations and hydraulic performance) of the ―B‖ Component Cooling Water 

pump is being performed to validate the continued operability of the pump.

The applicant‘s letter, dated September 25, 2009, amended the status of the WCP to define the 

program as a new AMP that will be consistent with the guidelines in GALL AMP XI.M32, 

―One-Time Inspection,‖ when subjected to an enhancement and applied as a one-time condition 

verification program for water chemistry and oil analysis preventive monitoring programs, and 

with the guidance in GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,‖ with noted exceptions and when subject to an enhancement 

and applied as a periodic, condition monitoring program. Thus, the WCP Program is a new 

condition monitoring program for the LRA that will be implemented (Commitment No. 25) prior to

the period of extended operation. The staff noted, however, that for all three examples given, 

the applicant summarized: (1) when the periodic surveillances or preventive maintenance 

activities were performed, (2) the type of conditions that were detected during the 

implementation of the stated periodic surveillance or preventative maintenance activities, (3) the 

relevant results of the relevant monitoring and trending activities that were implemented 

following detection of the stated conditions, and (4) which corrective actions or activities were 

implemented to justify continued operation of the plant.

In addition, during the audit of October 2009, the staff confirmed that the applicant has either 

updated its relevant WCP Program implementation procedures to add specific instructions for 

implementing aging management inspections when the in-scope components are opened up 

and made accessible for examination during preventative maintenance or periodic surveillance 

activities, or identified which WCP Program implementation procedures would need to be 

revised in the near future to incorporate these type of inspection guidelines. The staff also 

confirmed that the WCP Program implementing procedures were revised to incorporate 

appropriate monitoring and trending activities, acceptance criteria, and corrective actions when 

implemented as an AMP for the applicant‘s facility. When this is taken into account with the OE 

examples provided for the applicant, the staff noted that the applicant provided some evidence 

that the applicant‘s WCP Program will be capable of detecting and managing those aging 

effects the AMP is credited for, and if necessary, of taking corrective actions and adjusting the 

program based on the steps that will be taken to disposition the aging effects associated with 

the relevant OE. 

However, the staff noted that the three examples of OE provided by the applicant for the WCP 

Program create some doubt on whether the program element criteria for the AMP (and the 

future implementation of the program in accordance with these program elements) would be 

capable of managing the aging effects that are within the scope of the program. 

In a conference call with the staff dated March 18, 2010, the applicant informed the staff that the 

WCP Program is a new program that, when implemented, will be consistent with the criteria of 
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GALL AMP XI.M32, ―One-Time Inspection,‖ when performed on a one-time condition monitoring 

basis, and with the criteria in GALL AMP XI.M38, ―Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,‖ with exceptions, when performed on a 

periodic, condition monitoring basis. During this conference call, the applicant stated that, since 

the AMP is a new program, the OE discussions provided in the letter of September 25, 2009, 

were only provided as examples to indicate that the program had, in the past, detected relevant 

aging effects and that the examples were not used for the purpose of demonstrating the 

capability of the AMP to detect and manage aging. 

The staff noted that, in the general license renewal guidance of SRP-LR Section A.1.2.3.4, 

―Detection of Aging Effects,‖ the staff established its recommended position that AMPs ―based 

solely on detecting structure and component failure should not be considered as an effective 

aging management program for license renewal.‖ As a result, the staff issued RAI B2.1.32-5, 

Part 3 to address the issue on the acceptability of OE examples that were listed for the WCP 

Program in the applicant‘s letter of September 25, 2009. In this RAI, the staff asked the 

applicant to provide its basis on why the staff should not use the OE examples provided in the 

September 25, 2009, letter to assess whether the WCP Program will be capable of managing 

the aging effects for which the AMP is credited to manage. In addition, the staff asked the 

applicant to clarify whether it would be willing to amend the LRA to include the type of 

commitment that is recommended for new AMPs in SRP-LR Section A.1.2.3.10 and to apply 

this commitment to the future implementation of the WCP Program during the period of 

extended operation. The staff identified this as Open Item B2.1.32-1, Part 3.

By letter dated May 13, 2010, the applicant responded to RAI B2.1.32-5, Part 3. In its response 

to Part 3 of the RAI, the applicant stated that it agreed the three examples of WCP-related OE 

do not directly substantiate the future effectiveness of the WCP Program in managing the aging 

effects for which the AMP is credited. Instead, the applicant amended the AMP to remove the 

OE mentioned in its response dated September 25, 2009, from the program and amended the 

OE discussion to state that the WCP Program is a new program, in part, that will be 

implemented during the period of extended operation, and that consistent with the criteria in 

SRP-LR Branch Position RLSB-1, the LRA is amended to include Commitment No. 47, which 

will be added to LRA Appendix A, USAR Supplement, Table A6.0-1, and states as follows:

Submit three examples of operating experience associated with the Work Control 

Process – Internal Surfaces Monitoring program for NRC staff review in 

determining the effectiveness of the program to detect and correct the effects of 

aging prior to the loss of intended function.

In SRP-LR Appendix A.1, Section A.1.2.3.10, ―Aging Management Review – Generic (Branch 

Position RLSB-1),‖ the staff makes the following recommendation relative to providing OE for 

new programs that have yet to be implemented at an applicant‘s facility: ―An applicant may have 

to commit to providing operating experience for new programs to confirm their effectiveness.‖ 

The staff noted that the applicant‘s amendment of the OE basis for the WCP Program in the 

applicant‘s letter dated May 13, 2010, and amendment of the LRA to include Commitment 

No. 47 is consistent with the recommended guidance for new programs in SRP-LR 

Appendix A.1, Section A.1.2.3.10. Based on this review, the staff finds that the applicant‘s 

amended ―operating experience‖ program element basis for the WCP Program in its letter of 

May 13, 2010, and commitment to submit three examples of OE for the WCP Program for staff 

review is acceptable because it is in conformance with the commitment-based recommendation 
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for new programs in SRP-LR, Appendix A.1, Section A.1.2.3.10. Staff concerns in

RAI B2.1.32-5, Part 3 are resolved, and Open Item B2.1.32-1, Part 3 is closed.

Based on its review, the staff finds the applicant‘s ―operating experience‖ program element 

acceptable. 

USAR Supplement. In its letter dated September 25, 2009, the applicant amended LRA 

Section A2.1.32 and the USAR supplement for the WCP Program as follows:

Program Description

The Work Control Process program is a new program that will correspond to 

NUREG-1801, Section XI.M32, ―One-Time Inspection,‖ and Section XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components.‖ One-time inspections will manage the aging effects of cracking, 

loss of material, and reduction of heat transfer to verify the effectiveness of the 

Primary Water Chemistry, Secondary Water Chemistry, Closed-Cycle Cooling 

Water System, Fuel Oil Chemistry, and Lubricating Oil Analysis programs 

through inspections implemented in accordance with the work management 

process. The one-time inspections will be performed using NDE techniques that 

have been determined to be effective for the identification of potential aging 

effects. The program will use a representative sampling approach to verify 

degradation is not occurring. The sample size and location for the one-time 

inspections will be established to ensure that the number and scope of the 

inspections are sufficient to provide reasonable assurance that the aging effects 

will not compromise the intended functions during the period of extended 

operation.

The inspections of internal surfaces in miscellaneous piping and ducting 

components will manage the aging effects of change in material properties, 

cracking, hardening and loss of strength, loss of material, loss of sealing, loss of 

strength, and reduction of heat transfer for the in-scope structures and 

components through inspections implemented in accordance with the work 

management process. The program will perform visual inspections of piping, 

piping components, ducting and other components fabricated of aluminum, 

copper alloys, stainless steel, and steel to detect loss of material, reduction of 

heat transfer, and cracking. Visual inspections will also manage the degradation 

of the paper filter elements in the Compressed Air System. The program will 

include physical manipulation of elastomeric components as a supplement to the 

visual inspections. An enhanced VT-1 NDE examination will be performed to 

detect cracking of stainless steel diesel exhaust flexible connections.

Commitments

● Program Implementation: 

The Work Control Process program will be established.

The commitment is identified in Appendix A, Table A6.0-1 License 

Renewal Commitments, Item 25.

The staff also noted that in the letter of September 25, 2009, the applicant also stated that the 

program would be enhanced to be ―consistent with the recommendations in NUREG-1801, 
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Section XI.M32  ̳One-Time Inspection,‘ and NUREG-1801, Section AMP XI.M38,  ̳Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components,‘‖ and that this 

enhancement is reflected in Commitment No. 25 of the LRA which was placed in USAR 

Summary Table A6.0-1 and revised in the letter of September 25, 2009, to state: 

The Work Control Process program will be established. The program will perform 

one-time inspections as a verification of the effectiveness of chemistry control 

programs. The program will also perform visual inspections of component 

internal surfaces and external surfaces of selected components to manage the 

effects of aging when the surfaces are made available for examination through 

surveillance and maintenance activities.

The staff noted that SRP-LR Section 3.0 defines AMP enhancements as follows:

In some cases, an applicant may choose an existing plant program that does not 

currently meet all the program elements defined in the GALL Report AMP. If this 

is the situation, the applicant may make a commitment to augment the existing 

program to satisfy the GALL Report AMP element prior to the period of extended 

operation. This commitment is an AMP enhancement.

Enhancements are revisions or additions to existing aging management 

programs that the applicant commits to implement prior to the period of extended 

operation. Enhancements include, but are not limited to, those activities needed 

to ensure consistency with the GALL Report recommendations. Enhancements 

may expand, but not reduce, the scope of an AMP.

The staff noted that the SRP-LR Section 3.0 guidance does not indicate that enhancements can 

be applied to new AMPs. As a result, the staff noted that in the enhancement of the WCP 

Program (as given in the applicant's letter of September 25, 2009), the applicant only indicated 

that the program is a new program that ―will be consistent with the recommendations in 

NUREG-1801, Section XI.M32,  ̳One Time Inspection,‘ and NUREG-1801, Section XI.M38, 

 ̳Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,‘‖ and that 

this enhancement is being reflected in Commitment No. 25, which was placed in USAR 

Table A6.0-1. In contrast, the staff noted that Commitment No. 25 only indicated that the WCP 

Program will be implemented as a new AMP during the period of extended operation, as 

implemented on a one-time basis for verification of the effectiveness of chemistry programs or 

on a periodic basis when applied as a periodic, condition monitoring program. Thus, it was not 

evident to the staff whether Commitment No. 25 was being placed on the USAR Table A6.0-1: 

(1) solely for the purpose of reflecting the need to implement the program during the period of 

extended operation (without any real need for enhancement of the program) or (2) to reflect that 

the particular program element criteria for the WCP Program would need to be enhanced to 

make them consistent with the stated definition for AMP enhancements given in SRP-LR 

Section 3.0 and with the program elements in either GALL AMP XI.M32 (when applied on a 

one-time condition monitoring basis) or in GALL AMP XI.M38 (when applied on a periodic, 

condition monitoring basis).

In addition, the staff also observed that there were some apparent inconsistencies among the 

information provided in the letter of September 25, 2009, on the WCP Program, the 

enhancement of the WCP Program, USAR supplement Section A2.1.32, and Commitment 

No. 25. In particular, the updated enhancement and USAR supplement summary description for 

the WCP Program reflect that the AMP would be implemented consistent with the 
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recommended program element criteria in GALL AMP XI.M32, when applied on a one-time 

inspection basis, and with those in GALL AMP XI.M38, when applied as a periodic, condition 

monitoring program. However, the revised WCP Program basis for the AMP, as proposed in the 

letter of September 25, 2009, indicated that the AMP would be implemented consistent with the 

guidance in GALL AMP XI.M38 when applied as a periodic, condition monitoring program, but 

also when subjected to four specifically defined exceptions that the applicant was making to the 

program elements in GALL AMP XI.M38. 

The staff issued RAI B2.1.32-5, Part 4 to resolve the issues with the applicant‘s enhancement of 

the WCP Program and with Commitment No. 25, as placed in USAR Table 6.0-1 and placed 

relative to the summary description for the WCP Program in USAR supplement Section A2.1.32. 

In this RAI, the staff asked the applicant to review the information that has been supplied for the 

WCP Program, the enhancement for the WCP Program, USAR Section A.2.1.32, and 

Commitment No. 25 in the September 25, 2009, letter (as supplemented by the letter of January 

21, 2010), for consistency against each other. In this RAI, the staff also asked the applicant to 

clarify whether Commitment No. 25 was being placed on the LRA: (1) solely for the purpose of 

indicating that the WCP Program, as a new AMP, would be implemented during the period of 

extended operation, without any need to enhance the program elements of the AMP prior to 

implementation of the program; or (2) whether the commitment was being placed on the LRA to 

reflect that particular program elements for the WCP Program would need to be enhanced to 

make them consistent with the GALL Report, or with the GALL Report as subjected to particular 

exceptions, prior to implementation of the program. The staff identified this as Open 

Item B2.1.32-1, Part 4.

By letter dated May 13, 2010, the applicant responded to RAI B2.1.32-5, Part 4. In its response, 

the applicant stated that the WCP Program, as specified in LRA Section B.2.1.32 and 

supplemented in the applicant‘s letter dated September 25, 2009, is defined as a new AMP that 

will be implemented during the period of extended operation, and includes Commitment No. 25 

to implement the program during the period of extended operation consistent with the program 

element recommendations in GALL AMP XI.M32 for the components in the program that would 

be inspected on a one-time basis for confirmation of preventive program effectiveness, and with 

the program element recommendations in GALL AMP XI.M38 for managing age-related 

degradation in components that will be inspected on a periodic basis. The staff noted that this 

provides an adequate description of the program, considering also that the program includes

four exceptions that were taken to GALL AMP XI.M38 as defined by the applicant and accepted 

by the staff in this SER section.

The staff also noted that, in the applicant‘s letter of May 13, 2010, the applicant amended its 

―operating experience‖ program element for the WCP Program to include Commitment No. 47 in 

LRA USAR Supplement Table A6.0-1, and that in this commitment the applicant committed to 

submitting three examples of OE for the new WCP Program for staff review. The staff found this 

commitment to be acceptable because it is in conformance with the commitment based 

recommendation for new AMPs in SRP-LR, Appendix A.1, Section A.1.2.3.10.

The staff also noted that, in its letter of September 23, 2010, the applicant amended the 

program to include Commitment No. 50 in LRA USAR Supplement Table A6.0-1 in order to 

provide additional assurance that each of the components in the material/environment sample 

sets for the periodic condition monitoring portion of the program would be inspected on a 

periodic basis during the period of extended operation. Thus, based on this review, the staff 

finds that the information in the USAR supplement is an adequate summary description of the 

program as required by 10 CFR 54.21(d), because the summary description provides an 
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adequate summary of the program and because the USAR supplement for this program 

includes Commitment Nos. 25, 47, and 50 as found acceptable for implementation by the staff.

RAI B2.1.32-4 is resolved, and Open Item B2.1.32-1, Part 4 is closed.

Conclusion. On the basis of its audit and review of the applicant‘s WCP Program, the staff 

determined that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. In addition, the staff reviewed the four exceptions taken to GALL 

AMP XI.M38 and their justifications, and determined that the AMP, with the exceptions taken, is 

adequate to manage the aging effects for which the LRA credits it. The staff also reviewed the 

applicant‘s enhancements to implement the program during period of extended operation, to 

submit three examples of OE results for staff review, and to perform audits of the program to 

ensure that the components in the program‘s material/environment sample sets will be 

inspected during the period of extended operation, and confirmed that their implementation 

through Commitment Nos. 25, 47, and 50 in accordance with their schedules will make the new 

AMP consistent with the program elements in GALL Report AMPs XI.M32 and XI.M38 (as 

subject to the four exceptions), and with SRP-LR Section A1.2.3 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 functions 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 it provides an adequate summary description of 

the program, as required by 10 CFR 54.21(d). 

3.0.3.2.20 Metal Fatigue of Reactor Coolant Pressure Boundary Program

Summary of Technical Information in the Application. LRA Section B3.2 describes the existing 

Metal Fatigue of Reactor Coolant Pressure Boundary Program as consistent, with an 

enhancement, with GALL AMP X.M1, ―Metal Fatigue of Reactor Coolant Pressure Boundary.‖ 

The applicant stated that its program will monitor and track the critical thermal and pressure 

transients listed in USAR Table 4.1-8 to ensure that the design cycle limits are not exceeded so 

that the assumptions used in the fatigue analyses for the ASME Code Class 1 vessels and 

pressurizer surge line are maintained. The applicant also stated that it has evaluated the effects 

of the reactor coolant environment on component fatigue life for a sample of critical components 

identified in NUREG/CR-6260 that are applicable to an older vintage Westinghouse plant. The 

applicant further stated that the hot leg surge line nozzle and the charging nozzle locations will 

be managed by its program to ensure adequate margin against fatigue cracking due to 

anticipated cyclic strains and the effects of the reactor coolant environment. The applicant also 

stated that its program will monitor thermal cycles associated with selected auxiliary heat 

exchangers.

The applicant stated that its program uses EPRI software, FatigueProTM, to monitor transient

cycles and fatigue usage for selected ASME Code Class 1 components. In addition, the 

applicant stated that its program provides for corrective actions in response to approaching an 

―Action Limit‖ on cycle counts or fatigue usage. The applicant also stated that when the 

monitored transient cycles or fatigue usage exceeds 80 percent of the design limit, the condition 

is evaluated and appropriate corrective action is initiated to ensure the design limit is not 

exceeded.

Staff Evaluation. During its audit, the staff reviewed the applicant‘s claim of consistency with the 

GALL Report. The staff also reviewed the plant conditions to determine whether they are 

bounded by the conditions for which the GALL Report was evaluated.
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The staff compared elements one through six of the applicant‘s program to the corresponding 

elements of GALL AMP X.M1. As discussed in the Audit Report, the staff confirmed that each 

element of the applicant‘s program is consistent with the corresponding element of GALL 

AMP X.M1, with the exception of the areas identified below. For these areas, the staff 

determined the need for additional clarification, which resulted in the issuance of RAIs.

During its audit, the staff determined the need for additional clarification in areas regarding 

procedures for transient tracking, use of nonconforming analysis methodology, and issues 

related to OE, which resulted in RAIs B3.2-1 through RAI B3.2-4 issued by letter dated July 13, 

2009.

The staff noted the applicant‘s program relies on transient cycle monitoring to evaluate the 

fatigue usage described in the LRA. However, the staff also noted there was no description or 

discussion regarding how the applicant has been and will be monitoring the severity of pressure 

and thermal (P-T) activities during plant operations. The staff noted that it is essential that all 

thermal and pressure activities (transients) are bounded by the design specifications, including 

P-T excursion ranges and temperature rates, for an effective and valid AMP. 

By letter dated July 13, 2009, the staff issued RAI B3.2-1 requesting that the applicant: 

(a) describe the procedures that it uses for tracking thermal transients, (b) confirm that all 

monitored transient events were bounded by the design specifications, (c) confirm that transient 

events were continuously monitored since the plant startup, and (d) provide a histogram of 

cycles accrued for plant heatup and cooldown transients. 

In its response dated August 17, 2009, the applicant responded to parts (a) and (b) stating that 

the thermal and pressure transients listed in LRA Table 4.3-1 and USAR Table 4.1-8 are 

tracked by its program and that the requirements of the program are implemented by a plant 

surveillance procedure, which includes a summary description of critical parameters associated 

with the transient definition and requires tracking the occurrence of transients listed in LRA 

Table 4.3-1. The applicant also stated that transient conditions were defined for fatigue 

evaluation based on a conservative estimate of the magnitude and frequency of the temperature 

and pressure cycles resulting from normal operation, normal and abnormal load transients, and 

accident conditions. The applicant further stated that if a thermal or pressure transient occurs 

that is not bounded by the transient parameters described in the procedure, the event will be 

documented in the corrective action program and an engineering evaluation will be performed to 

determine the impact on applicable components and analyses. In its response to part (c), the 

applicant stated that thermal and pressure transients listed in LRA Table 4.3-1 have been 

monitored and tracked since initial plant operation in 1973. In its response to part (d), the 

applicant provided histograms of cycles accrued for plant heatup and cooldown transients.

Based on its review, the staff finds the applicant‘s response to RAI B3.2-1 acceptable because: 

(1) for parts (a) and (b), the applicant has demonstrated the effectiveness of its program on 

transient cycle capturing and counting, as well as keeping all transients being bounded within 

the design specifications; (2) for part (c), the applicant confirmed that transient events have 

been continuously monitored since the plant startup; and (3) for part (d), the applicant provided 

the transient cycle histograms for the plant heatup and cooldown transients, covering the plant

operating history thus far. Based on the applicant‘s response, the staff confirmed that: (a) all 

transients are bounded within the design specifications, and (b) all transient cycles that had 

occurred were captured and counted since the startup of the plant. The staff noted that these 

two requirements are the essence and technical bases of the cycle-based fatigue (CBF) 

management methodology. The staff‘s concern described in RAI B3.2-1 is resolved.
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The staff noted that the applicant‘s program relies on nonconforming software, FatigueProTM, to 

perform some of the fatigue usage calculations. LRA Section B3.2 states that its fatigue 

managing program uses all three modules of the EPRI software, FatigueProTM, to perform cycle 

counting, CBF monitoring, and stress-based fatigue (SBF) monitoring. However, the staff noted 

that in its SBF monitoring module, FatigueProTM does not use all six components of a transient 

stress tensor to perform fatigue analysis in accordance with the ASME Code Section III 

NB-3200. NRC Regulatory Issue Summary (RIS) 2008-30 recommends that the license renewal 

applicants that have used this simplified methodology to calculate fatigue usage should perform 

confirmatory analyses to demonstrate that the simplified analyses provide acceptable results.

By letter dated July 13, 2009, the staff issued RAI B3.2-2 requesting that the applicant: (a) make 

appropriate adjustments and corrections regarding the use of the ―stress-based monitoring‖ and 

―SBF‖ terminologies, and reliance on the SBF monitoring methodology for fatigue usage 

calculations; and (b) re-evaluate the cumulative usage factor (CUF), in accordance with the 

guidelines described in the ASME Code Section III NB-3200 guidance, for those components 

whose CUFs were calculated using the FatigueProTM SBF monitoring methodology.

In its response dated August 17, 2009, the applicant stated that the reanalysis of locations 

subject to evaluation of the environmental effects on fatigue usage in accordance with 

NUREG/CR-6260 that were initially evaluated using SBF monitoring methods, was in progress

but not complete. The applicant further stated that the response to RAI B3.2-2 would be 

provided following completion of the reanalysis. 

In an updated response dated February 2, 2010, the applicant stated that the reanalysis of the 

surge line hot leg nozzle and charging line nozzle in accordance with the guidance in ASME 

Code Section III, Subsection NB-3200, was still in progress and not yet complete. The staff 

noted that these two locations were the only locations that the applicant evaluated with SBF 

monitoring methods. The applicant committed (Commitment No. 41) to perform a fatigue 

analysis of the surge line hot leg nozzle and the charging line nozzle in accordance with ASME 

Code Section III, Subsection NB-3200 guidance and determine the CUF, considering the effects 

of the reactor coolant environment, and confirm that the CUF is less than 1.0 at the end of 60 

years of plant operation. The staff noted that a summary of results for the reanalysis of the 

surge line hot leg nozzle and charging line nozzle, in accordance with the guidance in ASME 

Code Section III, Subsection NB-3200, will be submitted to the staff. This staff identified this as 

Open Item 3.0.3.2.20-1.

By letter dated June 1, 2010, the applicant submitted a vendor-prepared summary report of the 

60-year environmentally-assisted fatigue (EAF) analysis. The applicant provided the analysis 

results for the two locations, the surge line hot leg nozzle and the charging line nozzle, for which 

the SBF monitoring method (EPRI FatigueProTM) was originally used in the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. The applicant stated that the results show 

acceptable fatigue usage for the NUREG/CR-6260 locations for which SBF monitoring methods 

(EPRI FatigueProTM) were originally used considering the reactor coolant environment. The staff 

noted that the applicant completed this analysis to fulfill Commitment No. 41. The staff noted 

that the applicant provided a detailed finite element model along with fatigue usage calculations 

that were performed in accordance with ASME Code Section III, Subsection NB-3200. The staff 

reviewed the applicant‘s submitted vendor-prepared summary report and noted that all six 

components of the transient stress tensor were used throughout the evaluation for the surge line 

hot-leg nozzle and the charging line nozzle, in accordance with ASME Code Section III 

requirements, which addressed the staff‘s concern expressed in RIS 2008-30. The staff noted 

that the vendor-prepared summary report concluded that, including the consideration of 
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environmental effects, the fatigue usage factors for the two locations are less than the ASME 

Code Section III allowable limit of 1.0.

The staff noted that for the charging line nozzle, the thermal analysis was simplified by lumping 

some transients together into single conservative sets, while transients such as plant heatup, 

plant cooldown, and inadvertent RCS depressurization were analyzed separately due to their 

large temperature or pressure changes. The staff noted that the bounding RCS transients were 

selected based on maximum cold leg temperature changes and ramp rates. Furthermore, four 

stress linearization paths within the nozzle were chosen for fatigue analysis. The staff noted that 

this feature allowed the analysis results to capture high stress intensity levels at various 

locations inside the nozzle; the 60-year CUF calculated for the bounding location was 0.0302. 

The staff noted that the maximum EAF usage factor, which accounted for the reactor water 

environment, was obtained by multiplying the maximum environmental fatigue life correction 

factor, Fen, of 15.35, calculated consistent with NUREG/CR-5704 for stainless steel, to the CUF. 

The staff noted that the resulting 60-year EAF usage factor was 0.4636, which is below the 

design limit of 1.0.

The staff noted that for the surge line hot leg nozzle, the thermal analysis was simplified by 

lumping transients together into a single conservative set. Furthermore, seven stress 

linearization paths were selected to capture high stress intensity levels at various locations 

inside the nozzle; the 60-year CUF in the fatigue analysis for the bounding location was 0.085. 

The applicant refined the EAF usage factor calculation by accounting for the strain rate and 

dissolved oxygen content of the environment. For the level of dissolved oxygen, the applicant 

assumed a value of 0.05 ppm or less. The staff noted that this is a conservative assumption with 

the Fen formulation for stainless steel materials because higher dissolved oxygen concentration 

would result in a lower and non-conservative Fen value. The applicant also incorporated the 

effect of strain concentration factor (penalty factor applied to alternating total stress intensity) 

into the analysis, which resulted in an increase in the strain rate of the transient and lowered the 

Fen value. However, the staff noted that while this removed some of the conservatism in the 

analysis, the staff finds this acceptable because (1) there is sufficient conservatism (such as 

transient lumping) that is built into in the analysis, and (2) there is margin between the CUFen 

and the design limit. The staff noted that the resulting 60-year EAF usage factor was 0.7467, 

which is below the design limit of 1.0. 

The vendor-prepared summary report concluded that, including the consideration of 

environmental effects, the fatigue usage factors for the two locations are less than the ASME 

Code Section III allowable value. However, the staff noted that the applicant‘s letter and the 

vendor-prepared summary report did not describe or demonstrate that the simplified analysis 

based on FatiguePro‘sTM SBF monitoring methods will provide acceptable results. In particular, 

the staff noted that, for the surge line hot-leg nozzle, the CUF and environmentally-assisted 

usage factor in the vendor-prepared summary report are greater than the CUF values presented 

in LRA Table 4.3-2. The staff also noted that for the charging line nozzle, the CUF and 

environmentally-assisted usage factor in the vendor-prepared summary report are less than 

those presented in LRA Table 4.3-2. The staff noted that the vendor-prepared summary report 

did not demonstrate or justify that the input parameters and assumptions are the same as those 

in the FatigueProTM SBF monitoring. The staff was also not clear on whether the FatigueProTM 

SBF monitoring module will be used by the applicant in the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program during the period of extended operation.

By letter dated September 10, 2010, the staff issued follow-up RAI B3.2-2a, requesting that the 

applicant clarify whether the SBF monitoring module in EPRI FatigueProTM will be used in the 
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Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff further requested that 

if this module will be used, justify its use for monitoring fatigue usage for the charging line 

nozzle and the surge line hot leg nozzle. Specifically, the staff requested that the applicant 

demonstrate that the fatigue analyses performed by the FatigueProTM software are conservative 

when compared to the fatigue analyses that were performed consistent with ASME Code 

Section III, Subsection NB-3200, for the charging line nozzle and the surge line hot leg nozzle. 

The applicant was further requested to clarify if relevant input parameters and assumptions 

used in both fatigue analyses (those performed by the FatigueProTM software and those 

performed consistent with ASME Code Section III, Subsection NB-3200) are the same; if not, 

the applicant should provide justification for any differences. The staff also requested that if this 

module will not be used, clarify the monitoring method (including but not limited to software that 

incorporates a six-component stress tensor method consistent with ASME Code Section III 

NB-3200 requirements) that will be used to manage the effects of fatigue for the charging line 

nozzle and the surge line hot leg nozzle, and justify the use of this method.

In its response dated September 23, 2010, the applicant stated that the EPRI FatigueProTM 

software is used as part of the Metal Fatigue of Reactor Coolant Pressure Boundary Program. 

The applicant also stated that the SBF monitoring module will not be used to monitor fatigue 

usage for either the surge line hot-leg nozzle or the charging line nozzle. The applicant stated 

that these locations were analyzed in accordance with ASME Code Section III, Subsection 

NB-3200, and that a summary of the analysis was provided for NRC staff review by letter dated 

June 1, 2010. The staff noted that the results of this evaluation for these two components, 

including environmental effects, demonstrated that the design limit of 1.0 would not be 

exceeded during the period of extended operation if the actual number of transient occurrences 

does not exceed the number of cycles used in the analysis. The applicant stated that the results 

of analysis for these two components provide the basis that these components are acceptable 

for the period of extended operation, subject to transient occurrences being within the limits of 

the analysis as confirmed through the Metal Fatigue of Reactor Coolant Pressure Boundary

Program. The staff finds it acceptable that the applicant will use its Metal Fatigue of Reactor 

Coolant Pressure Boundary Program to manage the effects of aging for these two components 

because it will continue to monitor the number of transient occurrences to ensure the limits used 

in the analysis are not exceeded and that the analysis remains valid.

Based on its review, the staff finds the responses to RAI B3.2-2 and B3.2-2a acceptable 

because: (1) the fatigue usage factor analysis was performed in accordance with ASME Code 

Section III, Subsection NB-3200, which utilizes six components of a transient stress tensor, thus 

addressing the staff‘s concern expressed in RIS 2008-30; (2) the CUFs and the EAF usage 

factors for both the surge line hot leg nozzle and the charging line nozzle are below the ASME 

Code Section III allowable limit of 1.0; (3) the applicant will manage the effects of aging for the 

surge line hot-leg nozzle and for the charging line nozzle, without the use of SBF; and (4) the 

applicant will use its Metal Fatigue of Reactor Coolant Pressure Boundary Program to monitor 

the number of transient occurrences to ensure the limits used in the analysis are not exceeded 

and the analysis remains valid. The staff‘s concerns are resolved and Open Item 3.0.3.2.20-1 is 

closed.

The staff also reviewed the portions of the ―preventive actions,‖ ―detection of aging effects,‖ 

―acceptance criteria,‖ and ―corrective actions‖ program elements associated with an 

enhancement to determine whether the program will be adequate to manage the aging effects 

for which it is credited. The staff‘s evaluation of this enhancement follows.
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Enhancement. LRA Section B3.2 states an enhancement to the ―preventive actions,‖ ―detection 

of aging effects,‖ ―acceptance criteria,‖ and ―corrective actions‖ program elements. The 

applicant stated that its program will be enhanced to include a routine assessment of the 

transient cycle count totals and fatigue usage status for monitored locations. The applicant also 

stated that the enhancement includes an ―action limit‖ provision, which will initiate corrective 

action if the current cycle counts or the CUF values exceed 80 percent of the design limits. In 

addition, the applicant stated that the current totals will be compared to the 60-year projections 

to confirm that the projections are accurate, and if short-term trends are not consistent with the 

60-year projections, the 60-year projection will be re-evaluated and adjusted as necessary.

Based on its review, the staff finds the applicant‘s enhancement is consistent with the 

recommendations of the ―preventive actions,‖ ―detection of aging effects,‖ ―acceptance criteria,‖ 

and ―corrective actions‖ program elements of GALL AMP X.M1 because the program will be 

enhanced to maintain the fatigue usage factor below the design code limit, update the status of 

the fatigue usage, initiate corrective action if necessary, and ensure the CUF is below the 

design code limit of 1.0, as recommended in GALL AMP X.M1.

Based on its audit and review of the applicant‘s responses to RAIs B3.2-1, B3.2-2, and B3.2-2a, 

the staff finds that elements one through six of the applicant‘s Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, with an enhancement, are consistent with the corresponding 

program elements of GALL AMP X.M1 and are, therefore, acceptable.

Operating Experience. LRA Section B3.2 summarizes OE related to the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. The applicant provided two examples of internal 

OE, as summarized below: 

● In June 2001, KPS engineering personnel identified that a potential challenge to 

charging line and reactor coolant loop piping nozzle fatigue limits may have occurred 

due to a letdown line isolation during a reactor trip recovery operation with high initial 

charging flow. 

● In August 2006, during a review of historical heatup and cooldown transient data 

recorded in the transient cycle counting surveillance procedure, KPS engineering 

personnel discovered unusually high differential temperatures ( T) between the 

pressurizer surge line and RCS hot leg have been mistakenly logged. 

The applicant stated that both incidences were satisfactorily resolved because its program 

demonstrated that the fatigue limits remained valid and it had taken the required corrective 

actions. The applicant also stated that the OE showed that its program is effective in monitoring 

and evaluating fatigue, and implementing corrective actions, when necessary. The applicant 

further stated that its program ensures that the intended functions of the ASME Code Class 1 

components are maintained.

During its review, the staff identified the need for additional clarifications on the applicant‘s OE, 

which resulted in the issuance of RAIs.

The staff noted that the 2001 incident involved a potential challenge to the charging line and 

reactor coolant loop piping nozzle fatigue limits caused by an incidental transient. The staff 

further noted that the applicant stated that effects of the 2001 incident were satisfactorily 

evaluated without discussing how the evaluations were performed. By letter dated July 13, 
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2009, the staff issued RAI B3.2-3 requesting that the applicant describe the engineering 

analysis that was performed for the incidental transient during 2001.

In its response dated August 17, 2009, the applicant stated that the 2001 event described above

was a letdown flow isolation that occurred with continued charging flow to the reactor coolant 

loop. The applicant also stated that this incident resulted in a thermal transient in the charging 

line, because without letdown flow, there was no pre-heating of charging flow in the 

regenerative heat exchanger. The applicant further stated that this incident was entered into the 

corrective action program and the thermal transient was evaluated for its effect on the charging 

line and reactor coolant loop piping and nozzle. The applicant stated that it performed a 

qualitative engineering evaluation considering the applicable requirements of the design code of 

record, USAS B31.1 (1967 Ed.). The applicant also stated that there is no requirement within 

this code for a detailed fatigue analysis; however, the code dictates a full range temperature 

cycle limit of 7,000 occurrences. The applicant further stated that the evaluation concluded that 

the charging line and reactor coolant loop piping nozzle did not experience temperature cycles 

approaching this limit, and the thermal sleeve would shield the nozzle from severe thermal 

stresses. The applicant concluded that there was no adverse effect on piping or nozzle 

structural integrity due to this incident and the design code requirements remain satisfied.

Based on its review, the staff finds the applicant‘s response to RAI B3.2-3 and the engineering 

analysis performed by the applicant acceptable because: (1) there is ample margin to 

7,000 cycles, (2) the applicant‘s evaluation determined that there was no adverse impact to the 

piping or the nozzle from this transient, and (3) the thermal sleeve protected the nozzle from 

severe thermal stresses during transients. Therefore, the concern described in RAI B3.2-3 is 

resolved. 

The staff noted that the 2006 incident involved an unusually high differential temperature 

between the pressurizer surge line and RCS hot leg that had been mistakenly logged. The staff 

further noted that the applicant attributed the erroneous records to a mistaken use of the 

―subcooling‖ data when the pressurizer was in a water-solid condition. In addition, the applicant 

stated that the water solid condition will be formed during the heatup and cooldown process 

under the ―Modified Steam Bubble‖ method. By letter dated July 13, 2009, the staff issued 

RAI B3.2-4 requesting that the applicant: (a) describe the ―Modified Steam Bubble‖ heatup and 

cooldown methodology, (b) explain at what stage of the heatup or cooldown process the 

water-solid condition will be established under the ―Modified Steam Bubble‖ method, and 

(c) describe how it determines T now since the mistake has been corrected.

In its response dated August 17, 2009, the applicant responded to part (a) by stating that the 

―Modified Steam Bubble‖ operating method was one of the plant start-up and shutdown 

methods defined during the Westinghouse Owner‘s Group (WOG) investigations into 

pressurizer insurge/outsurge and surge line thermal stratification issues. The applicant also 

stated that this operating method provides guidelines to increase pressurizer spray flow and 

reduce differential temperature between the pressurizer and the reactor coolant loop during 

plant heatup and cooldown, thereby reducing the potential metal fatigue effects of pressurizer 

insurge/outsurge. The applicant stated that this method had been used at KPS for start-up and 

shutdown since the initial plant operation in 1973 until it was replaced by the ―Water Solid‖ 

method at the end of cycle 28 (March 2008). The applicant stated that the ―Water Solid‖ method 

will provide even greater reduction in ∆T between the pressurizer and the hot leg during plant 

heatup and cooldown than the ―Modified Steam Bubble‖ method. The applicant responded to 

part (b) by stating that under the ―Modified Steam Bubble‖ operating method, water solid 

conditions were established in the pressurizer at the beginning of the plant heatup process and 
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maintained until a steam bubble was formed at reactor coolant loop conditions of approximately 

200 to 250 °F and 400 pounds per square inch (psig). During the cooldown process, the 

pressurizer steam bubble was collapsed at reactor coolant conditions of approximately 180 °F 

and 450 psig. In its response, the applicant responded to part (c) by stating that the T between 

the pressurizer and the reactor coolant loop is determined through a calculated plant computer 

data point that subtracts the greater of reactor coolant loop A or loop B wide range temperature 

from the pressurizer water temperature.

The staff noted that the applicant attributed the root cause of the 2006 incident to the use of the 

calculated subcooling data as an approximation of the temperature differential between the 

pressurizer and the reactor coolant loop. The applicant stated that the subcooling-data-based

analysis, which calculates the margin to boiling in the core based on the RCS pressure and the 

maximum in-core thermocouple reading, works only when the plant is operating with steam 

bubbles in the pressurizer (i.e., saturated P-T condition). However, since the applicant adopted 

the ―Modified Steam Bubble‖ method of heatup and cooldown operation, the pressurizer was not 

in the saturated condition during those portions of heating up or cooling down under 

consideration. In its LRA, the applicant stated that the identified condition was documented in 

the corrective action program, the differential temperature data between the pressurizer surge 

line and RCS hot leg were corrected, and the erroneous data were evaluated to ensure that no 

pressurizer surge line thermal cycling or fatigue limits were exceeded.

The staff noted that additional clarification was required related to the applicant‘s calculation of 

T. The staff also required confirmation as to whether the results of WCAP-12841/12842, which 

assisted the applicant in the closure of the thermal stratification issue identified in NRC 

Bulletin 88-11, remains valid since WCAP-12841/12842 was completed in 1991, whereas the 

T data incident occurred in 2006.

Therefore, by letter dated December 3, 2009, the staff issued follow-up RAI B3.2-4a requesting 

that the applicant: (1) demonstrate that the formula as described for the T calculation is 

conservative, and (2) justify that the WCAP-12841/12842 analyses remain valid.

In its response dated January 21, 2010, the applicant stated that the pressurizer-to-reactor 

coolant loop differential temperature is used to indicate the relative severity of plant heatup and 

cooldown transients for thermal cycle tracking purposes. The applicant further stated that the T 

value is not used directly as an input to pipe or component stress determinations and the T is 

normally measured between the pressurizer and reactor coolant loop B hot leg since that is 

where the surge line connects the pressurizer to the RCS. However, in the event that the 

reactor coolant loop B hot leg temperature data point is out of service (as indicated by an 

abnormally low or zero reading), an acceptable approximation can be obtained by substituting 

the reactor coolant loop A hot leg temperature data point. The applicant stated that the 

evaluations performed and documented in WCAP-12841 and WCAP-12842 (non-proprietary 

version), ―Structural Evaluation of the Kewaunee Pressurizer Surge Line, Considering the 

Effects of Thermal Stratification,‖ did not use the subject pressurizer-to-reactor coolant loop T 

data as an input. Therefore, the erroneously high T indications had no effect on the results of 

these evaluations or the resolution of NRC Bulletin 88-11, ―Pressurizer Surge Line Thermal 

Stratification.‖

Based on its review, the staff finds the applicant‘s responses to RAIs B3.2-4 and B3.2-4a 

acceptable because the applicant: (1) identified the root cause of the 2006 incident and 

corrected the situation, (2) took corrective actions to evaluate the erroneous data to ensure that 
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the pressurizer surge line thermal cycling or fatigue limits were not exceeded, (3) clarified that 

the pressurizer-to-reactor coolant loop T is not used for the calculation of pipe or component 

stress determinations, (4) clarified and demonstrated that taking the greater of the reactor 

coolant loop A or loop B temperature from the pressurizer water temperature will provide a 

reasonable indication of pressurizer insurge and outsurge, and (5) confirmed that the subject 

pressurizer-to-reactor coolant loop T data and erroneously high T indications were not inputs 

used in the evaluations for the resolution of NRC Bulletin 88-11. The staff‘s concerns described 

in RAIs B3.2-4 and B3.2-4a are resolved.

Based on its audit and review of the application, and review of the applicant‘s responses to 

RAIs B3.2-3, B3.2-4, and B3.2-4a, the staff finds that OE related to the applicant‘s program 

demonstrates that it can adequately manage the detrimental effects of aging on SSCs within the 

scope of the program, and that implementation of the program has resulted in the applicant 

taking corrective actions. The staff confirmed that the ―operating experience‖ program element 

satisfies the criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

USAR Supplement. LRA Section A3.2 provides the USAR supplement for the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. The staff reviewed this USAR supplement 

description of the program and notes that it conforms to the recommended description for this 

type of program as described in SRP-LR Table 4.3-2. 

The staff also notes that the applicant committed (Commitment No. 28) to enhance the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program prior to entering the period of extended 

operation. Specifically, the applicant committed to enhance its program to include routine 

assessments of the transient cycle count totals and fatigue usage status for monitored locations, 

including an action limit for the initiation of corrective action.

The staff 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 enhancement and confirmed that its implementation through Commitment No. 28, 

prior to the period of extended operation, would make the existing AMP consistent with the 

GALL Report 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 

functions 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 that one AMP is plant-specific. A second program 

was revised from being a plant-specific program to a new program that is consistent with the 

GALL Report, with exceptions and enhancements (this is discussed in Section 3.0.3.3.2). For 

any AMP that is not consistent with or not addressed by the GALL Report, the staff performed a 

complete review of that AMP to determine whether it was adequate to monitor or manage aging. 

The staff‘s review of this plant-specific AMP is documented below.
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3.0.3.3.1 Alloy 600 Inspections Program

Summary of Technical Information in the Application. LRA Section B2.1.1 provides a 

plant-specific Alloy 600 Inspections Program that manages cracking due to primary water 

stress-corrosion cracking (PWSCC) for Ni-alloy component locations. The program meets the 

GALL Report expectation to have a plant-specific program for managing Ni-alloy materials to 

comply with the applicable NRC publications and industry guidelines.

The Alloy 600 Inspections Program performs visual, bare metal, liquid penetrant, eddy current, 

and ultrasonic examinations to detect cracking of the in-scope components. The program 

implementing procedures define the requirements and scope of the program. The procedures 

identify the specific base metal and dissimilar metal weld locations included in the program, and 

the susceptibility of each location to PWSCC.

The program proactively addressed the industry OE for PWSCC of the Alloy 600 and dissimilar 

metal welds. Based on the industry experience, the reactor vessel head was replaced during the 

fall 2004 refueling outage. The Alloy 600 Inspections Program activities for the pressure 

boundary base metal and dissimilar metal weld locations are performed in accordance with the 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. The Alloy 600 Inspections 

Program provides verification that the Primary Water Chemistry Program has been effective in 

mitigating PWSCC and supports the Boric Acid Corrosion Program.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in 

the applicant‘s Alloy 600 Inspections Program to ensure that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation.

During its review, the staff identified an area that required further information in order to 

complete its evaluation. The staff noted that it could not determine whether the applicant‘s 

program ensured augmented ISI inspections of Alloy 600-based components in accordance with 

current regulatory requirements of 10 CFR 50.55a. By letter dated October 13, 2009, the staff 

issued RAI B2.1.1 requesting that the applicant provide an update to state compliance with 

these requirements.

By letter dated November 13, 2009, the applicant provided its response to RAI B2.1.1. The 

applicant stated that, due to NRC rulemaking activities to establish new regulatory requirements 

for Ni-based alloy inspections during the review process of the LRA, the Alloy 600 Inspections 

Program was updated to be consistent with these new regulatory requirements, identified in the 

following table:

Locations Additional Inspection Bases

Reactor vessel closure head penetrations (control rod 

drive mechanisms, reactor vessel level instrument 

system, and head vent) and associated J-groove welds

ASME Code Case N-729-1

Reactor vessel bottom head instrumentation tube 

penetrations and associated J-groove welds ASME Code Case N-722

Reactor vessel safety injection nozzles buttering weld EPRI MRP-139

Steam generator primary nozzles safe end/buttering ASME Code Case N-722

EPRI MRP-139
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Additionally, the applicant stated that, while the ASME Code Case N-770 had not yet been 

incorporated into the Alloy 600 Inspections Program, it would be incorporated into the program 

once the code case has been incorporated into 10 CFR 50.55a.

The applicant also stated that its AMP was developed using the industry guidance document 

EPRI 1009561 (MRP-126), ―Materials Reliability Program: Generic Guidance for Alloy 600 

Management,‖ and NRC First Revised Order EA-03-009, ―Issuance of First Revised NRC Order 

(EA-03-009) Establishing Interim Inspection Requirements for Reactor Pressure Vessel Heads 

at Pressurized Water Reactors.‖

The staff finds the applicant‘s response acceptable, because the applicant explained that, in 

accordance with these documents and as demonstrated by the applicant‘s expected inclusion of 

ASME Code Case N-770, the Alloy 600 Inspections Program is maintained consistent with 

current regulations and is a living program that will be revised periodically to reflect the latest 

plant configurations. The staff‘s concern described in RAI B2.1.1 is resolved.

SRP-LR, Revision 1, contains the staff‘s generic evaluation of existing plant programs and 

documents the technical basis for determining where existing programs are adequate without 

modification for the period of extended operation. Guidance for the aging management of 

Ni-alloy material components, of which Alloy 600 components fall within, is provided in SRP-LR 

Section A.1, ―Aging Management Review.‖ The staff reviewed the applicant‘s Alloy 600 

Inspections Program against the AMP elements found in Section A.1.2.3 based on the 

applicant‘s submittal.

 (1) Scope of the Program – Element 1 of the applicant‘s Alloy 600 Inspections Program will 

manage cracking due to PWSCC for the following Ni-alloy component locations:

● reactor vessel closure head penetrations (control rod drive mechanisms 

(CRDMs), reactor vessel level instrumentation system (RVLIS), and head 

vent) and associated j-groove welds

● reactor vessel bottom head instrument tube penetrations and associated 

j-groove welds

● reactor vessel safety injection nozzles buttering weld

● reactor vessel core support guide lug/weld

● steam generator primary nozzles safe end/buttering

These items are identified in the LRA in the Alloy 600 Inspections Program and as line 

items in Table 3.1.2, ―Reactor Vessel, Internals, and Reactor Coolant System – Reactor 

Vessel – Aging Management Evaluation.‖ Further, these items correspond to the 

following GALL Report, Volume 2 references:

● IV.A2-09 closure head CRDM head penetrations

● IV.A2-12 core support guides

● IV.A2-15 safety injection nozzle (cladding and buttering)
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● IV.A2-18 closure head instrument tube, spare CRDM penetrations, 

closure head vent, and RVLIS head penetrations

● IV.A2-19 bottom head instrument tube penetrations

● IV.D1-04 primary nozzles safe end/buttering

The staff confirmed that the ―scope of the program‖ program element satisfies the 

criterion defined in SRP-LR Section A.1.2.3.1. The staff finds this program element 

acceptable.

 (2) Preventive Actions – The staff found that the preventive actions usable under the 

applicant‘s Alloy 600 Inspections Program are inspection, repair, replacement, and 

mitigation. Inspection uses nondestructive and visual examination methods to monitor 

the aging of the Ni-alloy components as required by the applicant‘s ISI program and as 

augmented by the requirements of 10 CFR 50.55a and recommendations of applicable 

bulletins, GLs, and staff-approved industry guidance. In this manner, it is a condition or 

performance monitoring program and, in accordance with SRP-LR Section A.1.2.3.2, no 

additional review is required. 

The applicant noted several repair activities that have been performed to address 

preventative actions against PWSCC aging effects of Ni-based alloys. Specifically, the 

staff noted that the RPV head has been replaced with materials that are less susceptible 

to PWSCC. The staff finds this action demonstrates a proactive approach to preventive 

actions in addressing the aging effects of Ni-based alloys.

Additionally, implementation of the industry initiative MRP-139 and noting the 

incorporation of the ASME Code Case N-770 upon its inclusion within 10 CFR 50.55a 

into the Alloy 600 Inspections Program demonstrates that the program is a living 

program, updated with the latest requirements for various mitigation techniques that are 

available for use to address Ni-alloy components and numerous other options which are 

being explored to address the mitigation of active degradation mechanisms for these 

components. The staff found that the applicant‘s program demonstrates effective 

consideration of various mitigation techniques available.

Based on this review, the staff confirmed that the ―preventive actions‖ program element 

satisfies the guidance in SRP-LR Section A.1.2.3.2. The staff finds this program element 

acceptable.

 (3) Parameters Monitored or Inspected – The applicant‘s Alloy 600 Inspections Program 

detects degradation by using the examination and inspection requirements of 

10 CFR 50.55a or accepted industry guidelines. ―The parameters monitored are the 

presence and extent of cracking.‖

For condition monitoring programs, SRP-LR Section A.1.2.3.3 states:

The parameters to be monitored or inspected should be identified and 

linked to the degradation of the particular structure and component 

intended function(s), [and] [f]or a condition monitoring program, the 

parameter monitored or inspected should detect the presence and extent 

of aging effects. Some examples are measurements of wall thickness and 

detection and sizing of cracks. 
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The staff noted that the applicant‘s Alloy 600 Inspections Program uses the appropriate 

volumetric, surface, and visual NDE techniques for detection of degradation of the 

components identified in the scope of the program, as required by 10 CFR 50.55a and 

industry guidance.

Based on this review, the staff confirmed that the ―parameters monitored or inspected‖ 

program element satisfies the guidance in SRP-LR Section A.1.2.3.3. The staff finds this 

program element acceptable.

 (4) Detection of Aging Effects – The applicant‘s Alloy 600 Inspections Program uses the 

10 CFR 50.55a inspection requirements for the ISI and staff accepted industry guidance. 

The staff has approved, in accordance with 10 CFR 50.55a, the specific techniques and 

frequencies for monitoring Ni-alloy components for those components examined in 

accordance with the ISI Program. In addition, for other items included in the scope of the 

applicant‘s Alloy 600 Inspections Program, the methods and frequencies of examination 

are recommended in industry guidance. Each of these programs for the detection of 

aging effects has been analyzed by the staff to provide adequate detection capability.

The staff‘s review confirmed that the applicant‘s ―detection of aging effects‖ program 

element satisfies the guidance in SRP-LR Section A.1.2.3.4. The staff finds this program 

element acceptable.

 (5) Monitoring and Trending – The applicant‘s Alloy 600 Inspections Program uses the 

10 CFR 50.55a inspection requirements for ISI and staff-accepted industry guidance. In 

general, the tools for monitoring and trending of Ni-alloy component inspection programs 

are based on the scope and reporting requirements established by the ASME Code, as 

required by 10 CFR 50.55a. The staff noted that the ASME Code Section XI requires, 

―recording of examination and test results that provide a basis for evaluation and 

facilitate comparison with the results of subsequent examinations.‖ The ASME Code 

Section XI also requires, ―retention of all inspection, examination, test, and repair or 

replacement activity records and flaw evaluation calculations for the service lifetime of 

the component or system.‖ The ASME Code Section XI additionally provides rules for 

―additional examinations‖ (i.e., sample expansion), when flaws or relevant conditions are 

found that exceed the applicable acceptance criteria, to assist in determination of an 

extent of condition and causal analysis.

Specific monitoring or trending requirements may be created under staff-accepted 

industry guidance. Each of these programs for the detection of aging effects has been 

analyzed by the staff to provide adequate detection capability. In addition, for some of 

these programs, NRC temporary instructions for the staff inspection of these industry 

programs have been developed, such as the case of Temporary Instruction 2525/172 

which defines NRC inspection of applicant actions to complete the MRP-139 program 

noted within the scope of the applicant‘s Alloy 600 Inspections Program.

Based on its review, the staff confirmed that the ―monitoring and trending‖ program 

element satisfies the guidance in SRP-LR Section A.1.2.3.5. The staff finds this program 

element acceptable.

 (6) Acceptance Criteria – The applicant‘s Alloy 600 Inspections Program uses the 

10 CFR 50.55a inspection requirements for ISI and staff-accepted industry guidance. In 

general, the acceptance criteria of Alloy 600 component inspection programs are based 

on the scope and reporting requirements established by the ASME Code, as required by 

10 CFR 50.55a. The staff noted that the ASME Code Section XI, IWB-3000 contains 
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acceptance criteria appropriate for the RCPB components examined in accordance with 

Section XI. Also, the ASME Code Section XI, IWA-5250 was verified to contain 

acceptable steps for evaluation and corrective measures for sources of leakage 

identified by visual examinations for leakage. These requirements ensure that Alloy 600 

components in the RCPB maintain their designed function under all required design 

conditions.

Additional specific acceptance criteria can be found in staff-accepted industry guidance. 

MRP-139 establishes acceptance criteria for the inspection of dissimilar metal butt welds 

fabricated with Alloy 600 weld materials. NRC RIS 2008-025 states, in part, that the staff 

finds that MRP-139, with certain considerations, provides adequate protection of public 

health and safety for addressing PWSCC in butt welds for the near term, pending 

incorporation by reference into 10 CFR 50.55a of an ASME Code Case containing 

comprehensive inspection requirements.

Based on its review, the staff confirmed that the ―acceptance criteria‖ program element 

satisfies the guidance in SRP-LR Section A.1.2.3.6. The staff finds this program element 

acceptable.

 (7) Corrective Actions – The applicant has available several repair alternatives that address 

corrective actions to address PWSCC aging effects of Ni-based alloys. Specifically, the 

applicant‘s Alloy 600 Inspections Program uses the repair and replacement 

requirements of the ASME Code Section XI for ISI and staff-accepted industry guidance. 

The staff endorses the use of these repair and replacement activities through 

incorporation into the requirements of 10 CFR 50.55a.

The staff noted that the RPV head has been replaced with materials that are less 

susceptible to PWSCC. The staff finds, while no PWSCC or degradation was identified 

in the KPS RPV upper head, this action demonstrates a proactive approach as a 

corrective action addressing industry OE regarding the aging effects of Ni-based alloys.

In addition, LRA Section B1.3 states that the applicant‘s corrective action program is 

described in Topical Report DOM-QA-1, ―Dominion Nuclear Facility Quality Assurance 

Program Description,‖ and implements the requirements of 10 CFR 50, Appendix B, 

―Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants.‖ As 

stated in SER Section 3.0.4, the staff finds the applicant‘s quality assurance program 

(QAP) is consistent with SRP-LR Appendix A.2.

Based on this review, the staff confirmed that the ―corrective actions‖ program element 

satisfies the guidance in SRP-LR Section A.1.2.3.7. The staff finds this program element 

acceptable.

 (8) Confirmation Process – The confirmation process for the applicant‘s Alloy 600 

Inspections Program uses the ASME Code Section XI inspection requirements for ISI 

and staff-accepted industry guidance. Reinspection of each Alloy 600 component is 

specified through these programs. The reinspection frequency of these programs is 

adjusted based on flaw identification, repair technique, replacement, and mitigation. 

Through these reinspections, the confirmation of reasonable assurance of structural 

integrity is verified for each component. Additionally, if any of these techniques fails to 

meet its acceptance criteria, additional corrective actions will be implemented by the 

applicant through its programs.
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In addition, LRA Section B1.3 states that the confirmation process for this program is 

under the QAP, which is described in Topical Report DOM-QA-1, and implements the 

requirements of 10 CFR 50, Appendix B. As stated in SER Section 3.0.4, the staff finds 

the applicant‘s QAP is consistent with SRP-LR Appendix A.2.

Based on this review, the staff confirmed that the ―confirmation process‖ program 

element satisfies the guidance in SRP-LR Section A.1.2.3.8. The staff finds this program 

element acceptable.

 (9) Administrative Controls – The administrative controls for the applicant‘s Alloy 600 

Inspections Program uses the ASME Code Section XI inspection requirements for ISI 

and staff-accepted industry guidance. In addition, LRA Section B1.3 identifies 

responsibilities for this program under the QAP, which is described in Topical Report 

DOM-QA-1, and implements the requirements of 10 CFR 50, Appendix B. As stated in 

SER Section 3.0.4, the staff finds the applicant‘s QAP is consistent with SRP-LR 

Appendix A.2.

Based on this review, the staff confirmed that the ―administrative controls‖ program 

element satisfies the guidance in SRP-LR Section A.1.2.3.9. The staff finds this program 

element acceptable.

 (10) Operating Experience – The staff‘s review of the applicant‘s Alloy 600 Inspections 

Program finds that while no indications of PWSCC degradation had been found at KPS, 

the applicant has incorporated inspection methodologies based on industry experience 

regarding PWSCC and associated reactor coolant leakage incidents, and finds that the 

applicant‘s OE demonstrates a proactive and living program. Specifically, the applicant 

noted multiple inspections and examinations that have been performed with no 

indications of leakage, as well as replacement of several RCS components, as a 

conservative measure or for reasons other than RCS pressure boundary leakage. 

Further, insulation packages have been replaced or modified to allow ease of access for 

future inspections. These actions demonstrate to the staff that the Alloy 600 Inspections 

Program and the applicant‘s monitoring of OE are effective.

Based on this review, the staff confirmed that the ―operating experience‖ program 

element satisfies the guidance in SRP-LR Section A.1.2.3.10. The staff finds this 

program element acceptable.

USAR Supplement. In LRA Section A2.1.1, as revised by letter dated November 13, 2009, the 

applicant provided the USAR supplement for the Alloy 600 Inspections Program. The staff 

reviewed this section and finds the USAR supplement information an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. The staff has reviewed LRA Section B2.1.1, which describes the Alloy 600 

Inspections Program as a plant-specific program and finds that the program, in conjunction with 

the commitments made by the applicant, meets the guidance as established in the GALL 

Report, Volume 2, Revision 1, for structures and/or components made of Ni-alloy material.

On the basis of its technical review of the applicant‘s Alloy 600 Inspections Program, the staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions 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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3.0.3.3.2 Deletion of the Plant-Specific Version of Work Control Process and Amendment of the 

LRA to Make the Work Control Process Consistent with the GALL Report.

In the applicant‘s letter of September 25, 2009, the applicant amended the WCP Program from 

being a plant-specific AMP for the LRA to a new AMP that will be consistent with the program 

elements in GALL AMP XI.M32, ―One-Time Inspection,‖ with an enhancement, and with GALL 

AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,‖ with noted exceptions and an enhancement. The staff evaluates the applicant‘s 

WCP Program in SER Section 3.0.3.2.19.

3.0.3.3.3 Protective Coatings Monitoring and Maintenance Program

Summary of Technical Information in the Application. In LRA Table B2.0, item XI.S8, the 

applicant stated that the Protective Coatings Monitoring and Maintenance Program is ―not 

applicable.‖

Staff Evaluation. The staff reviewed LRA Section B2.0, ―Aging Management Programs 

Correlation,‖ item XI.S8, ―Protective Coatings Monitoring and Maintenance Program,‖ using 

GALL AMP XI.S8 as guidance. 

In RAI XI.S8 dated August 28, 2009, the staff requested that the applicant provide details on the 

Protective Coatings Monitoring and Maintenance Program to provide adequate assurance that 

the protective coatings in containment will be adequately managed, such that they will not 

degrade and become a debris source that would challenge the emergency core cooling system 

(ECCS). 

In the applicant‘s response dated September 28, 2009, the applicant described its Protective 

Coatings Monitoring and Maintenance Program. The applicant stated that the program conforms 

to RG 1.54, ―Quality Assurance Requirements for Protective Coatings Applied to Water Cooled 

Nuclear Power Plants,‖ dated June 1973 (Revision 0), and that it incorporates ASTM D5144, 

―Guide for the Use of Protective Coating Standards in Nuclear Power Plants,‖ and ASTM 

D5163, ―Standard Guide for Establishing Procedures to Monitor the Performance of 

Safety-Related Coatings in an Operating Nuclear Power Plant.‖ The applicant stated that the 

scope of the program includes coatings inside and outside containment, and that a condition 

assessment is required to be performed every refueling outage. 

The applicant also stated that the acceptance criteria are described in, and are based on, the 

following industry guidance: ASTM D610, ―Evaluating Degree of Rusting of Painted Steel 

Surfaces‖; ASTM D714, ―Evaluating Degree of Blistering of Paints‖; ASTM D1186, 

―Nondestructive Measurement of Dry Film Thickness of Nonmagnetic Coating Applied to a 

Ferrous Base‖; ASTM D1400, ―Nondestructive Measurement of Dry Film Thickness of 

Nonconductive Coating Applied to a Non-Ferrous Metal Base‖; and ASTM D3359, ―Method for 

Measuring Adhesion by Tape.‖ The applicant also stated that personnel qualifications for 

coatings inspectors, coating applicators, and surface preparation personnel are governed by 

approved procedures. The applicant stated further that, ―the Protective Coating program 

implemented during the current licensing period ensures that coatings inside Containment will 

be properly maintained during the period of extended operation.‖

The staff reviewed the response to RAI XI.S8. The staff found the frequency of the inspection of 

the coatings in containment to be acceptable since inspecting every refueling outage would 

provide adequate assurance that there is proper maintenance of the protective coatings in 
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containment, such that they will not degrade and become a debris source that may challenge 

the ECCS. The staff also found: (1) that the scope of the program is acceptable since it includes

coatings inside and outside containment; (2) the acceptance criteria are acceptable since the 

staff has accepted and confirmed the acceptability of ASTMs D610, D714, and D3359; (3) the 

method of performing the coatings inspection is acceptable since the staff has confirmed that 

ASTM D5163 is acceptable; (4) the qualification of personnel who perform the inspection is 

acceptable since they are qualified in accordance with approved station procedures and are 

knowledgeable in coating-related installation specifications, procedures, and engineering 

standards, in addition to relevant industry standards, good practices, failure modes, and industry 

OE common to protective coatings. In addition, the staff also finds the Protective Coatings 

Monitoring and Maintenance Program to be acceptable since the program conforms to RG 1.54, 

Revision 0, and incorporates ASTMs D5144 and D5163, which are endorsed by the staff.

Based on its review, the staff finds the applicant‘s response to RAI XI.S8 acceptable. The staff‘s 

concern described in RAI XI.S8 is resolved.

Conclusion. On the basis of its technical review of the applicant‘s Protective Coatings 

Monitoring and Maintenance Program, the staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended functions will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(2). 

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs

3.0.4.1 Summary of Technical Information in the Application

In LRA Appendix A, ―USAR Supplement‖; Section A1.0, ―Introduction‖; and Appendix B, ―Aging 

Management Programs,‖ Section B1.3, ―Quality Assurance Program and Administrative 

Controls,‖ 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. The KPS QAP includes the elements of corrective action, 

confirmation process, and administrative controls. Corrective actions, confirmation process, and 

administrative controls are applied in accordance with the QAP regardless of the safety 

classification of the components. LRA Sections A1.0 and B1.3 state that the QAP implements 

the requirements of 10 CFR 50, Appendix B, ―Quality Assurance Criteria for Nuclear Power 

Plants and Fuel Reprocessing Plants,‖ and is consistent with SRP-LR, Revision 1.

3.0.4.2 Staff Evaluation

Pursuant to 10 CFR 54.21(a)(3), an applicant is required to demonstrate that the effects of 

aging on SCs subject to an AMR will be adequately managed so that their intended functions 

will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, 

Branch Technical Position (BTP) RLSB-1, ―Aging Management Review – Generic,‖ describes 

10 attributes of an acceptable AMP. Three of these ten attributes are associated with the quality 

assurance (QA) activities of corrective action, confirmation process, and administrative controls. 

Table A.1-1, ―Elements of an Aging Management Program for License Renewal,‖ of 

BTP RLSB-1 provides the following description of these quality attributes:
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● Attribute No. 7 – Corrective Actions, including root cause determination and prevention 

of recurrence, should be timely

● Attribute No. 8 – Confirmation Process, which should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective

● Attribute No. 9 – Administrative Controls, which should provide a formal review and 

approval process

The SRP-LR, BTP IQMB-1, ―Quality Assurance for Aging Management Programs,‖ states that 

those aspects of the AMP that affect 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‘s existing 10 CFR Part 50, Appendix B, QAP may be used to address the 

elements of corrective action, confirmation process, and administrative control. BTP IQMB-1 

provides the following guidance with regard to the QA attributes of AMPs:

Safety-related SCs are subject to Appendix B to 10 CFR Part 50 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 for license renewal, an 

applicant has an option to expand the scope of its Appendix B to 10 CFR Part 50 

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 a commitment in the 

Final Safety Analysis Report supplement in accordance with 10 CFR 54.21(d).

The staff reviewed the applicant‘s AMPs described in LRA Appendix A and Appendix B, and the 

associated implementing procedures. The purpose of this review was to ensure that the QA 

attributes (i.e., corrective action, confirmation process, and administrative controls) were 

consistent with the staff‘s guidance described in BTP IQMB-1. Based on the staff‘s evaluation, 

the descriptions of the AMPs and their associated quality attributes provided in LRA 

Appendix A, Section A1.0, and Appendix B, Section B1.3, are consistent with the staff‘s position 

regarding QA for aging management.

3.0.4.3 Conclusion

On the basis of the staff‘s evaluation the descriptions and applicability of the plant-specific 

AMPs and their associated quality attributes provided in LRA Appendix A, Section A1.0 and 

Appendix B, Section B1.3, were determined to be consistent with the staff‘s position regarding 

QA for aging management. The staff concludes that the QA attributes (i.e., corrective action, 

confirmation process, and administrative control) of the applicant's AMPs are consistent with 

10 CFR 54.21(a)(3).
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3.1 Aging Management of Reactor Coolant System

This section of the SER documents the staff‘s review of the applicant‘s AMR results for the RCS 

components and component groups of the following:

● reactor vessel

● reactor vessel internals

● reactor coolant system

● steam generator

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the reactor vessel, RVIs, RCS, and steam generator. 

LRA Table 3.1.1, ―Summary of Aging Management Programs for Reactor Vessel, Internals and 

Reactor Coolant System Evaluated in Chapter IV of NUREG 1801,‖ is a summary comparison 

of the applicant‘s AMRs with those evaluated in the GALL Report for the reactor vessel, RVIs, 

RCS, and steam generator components and component groups.

The applicant‘s AMRs evaluated and incorporated applicable plant-specific and industry OE in 

the determination of AERMs. The plant-specific evaluation included issue reports and 

discussions with appropriate site personnel to identify AERMs. The applicant‘s review of 

industry OE included a review of the GALL Report and OE issues identified since the issuance 

of the GALL Report.

3.1.2 Staff Evaluation

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.

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, RVIs, RCS, and 

steam generator components, within the scope of license renewal and subject to an AMR, will 

be adequately managed so that the intended functions 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 two onsite audits of AMPs to confirm the applicant‘s claim that certain 

AMPs were consistent with the GALL Report. The purpose of these audits was to examine the 

applicant‘s AMPs and related documentation, and to verify the applicant‘s claim of consistency 

with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters 

described in the GALL Report. The staff‘s evaluations of the AMPs are documented in SER 

Section 3.0.3.

The staff reviewed the AMRs to confirm the applicant‘s claim that certain identified 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 had identified the appropriate GALL Report AMRs. Details of 

the staff‘s evaluation are discussed in SER Sections 3.1.2.1 and 3.1.2.2.
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The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The 

review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff‘s evaluation are discussed in SER Section 3.1.2.3.

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant‘s OE 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 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel pressure vessel 

support skirt and 

attachment welds 

(3.1.1-1)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

reactor vessel 

components: flanges; 

nozzles; penetrations; 

safe ends; thermal 

sleeves; vessel 

shells, heads, and 

welds 

(3.1.1-2)

Cumulative 

fatigue damage

TLAA, evaluated in

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Yes, TLAA Boiling water 

reactor (BWR) 

only

Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

RCPB piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-3)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Yes, TLAA BWR only Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Steel pump and valve 

closure bolting

(3.1.1-4)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

check Code limits 

for allowable cycles 

(less than

7,000 cycles) of 

thermal stress 

range

Yes, TLAA BWR only Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

Ni-alloy RVI 

components

(3.1.1-5)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Ni-alloy tubes and 

sleeves in a reactor 

coolant and 

secondary 

feedwater/steam 

environment

(3.1.1-6)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel and stainless 

steel RCPB closure 

bolting, head closure 

studs, support skirts 

and attachment 

welds, pressurizer 

relief tank 

components, steam 

generator 

components, piping 

and components 

external surfaces and 

bolting

(3.1.1-7)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c)

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel; stainless steel; 

and Ni-alloy RCPB 

piping, piping 

components, piping 

elements; flanges; 

nozzles and safe 

ends; pressurizer 

vessel shell heads 

and welds; heater 

sheaths and sleeves; 

penetrations; thermal 

sleeves

(3.1.1-8)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

reactor vessel 

components: flanges; 

nozzles; penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads, and 

welds

(3.1.1-9)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel; stainless steel; 

steel with Ni-alloy or 

stainless steel 

cladding; Ni-alloy 

steam generator 

components (flanges; 

penetrations; nozzles; 

safe ends, lower 

heads, and welds)

(3.1.1-10)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Yes, TLAA TLAA, evaluated 

in accordance with 

10 CFR 54.21(c) 

and environmental 

effects are to be 

addressed for 

Class 1 

components

Fatigue is a TLAA

(See SER 

Section 3.1.2.2.1)

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

(3.1.1-11)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel steam generator 

shell assembly 

exposed to secondary 

feedwater and steam

(3.1.1-12)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated

Once-through

steam generator 

(OTSG) only

Applicable to 

OTSGs, therefore, 

not applicable to 

KPS

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant

(3.1.1-13)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel, Ni 

alloy, and steel with 

Ni-alloy or stainless 

steel cladding reactor 

vessel flanges, 

nozzles, penetrations, 

safe ends, vessel 

shells, heads and 

welds

(3.1.1-14)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with Ni-alloy or 

stainless steel 

cladding, and Ni-alloy 

RCPB components 

exposed to reactor 

coolant

(3.1.1-15)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel steam generator 

upper and lower shell 

and transition cone 

exposed to secondary 

feedwater and steam

(3.1.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry. For

Westinghouse 

Model 44 and 51 

steam generators, if 

general and pitting 

corrosion of the 

shell is known to 

exist, additional 

inspection 

procedures are to 

be developed.

Yes, detection 

of aging effects 

is to be 

evaluated

ASME Section XI 

ISI (IWB, IWC, 

and IWD) and 

Secondary Water 

Chemistry

programs

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.2.4)

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds

(3.1.1-17)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

TLAA, evaluated in 

accordance with 

Appendix G of 

10 CFR 50 and 

RG 1.99. The 

applicant may 

choose to 

demonstrate that 

the materials of the 

nozzles are not 

controlling for the 

TLAA evaluations.

Yes, TLAA TLAA, evaluated 

in accordance with 

Appendix G of 

10 CFR 50 and 

RG 1.99

Loss of fracture 

toughness is a TLAA

(See SER 

Sections 3.1.2.2.3.1 

and 4.2)

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles

(3.1.1-18)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

Reactor Vessel 

Surveillance

Yes, 

plant-specific

Reactor Vessel 

Surveillance

Program

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.3.2)

Stainless steel and 

Ni-alloy top head 

enclosure vessel 

flange leak detection 

line

(3.1.1-19)

Cracking due to 

SCC and 

intergranular 

stress-corrosion 

cracking 

(IGSCC)

A plant-specific 

AMP is to be 

evaluated.

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel 

isolation condenser 

components exposed 

to reactor coolant

(3.1.1-20)

Cracking due to 

SCC and 

IGSCC

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and plant-specific 

verification program

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Reactor vessel shell 

fabricated of 

SA508-Cl 2 forgings 

clad with stainless 

steel using a 

high-heat-input 

welding process

(3.1.1-21)

Crack growth 

due to cyclic 

loading

TLAA Yes, TLAA TLAA Crack growth due to 

cyclic loading is a 

TLAA

(See SER 

Sections 3.1.2.2.5 

and 4.7.4)
Aging Management Review Results

3-187

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

Ni-alloy RVI 

components exposed 

to reactor coolant and 

neutron flux

(3.1.1-22)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement, 

void swelling

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No, but licensee 

commitment to 

be confirmed

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.6)

Stainless steel reactor 

vessel closure head 

flange leak detection 

line and 

bottom-mounted 

instrument guide 

tubes

(3.1.1-23)

Cracking due to 

SCC

A plant-specific 

AMP is to be 

evaluated.

Yes, 

plant-specific

Primary Water 

Chemistry, WCP, 

and ASME 

Section XI ISI

(IWB, IWC, and 

IWD) programs

Consistent with the 

GALL Report 

(See SER 

Section 3.1.2.2.7 for 

RPV)

Class 1 CASS piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant

(3.1.1-24)

Cracking due to 

SCC

Water Chemistry 

and, for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a 

plant-specific AMP

Yes, 

plant-specific

Primary Water 

Chemistry, WCP 

and, for CASS 

components that 

do not meet the 

NUREG-0313 

guidelines, ASME 

Section XI ISI

(IWB, IWC, and 

IWD) Program

Consistent with the 

GALL Report 

(See SER 

Section 3.1.2.2.7 for 

CASS piping)

Stainless steel jet 

pump sensing line

(3.1.1-25)

Cracking due to 

cyclic loading

A plant-specific 

AMP is to be 

evaluated.

Yes BWR only Not applicable to 

PWRs 

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components exposed 

to reactor coolant

(3.1.1-26)

Cracking due to 

cyclic loading

Inservice 

Inspection (IWB, 

IWC, and IWD) and 

plant-specific 

verification program

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-188

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

Ni-alloy RVI screws, 

bolts, tie rods, and 

hold down springs

(3.1.1-27)

Loss of preload 

due to stress 

relaxation

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No, but licensee 

commitment to 

be confirmed

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.9)

Steel steam generator 

feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater

(3.1.1-28)

Loss of material 

due to erosion

A plant-specific 

AMP is to be 

evaluated.

Yes, 

plant-specific

Not applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.1.2.2.10)

Stainless steel steam 

dryers exposed to 

reactor coolant

(3.1.1-29)

Cracking due to 

flow-induced 

vibration

A plant-specific 

AMP is to be 

evaluated.

Yes BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel RVI 

components 

(e.g., upper internals 

assembly, rod cluster 

control assembly 

(RCCA) guide tube 

assemblies, 

baffle/former 

assembly, lower 

internal assembly, 

shroud assemblies, 

plenum cover and 

plenum cylinder, 

upper grid assembly, 

control rod guide tube 

assembly, core 

support shield 

assembly, core barrel 

assembly, lower grid 

assembly, flow 

distributor assembly, 

thermal shield, 

instrumentation 

support structures)

(3.1.1-30)

Cracking due to 

SCC and 

irradiationassisted 

stress-corrosion 

cracking 

(IASCC)

Water Chemistry 

and USAR 

supplement 

commitment to: 

(1) participate in 

industry, RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No, but licensee 

commitment 

needs to be 

confirmed

Primary Water 

Chemistry

Program and 

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.12)
Aging Management Review Results

3-189

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Ni alloy and steel with 

Ni-alloy cladding 

piping, piping 

component, piping 

elements, 

penetrations, nozzles, 

safe ends, and welds 

(other than reactor 

vessel head); 

pressurizer heater 

sheaths, sleeves, 

diaphragm plate, 

manways, and 

flanges; core support 

pads/core guide lugs

(3.1.1-31)

Cracking due to 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry and 

USAR supplement 

commitment to 

implement 

applicable plant 

commitments to: 

(1) NRC orders, 

bulletins, and GLs 

associated with Ni 

alloys and 

(2) staff-accepted 

industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed

ASME XI ISI 

(IWB, IWC, and 

IWD), Primary 

Water Chemistry, 

and Alloy 600 

Inspections 

programs

Consistent with the 

GALL Report

(See SER 

Sections 3.1.2.2.13

and 3.1.2.1.7)

Steel steam generator 

feedwater inlet ring 

and supports

(3.1.1-32)

Wall thinning 

due to 

flow-accelerated 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes, 

plant-specific

Not applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.1.2.2.14)

Stainless steel and 

Ni-alloy RVI 

components

(3.1.1-33)

Changes in 

dimensions due 

to void swelling

USAR supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No, but licensee 

commitment to 

be confirmed

USAR supplement 

commitment to: 

(1) participate in

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.15)

Stainless steel and 

Ni-alloy reactor 

control rod drive 

(CRD) head 

penetration pressure 

housings

(3.1.1-34)

Cracking due to 

SCC and 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry. For Ni 

alloy, USAR 

supplement

commitment to 

implement 

applicable plant 

commitments to: 

(1) NRC orders, 

bulletins, and GLs 

associated with Ni 

alloys and 

(2) staff-accepted 

industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed

ASME XI ISI 

(IWB, IWC, and 

IWD) and Primary

Water Chemistry 

programs

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.16)
Aging Management Review Results

3-190

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel with stainless 

steel or Ni-alloy 

cladding primary side 

components; steam 

generator upper and 

lower heads, 

tubesheets, and 

tube-to-tubesheet 

welds

(3.1.1-35)

Cracking due to 

SCC and 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry. For Ni 

alloy, USAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to: 

(1) NRC orders, 

bulletins, and GLs 

associated with Ni 

alloys and (2) 

staff-accepted 

industry guidelines.

No, but licensee 

commitment 

needs to be 

confirmed

OTSG only Applicable to 

OTSGs, therefore, 

not applicable to 

KPS, except for 

tube-to-tubesheet 

welds between 

Ni-alloy cladding and 

Ni-alloy tubes in the 

steam generator –

see SER 

Section 3.1.2.2.16.1.

(See SER 

Sections 3.1.2.1.1 

and 3.1.2.2.16)

Ni-alloy, stainless 

steel pressurizer 

spray head

(3.1.1-36)

Cracking due to 

SCC and 

PWSCC

Water Chemistry 

and One-Time 

Inspection. For 

Ni-alloy welded 

spray heads, 

provide 

commitment in 

USAR supplement 

to submit AMP 

delineating 

commitments to 

NRC orders, 

bulletins, or GLs 

that inspect 

stipulated 

components for 

cracking of wetted 

surfaces.

No, unless 

licensee 

commitment 

needs to be 

confirmed

Not applicable Not applicable to 

KPS

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy RVI 

components 

(e.g., upper internals 

assembly, RCCA 

guide tube 

assemblies, lower 

internal assembly, 

CEA shroud 

assemblies, core 

shroud assembly, 

core support shield 

assembly, core barrel 

assembly, lower grid 

assembly, flow 

distributor assembly)

(3.1.1-37)

Cracking due to 

SCC, PWSCC, 

and IASCC

Water Chemistry 

and USAR 

supplement 

commitment to: 

(1) participate in 

industry RVI aging 

programs; 

(2) implement 

applicable results; 

and (3) submit for 

staff approval, 

greater than 24 

months before the 

period of extended 

operation, an RVI 

inspection plan 

based on industry 

recommendation.

No, but licensee 

commitment 

needs to be 

confirmed

Primary Water 

Chemistry 

Program and 

ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program, 

including its 

Commitment 

No. 1 

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.2.17)
Aging Management Review Results

3-191

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with or without 

stainless steel 

cladding) CRD return 

line nozzles exposed 

to reactor coolant

(3.1.1-38)

Cracking due to 

cyclic loading

BWR Control Rod 

Drive Return Line 

Nozzle

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant

(3.1.1-39)

Cracking due to 

cyclic loading

BWR Feedwater 

Nozzle

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy penetrations 

for CRD stub tubes 

instrumentation, jet 

pump 

instrumentation, 

standby liquid control, 

flux monitor, and 

drain line exposed to 

reactor coolant

(3.1.1-40)

Cracking due to 

SCC, IGSCC, 

and cyclic 

loading

BWR Penetrations 

and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy piping, piping 

components, and 

piping elements 

≥ 4′′ NPS; nozzle safe

ends and associated 

welds

(3.1.1-41)

Cracking due to 

SCC and 

IGSCC

BWR 

Stress-Corrosion 

Cracking and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy vessel shell 

attachment welds 

exposed to reactor 

coolant

(3.1.1-42)

Cracking due to 

SCC and 

IGSCC

BWR Vessel ID 

Attachment Welds 

and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel fuel 

supports and CRD 

assemblies and CRD 

housing exposed to 

reactor coolant

(3.1.1-43)

Cracking due to 

SCC and 

IGSCC

BWR Vessel 

Internals and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-192

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

Ni-alloy core shroud, 

core plate, core plate 

bolts, support 

structure, top guide,

core spray lines, 

spargers, jet pump 

assemblies, CRD 

housing, and nuclear 

instrumentation guide 

tubes

(3.1.1-44)

Cracking due to 

SCC, IGSCC, 

and IASCC

BWR Vessel 

Internals and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-45)

Wall thinning 

due to 

flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Ni-alloy core shroud 

and core plate access 

hole cover 

(mechanical covers)

(3.1.1-46)

Cracking due to 

SCC, IGSCC, 

and IASCC

Inservice 

Inspection (IWB, 

IWC, and IWD), 

and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Stainless steel and 

Ni-alloy RVIs exposed 

to reactor coolant

(3.1.1-47)

Loss of material 

due to pitting 

and crevice 

corrosion

Inservice 

Inspection (IWB, 

IWC, and IWD), 

and Water 

Chemistry

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel Class 1 piping, 

fittings, and branch 

connections less than 

4′′ NPS exposed to 

reactor coolant

(3.1.1-48)

Cracking due to 

SCC, IGSCC 

(for stainless 

steel only), and 

thermal and 

mechanical 

loading

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water chemistry, 

and One-Time 

Inspection of ASME 

Code Class 1 

Small-Bore Piping

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Ni-alloy core shroud 

and core plate access 

hole cover (welded 

covers)

(3.1.1-49)

Cracking due to 

SCC, IGSCC, 

and IASCC

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and, for BWRs with 

a crevice in the 

access hole covers, 

augmented 

inspection using UT 

or other 

demonstrated 

acceptable 

inspection of the 

access hole cover 

welds

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-193

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High-strength 

low-alloy steel top 

head closure studs 

and nuts exposed to 

air with reactor 

coolant leakage

(3.1.1-50)

Cracking due to 

SCC and 

IGSCC

Reactor Head 

Closure Studs

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

CASS jet pump 

assembly castings; 

orificed fuel support

(3.1.1-51)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Thermal Aging and 

Neutron Irradiation 

Embrittlement of 

CASS

No BWR only Not applicable to 

PWRs

(See SER 

Section 3.1.2.1.1)

Steel and stainless 

steel RCPB pump 

and valve closure 

bolting, manway and 

holding bolting, flange 

bolting, and closure 

bolting in 

high-pressure and 

high-temperature 

systems

(3.1.1-52)

Cracking due to 

SCC, loss of 

material due to 

wear, loss of 

preload due to 

thermal effects, 

gasket creep, 

and 

self-loosening

Bolting Integrity No Bolting Integrity

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water

(3.1.1-53)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water

(3.1.1-54)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program

Consistent with the 

GALL Report
Aging Management Review Results

3-194

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

CASS Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant > 250 °C 

(482 °F)

(3.1.1-55)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Inservice inspection 

(IWB, IWC, and 

IWD). Thermal 

aging susceptibility 

screening is not 

necessary, ISI 

requirements are 

sufficient for 

managing these 

aging effects. 

ASME Code Case 

N-481 also 

provides an 

alternative for pump 

casings.

No ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program. Thermal 

aging 

susceptibility 

screening is not 

necessary; ISI 

requirements are 

sufficient for 

managing these 

aging effects. 

ASME Code Case 

N-481 also 

provides an 

alternative for 

pump casings.

Consistent with the 

GALL Report

Copper alloy 

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water

(3.1.1-56)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Not applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.1.2.3.2)

CASS Class 1 piping, 

piping components, 

and piping elements 

and CRD pressure 

housings exposed to 

reactor coolant 

> 250 °C (482 °F)

(3.1.1-57)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

No Thermal Aging 

Embrittlement of 

CASS Program

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.1.2)

Steel RCPB external 

surfaces exposed to 

air with borated water 

leakage

(3.1.1-58)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion

Program

Consistent with the 

GALL Report

Steel steam generator 

steam nozzle and 

safe end, feedwater 

nozzle and safe end, 

AFW nozzles and 

safe ends exposed to 

secondary 

feedwater/steam

(3.1.1-59)

Wall thinning 

due to 

flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion

No Not applicable to 

KPS

Not applicable

(See SER 

Section 3.1.2.1.1)

Stainless steel flux 

thimble tubes (with or 

without chrome 

plating)

(3.1.1-60)

Loss of material 

due to wear

Flux Thimble Tube 

Inspection

No Flux Thimble Tube 

Inspection

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-195

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288 °C (550 °F)

(3.1.1-61)

Cracking due to 

cyclic loading

Inservice Inspection 

(IWB, IWC, and 

IWD)

No ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program

Consistent with the 

GALL Report

Stainless steel, steel 

with stainless steel 

cladding RCS cold 

leg, hot leg, surge 

line, and spray line 

piping and fittings 

exposed to reactor 

coolant

(3.1.1-62)

Cracking due to 

cyclic loading

Inservice Inspection 

(IWB, IWC, and 

IWD)

No ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program

Consistent with the 

GALL Report

Steel reactor vessel 

flange, stainless steel 

and Ni-alloy RVIs 

exposed to reactor 

coolant (e.g., upper 

and lower internals 

assembly, CEA 

shroud assembly, 

core support barrel, 

upper grid assembly, 

core support shield 

assembly, and lower 

grid assembly)

(3.1.1-63)

Loss of material 

due to wear

Inservice Inspection 

(IWB, IWC, and 

IWD)

No ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program

Consistent with the 

GALL Report

Stainless steel and 

steel with stainless 

steel or Ni-alloy 

cladding pressurizer 

components

(3.1.1-64)

Cracking due to 

SCC and 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry

No ASME Section XI 

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

programs

Consistent with the 

GALL Report

Ni-alloy reactor vessel 

upper head and CRD 

penetration nozzles, 

instrument tubes, 

head vent pipe (top 

head), and welds

(3.1.1-65)

Cracking due to 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry and 

Ni-Alloy Penetration 

Nozzles Welded to 

the Upper Reactor 

Vessel Closure 

Heads of 

Pressurized Water 

Reactors

No ASME Section XI 

ISI (IWB, IWC, 

and IWD), Primary 

Water Chemistry, 

and Alloy 600 

Inspections 

programs

Consistent with the 

GALL Report 

(See SER 

Section 3.1.2.1.8)
Aging Management Review Results

3-196

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel steam generator 

secondary manways 

and handholds 

(cover only) exposed 

to air with leaking 

secondary-side water 

and/or steam

(3.1.1-66)

Loss of material 

due to erosion

Inservice Inspection 

(IWB, IWC, and 

IWD) for Class 2 

components

No OTSG only Applicable to 

OTSGs, therefore, 

not applicable to 

KPS

(See SER 

Section 3.1.2.1.1)

Steel with stainless 

steel or Ni-alloy 

cladding; or stainless 

steel pressurizer 

components exposed 

to reactor coolant

(3.1.1-67)

Cracking due to 

cyclic loading

Inservice Inspection

(IWB, IWC, and 

IWD) and Water 

Chemistry

No ASME Section XI 

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry 

programs

Consistent with the 

GALL Report

Stainless steel, steel 

with stainless steel 

cladding Class 1 

piping, fittings, pump 

casings, valve bodies, 

nozzles, safe ends, 

manways, flanges, 

CRD housing; 

pressurizer heater 

sheaths, sleeves, 

diaphragm plate; 

pressurizer relief tank 

components, RCS 

cold leg, hot leg, 

surge line, and spray 

line piping and fittings

(3.1.1-68)

Cracking due to 

SCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry

No ASME Section XI 

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry 

programs

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.1.4)

Stainless steel, 

Ni-alloy safety 

injection nozzles, safe 

ends, and associated 

welds and buttering 

exposed to reactor 

coolant

(3.1.1-69)

Cracking due to 

SCC and 

PWSCC

Inservice Inspection 

(IWB, IWC, and 

IWD) and Water 

Chemistry

No ASME Section XI 

ISI (IWB, IWC, 

and IWD) 

Alloy 600 

Inspections, and 

Water Chemistry 

programs

Consistent with the 

GALL Report 

(See SER 

Section 3.1.2.1.9)

Stainless steel; steel 

with stainless steel 

cladding Class 1 

piping, fittings, and 

branch connections 

less than 4′′ NPS 

exposed to reactor 

coolant (3.1.1-70)

Cracking due to 

SCC; thermal 

and mechanical 

loading

Inservice Inspection 

(IWB, IWC, and 

IWD), Water 

Chemistry, and 

One-Time 

Inspection of ASME 

Code Class 1 

Small-Bore Piping

No ASME Section XI 

ISI (IWB, IWC, 

and IWD) and 

Water Chemistry

programs. 

Inspections of 

small-bore piping 

performed by the 

ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program.

Consistent with the 

GALL Report
Aging Management Review Results

3-197

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High-strength 

low-alloy steel closure 

head stud assembly 

exposed to air with 

reactor coolant 

leakage

(3.1.1-71)

Cracking due to 

SCC and loss of 

material due to 

wear

Reactor Head 

Closure Studs

No Reactor Head 

Closure Studs

Program

Consistent with the 

GALL Report

Ni-alloy steam 

generator tubes and 

sleeves exposed to 

secondary 

feedwater/steam

(3.1.1-72)

Cracking due to 

outsidediameter stresscorrosion 

cracking 

(ODSCC) and 

intergranular 

attack; loss of 

material due to 

fretting and 

wear

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity and 

Secondary Water 

Chemistry

programs

Consistent with the 

GALL Report

Ni-alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed to 

reactor coolant

(3.1.1-73)

Cracking due to 

PWSCC

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity and 

Water Chemistry

programs

Consistent with the 

GALL Report

Chrome plated steel, 

stainless steel, 

Ni-alloy steam 

generator 

anti-vibration bars 

exposed to secondary 

feedwater/steam

(3.1.1-74)

Cracking due to 

SCC; loss of 

material due to 

crevice 

corrosion and 

fretting

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity and 

Water Chemistry

programs

Consistent with the 

GALL Report

Ni-alloy OTSG-tubes 

exposed to secondary 

feedwater/steam

(3.1.1-75)

Denting due to 

corrosion of 

carbon steel 

tube support 

plate

Steam Generator 

Tube Integrity and 

Water Chemistry

No OTSG only Applicable to 

OTSGs, therefore, 

not applicable to 

KPS

(See SER 

Section 3.1.2.1.1)

Steel steam generator 

tube support plate 

and tube bundle 

wrapper exposed to 

secondary 

feedwater/steam

(3.1.1-76)

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion; 

ligament 

cracking due to 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity and 

Water Chemistry

programs

Consistent with the 

GALL Report.

Ligament cracking 

due to corrosion is

not applicable to the 

tube support plates 

since they are 

stainless steel.

Ni-alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater/steam

(3.1.1-77)

Loss of material 

due to wastage 

and pitting 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable to 

KPS

Not applicable

(See SER 

Section 3.1.2.1.1)
Aging Management Review Results

3-198

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel steam generator 

tube support lattice 

bars exposed to 

secondary 

feedwater/steam

(3.1.1-78)

Wall thinning 

due to 

flow-accelerated 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable to 

KPS

Not applicable

(See SER 

Section 3.1.2.1.1)

Ni-alloy steam 

generator tubes 

exposed to secondary 

feedwater/steam

(3.1.1-79)

Denting due to 

corrosion of 

steel tube 

support plate

Steam Generator 

Tube Integrity and 

Water Chemistry. 

For plants that 

could experience 

denting at the 

upper support 

plates, evaluate 

potential for rapidly 

propagating cracks 

and then develop 

and take corrective 

actions consistent 

with Bulletin 88-02.

No Not applicable to 

KPS

Not applicable

(See SER 

Section 3.1.2.1.1)

CASS RVIs 

(e.g., upper internals 

assembly, lower 

internal assembly, 

CEA shroud 

assemblies, control 

rod guide tube 

assembly, core 

support shield 

assembly, lower grid 

assembly)

(3.1.1-80)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Thermal Aging and 

Neutron Irradiation 

Embrittlement of 

CASS

No ASME Section XI 

ISI (IWB, IWC, 

and IWD)

Program, with 

enhancement

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.1.3)

Ni alloy or Ni-alloy 

clad steam generator 

divider plate exposed 

to reactor coolant

(3.1.1-81)

Cracking due to 

PWSCC

Water Chemistry No Water Chemistry

Program

Consistent with the 

GALL Report

(See SER 

Section 3.1.2.1.7)

Stainless steel steam 

generator primary 

side divider plate 

exposed to reactor 

coolant

(3.1.1-82)

Cracking due to 

SCC

Water Chemistry No Water Chemistry

Program

Consistent with the 

GALL Report, for 

steam generator 

manway cover 

diaphragm. KPS‘ 

steam generator 

divider plate is 

fabricated from Ni 

alloy and is 

evaluated in 

Table 3.1.1, 

item 3.1.1-81. 
Aging Management Review Results

3-199

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel; steel 

with Ni-alloy or 

stainless steel 

cladding; and Ni-alloy 

RVIs and RCPB 

components exposed 

to reactor coolant

(3.1.1-83)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No Water Chemistry

Program

Consistent with the 

GALL Report

Ni-alloy steam 

generator 

components, such as 

secondary-side 

nozzles (vent, drain, 

and instrumentation) 

exposed to secondary 

feedwater/steam

(3.1.1-84)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection or 

Inservice Inspection 

(IWB, IWC, and 

IWD)

No OTSG only Applicable to 

OTSGs, therefore, 

not applicable to 

KPS

(See SER 

Section 3.1.2.1.1)

Ni-alloy piping, piping 

components, and 

piping elements 

exposed to air-indoor 

uncontrolled 

(external)

(3.1.1-85)

None None NA – No AERM 

or AMP

None Consistent with the 

GALL Report

Stainless steel piping, 

piping components, 

and piping elements 

exposed to air-indoor 

uncontrolled 

(external); air with 

borated water 

leakage; concrete; 

gas

(3.1.1-86)

None None NA – No AERM 

or AMP

None Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements in 

concrete

(3.1.1-87)

None None NA – No AERM 

or AMP

None Not applicable to 

KPS 

(See SER 

Section 3.1.2.1.1)

The staff‘s review of the RCS component groups followed several approaches. One approach, 

documented in SER Section 3.1.2.1, discusses the staff‘s review of AMR results for components 

the applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another approach, documented in SER Section 3.1.2.2, discusses the staff‘s review of AMR 

results for components the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.1.2.3, discusses the staff‘s review of AMR results for components 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 RCS components is documented in 

SER Section 3.0.3.
Aging Management Review Results

3-200

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, RVIs, RCS, and steam generator components:

● Alloy 600 Inspections Program

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

● Bolting Integrity Program

● Boric Acid Corrosion Program

● Closed-Cycle Cooling Water System Program

● External Surfaces Monitoring Program

● Flux Thimble Tube Inspection Program

● Lubricating Oil Analysis Program

● Primary Water Chemistry Program

● Reactor Head Closure Studs Program

● Reactor Vessel Surveillance Program

● Secondary Water Chemistry Program

● Steam Generator Tube Integrity Program

● Work Control Process Program

LRA Tables 3.1.2-1 through 3.1.2-4 summarize the results of AMRs for the reactor vessel, RVIs, 

RCS, and steam generator components and indicate AMRs claimed to be consistent with the 

GALL Report.

For component groups evaluated in the GALL Report for which the applicant had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item describing how the information in the 

tables aligns with the information in the GALL Report. The staff reviewed those AMRs with 

notes A through E, which indicate how the AMR was 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 Report 

AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 

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 AMP 

identified in the GALL Report. The staff reviewed these line items to verify consistency with the 

GALL Report and that it had reviewed and accepted the identified exceptions to the GALL 

Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 
Aging Management Review Results

3-201

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line item of the different component applied 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 AMP identified in the GALL Report. The staff reviewed these line items 

to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of 

the different component was applicable to the component under review and whether the 

exceptions to the GALL Report AMPs had been reviewed and accepted by the staff. The staff 

also determined whether the AMP identified by the applicant was consistent with the AMP 

identified in the GALL Report 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 a different AMP is credited. The staff reviewed these line 

items to verify consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report 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, it did verify that the material presented in 

the LRA was applicable and that the applicant had identified the appropriate GALL Report 

AMRs. The staff‘s evaluation is discussed below.

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 

reactor vessel, RVIs, RCS, and steam generator 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 3.1.1, the applicant‘s references to the GALL Report are 

acceptable and no further staff review is required.

3.1.2.1.1 AMR Results Identified as Not Applicable

Based on its initial review, the staff identified several line items of LRA Table 3.1.1 in which the 

applicant stated the line items were not applicable to KPS. This subsection discusses the 

evaluation of those line items.

LRA Table 3.1.1, items 2–4, 11, 13-15, 19, 20, 25, 26, 29, and 38–51 discuss the applicant‘s 

determination on GALL Report AMR items that are applicable only to BWR-designed reactors. 

In the applicant AMR discussions for these items, no additional information is provided. The 

staff confirmed that these AMR items in Table 1 of the GALL Report, Volume 1 are only 

applicable to BWR-designed reactors, and that KPS is a PWR with a dry ambient containment. 

Based on this determination, the staff finds that the applicant has provided an acceptable basis 

for concluding AMR items 2–4, 11, 13–15, 19, 20, 25, 26, 29, and 38–51 in Table 1 of the GALL 

Report, Volume 1 are not applicable to KPS.
Aging Management Review Results

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LRA Table 3.1.1, items 12, 66, 75, and 84 discuss the applicant‘s determination on GALL

Report AMR items that are applicable only to OTSGs. The staff confirmed that these AMR items 

in Table 1 of the GALL Report, Volume 1 are only applicable to OTSGs and confirmed, by 

reviewing various sections of the LRA and USAR, that KPS has recirculating steam generators. 

Based on this determination, the staff finds that the applicant has provided an acceptable basis 

for concluding AMR items 12, 35, 66, 75, and 84 in Table 1 of the GALL Report, Volume 1 are 

not applicable to KPS.

LRA Table 3.1.1, item 3.1.1-35 addresses cracking due to SCC and PWSCC in steel with 

stainless steel or Ni-alloy cladding primary side components and steam generator upper and 

lower heads, tubesheets, and tube-to-tubesheet welds. The staff confirmed, with one exception 

noted below, that this AMR item in Table 1 of the GALL Report, Volume 1 is only applicable to 

OTSGs, and confirmed, by reviewing various sections of the LRA and the USAR, that KPS has 

recirculating steam generators. Based on this determination, the staff finds that the applicant 

has provided an acceptable basis for concluding AMR item 35 in Table 1 of the GALL Report, 

Volume 1 is not applicable to KPS with one exception: the tube-to-tubesheet welds for the 

steam generators. This issue is discussed and resolved in SER Section 3.1.2.2.16.1.

LRA Table 3.1.1, item 3.1.1-59 addresses wall thinning due to flow-accelerated corrosion in 

steel steam generator steam nozzle and safe end, feedwater nozzle and safe end, and AFW 

nozzles and safe ends exposed to secondary feedwater and steam. The applicant stated that 

this item is not applicable because in 2001, the original Westinghouse Model 51 steam 

generators were replaced with Westinghouse Model 54F. The applicant explained that this was 

accomplished by replacing the lower portion of the steam generator and refurbishing the upper 

steam generator internals. Furthermore, included in the upper internals refurbishment was the 

installation of a flow-accelerated, corrosion-resistant, Ni-alloy welded thermal sleeve in the 

feedwater nozzle that isolates the carbon steel nozzle from the fluid flow. Additionally, a steam 

flow limiting device was installed in the existing steam nozzle. This steam flow limiting device 

isolates the steam flow from the carbon steel steam nozzle, and the surfaces of the steam flow 

limiting device that are exposed to steam flow are constructed of a flow-accelerated, 

corrosion-resistant, Ni-alloy material.

The staff reviewed the steam generator description in LRA Sections 2.3.1.4 and B2.1.30 and the 

applicant‘s USAR in order to verify the design of the plant‘s steam generators and confirmed 

that the applicant‘s replacement steam generators (Westinghouse Model 54F replacement 

steam generators installed in 2001) have refurbished upper portions, including steam nozzle 

and safe end, feedwater nozzle and safe end, and AFW nozzles and safe ends exposed to 

secondary feedwater and steam that should be flow-accelerated and corrosion-resistant. 

Therefore, the staff finds that this item is not applicable. 

LRA Table 3.1.1, item 3.1.1-76 addresses, in part, ligament cracking due to corrosion of steel 

tube support plates exposed to secondary feedwater or steam. The applicant stated that such 

ligament cracking is not applicable because its steam generator tube support plates are made of 

stainless steel.

The staff reviewed the steam generator description in LRA Section 2.3.1.4 in order to verify the 

design of the plant‘s steam generators and confirmed that the applicant‘s steam generators 

(Westinghouse Model 54F replacement steam generators installed in 2001) have tube support 

plates made of stainless steel. Therefore, the staff finds that this item is not applicable.
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LRA Table 3.1.1, item 3.1.1-77 addresses the loss of material due to wastage and pitting 

corrosion in Ni-alloy steam generator tubes and sleeves exposed to phosphate chemistry in 

secondary feedwater and steam. The applicant stated that this item is not applicable because it 

does not use phosphate chemistry.

The staff reviewed the description of the applicant‘s Secondary Water Chemistry Program in 

LRA Section B2.1.28 in order to verify which water chemistry is used for the plant‘s steam 

generators and confirmed that the applicant‘s plant does not use a phosphate chemistry 

program. Therefore, the staff finds that this item is not applicable. 

LRA Table 3.1.1, item 3.1.1-78 addresses the wall thinning due to flow-accelerated corrosion in 

steel steam generator tube support lattice bars exposed to secondary feedwater and steam. 

The applicant stated that this item is not applicable because the steam generators do not 

contain tube support lattice bars.

The staff reviewed the steam generator description in LRA Section 2.3.1.4 in order to verify the 

design of the plant‘s steam generators and confirmed that the applicant‘s plant steam 

generators (Westinghouse Model 54F replacement steam generators installed in 2001) do not 

contain tube support lattice bars. Therefore, the staff finds that this item is not applicable. 

LRA Table 3.1.1, item 3.1.1-79 addresses the denting due to corrosion of steel tube support 

plates in Ni-alloy steam generator tubes exposed to secondary feedwater and steam. The 

applicant stated that this item is not applicable because the steam generator tube support plates 

are made of stainless steel.

The staff reviewed the steam generator description in LRA Section 2.3.1.4 in order to verify the 

design of the plant‘s steam generators and confirmed that the applicant‘s plant steam 

generators (Westinghouse Model 54F replacement steam generators installed in 2001) have 

tube support plates made of stainless steel. Therefore, the staff finds that this item is not 

applicable. 

LRA Table 3.1.1, item 3.1.1-85 addresses Ni-alloy piping, piping components, and piping 

elements exposed to air-indoor uncontrolled (external). The GALL Report indicates that there is 

no aging effect or mechanism and, therefore, does not recommend an AMP. The applicant 

stated that item 3.1.1-85 is consistent with the GALL Report and that there were no aging 

effects associated with this combination. Based on its review of the LRA, the staff confirmed that 

there are no Ni-alloy piping, piping components, and piping elements exposed to air-indoor 

uncontrolled (external) in the reactor vessel, RVIs, and RCS. The staff finds the applicant‘s 

determination acceptable.

LRA Table 3.1.1, item 3.1.1-87 addresses steel piping, piping components, and piping elements 

in concrete. The GALL Report does not identify an aging effect or mechanism and there is no 

GALL Report-recommended AMP program to manage aging for this component group. The 

applicant stated that this item is not applicable because there are no reactor vessel, RVI, and 

RCS components in concrete within the scope of license renewal. The staff reviewed LRA 

Sections 2.3.3 and 3.1 and confirmed that the applicant‘s LRA does not have any AMR results 

for the RCS that include steel piping, piping components, and piping elements exposed to 

concrete. Based on its review of the LRA, the staff confirmed that there are no in-scope steel 

piping, piping components, and piping elements exposed to concrete in the RCS and, therefore, 

finds the applicant‘s determination acceptable.
Aging Management Review Results

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LRA Table 3.1.1, item 3.1.1-36 addresses cracking due to SCC and PWSCC in Ni-alloy or 

stainless steel pressurizer spray heads. The GALL Report recommends the use of the Water 

Chemistry Program and the One-Time Inspection Program. In addition, for Ni-alloy spray heads, 

the GALL Report recommends that the applicant, ―provide [a] commitment in [the] FSAR

supplement to submit AMP delineating commitments to Orders, Bulletins, or Generic Letters 

that inspect stipulated components for cracking of wetted surfaces.‖ The applicant stated that 

this item is not applicable because the spray head assembly does not perform an intended 

function in accordance with 10 CFR 54.4(a); thus, the item is not applicable to KPS.

The staff reviewed LRA Section 3.1.2.2.16.2 and USAR Sections 14.1.12, ―Anticipated 

Transients Without Scram,‖ and 14.2.4, ―Steam Generator Tube Rupture,‖ as well as 

WCAP-8330, ―Westinghouse Anticipated Transients without Trip Analysis‖ (ADAMS Accession

No. ML0617902740), since USAR Section 14.1.12 uses this document to show that anticipated 

transients without trip will not result in RCS failure nor fuel failure. The staff finds that the 

pressurizer spray heads do not perform an intended function under 10 CFR 54.4(a) and, 

therefore, the applicant‘s determination is acceptable.

3.1.2.1.2 Loss of Fracture Toughness Due to Thermal Aging Embrittlement of Cast Austenitic

Stainless Steel

LRA Table 3.1.1, item 3.1.1-57 describes the aging effect in CASS Class 1 piping, piping 

components, piping elements, and CRD pressure housings exposed to reactor coolant greater 

than 250 °C (482 °F). However, the aging management evaluation of these items is not 

described in LRA Table 3.1.2-3. The applicant stated that the CASS Class 1 RCS loop piping 

has been evaluated for the effects of aging and found to be not susceptible to thermal aging 

embrittlement, as discussed in SER Section 4.7.5, ―Reactor Coolant Loop Piping Flaw 

Tolerance Evaluation.‖ The applicant further stated that it is, therefore, not necessary to manage 

the effects of thermal aging embrittlement of CASS reactor coolant loop piping for the period of 

extended operation. The applicant also stated that AMR item 3.1.1-57 is not applicable for the 

CRD pressure housings because they are fabricated from stainless steel forgings and not 

castings. 

The staff reviewed LRA Section 4.7.5 to evaluate the flaw tolerance evaluation for the reactor 

coolant loop piping. The staff‘s evaluation is discussed in SER Section 4.7.5 of this report. The 

applicant stated that the loop piping is constructed of ASME SA-351 Grade CF8M with less than 

25 percent ferrite, and consisted of centrifugally-cast piping segments and statically-cast 

elbows. Based on the screening criteria recommended in GALL AMP XI.M12, four statically-cast 

elbows and one centrifugally-cast pipe were identified to be potentially susceptible to thermal 

aging embrittlement (i.e., contained more than 14 percent and more than 20 percent ferrite, 

respectively). The applicant stated that because the delta ferrite content of the CASS materials 

does not exceed 25 percent, flaw evaluation was performed in accordance with the principles 

associated with IWB-3640 procedures for submerged arc welds (SAW), discarding the code 

restriction of 20 percent delta ferrite content in IWB-3641(b)(1). The staff finds this to be an 

acceptable approach consistent with the GALL Report. 

The applicant further stated that the results indicated that the limiting initial flaw depth for an 

aspect ratio of 6 was in the crossover leg (i.e., 28 percent through-wall), and that flaw of this 

initial size would not grow to critical size (i.e., a size that could result in piping failure at 

design-basis loading conditions) during an additional 30 years of service. Based on these 

results, the applicant concluded that even with thermal aging embrittlement of CASS loop piping 

materials to the fully-aged condition, the susceptible piping locations are tolerant of large flaws. 
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Therefore, there is no requirement to manage the effects of thermal aging embrittlement of 

CASS reactor coolant loop piping for the period of extended operation. The staff found this to be 

consistent with GALL AMP XI.M12 and is, therefore, acceptable. 

Based on its review of the program to manage the loss of fracture toughness due to thermal 

aging embrittlement of CASS Class 1 piping, piping components, and piping elements in the 

RCS, the staff finds that all program elements are consistent with GALL AMP XI.M12 and are, 

therefore, acceptable. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.1.3 Loss of Fracture Toughness Due to Thermal Aging and Neutron Irradiation 

Embrittlement of Cast Austenitic Stainless Steel 

LRA Table 3.1.1, item 3.1.1-80 addresses the loss of fracture toughness due to thermal aging 

and neutron irradiation embrittlement of CASS RVI components. The AMR items corresponding 

to item 3.1.1-80 are described in LRA Table 3.1.2-2 and include the CASS cruciform top end 

piece of the bottom-mounted instrumentation (BMI) column, CASS base of the upper support 

columns and upper instrumentation columns, and CASS flow mixing base of the RCCA guide 

tubes. The applicant stated in LRA Table 3.1.1 that the loss of fracture toughness due to 

thermal aging and neutron irradiation embrittlement of CASS RVI components is managed by 

an enhancement to the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to 

include the recommendations of GALL AMP XI.M13, ―Thermal Aging and Neutron Irradiation 

Embrittlement of Cast Austenitic Stainless Steel (CASS),‖ following participation in the industry 

programs for investigating and managing aging effects on reactor internals. 

The staff reviewed LRA item 3.1.1-80 in comparison with the GALL Report, Volume 1, Table 1, 

ID 80. The staff noted that the generic note for the AMR items was E, which means that the 

component, material, environment, and aging effect or mechanism are consistent with the GALL 

Report, but a different AMP is credited to manage the aging effects. In its review and 

comparison, the staff found that the LRA AMR items were consistent with the GALL Report in 

component, material, environment, and aging effect. The applicant stated that the program to 

manage the loss of fracture toughness of CASS vessel internal components consists of the 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, with an enhancement to 

include identification of the limiting susceptible CASS RVI components from the standpoint of 

thermal aging susceptibility, neutron fluence, and cracking. The applicant further stated that for 

each identified component, a plan will be developed to manage the aging effects, either through 

supplemental examination or a component-specific evaluation. The applicant stated that this 

program will be consistent with the GALL Report.

The staff reviewed the applicant‘s ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program and its evaluation is documented in SER Section 3.0.3.2.1. In its review, the staff 

found that the applicant committed (Commitment No. 2) to develop and implement an AMP for 

managing the loss of fracture toughness due to thermal and neutron irradiation embrittlement of 

CASS RVI components that will be consistent with GALL AMP XI.M13, ―Thermal Aging and 

Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS).‖ The applicant 

further stated that the plan will be submitted for staff review and approval not less than 

24 months before entering the period of extended operation. The staff finds this acceptable 
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because the applicant has made a commitment to develop and submit for staff review and 

approval a program to manage loss of fracture toughness of CASS vessel internal components 

that is consistent with the recommendations of GALL AMP XI.M13. 

On the basis of its review of the applicant‘s program to manage the loss of fracture toughness 

due to thermal aging and neutron irradiation embrittlement of CASS RVI components, the staff 

finds that all program elements of the applicant‘s program are consistent with GALL 

AMP XI.M13 and are, therefore, acceptable. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). 

3.1.2.1.4 Cracking Due to Stress-Corrosion Cracking

LRA Table 3.1.1, item 3.1.1-68 addresses the cracking due to SCC of austenitic stainless steel 

RCS components. The AMR items corresponding to item 3.1.1-68 are described in LRA 

Table 3.1.2-3 and include austenitic stainless steel RCP thermal barriers heat exchanger, 

pressurizer manway, and RCS thermal sleeves. The applicant stated that the cracking due to 

SCC of these stainless steel components is managed by the Primary Water Chemistry Program. 

The applicant further stated that the program is consistent with the GALL Report. 

The staff reviewed LRA item 3.1.1-68 in comparison with the GALL Report, Volume 1, Table 3, 

ID 68. The staff noted that the consistency note for the AMR item was E, which means that the 

combination of component, material, environment, and aging effect or mechanism was 

consistent with the combination in the GALL Report, but a different AMP is credited to manage 

the effects of cracking due to SCC during the period of extended operation. The applicant stated 

that the Primary Water Chemistry Program is used to manage the effects of cracking due to 

SCC, instead of the ASME Section XI ISI, Subsections IWB, IWC, and IWD and Primary Water 

Chemistry programs recommended in the GALL Report. In its review and comparison, the staff 

found that the LRA AMR items were consistent with the GALL Report in component, material, 

environment, and aging effect. However, it was not clear how the applicant‘s program for 

stainless steel RCP thermal barriers heat exchanger, pressurizer manway, and RCS thermal 

sleeves is consistent with the GALL Report AMP. In LRA Table 3.1.2-3, the applicant stated that 

the cracking of these components due to SCC was managed by the Water Chemistry Program, 

whereas SCC cracking of stainless steel piping, fittings, pump casings, valve bodies, nozzles, 

etc. is managed by the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, as well 

as the Primary Water Chemistry Program. By letter dated October 13, 2009, the staff issued 

RAI 3.1.2.1.3-1 requesting that the applicant explain how its program to manage cracking due to 

SCC is consistent with the programs recommended in the GALL Report. Also, describe how the 

effectiveness of the program is verified to ensure that cracking does not occur and the structural 

and functional integrity of the components will be maintained during the period of extended 

operation.

In its response dated November 13, 2009, the applicant stated that for the RCP thermal barriers 

heat exchanger and pressurizer manway (including stainless steel insert), the ASME Section XI 

ISI, Subsections IWB, IWC, and IWD Program is added as an additional AMP and would 

provide verification of the effectiveness of the Primary Water Chemistry Program for 

management of cracking due to SCC. The applicant stated this change provides consistency 

with the GALL Report (item 3.1.1-68).
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The applicant also stated that for the non-pressure boundary thermal sleeves, the One-Time 

Inspection Program within the WCP Program, as described in its letter dated September 25, 

2009, is added as an additional AMP for management of cracking due to SCC. The One-Time 

Inspection Program, within the WCP Program, uses NDE techniques that have been determined 

to be effective for the identification of SCC in stainless steel. The applicant further stated that 

the inspections would verify that unacceptable degradation is not occurring for material and 

environment combinations that include stainless steel in primary treated water. The applicant 

further added that indications of degradation would result in an engineering review of the 

condition through the corrective action program and could result in further corrective actions, 

such as an expansion of the inspection scope.

The staff noted that the non-pressure boundary thermal sleeves are not Class 1 components 

and, therefore, are not within the scope of the ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program. The staff noted that the applicant has credited its Primary Water Chemistry 

Program to provide periodic monitoring and control of known detrimental contaminants that can 

result in cracking due to SCC. The staff further noted that the applicant has credited its WCP 

Program with confirming the effectiveness of its Primary Water Chemistry Program to ensure 

that cracking due to SCC does not occur for these non-pressure boundary thermal sleeves.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.1.3-1 acceptable 

because: (1) the applicant credited its Primary Water Chemistry and ASME Section XI ISI, 

Subsections IWB, IWC, and IWD programs to manage cracking due to SCC for the RCP 

thermal barrier heat exchangers and pressurizer manway (including stainless steel insert), 

consistent with the GALL Report; and (2) for the non-pressure boundary thermal sleeves, the 

applicant is controlling primary water chemistry to ensure the environment is not conducive to 

cracking due to SCC and will confirm its effectiveness with the WCP Program. The staff‘s 

concern described in RAI 3.1.2.1.3-1 is resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.5 Cracking Due to Outside-Diameter Stress-Corrosion Cracking and Intergranular 

Attack, and Loss of Material Due to Fretting and Wear

LRA Table 3.1.1, item 3.1.1-72 addresses the cracking due to ODSCC and/or intergranular 

attack and loss of material due to fretting and wear for Ni-alloy steam generator tubes and 

sleeves exposed to secondary feedwater/steam.

The GALL Report differentiates the cracking due to intergranular attack (item IV.D1-22) from the 

cracking due to ODSCC (item IV.D1-23). In its review of LRA Table 3.1.1, item 3.1.1-72, the 

staff noted that the applicant did not credit the GALL Report AMR item IV.D1-23 in LRA 

Table 3.1.2-4 for cracking due to ODSCC as an aging effect or mechanism for Ni-alloy steam 

generator tubes and sleeves exposed to secondary feedwater and steam. The staff further 

noted that the applicant only addressed cracking due to intergranular attack in its LRA.

By letter dated August 28, 2009, the staff issued RAI B2.1.30-14 requesting that the applicant 

clarify why ODSCC is not an AERM for its steam generators. The staff also requested that the 

applicant provide an AMP for addressing this aging effect, if the applicant has concluded that 

the aging management of ODSCC in its steam generators is required. 
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In its response dated September 28, 2009, the applicant recognized that it incorrectly omitted 

GALL AMR item IV.D1-23 for cracking due to ODSCC from LRA Table 3.1.2-4, but this item is 

applicable to the component group ―Tubes and Sleeves‖ exposed to a secondary feedwater and 

steam environment (treated water and/or steam-secondary) in LRA Table 3.1.2-4. It further 

clarified that as currently indicated in LRA Table 3.1.1, item 72, cracking due to ODSCC and 

intergranular attack for Ni-alloy steam generator tubes and sleeves exposed to secondary 

feedwater and steam is managed with the Secondary Water Chemistry Program and the Steam 

Generator Tube Integrity Program.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-14 acceptable 

because the applicant: (1) identified the aging effect of cracking due to ODSCC as an aging 

effect or mechanism for Ni-alloy steam generator tubes and sleeves exposed to secondary 

feedwater and steam as being omitted from LRA Table item 3.1.1-72 and (2) confirmed that it 

credits the Secondary Water Chemistry Program and the Steam Generator Tube Integrity 

Program to manage this aging effect, consistent with GALL AMR item IV.D1-23. The staff‘s 

concern described in RAI B2.1.30-14 is resolved. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.1.6 Cracking Due to Stress-Corrosion Cracking and Loss of Material Due to Crevice 

Corrosion and Fretting

LRA Table 3.1.1, item 3.1.1-74 addresses the cracking due to SCC and loss of material due to 

crevice corrosion and fretting for chrome plated steel, stainless steel, and Ni-alloy steam 

generator anti-vibration bars exposed to secondary feedwater and steam.

LRA Table 3.1.2-4 addresses AMR items of cracking due to SCC for steam generator Ni-alloy 

components exposed to treated water and/or steam-secondary. In LRA Table 3.1.2-4, the 

applicant proposed to extend this aging management mechanism designed for anti-vibration 

bars to other components of the steam generators, in relation to the material, the environment, 

and the aging effect, for which the applicant credited GALL AMR item IV.D1-14, corresponding 

to LRA Table 3.1.1, item 3.1.1-74.

The staff reviewed the corresponding item from the SRP-LR, which states that the aging effects 

associated with this item are managed by the Steam Generator Tube Integrity Program and 

Water Chemistry Program. The staff noted that for most additional components, the applicant 

credited the above two AMPs. However, for the feedwater nozzle (and Ni-alloy cladding), 

feedwater nozzle thermal sleeve, and steam nozzle flow restrictor, the applicant does not credit 

the Steam Generator Tube Integrity Program. For these three components, the applicant 

credited only the Secondary Water Chemistry Program, while it stated that these items are 

consistent with the GALL Report in all aspects except a different AMP is credited (note E). 

In its review of LRA Table 3.1.1, item 3.1.1-74, the staff noted that for the three components 

listed above, the applicant did not cover all the AMPs recommended by the GALL Report in 

item IV.D1-14. In LRA Table 3.1.1, item 3.1.1-74, the applicant stated that the aging effects 

identified for the anti-vibration bars are managed by the Steam Generator Tube Integrity 

Program and/or the Secondary Water Chemistry Program. The staff noted that GALL 

AMP XI.M19 states that the scope of the program is specific to steam generator tubes, plugs, 
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sleeves, and tube supports. The staff finds that the three previous components do not strictly 

belong to the components described in the scope of GALL AMP XI.M19. Nevertheless, the staff 

noted that the applicant did not explain when and why it applies only one program among the 

two recommended by the GALL Report, whereas it stated in its LRA that item 3.1.1-74 is 

consistent with the GALL Report.

By letter dated August 28, 2009, the staff issued RAI B2.1.30-15 requesting that the applicant 

verify whether the Steam Generator Tube Integrity Program is needed for the three steam 

generator secondary-side components listed above to be consistent with the GALL Report. The 

staff also requested that the applicant explain how LRA Table 3.1.1, item 3.1.1-74 is consistent 

with the GALL Report, since it credits only one program among the two recommended by the 

GALL Report.

In its response dated September 28, 2009, the applicant referred to LRA Section B2.1.30, 

where it states that the Steam Generator Tube Integrity Program encompasses secondary-side 

components whose failure could prevent the steam generator from fulfilling its intended safety 

function. The applicant also clarified that it includes the Ni-alloy cladding of the feedwater 

nozzle, the feedwater nozzle thermal sleeve, and the steam nozzle flow restrictor. As noted by 

the staff, the applicant explained that LRA Table 3.1.2-4 identifies the Secondary Water 

Chemistry Program as the AMP used to manage SCC for these Ni-alloy components in a 

treated water and/or steam-secondary environment. However, the applicant further stated that 

the Steam Generator Tube Integrity Program was incorrectly omitted from LRA Table 3.1.2-4 to 

manage SCC of these components, and LRA Table 3.1.1, item 3.1.1-74 should have specified 

both programs for managing aging. The applicant further concluded that the application of both 

programs for managing SCC for these Ni-alloy components in a treated water and/or 

steam-secondary environment is consistent with SRP-LR Table 3.1.1, item 74 and the GALL 

Report, Volume 2, item IV.D1-14.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-15 acceptable 

because the applicant amended its LRA to credit the Steam Generator Tube Integrity Program 

and its Secondary Water Chemistry Program, in order to manage the aging effect of cracking 

due to SCC, consistent with the GALL Report, Volume 1, ID 74 for steam generator 

secondary-side components. The staff‘s concern described in RAI B2.1.30-15 is resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.1.7 Cracking Due to Primary Water Stress-Corrosion Cracking (Steam Generator Divider 

Plate)

LRA Table 3.1.1, item 3.1.1-81 addresses cracking due to PWSCC for Ni alloy or Ni-alloy clad 

steam generator divider plates exposed to reactor coolant. The applicant stated in item 3.1.1-82 

that the steam generator divider plate is fabricated from Ni-alloy. The applicant credited its 

Primary Water Chemistry Program to manage the cracking due to PWSCC.

The staff noted that, from recent foreign OE in steam generators with a similar design to that of 

the applicant, extensive cracking due to PWSCC has been identified in steam generator divider 

plates, even with proper primary water chemistry. The staff noted that, specifically, cracks have 

been detected in the stub runner, very close to the tubesheet/stub runner weld and with depths 
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of almost a quarter of the divider plate thickness. Therefore, the staff noted that the Primary 

Water Chemistry Program alone may not be effective in managing the aging effect of cracking 

due to PWSCC in steam generator divider plates. 

The staff noted that although these steam generator divider plate cracks may not have a 

significant safety impact in themselves, such cracks could impact adjacent items, such as the 

tubesheet and the channel head, if they propagate to the boundary with these items. The staff 

further noted that for the tubesheet, PWSCC cracks in the divider plate could propagate to the 

tubesheet cladding with possible consequences to the integrity of the tube/tubesheet welds. 

Furthermore, for the channel head, the PWSCC cracks in the divider plate could propagate to 

the steam generator triple point and potentially affect the pressure boundary of the steam 

generator channel head.

By letter dated March 11, 2010, the staff issued RAI 3.1.2.2.13-1 requesting that the applicant 

discuss the materials of construction of the steam generator divider plate assembly; 

furthermore, if these materials are susceptible to cracking (e.g., Alloy 600 or the associated 

Alloy 600 weld materials), the staff requested that the applicant discuss the possibility that 

cracking in the divider plate might propagate into other components (e.g., tubesheet cladding). 

The staff further requested that if propagation into these other components cannot be ruled out, 

the applicant should describe an inspection program (examination technique and frequency) for 

ensuring that there are no cracks propagating into other items (e.g., tubesheet and/or channel 

head) that could challenge the integrity of these other items. The staff identified this as 

Open Item 3.1.2.1.7-1.

In its response dated July 22, 2010, the applicant described the materials of its steam generator

divider plate assembly, which are Alloy 600 for the stub runner and the divider plate, and 

Alloy 52/152 for the welds between the divider plate and the stub runner, as well as between the 

stub runner and the tubesheet. The applicant also offered additional explanation in order to 

justify why such cracks could not propagate to adjoining elements of the steam generator

divider plate assembly and, consequently, why no inspection would be required.

Based on its review of the applicant‘s response, the staff noted that the applicant‘s response 

provided essentially qualitative arguments for concluding that divider plate crack growth is not a 

concern. The staff considered that this response did not provide a reasonable and sufficient 

basis for justifying the applicant‘s conclusions. Further, the staff noted that the use of purely 

analytical tools to predict the behavior of service-induced cracking (in other components) has 

not always bounded actual service performance of those cracks. In addition, the staff noted that 

the likely presence of cracks in Alloy 600 steam generator divider plate assemblies may result in 

a condition where these cracks could propagate into surrounding pressure boundary areas, 

such as the tube-to-tubesheet welds and the channel head.

Therefore, by letter dated September 10, 2010, the staff issued follow-up RAI 3.1.2.2.13-1a,

requesting that the applicant provide an AMP, changes to an existing AMP, or a commitment to 

inspection(s) that would demonstrate the condition of the steam generator divider plate 

assemblies to support a conclusion that there will be no adverse consequences of divider plate 

assembly degradation during the period of extended operation.

In its response dated September 23, 2010, the applicant stated that the lower portions of its

steam generators, including the divider plate assembly and welds, have accumulated less than 

10 years of service time since having been replaced in 2001. The applicant further stated that

the cited foreign OE involved approximately 20 years of service time before PWSCC became
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detectable, and that this provides high confidence that detectable cracks do not currently exist in 

its steam generator divider plate assemblies. The applicant further explained that the industry 

plans to study the potential for divider plate crack growth and develop an industry-applied 

resolution to the concern through the EPRI Steam Generator Management Program (SGMP) 

Engineering and Regulatory Technical Advisory Group. The applicant stated that, recognizing 

that the EPRI SGMP resolution is still under development, it will commit to perform an 

inspection of each of the steam generators to assess the condition of the divider plate 

assembly. The applicant also stated that the examination technique(s) used will be capable of 

detecting PWSCC in the steam generator divider plate assembly and associated welds. 

Moreover, the applicant stated that steam generator divider plate inspections will be completed 

prior to exceeding 10 years into the period of extended operation (i.e., prior to 2023). In addition, 

the applicant stated that it also plans to remain involved with the ongoing industry studies 

related to divider plate cracking to ensure that any inspection requirements or other resolution

actions promulgated to the industry are evaluated and implemented, as appropriate. Finally, the 

applicant stated that Commitment No. 49, covering the above inspection of each steam 

generator to assess the condition of the divider plate assembly, will be added to LRA 

Appendix A, USAR Supplement, Table A6.0-1. 

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.2.13-1a and associated 

Commitment No. 49 acceptable because the applicant will assess the condition of the divider

plate assembly in each steam generator by inspection during the period of extended operation, 

in a time period consistent with the detection of potential PWSCC cracks, and with appropriate 

examination techniques. The staff also notes that the applicant will remain involved with ongoing 

industry efforts related to the divider plate cracking issue. The staff‘s concerns described in 

RAIs 3.1.2.2.13-1 and 3.1.2.2.13-1a are resolved. Open Item 3.1.2.1.7-1 is closed. The staff 

concludes that the applicant has demonstrated that the effects of aging for these components 

will be adequately managed so that their intended functions will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.1.8 Cracking Due to Primary Water Stress-Corrosion Cracking

LRA Table 3.1.1, item 3.1.1-65 addresses the cracking due to PWSCC of Ni-alloy reactor vessel 

upper head and CRD penetration nozzles, instrument tubes, head vent pipe (top head), and 

welds exposed to primary water. LRA Table 3.1.2-1 further addresses the AMR items 

corresponding to item 3.1.1-65 and indicates that the components of the AMR items are closure 

head CRDM head penetrations, closure head instrument tube and spare CRDM penetrations, 

and closure head vent and RVLIS head penetrations. 

The applicant indicated that the cracking due to PWSCC of these Ni-alloy components is 

managed by the ASME Section XI ISI, Subsections IWB, IWC, and IWD; Primary Water 

Chemistry; and Alloy 600 Inspections programs, where the GALL Report recommends GALL 

AMP XI.M1, ―ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD‖; GALL 

AMP XI.M2, ―Water Chemistry,‖ for primary water; and GALL AMP XI.M11A, ―Nickel-Alloy 

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water 

Reactors (PWRs Only).‖ LRA Table 3.1.1, item 3.1.1-65 also states that the AMR results are 

consistent with the GALL Report. 

The staff reviewed the AMR results in the LRA in comparison with the GALL Report, Volume 1, 

Table 1, ID 65 and GALL Report, Volume 2, items IV.A2-9 and IV.A2-18. In its review and 

comparison, the staff noted that the applicant claimed LRA note E, which means the AMR item 

is consistent with the GALL Report for component, material, environment, and aging effect, but 
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a different AMP is credited. The staff noted that the applicant credited the Alloy 600 Inspections 

Program instead of GALL AMP XI.M11A, ―Nickel-Alloy Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (PWRs Only).‖ The 

applicant further stated that the Alloy 600 Inspections Program is a plant-specific program that 

encompasses the recommendations of GALL AMP XI.M11A, ―Nickel-Alloy Penetration Nozzles 

Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (PWRs 

Only).‖

LRA Section B2.1.1 states that the Alloy 600 Inspections Program is a plant-specific program 

that manages the aging effects of PWSCC in Alloy 600 base metal and Alloy 82/182 dissimilar 

metal welds and Alloy 690 base metal and Alloy 52/152 dissimilar metal welds. The applicant 

further stated that the program performs visual/bare metal, liquid penetrant, eddy current, and 

ultrasonic examinations to detect cracking of the in-scope components. The staff‘s evaluation of 

the AMP is documented in SER Section 3.0.3.3.1. Based on its review, the staff finds the use of 

the proposed LRA AMPs acceptable because: (1) the applicant credited the Primary Water 

Chemistry Program and ASME Section XI ISI, Subsections IWB, IWC, and IWD Program 

consistent with the GALL Report; (2) the inspections of the Alloy 600 Inspections Program are 

performed in accordance with the requirements of industry guidance, ASME Code Section XI, 

and 10 CFR 50.55a so that the inspections can ensure the detection of the aging effect; (3) the 

acceptance criteria of the Alloy 600 Inspections Program are consistent with the industry 

guidance, ASME Code Section XI, and 10 CFR 50.55a such that the use of the acceptance 

criteria can ensure that the intended functions of the components are adequately maintained; 

and (4) the program elements of the Alloy 600 Inspections Program satisfy the criteria in 

SRP-LR Section A.1.2.3 for a plant-specific program such that the program is acceptable to 

manage the aging effect.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.9 Cracking Due to Stress-Corrosion Cracking and Primary Water Stress-Corrosion 

Cracking

LRA Table 3.1.1, item 3.1.1-69 addresses the cracking due to SCC and PWSCC of stainless 

steel or Ni-alloy safety injection nozzles, safe ends, and associated welds and buttering 

exposed to reactor coolant. LRA Table 3.1.2-1 further addresses the AMR item corresponding 

to item 3.1.1-69 and indicates that the component of the AMR item is the safety injection nozzle 

(cladding and buttering). The applicant indicated, using LRA note 2, that since the identified 

material for the component under the AMR item is Ni-based alloy, the applicable aging 

mechanism for this item is PWSCC and not SCC.

The applicant further indicated that the cracking due to PWSCC of the component is managed 

by the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program; Primary Water 

Chemistry Program; and Alloy 600 Inspections Program, where the GALL Report recommends 

GALL AMP XI.M1, ―ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,‖ 

and GALL AMP XI.M2, ―Water Chemistry,‖ for primary water. LRA Table 3.1.1, item 3.1.1-69 

also states that the AMR results are consistent with the GALL Report. 
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The staff reviewed the AMR results in the LRA in comparison with the GALL Report, Volume 1, 

Table 1, ID 69 and GALL Report, Volume 2, item IV.A2-15. In its review and comparison, the 

staff noted that the applicant claimed LRA note E, which means the AMR item is consistent with 

the GALL Report for component, material, environment, and aging effect, but a different AMP is 

credited. The staff noted that the applicant credited the Alloy 600 Inspections Program, in 

addition to the Primary Water Chemistry Program and ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program that are recommended by the GALL Report. The applicant further 

stated that the Alloy 600 Inspections Program is a plant-specific program that encompasses the 

recommendations of GALL AMP XI.M11A, ―Nickel-Alloy Penetration Nozzles Welded to the 

Upper Reactor Vessel Closure Heads of Pressurized Water Reactors (PWRs Only).‖

LRA Section B2.1.1 states that the Alloy 600 Inspections Program is a plant-specific program 

that manages the aging effects of PWSCC in Alloy 600 base metal and Alloy 82/182 dissimilar 

metal welds and Alloy 690 base metal and Alloy 52/152 dissimilar metal welds. The applicant 

further stated that the program performs visual/bare metal, liquid penetrant, eddy current, and 

ultrasonic examinations to detect cracking of the in-scope components. The staff‘s evaluation of 

the AMP is documented in SER Section 3.0.3.3.1. Based on its review, the staff finds the use of 

the proposed LRA AMPs acceptable because: (1) the applicant credited the Primary Water 

Chemistry Program and ASME Section XI ISI, Subsections IWB, IWC, and IWD Program 

consistent with the GALL Report; (2) the inspections of the Alloy 600 Inspections Program are 

performed in accordance with the requirements of industry guidance, ASME Code Section XI, 

and 10 CFR 50.55a so that the inspections can ensure the detection of the aging effect; (3) the 

acceptance criteria of the Alloy 600 Inspections Program are consistent with the industry 

guidance, ASME Code Section XI, and 10 CFR 50.55a such that the use of the acceptance 

criteria can ensure that the intended functions of the components are adequately maintained; 

and (4) the program elements of the Alloy 600 Inspections Program satisfy the criteria in 

SRP-LR Section A.1.2.3 for a plant-specific program such that the program is acceptable to 

manage the aging effect.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.1.2.1.10 Conclusion for AMRs Consistent with 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 OE and proposals for 

managing the associated 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 consistent 

with the GALL Report AMRs. Therefore, the staff concludes that the applicant has demonstrated 

that the aging effects for these components will be adequately managed so that their intended 

functions 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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3.1.2.2 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended

LRA Section 3.1.2.2 provides further evaluation of aging management as recommended by the 

GALL Report for the RCS components. The applicant provided information concerning how it 

will manage the following aging effects:

● 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 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

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the report recommends further evaluation, the 

staff audited and reviewed the applicant‘s evaluation. The staff determined whether the 

applicant adequately addressed the issues for which further evaluation is recommended. 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.

3.1.2.2.1 Cumulative Fatigue Damage

In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in 10 CFR 54.3, 

which must be evaluated in accordance with 10 CFR 54.21(c)(1). In LRA Table 3.1.1, the 

applicant identified AMR lines 3.1.1-1 and 3.1.1-5 through 3.1.1-10 as TLAA items for the RCS, 

reactor vessel, RVIs, and steam generator. The applicant performed cumulative fatigue 

evaluations for these components. SER Section 4.3 documents the staff‘s review of the 

applicant‘s evaluation of TLAA for these components.

The applicant stated that LRA Table 3.1.1, items 3.1.1-2, 3.1.1-3, and 3.1.1-4 are applicable to 

BWRs only. The staff reviewed these AMR items in the SRP-LR and in the GALL Report and 

found that these items are not applicable because KPS is a PWR design.

In its review, the staff noted that LRA Section 4.3 does not include TLAA for RVIs because the 

applicant stated that the vessel was designed to the 1968 Code Edition and there were no 

requirements for a fatigue analysis of vessel internals. Instead, the applicant stated it will 

manage aging for the RVI components with its ASME Section XI ISI, Subsections IWB, IWC, 
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and IWD Program. The staff reviewed the applicant‘s ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program and its evaluation is documented in SER Section 3.0.3.2.1. 

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 criteria in SRP-LR Section 3.1.2.2.2. LRA 

Section 3.1.2.2.2 addresses loss of material due to general, pitting, and crevice corrosion for 

certain portions (for PWRs) of the steam generators. 

Item 1. Table 3.1.1, item 3.1.1-12 is only applicable to Babcock & Wilcox Co. (B&W) OTSGs. 

Therefore, it is not applicable to KPS.

Item 2. Table 3.1.1, item 3.1.1-13 is applicable to BWRs only, as discussed in SER 

Section 3.1.2.1.1 above.

Item 3. Table 3.1.1, items 3.1.1-14 and 3.1.1-15 are applicable to BWRs only, as discussed in 

SER Section 3.1.2.1.1 above.

Item 4. LRA Section 3.1.2.2.2.4 addresses the loss of material due to general, pitting, and 

crevice corrosion in the upper and lower shell and transition cone made of steel and exposed to 

secondary feedwater and steam. The applicant stated that aging for the steam generator shell 

and transition cone is managed with a combination of the Secondary Water Chemistry Program 

and the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program for Class 2 

components. The applicant stated that, prior to the issuance of IN 90-04, ―Cracking of Upper 

Shell-To-Transition Cone Girth Welds in Steam Generators,‖ flaw indications were detected and 

reported in the girth weld between the upper shell and transition cone at KPS. The applicant 

stated that, based on experience at other plants, uncertainties in the test techniques at that 

time, and the potential for significant service induced cracking, augmented volumetric 

inspections to confirm that the indications were not surface connected cracks were required. 

The applicant stated that in 1992, based on a subsequent review of the related industry data, 

NDE methodology, augmented inspection results, and fracture analyses that showed no 

significant service growth, the staff agreed with the conclusion that the indications were 

embedded slag or voids, and approved a request to discontinue the augmented inspections. 

The applicant stated that in 2001, the original Westinghouse Model 51 steam generators were 

replaced with Westinghouse Model 54Fs, and this was partly accomplished by replacing the 

lower portion of the steam generator. Furthermore, a cut was made in the middle of the 

transition cone and the upper original girth weld was inspected from the inside during that time. 

The applicant stated that previously identified indications were evaluated and it was determined 

that there had been no service growth. Therefore, the applicant concluded that the augmented 

inspection recommended by Table 3.1.1, item 3.1.1-16 has been completed and no further 

action was required beyond the inspections required by the ASME Section XI ISI, Subsections 

IWB, IWC, or IWD Program.

The staff reviewed LRA Section 3.1.2.2.2.4 against the criteria of SRP-LR Section 3.1.2.2.2.4 

(SRP-LR Table 3.1.1, item 3.1.1-16), which states that, according to NRC IN 90-04, the existing 

program may not be sufficient to detect pitting and crevice corrosion, and that if general and 

pitting corrosion of the shell is known to exist, an augmented inspection is recommended to 

manage this aging effect. The GALL Report (AMR IV.D1-12) clarifies that this issue is limited to 

Westinghouse Model 44 and 51 steam generators, which the applicant replaced with 

Westinghouse Model 54Fs in 2001. Moreover, as stated by the applicant and approved by the 
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staff in 1992, the augmented inspections were no longer required for the original upper 

shell-to-transition cone girth weld that remains in the replacement steam generators.

Nevertheless, the staff noted that SRP-LR Section 3.1.2.2.2.4 states that loss of material due to 

general, pitting, and crevice corrosion could occur in the steel PWR steam generator upper and 

lower shell and transition cone exposed to secondary feedwater and steam. The SRP-LR further 

states that the existing program relies on control of 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. 

In its review of LRA Section 3.1.2.2.2.4, the staff found that the applicant did not provide any 

information or discussion of inspections of the new weld generated by the cut made in the 

middle of the transition cone at the time of steam generator replacement, specified as the 

―transition weld‖ in USAR Section 4.2.2.6 and license renewal drawing LRXK-100-10. The staff 

noted that the applicant did not discuss whether loss of material due to general, pitting, and 

crevice corrosion could occur in the transition weld. The staff noted that this weld could 

experience the same operating conditions as the upper shell-to-transition cone girth weld and, 

therefore, could be affected by the same aging effect (even if the shell geometry is less severe). 

The staff noted that from license renewal drawing LRXK-100-10, the new transition weld 

appears to be located in a ―gross structural discontinuity‖ because the transition cone is, by 

definition, a junction between shells of different diameters (as defined in ASME Code 

Section XI, Subsection NB-3213.2).

By letter dated November 20, 2009, the staff issued RAI 3.1.2.2.2.4-2 requesting that the 

applicant describe the inspections that will be performed on the transition weld during the period 

of extended operation.

In its response dated December 28, 2009, the applicant stated that the new weld, generated by 

the cut made in the transition cone at the time of steam generator replacement, received a 

radiography examination in accordance with the requirements of ASME Code Section III. The 

applicant explained that there were no unacceptable indications (i.e., no indications exceeded 

the acceptance criteria of ASME Code Section III).

The applicant further clarified that the new transition cone closure weld is not a gross structural 

discontinuity in accordance with the definition in ASME Code Section III, NB-3213.2 (ASME 

Code Section XI, Table IWC-2500-1 and Figure IWC-2500-1 provide applicable examples of 

gross structural discontinuities) and that the closure weld is located a sufficient distance from 

the structural discontinuity at the transition cone-to-upper shell junction such that the resulting 

stresses do not affect the weld area (i.e., the closure weld is not a high-stress region). The 

applicant determined that the new transition cone closure weld does not require volumetric 

examination in accordance with ASME Code Section XI ISI requirements and stated that the 

new transition cone closure weld receives a VT-2 visual examination as part of the system 

pressure test, in accordance with IWC 2500-1, Category C-H.

The applicant further explained that the concerns identified in NRC IN 90-04, ―Cracking of the 

Upper Shell-to-Transition Cone Girth Welds in Steam Generators,‖ which are further clarified in 

the GALL Report as being limited to Westinghouse Model 44 and 51 steam generators where a 

high-stress region exists at the shell-to-transition cone weld, are not applicable to the new 

transition cone closure weld based on: (1) the new transition cone closure weld is not located at 

a structural discontinuity since it is a plate-to-plate weld configuration with a 0.02-inch maximum 
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plate thickness difference, (2) the weld is located away from the locally stressed area 

associated with the original existing upper shell-to-transition cone weld, and (3) the weld is not a 

high-stress region. Therefore, the applicant concluded that, consistent with ASME Code 

Section XI requirements, and since the issues identified in IN 90-04 are not applicable, no 

inspections other than a system pressure test leakage examination are required for the new 

transition cone closure weld during the period of extended operation.

The staff reviewed the applicant‘s response to RAI 3.1.2.2.2.4-2. Since a gross structural 

discontinuity is intended to address discontinuity which affects the stress or strain distribution 

through the entire wall thickness of the pressure-retaining member, the staff noted that the 

applicant has demonstrated that its steam generator new transition cone closure weld should 

not be considered as a ―gross structural discontinuity‖ because: (1) the applicant has 

determined that this weld is not a high-stress region, and (2) the configuration of this weld does 

not correspond to a geometrical discontinuity (i.e., plate-to-plate weld with no significant plate 

thickness difference). 

However, the staff found the applicant‘s answer unacceptable because the staff noted that 

GALL AMR item 3.1.1-16 was included in the GALL Report to ensure that volumetric 

examinations performed, in accordance with the requirements of ASME Code Section XI 

IWC-2500-1, Examination Category C-A, Inspection Item C1.10, for upper shell- and lower 

shell-to transition cones with gross structural discontinuities would be capable of managing loss 

of material due to general, pitting, and crevice corrosion in the welds. The staff noted that the 

new continuous circumferential weld in the applicant‘s steam generator transition cone design 

should not be aligned to the intent of GALL AMR item 3.1.1-16 because the intent of this GALL 

Report item was to address problems in the steam generator transition cone welds containing 

geometric discontinuities, and the new steam generator transition cone weld does not meet this 

design description.

The staff also noted that the new transition area weld is a field weld as opposed to having been 

made in a controlled manufacturing facility, and the surface conditions of the transition weld may 

result in flow conditions more conducive to the initiation of general, pitting, and crevice corrosion 

than those of the upper and lower transition cone welds. 

The staff noted that SRP-LR Section A.1.2.3.4 states that a program based solely on detecting 

SC failure should not be considered an effective AMP for license renewal, as would be the case 

using detection of leakage as the aging management for the transition weld. Thus, the staff 

determined the crediting of the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program 

for the new steam generator transition cone weld to be an ineffective basis for managing loss of 

material in this weld because: (1) the ISI criteria would only perform a VT-2 visual leakage 

examination of the weld as part of the system leakage test performed pursuant to ASME Code 

Section XI, Table IWC 2500-1, Examination Category C-H requirements, and (2) this type of 

examination would allow leakage to occur before appropriate corrective actions would be 

initiated on the weld. In addition, the staff noted that ASME Code Section XI, IWA-5242 does 

not require licensees to remove insulation when performing visual examination on non-borated 

treated water systems. 

As a result, the staff found the applicant‘s response to RAI 3.1.2.2.2.4-2 did not completely 

resolve the request in the RAI. Therefore, the staff issued a follow-up RAI.

By letter dated March 11, 2010, the staff issued RAI 3.1.2.2.2.4-2a requesting that the applicant 

describe the surface condition and the resultant flow near the transition weld (e.g., weld crown, 
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ground flush, etc.) and how these parameters could affect the susceptibility of this weld to these 

aging mechanisms, relative to that of the upper and lower transition welds. The staff further 

requested that the applicant, based on this information, justify if any additional aging 

management of the transition weld is necessary and if additional aging management is 

necessary, describe an AMP for the steam generator transition weld (including examination 

frequency and technique) that will be effective in managing an aging effect, such as the loss of 

material due to general, pitting, and crevice corrosion, during the period of extended operation. 

In its response dated March 26, 2010, the applicant stated that although the transition cone 

closure was field welded, there were controls in place to ensure a high-quality weld. These 

controls included welder qualifications, welding in accordance with a qualified and approved 

welding procedure, pre- and post-weld heat treatment in accordance with engineering 

specifications, and NDEs of the weld. The applicant also clarified the configuration of the 

transition weld and stated that the ASME Code limits on projection from the surrounding surface 

(7/32 inch) and the contour necessary to support NDE resulted in a weld profile that is not 

expected to cause significant flow disturbance or other fluid conditions that may increase 

susceptibility to general, pitting, and crevice corrosion in the area of the weld. 

The applicant further described the conditions in which its new steam generator transition cone 

closure welds were fabricated during the steam generator replacement in order to avoid the 

cracking issue identified in IN 90-04 and in accordance with the EPRI-issued technical report 

TR-103498, ―Review of Steam Generator Girth Weld Cracking.‖ 

The applicant further stated that during normal operation and shutdown conditions, its 

secondary water chemistry controls (described in LRA Section B2.1.28, ―Secondary Water 

Chemistry‖) minimize exposure of this weld to oxidizing conditions such that significant general, 

pitting, and crevice corrosion is not expected. The applicant explained that as an indication of 

the effectiveness of secondary water chemistry controls, the results of a surface examination 

(magnetic particle test) of the original steam generator transition cone-to-upper shell girth welds, 

that was performed during steam generator replacement in 2001 (after 27 years of service), 

identified no reportable indications on the inside surface of the weld.

The applicant further referred to industry OE and explained that the generation of a new steam 

generator transition cone closure weld is not unique to its replacement steam generators, and 

has been employed for other steam generator replacement projects in the industry. Field welded 

transition cone closure welds (similar to the KPS welds) have been in service for up to 

approximately 30 years with no reported OE to indicate that the welds have an increased 

susceptibility to general, pitting, and crevice corrosion. The applicant stated that ASME B&PV 

Code Section XI requirements for weld examinations have not been changed to require 

additional or more rigorous inspection of these welds and there are no current industry issues 

that might require additional inspections of inside surface conditions in the vicinity of the 

transition cone closure welds.

The applicant further stated that the steam generator transition cone closure weld is included 

within the subcomponent shell-upper, lower, and transition cone identified in LRA Table 3.1.2-4, 

along with the other steam generator welds associated with the upper and lower shell and the 

transition cone, to be consistent with the recommendations of the GALL Report for the AMPs.

The applicant further stated that the inspections performed in accordance with the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program ensure the absence of aging effects 

by examining the most likely locations for degradation, such as the shell-to-tubesheet, transition 
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cone-to-shell, and shell-to-dome junctions, using volumetric examination. The applicant 

explained that any degradation identified during these inspections requires an engineering 

evaluation for disposition, and corrective actions would include evaluation of the extent of the 

condition, evaluation of necessary repairs, the need for expansion of inspection scope, and the 

need for enhancements to secondary water chemistry controls.

The applicant concluded that no additional aging management is necessary to provide 

reasonable assurance that the function of the steam generator transition cone closure weld will 

be maintained for the period of extended operation.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.2.2.4-2a acceptable 

because the applicant justified why the conditions of fabrication and operation of the new 

transition cone closure weld should prevent the aging effect of loss of material due to general, 

pitting, and crevice corrosion from occurring before the end of the period of extended operation, 

at which time the replacement steam generators would be 33 years old. This is also consistent 

with the current industry OE, including the applicant‘s own OE. Moreover, the staff noted that 

more susceptible welds (i.e., upper shell-cone shell and cone shell-lower shell welds) would 

continue to be inspected by a volumetric examination leading to corrective actions if degradation 

is identified. The staff‘s concerns described in RAIs 3.1.2.2.2.4-2 and 3.1.2.2.2.4-2a are 

resolved.

Based on the programs identified, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.1.2.2.2.4 criteria. For those line items that apply to LRA Section 3.1.2.2.2.4, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

Item 1: Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement (TLAA). The staff 

reviewed LRA Section 3.1.2.2.3.1 and Table 3.1.1, item 3.1.1-17 against the criteria in SRP-LR 

Section 3.1.2.2.3.1. LRA Section 3.1.2.2.3.1 addresses loss of fracture toughness due to certain 

aspects of neutron irradiation embrittlement as an aging effect that the applicant will manage 

through conducting TLAAs, consistent with the SRP-LR. The evaluation of these TLAAs is 

discussed in LRA Section 4.2. SRP-LR Section 3.1.2.2.3.1 states that, ―[c]ertain aspects of 

neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3. TLAAs are required to 

be evaluated in accordance with 10 CFR 54.21(c)(1). This TLAA is addressed separately in 

Section 4.2 of this SRP-LR.‖ 

As discussed in Section 4.2 of this SER, loss of fracture toughness due to neutron irradiation 

embrittlement is limited to RPV beltline and extended beltline materials having a neutron fluence 

greater than 1 x 1017 neutrons per square centimeter (n/cm2) (E > 1.0 million electron volts 

(MeV)) at the end of the period of extended operation. SER Section 4.2 accepted the applicant‘s 

evaluation of RPV neutron embrittlement in terms of USE, PTS, and P-T limits, which represent 

a complete set of analytical means for predicting and managing loss of fracture toughness due 

to neutron irradiation embrittlement. Therefore, the staff concludes that the applicant‘s program 

meets SRP-LR Section 3.1.2.2.3.1 criteria. The staff also confirmed that LRA Table 3.1.2-1 

identified all GALL AMR Table IV.A2 items under this aging mechanism (IV.A2-16 and 

IV.A2-23).
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Item 2: Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement (Surveillance).

The staff reviewed LRA Section 3.1.2.2.3.2 and Table 3.1.1, item 3.1.1-18 against the criteria in 

SRP-LR Section 3.1.2.2.3.2. LRA Section 3.1.2.2.3.2 addresses loss of fracture toughness due 

to neutron irradiation embrittlement as an aging effect that the applicant will manage, consistent 

with the SRP-LR, by the applicant‘s Reactor Vessel Surveillance Program. The materials 

outside of the RPV beltline region, which are expected to receive neutron fluence greater than 

1 x 1017 n/cm2(E > 1.0 MeV), were evaluated to be not limiting during the period of extended 

operation.

SRP-LR Section 3.1.2.2.3.2 states that:

[l]oss of fracture toughness due to neutron irradiation embrittlement could occur 

in BWR and PWR vessel beltline shell, nozzle, and welds exposed to reactor 

coolant and neutron flux. 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 Chapter XI, 

Section M31 of the GALL Report.

The staff noted that LRA Table 3.1.2-1 subcomponents, ―Primary Nozzles (and cladding)‖ and 

―Upper, Intermediate and Lower Shell (and cladding),‖ credit the Reactor Vessel Surveillance 

Program for managing loss of fracture toughness. They represent GALL AMR item IV.A2-17 for 

RPV nozzles and GALL AMR item IV.A2-24 for RPV shells, including beltline welds. However, 

―beltline welds,‖ which are mentioned in GALL AMR items IV.A2-17 and IV.A2-24 and SRP-LR 

Section 3.1.2.2.3.2, have not been specified explicitly as part of the LRA Table 3.1.2-1 

subcomponents discussed above. This requires clarification because regardless of the selected 

methodology (Charpy V-notch or Master Curve) for evaluating embrittlement and the planned 

capsule withdrawal date, a Reactor Vessel Surveillance Program is needed for managing the 

loss of fracture toughness aging effect on RPV materials, including welds. Hence, the staff 

issued RAI 3.1.2.2.3.2-1 by letter dated October 13, 2009.

RAI 3.1.2.2.3.2-1:

The staff noted that LRA Table 3.1.2-1 subcomponents, ―Primary Nozzles (and 

cladding)‖ and ―Upper, Intermediate and Lower Shell (and cladding),‖ credit the 

Reactor Vessel Surveillance Program for managing loss of fracture toughness 

aging effect on them. They represent GALL AMR item IV.A2-17 for [RPV] 

nozzles and GALL AMR Item IV.A2-24 for RPV shells, including beltline welds. 

―Beltline welds,‖ which are mentioned in GALL AMR items IV.A2-17 and IV.A2-24 

and SRP-LR Section 3.1.2.2.3.2, have not been specified explicitly as part of the 

LRA Table 3.1.2-1 subcomponents discussed above. Please resolve this 

discrepancy because regardless of the selected methodology (Charpy V-notch or 

Master Curve) for evaluation of material embrittlement, a Reactor Vessel 

Surveillance Program is needed for managing loss of fracture toughness aging 

effect on relevant RPV materials, including welds.

The applicant‘s response dated November 13, 2009, to RAI 3.1.2.2.3.2-1 clarified that the 

LRA Table 3.1.2-1 subcomponents ―Primary Nozzles (and cladding)‖ and ―Upper, Intermediate 

and Lower Shell (and cladding),‖ include the associated component welds. Thus, the staff 

concludes that the applicant‘s AMR evaluation of RPV primary nozzles and upper, intermediate, 
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and lower shell in LRA Table 3.1.2-1 is consistent with the recommendations for GALL AMR 

items IV.A2-17 and IV.A2-24. The staff accepted the applicant‘s Reactor Vessel Surveillance 

Program as indicated in SER Section 3.0.3.2.16. Furthermore, as a supplement to the Reactor 

Vessel Surveillance Program, the applicant has evaluated the materials outside the beltline 

region which are expected to receive fluence values greater than 1 x 1017 n/cm2(E > 1.0 MeV) 

and determined that none of these materials are limiting. Hence, the staff concludes that the 

applicant‘s program meets SRP-LR Section 3.1.2.2.3.2 criteria. The staff also confirmed that 

LRA Table 3.1.2-1 identified all GALL AMR Table IV.A2 items under this aging mechanism 

(IV.A2-17 and IV.A2-24).

Based on the TLAA and the program identified above, the staff concludes that the applicant‘s 

programs meet SRP-LR Section 3.1.2.2.3.1 and Section 3.1.2.2.3.2 criteria. For those AMR 

items that apply to LRA Section 3.1.2.2.3, the staff concludes 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 functions 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

Table 3.1.1, items 3.1.1-19 and 3.1.1-20 are not applicable to KPS, as they are applicable to 

BWRs only. See SER Section 3.1.2.1.1 above.

3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5 and Table 3.1.1, item 3.1.1-21 discuss reactor vessel underclad cracking. 

This is a TLAA and is discussed in SER Section 4.7.4, ―Reactor Vessel Underclad Cracking.‖ 

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 and Table 3.1.1, item 3.1.1-22 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 as an aging effect that the applicant will 

manage, consistent with the SRP-LR, by the ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program. This AMP is enhanced with Commitment No. 1 (LRA Table A6.0-1) to: 

―(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, submit an inspection plan for reactor internals 

to the NRC for review and approval to augment the current inspections.‖ Commitment No. 1 is 

also identified in the USAR supplement description of the program. 

SRP-LR Section 3.1.2.2.6 states that: 

[l]oss of fracture toughness due to neutron irradiation embrittlement and void 

swelling could occur in stainless steel and nickel alloy reactor vessel internals 

components exposed to reactor coolant and neutron flux. The GALL Report 

recommends no further aging management review if the applicant commits in the 

FSAR Supplement to (1) participate in the industry programs for investigating 

and managing aging effects on reactor internals; (2) evaluate and implement the 
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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, submit an inspection plan for reactor 

internals to the NRC for review and approval.

As described in LRA Sections 3.1.2.2.6, A.2.1.2, and B.2.1.2, the applicant made Commitment 

No. 1 to enhance its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, 

incorporating all three GALL Report requirements stated above to manage this aging 

mechanism. Therefore, the staff concludes that the applicant‘s program meets the SRP-LR 

Section 3.1.2.2.6 criteria because using the ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program with Commitment No. 1 to manage the aging effects due to neutron irradiation 

embrittlement and void swelling is consistent with the SRP-LR guidance. The staff also 

examined LRA Table 3.1.2-2 to find out whether the RPV internals subjected to these aging 

effects are consistent with those listed in GALL AMR Table IV.B2. The staff confirmed that LRA 

Table 3.1.2-2 identified all GALL AMR Table IV.B2 items under this aging mechanism (IV.B2-3, 

IV.B2-6, IV.B2-9, IV.B2-17, IV.B2-18, and IV.B2-22). However, unlike GALL AMR Table IV.B2, 

LRA Table 3.1.2-2 also identified nine additional components under item IV.B2-9. Hence, the 

staff issued RAI 3.1.2.2.6-1 by letter dated October 13, 2009.

RAI 3.1.2.2.6-1:

[LRA] Table 3.1.2-2 references [GALL AMR] item IV.B2-9 and lists loss of 

fracture toughness due to neutron irradiation embrittlement and void swelling (an 

aging mechanism discussed in LRA Section 3.1.2.2.6) as one of the aging 

mechanisms affecting the following [RPV] internals: head & vessel alignment 

pins, rod cluster control assembly (RCCA) guide tube bolts, RCCA guide tube 

support pins, upper core plate alignment pins, upper fuel alignment pins, upper 

support column bolts, upper support plate assembly, upper core plate, and 

hold-down spring. However, GALL Table IV.B2 (Item IV.B2-9 and other items 

relevant to these [RPV] internals) does not consider the above-mentioned aging 

mechanism applicable to these [RPV] internals. Please indicate if the listing of 

aging mechanisms (loss of fracture toughness due to neutron irradiation 

embrittlement and void swelling) for the above mentioned [RPV] internals was 

prompted by plant-specific experience or if this was due to a conservative 

approach.

The staff reviewed the applicant‘s response, dated November 13, 2009, to RAI 3.1.2.2.6-1. The 

applicant stated that the identification of loss of fracture toughness due to neutron irradiation 

embrittlement and void swelling for the subject RPV internals was due to a conservative 

approach, and there is no plant-specific OE that indicates these aging mechanisms are actually 

occurring for these components. Therefore, the staff‘s concern described in RAI 3.1.2.2.6-1 is 

resolved. Based on this and the staff‘s evaluation presented earlier, the staff concludes that the 

applicant‘s program meets the SRP-LR Section 3.1.2.2.6 criteria. For those AMR items that 

apply to LRA Section 3.1.2.2.6, the staff concludes that the LRA exceeds the GALL Report 

recommendations by including nine additional components under GALL AMR item IV.B2-9 and 

that the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions 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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3.1.2.2.7 Cracking Due to Stress-Corrosion Cracking

Item 1. The staff reviewed LRA Section 3.1.2.2.7.1 and Table 3.1.1, item 3.1.1-23 against the 

criteria in SRP-LR Section 3.1.2.2.7.1. LRA Section 3.1.2.2.7.1 addresses cracking due to SCC 

in the stainless steel RPV flange leak detection lines and the BMI guide tubes. It further states 

that the RPV flange leak detection line SCC is managed by the Primary Water Chemistry 

Program and the WCP Program, and the BMI guide tube SCC is managed by the Primary 

Water Chemistry Program and the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program.

SRP-LR Section 3.1.2.2.7.1 states that, ―[c]racking due to SCC could occur in the PWR 

stainless steel reactor vessel flange leak detection lines and [BMI] 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.‖

LRA Table 3.1.2-1 credits the Primary Water Chemistry Program and the WCP Program for 

managing cracking due to SCC for vessel flange leak detection lines that are fabricated from 

stainless steel and exposed to borated water. The vessel flange leak detection lines serve no 

safety-related function and, therefore, need management only so leakage has no adverse 

impact on other components inside containment. Based on evaluation and acceptance of the 

Primary Water Chemistry Program documented in SER Section 3.0.3.1.9, the staff considers 

this AMP adequate to mitigate SCC in vessel flange leak detection lines. However, although the 

staff accepted the applicant‘s WCP Program as indicated in SER Section 3.0.3.2.19, it is not 

clear that the WCP Program, using the One-Time Inspection Program, is sufficient to ensure no 

leakage in vessel flange leak detection lines during the period of extended operation. Hence, 

the staff issued RAI 3.1.2.2.7-1 by letter dated December 3, 2009.

RAI 3.1.2.2.7-1:

In LRA Table 3.1.2-1, the applicant proposes to manage cracking/SCC in the 

stainless steel vessel flange leakage monitor lines exposed to primary reactor 

coolant water through the use of its AMPs, ―Primary Water Chemistry‖ and ―Work 

Control Process (WCP)‖ (LRA B2.1.24 and B2.1.32). The vessel flange leak 

monitor lines require management so leakage from them, if it occurred, has no 

adverse impact on other components inside containment. SRP-LR 

Section 3.1.2.2.7 requires that a plant-specific AMP be evaluated to ensure this 

aging effect is adequately managed, since existing programs may not be capable 

of mitigating or detecting crack initiation and growth due to SCC in the vessel 

flange leak monitor line.

LRA Section 3.1.2.2.7.1 utilizes the Primary Water Chemistry and the WCP 

AMPs. Hence, leakage occurring after a one-time inspection will not be 

discovered and its impact on other components will not be assessed. Provide 

additional justification to demonstrate that the applicant's WCP AMP is effective 

on an ongoing basis in detecting cracks in the vessel flange leakage monitor 

lines exposed to treated primary coolant water. The justification should include a 

summary of industry experience with flawed vessel flange leak detection lines to 

demonstrate that failure of these lines is unlikely to occur.
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The staff reviewed the applicant‘s response to RAI 3.1.2.2.7-1, dated January 21, 2010. The 

applicant stated that industry OE indicated two instances of cracking due to transgranular SCC 

in these lines, caused by high concentrations of chlorides coupled with stagnant water at high 

temperatures. KPS procedures require draining the lines prior to plant heatup, and so far, the 

RPV flange leakage monitor lines have not experienced SCC. Therefore, the staff agrees with 

the applicant‘s conclusion that the One-Time Inspection Program, within the WCP Program, 

provides an inspection that either verifies that unacceptable degradation is not occurring or 

results in additional actions that assure the intended function of affected components will be 

maintained during the period of extended operation. Hence, RAI 3.1.2.2.7-1 is resolved, and the 

staff considers that using the Primary Water Chemistry Program and the WCP Program through 

the One-Time Inspection Program for managing cracking due to SCC for vessel flange leak 

detection lines is acceptable. 

LRA Table 3.1.2-1 credits the Primary Water Chemistry Program and the ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program for managing cracking due to SCC for BMI guide 

tubes and seal table that are fabricated from stainless steel and exposed to borated water. On 

the basis of the staff‘s review and acceptance of these two AMPs, documented in SER 

Sections 3.0.3.1.9 and 3.0.3.2.1, the staff finds that the applicant‘s use of the Primary Water 

Chemistry Program and the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program is 

adequate to mitigate and manage cracking due to SCC in stainless steel BMI guide tubes. The 

staff also confirmed that the applicant‘s evaluation is consistent with GALL AMR items IV.A2-5 

and IV.A2-1. The Ni-alloy BMI penetrations are reviewed separately under SER 

Section 3.1.2.2.13.

Item 2. LRA Section 3.1.2.2.7.2 states that cracking due to SCC of CASS RCS components is 

managed by a combination of the Primary Water Chemistry Program together with the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program. The applicant also stated that its 

Primary Water Chemistry Program monitors and controls primary water chemistry in accordance 

with the guidelines in EPRI 1002884 (formerly TR-105714) to minimize the potential for SCC, 

and the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program has been shown to be 

effective in managing aging effects in Class 1, 2, and 3 components and their integral 

attachments in light-water cooled power plants.

The staff reviewed LRA Section 3.1.2.2.7.2 and Table 3.1.1, item 3.1.1-24 against the criteria in 

SRP-LR Section 3.1.2.2.7.2 and GALL Report, item IV.C2-3, which recommend control of water 

chemistry to mitigate SCC. Furthermore, for CASS components that do not meet the 

NUREG-0313 guidelines with regard to a minimum of 7.5 percent ferrite and maximum of 

0.035 percent carbon content, a plant-specific program is to 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. LRA Section 3.1.2.2.7.2 states 

that the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program has been shown to be 

effective in managing aging effects in Class 1, 2, and 3 components. The reactor coolant loop 

piping flaw tolerance evaluation to account for susceptibility of the CASS piping materials to 

thermal aging embrittlement is discussed in LRA Section 4.7.5. 

The staff reviewed the applicant‘s ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program and Primary Water Chemistry Program and its evaluations are documented in SER 

Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. The staff‘s evaluation of the applicant‘s flaw 

tolerance analysis is documented in SER Section 4.7.5.2. The applicant stated that the flaw 

evaluation analysis is based on the methods described in the ASME B&PV Code Section XI, 

Subsection IWB-3640. In addition, an environmental factor of 2 is applied to the crack growth 
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reference curves for austenitic stainless steel in air to account for the effect of a PWR 

environment on growth rates. The applicant further stated that because the delta ferrite content 

of the CASS materials does not exceed 25 percent, flaw evaluation is performed in accordance 

with the principles associated with IWB-3640 procedures for SAW, discarding the ASME Code 

restriction of 20 percent delta ferrite content in IWB-3641(b)(1). The staff finds this to be an 

acceptable approach consistent with the GALL Report. 

Based on its review of the programs to manage cracking due to SCC in CASS Class 1 piping, 

piping components, and piping elements exposed to reactor coolant greater than 140 °F, the 

staff finds that all program elements are consistent with the GALL Report and are, therefore, 

acceptable.

Conclusion. 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 items that apply to LRA 

Section 3.1.2.2.7, the staff concludes 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 functions 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

Table 3.1.1, items 3.1.1-25 and 3.1.1-26 are applicable to BWRs only, as discussed in SER 

Section 3.1.2.1.1 above.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

The staff reviewed LRA Section 3.1.2.2.9 and Table 3.1.1, item 3.1.1-27 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 that could occur in stainless steel and Ni-alloy PWR RVIs screws, bolts, and hold

down springs exposed to reactor coolant as an aging effect that the applicant will manage, 

consistent with the SRP-LR, by the ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program. This AMP is enhanced with Commitment No. 1, which is also identified in the USAR 

supplement description of the program.

SRP-LR Section 3.1.2.2.9 states that:

[l]oss of preload due to stress relaxation could occur in stainless steel and nickel 

alloy PWR reactor vessel internals screws, bolts, tie rods, and holddown springs 

exposed to reactor coolant. The GALL Report recommends no further [AMR] if 

the applicant provides a commitment in the FSAR Supplement to (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, 

submit an inspection plan for reactor internals to the NRC for review and 

approval.

As described in LRA Sections 3.1.2.2.9, A.2.1.2, and B.2.1.2, the applicant made Commitment 

No. 1 to enhance its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to 

incorporate all three GALL Report requirements stated above regarding managing aging effects 

on reactor internals. Therefore, the staff concludes that the applicant‘s program meets the 
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SRP-LR Section 3.1.2.2.9 criteria because using the ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program with Commitment No. 1 to manage the aging effects of loss of preload 

due to stress relaxation is consistent with the SRP-LR guidance. The staff also confirmed that 

LRA Table 3.1.2-2 identified all GALL AMR Table IV.B2 items under this aging mechanism 

(IV.B2-5, IV.B2-14, IV.B2-25, IV.B2-33, and IV.B2-38). The staff concludes 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 functions 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

LRA Section 3.1.2.2.10 states that this item is not applicable as the installed steam generators 

do not have feedwater impingement plates and associated supports.

The staff reviewed the documentation supporting the applicant‘s AMR evaluation and its USAR 

supplement and confirmed that the installed steam generators do not contain steel steam 

generator feedwater impingement plates as specified in SRP-LR Section 3.1.2.2.10. Therefore, 

the staff finds that Table 3.1.1, item 3.1.1-28 and SRP-LR Section 3.1.2.2.10 are not applicable 

to KPS.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

Table 3.1.1, item 3.1.1-29 is applicable to BWRs only, as discussed in SER Section 3.1.2.1.1 

above.

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 and Table 3.1.1, item 3.1.1-30 against the criteria in 

SRP-LR Section 3.1.2.2.12. LRA Section 3.1.2.2.12 addresses cracking due to SCC and IASCC 

that may occur in stainless steel PWR RVIs exposed to reactor coolant as an aging effect that 

the applicant will manage, consistent with the SRP-LR, by the Primary Water Chemistry 

Program and the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. The ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program is enhanced with Commitment No. 1, 

which is also identified in the USAR supplement description of the ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program.

SRP-LR Section 3.1.2.2.12 states that: 

[c]racking due to SCC and IASCC could occur in PWR stainless steel reactor 

internals exposed to reactor coolant. The existing program relies on control of 

water chemistry to mitigate these effects. The GALL Report recommends no 

further [AMR] if the applicant provides a commitment in the FSAR Supplement to 

(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, submit an inspection plan for reactor internals to the NRC for review 

and approval.
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As indicated in SER Section 3.0.3.1.9, the staff accepts the Primary Water Chemistry Program 

for mitigating the aging effects due to SCC and IASCC, meeting one of the requirements 

mentioned in SRP-LR Section 3.1.2.2.12. Furthermore, the applicant made Commitment No. 1 

in LRA Sections 3.1.2.2.12, A.2.1.2, and B.2.1.2 to enhance its ASME Section XI ISI, 

Subsections IWB, IWC, and IWD Program to incorporate all three GALL Report requirements 

stated above regarding managing aging effects on reactor internals. Therefore, the staff 

concludes that the applicant‘s program meets the SRP-LR Section 3.1.2.2.12 criteria because, 

in addition to the Water Chemistry Program, using the ASME Section XI ISI, Subsections IWB, 

IWC, and IWD Program with Commitment No. 1 to manage the aging effects due to SCC and 

IASCC is consistent with the SRP-LR guidance. The staff also confirmed that LRA Table 3.1.2-2 

identified all GALL AMR Table IV.B2 items under this aging mechanism (IV.B2-2, IV.B2-8, 

IV.B2-10, IV.B2-12, IV.B2-24, IV.B2-30, IV.B2-36, and IV.B2-42). The staff concludes 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 functions 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 and Table 3.1.1, item 3.1.1-31 against the criteria in 

SRP-LR Section 3.1.2.2.13. (Note: the specific case of cracking due to PWSCC for the Ni-alloy 

steam generator divider plates is reviewed in SER Section 3.1.2.1.7.) The applicant stated that 

cracking due to PWSCC could occur in PWR components made with Ni alloy and steel with 

Ni-alloy cladding exposed to reactor coolant. Cracking due to SCC (including PWSCC) of Ni 

alloy and low-alloy steel with Ni-alloy cladding, including RCPB components and penetrations 

inside the RCS, such as nozzle safe ends, core support guides, and bottom head instrument 

tube penetrations, is managed by a combination of the Primary Water Chemistry Program; 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program; and Alloy 600 Inspections 

Program. 

Based on its review of the programs identified above, the staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). As each of these programs was reviewed in detail within this 

safety evaluation, no further discussion under this section is deemed necessary.

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

LRA Section 3.1.2.2.14 states that in 2001, the original Westinghouse Model 51 steam 

generators were replaced with Westinghouse Model 54Fs. The applicant stated that this was 

accomplished by replacing the lower portion of the steam generator and refurbishing the upper 

steam generator internals. The applicant further stated that the Model 54F steam generator 

incorporated a number of design improvements in response to OE with recirculating-type steam 

generators, and as part of the upper internals refurbishment, the total redesign and replacement 

of the feedwater inlet ring and supports. The applicant stated that design improvements 

included the use of flow-accelerated corrosion-resistant materials, support system based on a 

detailed feedwater ring stress analysis, and top discharge through Alloy 690 J tubes.

The applicant stated that IN 91-19, ―Steam Generator Feedwater Distribution Piping Damage,‖ 

describes the root cause as inadequate design of the feedring and feedring support system 

resulting from inadequate consideration of the potential for erosion and corrosion 
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(i.e., flow-accelerated corrosion) and lack of a detailed stress analysis. Furthermore, these items 

have been addressed in the redesigned feedwater inlet ring and supports in the installed steam 

generators. Therefore, the applicant has determined that based on the design and construction 

of the feedwater inlet ring and supports, wall thinning due to flow-accelerated corrosion is not 

expected to occur and this item is not applicable.

The staff reviewed LRA Section 3.1.2.2.14 and Table 3.1.1, item 3.1.1-32 against the criteria of 

SRP-LR Section 3.1.2.2.14, which states that wall thinning due to flow-accelerated corrosion 

could occur in steel feedwater 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 LRA Sections 3.1.2.2.14, 2.3.1.4, and B2.1.30 and IN 91-19. The staff noted 

that the IN documented OE of degradation in feedwater inlet ring and supports, and 

recommends modification and redesign of feedwater inlet ring and supports. The staff noted that 

the applicant identified causal factors described in IN 91-19. In LRA Sections B2.1.30 and 

2.3.1.4, the applicant provided a description of some modifications in the upper steam 

generator. However, the staff noted that additional information is required to clarify why the 

aging effect of wall thinning due to flow-accelerated corrosion is not expected to occur. By letter 

dated August 28, 2009, the staff issued RAI 3.1.2.2.14-1 requesting that the applicant provide 

additional information regarding the new design and construction of the steam generator

feedwater inlet ring and supports, and explain why the wall thinning due to flow-accelerated 

corrosion is not expected to occur.

In its response dated September 28, 2009, the applicant explained that the new design and 

construction of the feedwater inlet ring for each of the steam generators used Ni-based alloys 

and chrome-moly alloys (A335 Grade P11 and A234 Grade WP11), which are not susceptible to 

flow-accelerated corrosion. The applicant also clarified that, regarding the supports, the 

feedwater distribution system was analyzed as acceptable for thermal and seismic conditions, 

as documented in WCAP-15324, Volume 1, ―Model 54F Replacement Steam Generator, 

Feedwater Nozzle and Thermal Sleeve Analysis,‖ and Volume 2, ―Model 54F Replacement 

Steam Generator, Modified Upper Assembly Stress Report, Feedring Seismic and Steam Line 

Break Analysis.‖ The applicant concluded that, based on the above, aging management for the 

loss of material due to flow-accelerated corrosion for the refurbished steam generator feedwater 

inlet rings and supports is not required.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.2.14-1 acceptable 

because according to the additional elements about the design improvements (materials and 

stress analysis) for steam generator feedwater inlet ring and supports, these components are 

not susceptible to flow-accelerated corrosion. The staff‘s concern described in RAI 3.1.2.2.14-1 

is resolved.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.14 criteria. The staff finds that the applicant‘s determination that this aging effect 

does not apply to KPS is acceptable, and that the applicant has demonstrated that aging 

management is not necessary to ensure that these components will be adequately managed so 

that their intended functions 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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3.1.2.2.15 Changes in Dimensions Due to Void Swelling

The staff reviewed LRA Section 3.1.2.2.15 and Table 3.1.1, item 3.1.1-33 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 that could occur in stainless steel and Ni-alloy PWR RVI components exposed to 

reactor coolant as an aging effect that the applicant will manage, consistent with the SRP-LR, 

by the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. This AMP is enhanced 

with Commitment No. 1, which is also identified in the USAR supplement description of the

program.

SRP-LR Section 3.1.2.2.15 states that: 

[c]hanges in dimensions due to void swelling could occur in stainless steel and 

nickel alloy PWR reactor internal components exposed to reactor coolant. The 

GALL Report recommends no further [AMR] if the applicant provides a 

commitment in the FSAR Supplement to (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, submit an inspection 

plan for reactor internals to the NRC for review and approval.

As described in LRA Sections 3.1.2.2.15, A.2.1.2, and B.2.1.2, the applicant made Commitment 

No. 1 to enhance its ASME Section XI ISI, Subsections IWB, IWC, and IWD Program to 

incorporate all three GALL Report requirements stated above regarding managing aging effects 

on RVIs. Therefore, the staff concludes that the applicant‘s program meets the SRP-LR 

Section 3.1.2.2.15 criteria because using the ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program with Commitment No. 1 to manage the aging effects due to SCC and IASCC is 

consistent with the SRP-LR guidance. The staff also confirmed that LRA Table 3.1.2-2 identified 

all GALL AMR Table IV.B2 items under this aging mechanism (IV.B2-1, IV.B2-4, IV.B2-7, 

IV.B2-11, IV.B2-15, IV.B2-19, IV.B2-23, IV.B2-27, IV.B2-29, IV.B2-35, IV.B2-39, and IV.B2-41).

The staff concludes 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 

functions 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 3.1.2.2.16.

Item 1. The staff reviewed LRA Section 3.1.2.2.16.1 against the criteria in SRP-LR 

Section 3.1.2.2.16. LRA Table 3.1.1, item 3.1.1-34 describes the cracking due to SCC and 

PWSCC of austenitic stainless steel reactor vessel components that were exposed to reactor 

coolant. The AMR items corresponding to item 3.1.1-34 include the CRDM pressure housing 

and the stainless steel portion of the closure head instrument tubes and spare CRDM 

penetrations, bottom head instrument tube penetrations, and closure head CRDM penetrations 

(Table 3.1.2-1). The applicant stated that cracking due to SCC of these components is managed 

by the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program and Primary Water 

Chemistry Program. The applicant further stated that the programs are consistent with the GALL 

Report. 
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The staff reviewed LRA item 3.1.1-34 in comparison with the GALL Report, Volume 1, Table 1, 

ID 34. In its review, the staff noted that for these components or portion of the components 

constructed of austenitic stainless steel, the GALL Report recommends a combination of ASME 

Section XI ISI and control of primary water chemistry to manage the effect of cracking due to 

SCC. The staff‘s reviews of the applicant‘s ASME Section XI ISI, Subsections IWB, IWC, and 

IWD Program and the Primary Water Chemistry Program are discussed in SER 

Sections 3.0.3.2.1 and 3.0.3.1.9, respectively. In its review, the staff found that the applicant‘s 

programs are consistent with the GALL Report and are, therefore, acceptable. 

On the basis of its review, the staff determines that the applicant‘s proposed program is 

acceptable for managing the cracking due to SCC in austenitic stainless steel reactor vessel 

components corresponding to item 3.1.1-34. The staff concludes that the applicant has 

demonstrated that the effects of aging for these components will be adequately managed so 

that the intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). 

Steam generator components associated with LRA Section 3.1.2.2.16.1. The components 

covered in GALL Report Table 3.1.1, item 3.1.1-35 are applicable to B&W model OTSGs. KPS 

has Westinghouse recirculating steam generators, so this item is not applicable to KPS, except 

for the case discussed in the following paragraphs.

SRP-LR Section 3.1.2.2.16.1 identifies that cracking due to PWSCC could occur on the primary 

coolant side of PWR steel steam generator tube-to-tubesheet welds made or clad with Ni-alloy. 

The GALL Report recommends controls of the ASME Code Section XI ISI, Subsections IWB, 

IWC, and IWD and Water Chemistry programs to manage this aging, and recommends no 

further AMR for PWSCC of Ni-alloy if the applicant complies with applicable NRC orders and 

provides a commitment in its USAR supplement to implement applicable NRC bulletins, GLs, 

and staff-accepted industry guidelines. GALL Report Revision 1, Volume 2 addresses this aging 

in item IV.D2-4, stating the item is applicable to OTSGs, but not to recirculating steam 

generators.

USAR Section 4.2.2.6 states that the applicant‘s steam generator tubes are fabricated from 

Alloy 690TT (Thermally Treated), that the side of the tubesheet in contact with the reactor 

coolant is clad with Inconel (Alloy 600 in USAR Table 4.2-1), and that the tube-to-tubesheet 

joints are welded.

The staff noted that the ASME Code Section XI does not require inspection of the 

tube-to-tubesheet welds. In addition, no specific NRC orders or bulletins address inspection 

requirements for these welds. The staff‘s concern is that, if the tubesheet cladding is Alloy 600, 

autogenous tube-to-tubesheet welds may not have sufficient chromium content to prevent 

initiation of PWSCC, even when the steam generator tubes are made from Alloy 690TT, which 

is the configuration of the applicant‘s steam generator tubes. Consequently, such a PWSCC 

crack initiated in this region, close to a tube, could propagate into or through the weld, causing a 

failure of the weld and of the RCPB, even for recirculating steam generators such as those of 

the applicant. Therefore, because the NRC has not approved a redefinition of the pressure 

boundary for these steam generators in which the autogenous tube-to-tubesheet weld is no 

longer included, the staff considers that the effectiveness of the primary water chemistry 

program should be verified to ensure PWSCC cracking is not occurring.
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In a conference call on October 13, 2010, between the staff and the applicant, the staff 

questioned how cracking in the applicant‘s steam generator tube-to-tubesheet welds will be 

managed if that material is susceptible to PWSCC. The applicant agreed to provide information 

on its management of this issue.

In its response dated October 20, 2010, the applicant stated that it will commit to developing a 

plan to address potential failure of the steam generator primary-to-secondary pressure 

boundary due to PWSCC cracking of tube-to-tubesheet welds. The applicant further stated that 

the plan will consist of two resolution options:

● In the first option, the applicant stated that it would perform an analytical evaluation of 

the steam generator tube-to-tubesheet welds in order to establish a technical basis for 

concluding that the structural integrity of the steam generator tube-to-tubesheet interface 

is adequately maintained even with the presence of tube-to-tubesheet weld cracking, 

and that the steam generator tube-to-tubesheet weld is not required for the RCPB. 

● In the second option, the applicant stated that it would perform a one-time inspection of 

a representative number of tube-to-tubesheet welds in each steam generator to 

determine if PWSCC cracking is present. The applicant also stated that if weld cracking 

is identified, the condition will be resolved through repair or engineering evaluation for 

continued service, as appropriate, and that an ongoing monitoring program will be 

established to perform routine inspections of tube-to-tubesheet welds for the remaining 

life of the steam generators. 

Moreover, the applicant stated that it will develop its plan prior to the period of extended 

operation. As described in its response to RAI 3.1.2.2.13-1a dated September 23, 2010, the 

applicant explained that the lower portions of its steam generators, including the tubes and 

tubesheets, have accumulated less than 10 years of service time since having been replaced in 

2001. Considering this limited service time of the replaced portions of the steam generators, the 

applicant further stated that the implementation of its plan, including weld inspections for the 

presence of PWSCC cracking if necessary, will be completed prior to 50 years of plant 

operation (i.e., prior to 2023). Finally, the applicant stated that Commitment No. 53, covering the 

above plan to manage the aging effect due to PWSCC of steam generator tube-to-tubesheet 

welds, will be added to LRA Appendix A, USAR Table A6.0-1.

Based on its review, the staff finds the applicant ̳s plan and associated Commitment No. 53 

acceptable because the applicant stated that it will manage the aging effect of cracking due to 

PWSCC in the steam generator tube-to-tubesheet welds either by demonstrating that those 

welds do not have a structural integrity or pressure boundary function, or by implementing a 

one-time inspection capable of detecting PWSCC cracking on a representative number of 

tube-to-tubesheet welds of each steam generator, in a time period consistent with the detection 

of potential PWSCC cracks and the period of extended operation. The staff finds that the timing 

of this inspection prior to 50 years of plant operation is acceptable because at that time, the 

replaced lower portion of the steam generator will have been in operation for less than 22 years, 

and it is unlikely that significant PWSCC cracking will have initiated. The staff also notes that, in 

case the aging effect is revealed, this one-time inspection program is accompanied by an 

appropriate corrective action process, including an evaluation of the degradation and the 

implementation of routine inspections for the remaining life of the steam generators. The staff 

concludes that the applicant has demonstrated that the effects of aging for these components 
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will be adequately managed so that their intended functions will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 2. The components covered by Table 3.1.1, item 3.1.1-36 are not applicable to KPS. See 

SER Section 3.1.2.1.1.

3.1.2.2.17 Cracking Due to Stress-Corrosion Cracking, Primary Water Stress-Corrosion 

Cracking, and Irradiated-Assisted Stress-Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.17 and Table 3.1.1, item 3.1.1-37 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 that could occur in stainless steel and Ni-alloy PWR reactor internal components 

exposed to reactor coolant as an aging effect that the applicant will manage, consistent with the 

SRP-LR, with the Primary Water Chemistry Program and the ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program. The ASME Section XI ISI, Subsections IWB, IWC, and IWD 

Program is enhanced with Commitment No. 1, which is also identified in the USAR supplement 

description of the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program. 

SRP-LR Section 3.1.2.2.17 states that: 

[c]racking due to [SCC, PWSCC, and IASCC] could occur in PWR stainless steel 

and nickel alloy reactor vessel internals components. The existing program relies 

on control of water chemistry to mitigate these effects. However, the existing 

program should be augmented to manage these aging effects for reactor vessel 

internals components. The GALL Report recommends no further AMR if the 

applicant provides a commitment in the USAR Supplement to (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, 

submit an inspection plan for reactor internals to the NRC for review and 

approval.

As indicated in SER Section 3.0.3.1.9, the staff accepts the Primary Water Chemistry Control 

Program for mitigating the aging effects due to SCC, PWSCC, and IASCC, meeting one of the 

requirements mentioned in SRP-LR Section 3.1.2.2.17. Furthermore, the applicant made 

Commitment No. 1 in LRA Sections 3.1.2.2.17, A.2.1.2, and B.2.1.2 to enhance its ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program to incorporate all three GALL Report 

requirements stated above regarding managing aging effects on reactor internals. Therefore, 

the staff concludes that the applicant‘s program meets the SRP-LR Section 3.1.2.2.17 criteria 

because, in addition to the required Water Chemistry Control Program, using the ASME 

Section XI ISI, Subsections IWB, IWC, and IWD Program with Commitment No. 1 to manage 

the aging effects due to SCC, PWSCC, and IASCC is consistent with the SRP-LR guidance. 

The staff also confirmed that LRA Table 3.1.2-2 identified all GALL AMR Table IV.B2 items 

under this aging mechanism (IV.B2-16, IV.B2-20, IV.B2-28, and IV.B2-40). The staff concludes 

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 functions 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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3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff‘s evaluation of the applicant‘s QA program.

3.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.1.2-1 through 3.1.2-4, the staff reviewed additional details of 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 3.1.2-4, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. The applicant provided further information concerning how the aging 

effects will be managed. Specifically, note F indicates that the material for the AMR item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR item component and material is not evaluated in the GALL Report. Note H indicates that 

the aging effect for the AMR 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 item component, material, and environment combination is not applicable. Note J 

indicates that neither the component nor the material and environment combination for the 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 had 

demonstrated that the aging effects will be adequately managed so that the intended functions 

will be maintained consistent with the CLB during the period of extended operation. The staff‘s 

evaluation is discussed in the following sections.

3.1.2.3.1 Reactor Vessel, Reactor Coolant System, and Steam Generators – Steel 

Components Exposed to Air-Indoor Uncontrolled Environment

In LRA Tables 3.1.2-1, 3.1.2-3, and 3.1.2-4, the applicant stated that the exterior surfaces of 

steel components exposed to air-indoor uncontrolled have no aging effect. The applicant also 

stated that no AMP is required. The AMR items cite generic note H indicating that the 

component, material, and environment combination is not addressed in the GALL Report.

The staff reviewed all AMR result items in the GALL Report where the material is steel and the 

environment is air-indoor uncontrolled and noted that loss of material is the recommended aging 

effect. The staff also noted that the air-indoor uncontrolled environment is defined in the GALL 

Report as an environment where condensation can occur, but only rarely. The staff further 

noted that, contrary to LRA note 4, the components under consideration may routinely have 

temperatures above 212 °F, during operation, and be exposed to much lower temperatures 

approaching ambient (i.e., during outages). By letter dated December 16, 2009, the staff issued 

RAI 3.1.2.3-1 requesting that the applicant select an AMP appropriate for the management of 

steel components exposed to uncontrolled indoor air, as recommended by the GALL Report. 

In its response dated January 21, 2010, the applicant stated that during an 18-month power 

operation cycle, the temperatures of the external surfaces of the reactor vessel, pressurizer, and 

steam generator are greater than the dew point of the surrounding air. The applicant also stated 

that refueling outages are of short duration, that significant condensation is not expected 

because the component external surfaces are insulated, and that any condensation on the 
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component surface is eliminated when the surface temperature increases upon plant startup. 

The applicant further stated that the loss of material aging affect was determined not to be 

applicable and an AMP is not required. The staff finds the applicant‘s response acceptable 

because there would typically be insufficient time for any corrosion to occur from condensation 

that would cause the component‘s design function not to be met. The staff‘s concern described

in RAI 3.1.2.3-1 is resolved.

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. The staff finds that the 

applicant has demonstrated that aging management is not necessary to ensure that these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.3.2 Copper Alloy Piping Greater than 15 Percent Zinc, Piping Components, Piping 

Elements, and Heat Exchanger Components Exposed to Closed-Cycle Cooling Water

LRA Table 3.1.1, item 3.1.1-56 addresses copper alloy (with greater than 15 percent Zn) piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water. The GALL Report recommends the use of GALL AMP XI.M33, ―Selective 

Leaching of Materials,‖ to manage loss of material due to selective leaching for this component 

group. The applicant stated that this item is not applicable because there are no RCS 

components fabricated from copper alloy greater than 15 percent Zn and exposed to 

closed-cycle cooling water. The staff reviewed LRA Sections 2.3.1 and 3.1 and confirmed that 

the applicant‘s LRA does not have any AMR results for the RCS that include copper alloy piping 

with greater than 15 percent Zn, piping components, piping elements, and heat exchanger 

components exposed to closed-cycle cooling water. Based on its review of the LRA, the staff 

confirmed that there are no in-scope copper alloy piping with greater than 15 percent Zn, piping 

components, piping elements, and heat exchanger components exposed to closed-cycle cooling 

water in the RCS and, therefore, finds the applicant‘s determination acceptable.

3.1.2.3.3 Steel Components Subject to Loss of Material Due to General, Pitting, and Crevice 

Corrosion Exposed to Treated Water-Primary

In LRA Table 3.1.2-3, the applicant stated that the steel pressurizer relief tank exposed to 

treated water-primary is being managed for loss of material due general, pitting, and crevice 

corrosion by the Primary Water Chemistry and the WCP programs. The AMR line items cite 

generic note H, indicating that for the line items, the aging effect is not in the GALL Report for 

this component, material, and environment combination.

The staff reviewed the applicant‘s Primary Water Chemistry Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff 

determined that the Primary Water Chemistry Program includes periodic monitoring and control 

of contaminants, such as chloride, fluoride, dissolved oxygen, and sulfate concentrations below 

specified levels that may result in loss of material, and that the program also maintains water 

quality (pH and conductivity). The staff further determined that the applicant‘s program specifies 

sampling and analysis frequencies and corrective actions if specified limits are exceeded. The 

staff determined that the applicant‘s WCP Program will manage the aging effect of loss of 

material through program inspections that provide verification of the effectiveness of the Primary 

Water Chemistry Program where: (a) an aging effect is not expected to occur but the data is 

insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to progress 
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very slowly in the specified environment, but the local environment may be more adverse than 

generally expected; or (c) the characteristics of the aging effect include a long incubation period. 

The staff further determined that these inspections will be performed by using NDE techniques 

that are effective and capable of identifying this potential aging effect, and that the sample size 

and location will be based on an assessment of materials, environments, plausible aging 

effects, and OE.

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.4 Copper Alloy Components Subject to Loss of Material Due to Pitting and Crevice 

Corrosion Exposed to Lubricating Oil

In LRA Table 3.1.2-3, the applicant stated that the copper alloy RCP motor lower bearing oil 

coolers and RCP motor upper bearing oil coolers (tubes) exposed to lubricating oil (external) are 

being managed for loss of material due to pitting and crevice corrosion by the Lubricating Oil 

Analysis Program and WCP Program. The AMR line items cite generic note H, indicating that 

for the line items, the aging effect is not in the GALL Report for this component, material, and 

environment combination. The staff reviewed all AMR result line items in the GALL Report 

where the component and material is copper alloy piping, piping components, and piping 

elements exposed to lubricating oil (external) and confirmed that there are aging effect entries in 

the GALL Report for this component, material, and environment combination. 

The staff noted that GALL AMR items VII.C1-8, VII.C2-5, VII.E1-12, VII.E4-6, VII.G-11, and 

VII.H2-10 state that loss of material due to pitting and crevice corrosion is an AERM for copper 

alloy exposed to lubricating oil. 

The staff finds the applicant has appropriately identified this aging effect for copper alloy 

components exposed to lubricating oil. The staff reviewed the applicant‘s Lubricating Oil 

Analysis Program and WCP Program and its evaluations are documented in SER 

Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff determined that the Lubricating Oil 

Analysis Program includes periodic sampling and analysis of lubricating oil to determine if 

contaminants, such as particulates, metals, and water are present. The staff noted that the 

presence of these impurities in the lubricating oil can create an environment that is conducive to 

age-related degradation, such as loss of material and reduction of heat transfer. The staff 

determined that the activities performed as part of this program will be capable of preserving an 

environment that will not promote loss of material and reduction of heat transfer. The staff finds 

that these activities are consistent with the recommendations in the GALL Report and are 

adequate to manage loss of material in copper alloy components exposed to lubricating oil. The 

staff determined the applicant‘s WCP Program will provide verification of the effectiveness of the 

Lubricating Oil Analysis Program where: (a) an aging effect is not expected to occur but the data 

is insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to 

progress very slowly in the specified environment, but the local environment may be more 

adverse than generally expected; or (c) the characteristics of the aging effect include a long 

incubation period. The staff further determined that these inspections will be performed by using 

NDE techniques that are effective and capable of identification of these potential aging effects 

and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE.
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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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.5 Copper Alloy Components Subject to Loss of Material Due to 

Microbiologically-Influenced Corrosion Exposed to Treated Water-Closed-Cycle Cooling

In LRA Table 3.1.2-3, the applicant stated that the copper alloy RCP motor lower bearing oil 

coolers and RCP motor upper bearing oil coolers (tubes) exposed to treated water-closed-cycle 

cooling (internal) are being managed for loss of material due to MIC by the Closed-Cycle 

Cooling Water System Program and WCP Program. The AMR line items cite generic note H, 

indicating that for the line items, the aging effect is not in the GALL Report for this component, 

material, and environment combination. The staff reviewed all AMR result line items in the GALL 

Report where the component and material is copper alloy piping, piping components, and piping 

elements exposed to treated water-closed-cycle cooling (internal) and confirmed that there are 

aging effect entries in the GALL Report for this component, material, and environment 

combination. 

The staff noted that the applicant has identified loss of material due to pitting, crevice, and 

galvanic corrosion as an AERM, which is consistent with GALL AMR items V.A-5, V.D1-2, 

V.D2-3, V.A-20, V.B-6, V.D1-17, and V.D2-21. The staff found the applicant has conservatively 

identified the additional aging mechanism of MIC to be managed by its Closed-Cycle Cooling 

Water System Program and WCP Program. 

The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff determined that the performance of these systems are monitored to 

verify the effectiveness of the chemistry controls, which include system operation monitoring, 

system testing, heat exchanger thermal performance testing, heat exchanger tube eddy current 

testing, and pump performance testing. The staff determined the applicant‘s WCP Program will 

manage the aging effects of cracking, loss of material, and reduction of heat transfer through 

program inspections that provide verification of the effectiveness of the Closed-Cycle Cooling 

Water System Program where: (a) an aging effect is not expected to occur but the data is 

insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to progress 

very slowly in the specified environment, but the local environment may be more adverse than 

generally expected; or (c) the characteristics of the aging effect include a long incubation period. 

The staff further determined that these inspections will be performed by using NDE techniques 

that are effective and capable for identification of these potential aging effects and that the 

sample size and location will be based on an assessment of materials, environments, plausible 

aging effects, and OE.

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 functions 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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3.1.2.3.6 Nickel-Alloy Components Exposed to Borated Water Leakage

In LRA Table 3.1.2-1, the applicant stated that the Ni-alloy bottom head instrument tube 

penetrations, closure head CRDM head penetrations, closure head instrument tube and spare 

CRDM penetrations, closure head vent and RVLIS head penetrations, and safety injection 

nozzle exposed to borated water leakage (external) are not subject to an AERM. In LRA 

Table 3.1.2-3, the applicant stated that the Ni-alloy rupture discs exposed to borated water 

leakage (external) are not subject to an AERM. In LRA Table 3.1.2-4, the applicant stated that 

the Ni-alloy channel head and primary nozzle safe ends/buttering exposed to borated water 

leakage (external) are not subject to an AERM. The AMR line items cite generic note H, 

indicating that for the line items, the aging effect is not in the GALL Report for this component, 

material, and environment combination.

The staff noted that austenitic materials, such as Ni alloys, are not subject to loss of material or 

cracking when subjected to this environment and these materials are used as 

corrosion-resistant replacement materials where other materials have degraded. The staff noted 

that according to EPRI NP-5769, ―Degradation and Failure of Bolting in Nuclear Power Plants, 

Volumes 1 and 2, April 1988,‖ corrosion resistant materials, such as austenitic and martensitic 

stainless steels, and high-strength Ni base alloys offer good protection against boric acid 

corrosion. Therefore, the staff finds no AMP is necessary for Ni alloys in a borated water 

leakage (external) environment. The staff confirmed that the applicant is managing the aging 

effect of cracking of these Ni-alloy components as described above when exposed to a treated 

water-primary environment, consistent with the recommendations in the GALL Report.

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.7 Stainless Steel Components Subject to Loss of Material Due to Pitting, Crevice, and 

Microbiologically-Influenced Corrosion Exposed to Treated Water-Closed-Cycle Cooling

In LRA Table 3.1.2-3, the applicant stated that the stainless RCP thermal barriers (flange and 

heat exchanger) exposed to treated water-closed-cycle cooling (internal) are being managed for 

loss of material due to pitting, crevice, and microbiologically-influenced corrosion by the 

Closed-Cycle Cooling Water System Program and WCP Program. The AMR line items cite 

generic note H, indicating that for the line items, the aging effect is not in the GALL Report for 

this component, material, and environment combination. The staff reviewed all AMR result line 

items in the GALL Report where the component and material is stainless steel piping, piping 

components, and piping elements exposed to treated water-closed-cycle cooling (internal) and 

confirmed that there are aging effect entries in the GALL Report for this component, material, 

and environment combination. 

The staff noted that the applicant has identified loss of material due to pitting and crevice 

corrosion as an AERM, which is consistent with GALL AMR items V.A-7, V.D1-4, V.D2-5, 

V.A-23, V.C-7, V.D1-22, and V.D2-25. The staff found the applicant has conservatively identified 

the additional aging mechanism of MIC to be managed by its Closed-Cycle Cooling Water 

System Program and WCP Program. 
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The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff determined that the performance of these systems are monitored to 

verify the effectiveness of the chemistry controls, which include system operation monitoring, 

system testing, heat exchanger thermal performance testing, heat exchanger tube eddy current 

testing, and pump performance testing. The staff determined that the applicant‘s WCP Program 

will manage the aging effects of cracking, loss of material, and reduction of heat transfer 

through program inspections that provide verification of the effectiveness of the Closed-Cycle 

Cooling Water System Program where: (a) an aging effect is not expected to occur but the data 

is insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to 

progress very slowly in the specified environment, but the local environment may be more 

adverse than generally expected; or (c) the characteristics of the aging effect include a long 

incubation period. The staff further determined that these inspections will be performed by using 

NDE techniques that are effective and capable for identification of these potential aging effects 

and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE.

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.8 Steel Components Subject to Loss of Material Due to Microbiologically-Influenced 

Corrosion Exposed to Treated Water-Closed-Cycle Cooling

In LRA Table 3.1.2-3, the applicant stated that the steel pipe (less than 4 inches NPS), RCP 

motor upper bearing oil coolers (channel head and tubesheet) exposed to treated 

water-closed-cycle cooling (internal) are being managed for loss of material due to MIC by the 

Closed-Cycle Cooling Water System Program and WCP Program. The AMR line items cite 

generic note H, indicating that for the line items, the aging effect is not in the GALL Report for 

this component, material, and environment combination. The staff reviewed all AMR result line 

items in the GALL Report where the component and material is steel piping, piping components, 

and piping elements exposed to treated water-closed-cycle cooling (internal) and confirmed that 

there are aging effect entries in the GALL Report for this component, material, and environment 

combination. 

The staff noted that the applicant has identified loss of material due to general, pitting, and 

crevice corrosion as an AERM, which is consistent with GALL AMR item V.C-9. The staff finds 

the applicant has conservatively identified the additional aging mechanism of MIC to be 

managed by its Closed-Cycle Cooling Water System Program and WCP Program. 

The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff determined that the performance of these systems are monitored to 
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verify the effectiveness of the chemistry controls, which include system operation monitoring, 

system testing, heat exchanger thermal performance testing, heat exchanger tube eddy current 

testing, and pump performance testing. The staff determined that the applicant‘s WCP Program 

will manage the aging effects of cracking, loss of material, and reduction of heat transfer 

through program inspections that provide verification of the effectiveness of the Closed-Cycle 

Cooling Water System Program where: (a) an aging effect is not expected to occur but the data 

is insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to 

progress very slowly in the specified environment, but the local environment may be more 

adverse than generally expected; or (c) the characteristics of the aging effect include a long 

incubation period. The staff further determined that these inspections will be performed by using 

NDE techniques that are effective and capable for identification of these potential aging effects 

and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE.

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 functions 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, RVIs, RCS, and steam generator components, within 

the scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended functions 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 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 (ESF) components and component groups of the following:

● containment vessel internal spray system

● safety 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 containment vessel internal spray system, the 

safety injection system, and the RHR system. LRA Table 3.2.1, ―Summary of Aging 

Management Programs for Engineered Safety Features Evaluated in Chapter V of 

NUREG-1801,‖ is a summary comparison of the applicant‘s AMRs with those evaluated in the 

GALL Report for the containment vessel internal spray, safety injection, and RHR components 

and component groups.

The applicant‘s AMRs evaluated and incorporated applicable plant-specific and industry OE in 

the determination of AERMs. The plant-specific evaluation included issue reports and 

discussions with appropriate site personnel to identify AERMs. The applicant‘s review of 

industry OE included a review of the GALL Report and OE issues identified since the issuance 

of the GALL Report.

3.2.2 Staff Evaluation

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.

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the containment vessel internal spray 

system, safety injection system, and RHR system components within the scope of license 

renewal and subject to an AMR, will be adequately managed so that the intended functions 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 two onsite audits of AMPs to confirm the applicant‘s claim that certain 

AMPs were consistent with the GALL Report. The purpose of these audits was to examine the 

applicant‘s AMPs and related documentation and to verify the applicant‘s claim of consistency 

with the corresponding GALL Report AMPs. The staff did not repeat its review of the matters 

described in the GALL Report. The staff‘s evaluation of the AMPs is documented in SER 

Section 3.0.3.

The staff reviewed the AMRs to confirm the applicant‘s claim that certain identified 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 had identified the appropriate GALL Report AMRs. Details of 

the staff‘s evaluation are discussed in SER Sections 3.2.2.1 and 3.2.2.2.
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The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The 

review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff‘s evaluation are discussed in SER Section 3.2.2.3.

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant‘s OE 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 System Components in the 

GALL Report

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

the ECCS

(3.2.1-1)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance 

with 

10 CFR 54.21(c)

Yes, TLAA TLAA Fatigue is a TLAA

(See SER 

Section 3.2.2.2.1)

Steel with stainless 

steel cladding pump 

casing exposed to 

treated borated 

water

(3.2.1-2)

Loss of material 

due to cladding 

breach

A plant-specific 

AMP is to be 

evaluated. 

Reference NRC 

IN 94-63, ―Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused 

by Cladding 

Cracks‖

Yes, verify that 

plant-specific 

program 

addresses 

cladding 

breach.

Not 

applicable to 

KPS

Consistent with the 

GALL Report. 

A VT-1 visual 

examination of 1 

safety injection

pump performed 

prior to the period 

of extended 

operation. 

(See SER 

Sections 3.2.2.1.2 

and 3.2.2.2.2)

Stainless steel 

containment 

isolation piping and 

components internal 

surfaces exposed to 

treated water

(3.2.1-3)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Primary 

Water 

Chemistry 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.3.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.2.1-4)

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes, 

plant-specific

Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.3)

Stainless steel and 

aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.2.1-5)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

BWR Only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.2.1-6)

Loss of material 

due to pitting and 

crevice corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Lubricating 

Oil Analysis 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.3.4)

Partially encased 

stainless steel tanks 

with breached 

moisture barrier 

exposed to raw 

water

(3.2.1-7)

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific 

AMP is to be 

evaluated for 

pitting and 

crevice corrosion 

of tank bottoms 

because 

moisture and 

water can egress 

under the tank 

due to cracking 

of the perimeter 

seal from 

weathering.

Yes, 

plant-specific

Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.4)

Stainless steel 

piping, piping 

components, piping 

elements, and tank 

internal surfaces 

exposed to 

condensation 

(internal)

(3.2.1-8)

Loss of material 

due to pitting and 

crevice corrosion

A plant-specific 

AMP is to be 

evaluated

Yes, 

plant-specific

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.3.6)

Steel, stainless

steel, and copper 

alloy heat exchanger 

tubes exposed to 

lubricating oil

(3.2.1-9)

Reduction of 

heat transfer due 

to fouling

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Lubricating 

Oil Analysis 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.4)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water

(3.2.1-10)

Reduction of 

heat transfer due 

to fouling

Water Chemistry 

and One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Primary 

Water 

Chemistry 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.4)

Elastomer seals and 

components in 

standby gas 

treatment system 

exposed to 

air-indoor 

uncontrolled

(3.2.1-11)

Hardening and 

loss of strength 

due to elastomer 

degradation

A plant-specific 

AMP is to be 

evaluated

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

high-pressure safety 

injection (HPSI)

(charging) pump 

miniflow orifice 

exposed to treated 

borated water

(3.2.1-12)

Loss of material 

due to erosion

A plant-specific 

AMP is to be 

evaluated for 

erosion of the 

orifice due to 

extended use of 

the centrifugal 

HPSI pump for 

normal charging.

Yes, 

plant-specific

Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.5)

Steel drywell and 

suppression 

chamber spray 

system nozzle and 

flow orifice internal 

surfaces exposed to 

air-indoor 

uncontrolled 

(internal)

(3.2.1-13)

Loss of material 

due to general 

corrosion and 

fouling

A plant-specific 

AMP is to be 

evaluated.

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.2.1-14)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

Steel containment 

isolation piping, 

piping components, 

and piping elements 

internal surfaces 

exposed to treated 

water

(3.2.1-15)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Primary 

Water 

Chemistry 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.8.2)

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.2.1-16)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes, detection 

of aging effects 

is to be 

evaluated.

Lubricating 

Oil Analysis 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.8.3)

Steel (with or without 

coating or wrapping) 

piping, piping 

components, and 

piping elements 

buried in soil

(3.2.1-17)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Buried Piping 

and Tanks 

Surveillance or 

Buried Piping 

and Tanks 

Inspection

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60 °C 

(140 °F)

(3.2.1-18)

Cracking due to 

SCC and IGSCC

BWR 

Stress-Corrosion 

Cracking and 

Water Chemistry

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.2.1-19)

Wall thinning due 

to 

flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated or 

unborated) > 250 °C 

(482 °F)

(3.2.1-20)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.2.1-21)

Cracking due to 

cyclic loading 

and SCC

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage

(3.2.1-22)

Loss of material 

due to general 

corrosion

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel bolting and 

closure bolting 

exposed to 

air-outdoor 

(external), or 

air-indoor 

uncontrolled 

(external)

(3.2.1-23)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel closure bolting 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.2.1-24)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water > 60 °C 

(140 °F)

(3.2.1-25)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling 

Water System 

Program and 

WCP 

Program

Consistent with the 

GALL Report
Aging Management Review Results

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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water

(3.2.1-26)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling 

Water System 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.1.1)

Steel heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-27)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling 

Water System 

Program and 

WCP 

Program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-28)

Loss of material 

due to pitting and 

crevice corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling 

Water System 

Program and 

WCP 

Program

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

piping elements, and 

heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-29)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Not 

applicable

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.6)

Stainless steel and 

copper alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.2.1-30)

Reduction of 

heat transfer due 

to fouling

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling 

Water System 

Program and 

WCP 

Program

Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

External surfaces of 

steel components 

including ducting, 

piping, ducting 

closure bolting, and 

containment 

isolation piping 

external surfaces 

exposed to 

air-indoor 

uncontrolled 

(external); 

condensation 

(external) and 

air-outdoor 

(external)

(3.2.1-31)

Loss of material 

due to general 

corrosion

External 

Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Steel piping and 

ducting components 

and internal surfaces 

exposed to 

air-indoor 

uncontrolled 

(internal)

(3.2.1-32)

Loss of material 

due to general 

corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No Not 

applicable

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.7)

Steel encapsulation 

components 

exposed to 

air-indoor 

uncontrolled 

(internal)

(3.2.1-33)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.3.2)

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal)

(3.2.1-34)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

BWR only Not applicable to 

PWRs

(See SER 

Section 3.2.2.1.1)

Steel containment 

isolation piping and 

components internal 

surfaces exposed to 

raw water

(3.2.1-35)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Not 

applicable for 

KPS ESF 

systems

Not applicable for 

KPS ESF systems

(See SER 

Section 3.2.2.1.1)

Steel heat 

exchanger 

components 

exposed to raw 

water

(3.2.1-36)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Not 

applicable

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.8)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.2.1-37)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Open-Cycle 

Cooling Water 

System

No Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.9)

Stainless steel 

containment 

isolation piping and 

components internal 

surfaces exposed to 

raw water

(3.2.1-38)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Not 

applicable for 

KPS ESF 

systems

Not applicable for 

KPS ESF systems

(See SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger 

components 

exposed to raw 

water

(3.2.1-39)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.1.17)

Steel and stainless 

steel heat exchanger 

tubes (serviced by 

open-cycle cooling 

water) exposed to 

raw water

(3.2.1-40)

Reduction of 

heat transfer due 

to fouling

Open-Cycle 

Cooling Water 

System

No Not 

applicable

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.10)

Copper alloy 

> 15% Zn piping, 

piping components, 

piping elements, and 

heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.2.1-41)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.11)

Gray cast iron 

piping, piping 

components, piping 

elements exposed to 

closed-cycle cooling 

water

(3.2.1-42)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Selective 

Leaching of 

Materials 

Program

Consistent with the 

GALL Report

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.2.1-43)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.12)

Gray cast iron motor 

cooler exposed to 

treated water

(3.2.1-44)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.13)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum, copper 

alloy > 15% Zn, and 

steel external 

surfaces, bolting, 

and piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage

(3.2.1-45)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program

Consistent with the 

GALL Report

Steel encapsulation 

components 

exposed to air with 

borated water 

leakage (internal)

(3.2.1-46)

Loss of material 

due to general, 

pitting, crevice, 

and boric acid 

corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.3.2)

CASS piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

> 250 °C (482 °F)

(3.2.1-47)

Loss of fracture 

toughness due to 

thermal aging 

embrittlement

Thermal Aging 

Embrittlement of 

CASS

No ASME 

Section XI 

ISI, 

Subsections 

IWB, IWC, 

and IWD 

Program

Consistent with 

GALL Report

(See SER 

Section 3.2.2.1.14)

Stainless steel or 

stainless steel clad 

steel piping, piping 

components, piping 

elements, and tanks 

(including safety 

injection 

tanks/accumulators) 

exposed to treated 

borated water 

> 60 °C (140 °F)

(3.2.1-48)

Cracking due to 

SCC

Water Chemistry No Primary 

Water 

Chemistry 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.1.15)

Stainless steel

piping, piping 

components, piping 

elements, and tanks 

exposed to treated 

borated water

(3.2.1-49)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry No Primary 

Water 

Chemistry 

Program and 

WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.1.18)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

air-indoor 

uncontrolled 

(internal/external)

(3.2.1-50)

None None Not applicable None Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Galvanized steel 

ducting exposed to 

air-indoor controlled 

(external)

(3.2.1-51)

None None Not applicable Not 

applicable

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.16)

Glass piping 

elements exposed to 

air-indoor 

uncontrolled 

(external), 

lubricating oil, raw 

water, treated water, 

or treated borated 

water

(3.2.1-52)

None None Not applicable None Consistent with the 

GALL Report

Stainless steel, 

copper alloy, and 

Ni-alloy piping, 

piping components, 

and piping elements 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.2.1-53)

None None Not applicable None Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

air-indoor controlled 

(external)

(3.2.1-54)

None None Not applicable Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.1)

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.2.1-55)

None None Not applicable None Consistent with the 

GALL Report

Steel, stainless 

steel, and copper 

alloy piping, piping 

components, and 

piping elements 

exposed to gas

(3.2.1-56)

None None Not applicable None Consistent with the 

GALL Report

Stainless steel and 

copper alloy 

< 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.2.1-57)

None None Not applicable Not 

applicable to 

KPS

Not applicable to 

KPS

(See SER 

Section 3.2.2.1.1)
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The staff‘s review of the ESF component groups followed several approaches. One approach, 

documented in SER Section 3.2.2.1, discusses the staff‘s review of AMR results for components 

the applicant indicated are consistent with the GALL Report and require no further evaluation. 

Another approach, documented in SER Section 3.2.2.2, discusses the staff‘s review of AMR 

results for components the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.2.2.3, discusses the staff‘s review of AMR results for components 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 ESF components is documented in 

SER Section 3.0.3.

3.2.2.1 AMR Results That Are 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 ESF systems and components:

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

● Bolting Integrity Program

● Boric Acid Corrosion Program

● Closed-Cycle Cooling Water System Program

● External Surfaces Monitoring Program

● Lubricating Oil Analysis Program

● Open-Cycle Cooling Water System Program

● Primary Water Chemistry Program

● Selective Leaching of Materials Program

● Work Control Process Program

LRA Tables 3.2.2-1 through 3.2.2-3 summarize the results of AMRs for components of the 

containment vessel internal spray system, the safety injection system, and the RHR system and 

indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant has claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item describing how the information in the 

tables aligns with the information in the GALL Report. The staff reviewed those AMRs with 

notes A through E, which indicate how the AMR was 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 Report 

AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 

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 AMP 

identified in the GALL Report. The staff reviewed these line items to verify consistency with the 

GALL Report and confirmed that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 
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consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line item of the different component applied 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 AMP identified in the GALL Report. The staff reviewed these line items 

to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of 

the different component was applicable to the component under review and whether the 

exceptions to the GALL Report AMPs had been reviewed and accepted by the staff. The staff 

also determined whether the AMP identified by the applicant was consistent with the AMP 

identified in the GALL Report 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 a different AMP is credited. The staff reviewed these line 

items to verify consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report 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, it did verify that the material presented in 

the LRA was applicable and that the applicant had identified the appropriate GALL Report 

AMRs. The staff‘s evaluation is discussed below.

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 

containment vessel internal spray, safety injection, and RHR systems‘ 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 3.2.1, the applicant‘s references to the GALL Report are 

acceptable and no further staff review is required.

3.2.2.1.1 AMR Results Identified as Not Applicable

LRA Table 3.2.1, items 5, 11, 13, 14, 17-20, and 34 discuss the applicant‘s determination on 

GALL Report AMR items that are applicable only to BWR-designed reactors. In the applicant 

AMR discussions for these items, no additional information is provided. The staff confirmed that 

these AMR items in Table 1 of the GALL Report, Volume 1 are only applicable to 

BWR-designed reactors, and that KPS is a PWR with a dry ambient containment. Based on this 

determination, the staff finds that the applicant has provided an acceptable basis for concluding
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that AMR items 5, 11, 13, 14, 17-20, and 34 in Table 1 of the GALL Report, Volume 1 are not 

applicable to KPS.

LRA Table 3.2.1, item 3.2.1-26 addresses steel piping, piping components, and piping elements 

exposed to closed-cycle cooling water. The GALL Report recommends the use of GALL 

AMP XI.M21, ―Closed-Cycle Cooling Water System,‖ to manage loss of material due to general, 

pitting, and crevice corrosion for this component group. The applicant stated that steel 

containment isolation piping, piping components, and piping elements exposed to closed-cycle 

cooling water are evaluated for aging management in their respective mechanical systems. The 

staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed that the applicant‘s LRA does not 

have any AMR results for the ESF systems that include steel piping, piping components, and 

piping elements exposed to closed-cycle cooling water. The staff also reviewed the AMR results 

for the mechanical systems, into which the components that are intended to be evaluated using

this GALL Report item were placed, and confirmed that the components are evaluated for aging 

management in accordance with GALL AMP XI.M21. The staff noted that a search of the 

applicant‘s USAR did not find any evidence of steel piping, piping components, and piping 

elements in the ESF systems exposed to closed-cycle cooling water that are not included in the 

evaluations performed in the applicable mechanical systems. Based on its review of the LRA 

and USAR, the staff confirmed that there is no in-scope steel piping, piping components, and 

piping elements exposed to closed-cycle cooling water in the ESF systems and, therefore, finds 

the applicant‘s determination acceptable.

LRA Table 3.2.1, item 3.2.1-35 addresses steel containment isolation piping and components 

exposed to raw water. The GALL Report recommends the use of GALL AMP XI.M20, 

―Open-Cycle Cooling Water System,‖ to manage loss of material due to general, pitting, crevice, 

and microbiologically-influenced corrosion and fouling for this component group. The applicant 

stated that the associated items are evaluated for aging management in their respective 

mechanical systems. The staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed that the 

applicant‘s LRA does not have any AMR results for the ESF systems that include steel 

containment isolation piping and components exposed to raw water. The staff also reviewed the 

AMR results for the mechanical systems, into which the components that are intended to be 

evaluated using this GALL Report item were placed, and confirmed that the components are 

evaluated for aging management in accordance with GALL AMP XI.M20. The staff noted that a 

search of the applicant‘s USAR did not find any evidence of steel containment isolation piping 

and components in the ESF systems exposed to raw water that are not included in the 

evaluations performed in the applicable mechanical systems. Based on its review of the LRA 

and USAR, the staff confirmed that there are no in-scope steel containment isolation piping and 

components exposed to raw water in the ESF systems and, therefore, finds the applicant‘s 

determination acceptable.

LRA Table 3.2.1, item 3.2.1-38 addresses stainless steel containment isolation piping and 

components exposed to raw water. The GALL Report recommends the use of GALL 

AMP XI.M20, ―Open-Cycle Cooling Water System,‖ to manage loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion and fouling for this component group. 

The applicant stated that the associated items are evaluated for aging management in their 

respective mechanical systems. The staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed 

that the applicant‘s LRA does not have any AMR results for the ESF systems that include steel 

containment isolation piping and components exposed to raw water. The staff also reviewed the 

AMR results for the mechanical systems, into which the components that are intended to be 

evaluated using this GALL Report item were placed, and confirmed that the components are 

evaluated for aging management in accordance with GALL AMP XI.M20. The staff noted that a 
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search of the applicant‘s USAR did not find any evidence of stainless steel containment isolation 

piping and components in the ESF systems exposed to raw water that are not included in the 

evaluations performed in the applicable mechanical systems. Based on its review of the LRA 

and USAR, the staff confirmed that there are no in-scope stainless steel containment isolation 

piping and components exposed to raw water in the ESF systems and, therefore, finds the 

applicant‘s determination acceptable.

LRA Table 3.2.1, item 3.2.1-54 addresses steel piping, piping components, and piping elements 

exposed externally to indoor controlled air and states that there are no aging effects or aging 

mechanisms, and that no AMPs will be credited for this material and environment combination. 

The GALL Report, Table V.F, item V.F-16 states that there is no aging effect or aging 

mechanism, and that no AMP is recommended for this component group exposed to this 

environment and, therefore, the staff finds the applicant‘s determination acceptable.

LRA Table 3.2.1, item 3.2.1-57 addresses stainless steel and copper alloy (with less than 

15 percent Zn) piping, piping components, and piping elements exposed to air with borated 

water leakage and states that there are no aging effects or aging mechanisms, and that no 

AMPs will be credited for this material and environment combination. The GALL Report, 

Table V.F, items V.F-5 and V.F-13 state that there are no aging effects or aging mechanisms, 

and that no AMPs are recommended for this component group exposed to this environment 

and, therefore, the staff finds the applicant‘s determination acceptable.

3.2.2.1.2 Loss of Material Due to Cladding Breach

LRA Table 3.2.1, item 3.2.1-2 discusses loss of material due to cladding breach for pumps with 

steel pump casings and stainless steel cladding, which are exposed to treated borated water. 

The applicant stated that this is not applicable to KPS. See SER Section 3.2.2.2.2 for the staff‘s 

evaluation of this issue. 

3.2.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-4 and Section 3.2.2.2.3.2 address loss of material due to pitting and 

crevice corrosion of 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 applicant stated that this item is not applicable 

because there are no in-scope components constructed of stainless steel exposed to soil in the 

ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the applicant‘s 

LRA does not have any AMR results for the ESF systems that include stainless steel 

components exposed to soil. The staff also reviewed the USAR to verify the same. Based on its 

review of the LRA and USAR, the staff confirmed that the applicant‘s plant does not have any 

in-scope components constructed of stainless steel exposed to soil in the ESF systems and, 

therefore, finds the applicant‘s determination acceptable.

3.2.2.1.4 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-7 addresses the exterior of a stainless steel tank bottom that may

have its moisture barrier breached and exposed to rain water or other sources of raw water. The 

GALL Report recommends further evaluation to ensure that the aging effect is adequately 

managed and that a plant-specific AMP be evaluated because moisture and water can 

accumulate under the tank due to cracking of the perimeter seal from weathering. The applicant 

stated that this item is not applicable because its refueling water storage tank is located inside 
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the auxiliary building and is not exposed to a raw water environment. The applicant also stated 

that based on plant-specific OE, the tank has not been exposed to any moisture that could 

collect underneath the tank. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that 

the applicant‘s LRA does not have any stainless steel tanks in the ESF systems other than the 

refueling water storage tank. The staff also reviewed the USAR to verify the same. The staff 

determined that the presence of the tank inside the auxiliary building effectively eliminates the 

potential for ingress of raw water below the tank. Based on its review of the LRA and USAR, the 

staff confirmed that the applicant‘s plant does not have a tank whose bottom may have its 

moisture barrier breached and exposed to rain water or other sources of raw water in the ESF 

systems and, therefore, finds the applicant‘s determination acceptable.

3.2.2.1.5 Loss of Material Due to Erosion

LRA Table 3.2.1, item 3.2.1-12 addresses erosion in the miniflow recirculation orifice for 

centrifugal charging pumps used as high-head safety injection pumps exposed to treated 

borated water. The GALL Report recommends a plant-specific AMP be evaluated for erosion of 

the miniflow recirculation orifice due to extended use of the centrifugal safety injection pump for 

normal charging. The GALL Report references Licensee Event Report (LER) 50-275/94-023 for 

evidence of erosion. The applicant stated that this item is not applicable because its installed 

safety injection pumps are not used as the normal charging pumps. The applicant also stated 

that the charging pumps are positive displacement pumps which do not have miniflow 

recirculation orifices. The staff reviewed LRA Sections 2.2.3 and 3.2 and confirmed that the 

applicant‘s LRA does not have any AMR results for centrifugal charging pumps used as 

high-head safety injection pumps exposed to treated borated water. 

The staff noted that the applicant stated that it is currently not using the centrifugal pumps in a 

manner which would result in prolonged use. The staff also noted that one of the responses to 

the events of LER 50-275/94-023 was to switch from using the centrifugal pump to the positive 

displacement pump for normal injection. Based on the ability of the applicant to switch from 

using the centrifugal pump to the positive displacement pump for normal injection, the staff 

cannot conclude from the applicant‘s statement that the positive displacement pump is being 

used for normal injection and that the centrifugal pump has not been used for that purpose in 

the past. Past use of the centrifugal pump for normal injection could indicate that greater than 

acceptable erosion has occurred or may occur with minimal additional use during the period of 

extended operation. By letter dated October 13, 2009, the staff issued RAI 3.2.2.2.6-1 

requesting that the applicant provide information concerning the interchangeability of the safety 

injection pumps and the charging pumps, and the operating history of the safety injection pumps 

so as to allow the staff to determine whether these pumps have been or will be operated for a 

sufficient period of time to cause erosion of the miniflow recirculation orifice.

In its response dated November 13, 2009, the applicant stated that the charging pumps are 

positive displacement pumps which do not have miniflow recirculation orifices. The applicant 

also stated that while the safety injection pumps are centrifugal pumps, they are not 

interchangeable with the charging pumps and are not operated for sufficient periods to cause 

loss of material due to erosion. 

The staff finds that this item is not applicable because the conditions of the item, centrifugal 

charging pumps with miniflow recirculation orifices, are not met. The staff‘s concern described in 

RAI 3.2.2.2.6-1 is closed. Based on its review of the LRA and RAI 3.2.2.2.6-1, the staff 

confirmed that there are no in-scope centrifugal charging pumps used as high-head safety 
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injection pumps exposed to treated borated water and, therefore, finds the applicant‘s 

determination acceptable.

3.2.2.1.6 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion

LRA Table 3.2.1, item 3.2.1-29 addresses copper alloy piping, piping components, piping 

elements, and heat exchanger components exposed to closed-cycle cooling water. The GALL 

Report recommends the use of GALL AMP XI.M21, ―Closed-Cycle Cooling Water System,‖ to 

manage loss of material due to pitting, crevice, and galvanic corrosion for this component group. 

The applicant stated that this item is not applicable because the applicant has no components 

fabricated from copper alloy that are exposed to closed-cycle cooling water in the ESF systems. 

The staff reviewed LRA Sections 2.3.3 and 3.2 and confirmed that the applicant‘s LRA does not 

have any AMR results for the ESF systems that include copper alloy piping, piping components, 

piping elements, and heat exchanger components exposed to closed-cycle cooling water. The 

staff also noted that a search of the applicant‘s USAR did not find any evidence of copper alloy 

piping, piping components, piping elements, and heat exchanger components in the ESF 

systems exposed to closed-cycle cooling water. Based on its review of the LRA and USAR, the 

staff confirmed that there are no in-scope copper alloy piping, piping components, piping 

elements, and heat exchanger components exposed to closed-cycle cooling water in the ESF 

systems and, therefore, finds the applicant‘s determination acceptable.

3.2.2.1.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-32 addresses steel piping and ducting components and internal 

surfaces exposed to air-indoor uncontrolled (internal). The GALL Report recommends the use of 

GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components,‖ to manage loss of material due to general, pitting, and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because there are no 

ESF steel piping or ducting components fabricated from steel and internally exposed to 

air-indoor uncontrolled. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the 

applicant‘s LRA does not have any AMR results for the ESF systems that include steel piping 

and ducting components and internal surfaces exposed to air-indoor uncontrolled (internal). The 

staff also noted that a search of the applicant‘s USAR did not find any evidence of steel piping 

and ducting components and internal surfaces in the ESF systems exposed to air-indoor 

uncontrolled (internal). Based on its review of the LRA and USAR, the staff confirmed that there 

are no in-scope steel piping and ducting components and internal surfaces exposed to 

air-indoor uncontrolled (internal) in the ESF systems and, therefore, finds the applicant‘s 

determination acceptable. 

3.2.2.1.8 Loss of Material Due to General, Pitting, Crevice, Galvanic, and 

Microbiologically-Influenced Corrosion and Fouling

LRA Table 3.2.1, item 3.2.1-36 addresses steel heat exchanger components exposed to raw 

water. The GALL Report recommends the use of GALL AMP XI.M20, ―Open-Cycle Cooling 

Water System,‖ to manage loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion and fouling for this component group. The applicant 

stated that this item is not applicable because there are no ESF system steel heat exchanger 

components exposed to raw water. The staff reviewed LRA Sections 2.3.2 and 3.2 and 

confirmed that the applicant‘s LRA does not have any AMR results for the ESF systems that 

include steel heat exchanger components exposed to raw water. The staff also noted that a

search of the applicant‘s USAR did not find any evidence of steel heat exchanger components 
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in the ESF systems exposed to raw water. Based on its review of the LRA and USAR, the staff 

confirmed that there are no in-scope steel heat exchanger components exposed to raw water in 

the ESF systems and, therefore, finds the applicant‘s determination acceptable. 

3.2.2.1.9 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

LRA Table 3.2.1, item 3.2.1-37 addresses stainless steel piping, piping components and piping 

elements exposed to raw water. The GALL Report recommends the use of GALL AMP XI.M20, 

―Open-Cycle Cooling Water System,‖ to manage loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion for this component group. By letter dated September 25, 

2009, the applicant amended its LRA to state that LRA Table 3.2.1, item 3.2.1-37 is not 

applicable.

The applicant also amended its LRA by removing its reference to LRA Table 3.2.1, 

item 3.2.1-37 in the safety injection system for the stainless steel pipe exposed to raw water, 

which is subject to loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion. The staff noted that this was the only AMR item that referenced LRA Table 3.2.1, 

item 3.2.1-37. The staff‘s review of stainless steel components exposed to raw water subject to 

loss of material due to pitting, crevice, and microbiologically-influenced corrosion and its 

evaluation is documented in SER Section 3.2.2.3.1. 

Based on its review of the LRA and the applicant‘s letter dated September 25, 2009, the staff 

confirmed that the in-scope stainless steel pipe exposed to raw water in the safety injection

system is evaluated in SER Section 3.2.2.3.2 and, therefore, finds the applicant‘s determination 

acceptable.

3.2.2.1.10 Reduction of Heat Transfer Due to Fouling

LRA Table 3.2.1, item 3.2.1-40 addresses steel and stainless steel heat exchanger tubes 

serviced by open-cycle cooling water exposed to raw water. The GALL Report recommends the 

use of GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ to manage reduction of heat 

transfer due to fouling for this component group. The applicant stated that this item is not 

applicable because there are no ESF heat exchanger tubes fabricated from steel or stainless 

steel and exposed to open-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 

and confirmed that the applicant‘s LRA does not have any AMR results for the ESF systems 

that include steel and stainless steel heat exchanger tubes serviced by open-cycle cooling water 

exposed to raw water. The staff also noted that a search of the applicant‘s USAR did not find 

any evidence of steel and stainless steel heat exchanger tubes serviced by open-cycle cooling 

water exposed to raw water. Based on its review of the LRA and USAR, the staff confirmed that 

there are no in-scope steel and stainless steel heat exchanger tubes serviced by open-cycle 

cooling water exposed to raw water in the ESF systems and, therefore, finds the applicant‘s 

determination acceptable.

3.2.2.1.11 Loss of Material Due to Selective Leaching

LRA Table 3.2.1, item 3.2.1-41 addresses copper alloy (greater than 15 percent Zn) piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water. The GALL Report recommends the use of GALL AMP XI.M33, ―Selective 

Leaching of Materials,‖ to manage loss of material due to selective leaching for this component 

group. The applicant stated that this item is not applicable because there are no ESF system 

components fabricated from copper alloy (greater than 15 percent Zn) and exposed to 
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closed-cycle cooling water. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that 

the applicant‘s LRA does not have any AMR results for the ESF systems that include copper 

alloy greater than 15 percent Zn piping, piping components, piping elements, and heat 

exchanger components exposed to closed-cycle cooling water. Based on its review of the LRA, 

the staff confirmed that there are no in-scope copper alloy (greater than 15 percent Zn) piping, 

piping components, piping elements, and heat exchanger components exposed to closed-cycle 

cooling water in the ESF systems and, therefore, finds the applicant‘s determination acceptable.

3.2.2.1.12 Loss of Material Due to Selective Leaching

LRA Table 3.2.1, item 3.2.1-43 addresses gray cast iron piping, piping components, and piping 

elements exposed to soil. The GALL Report recommends the use of GALL AMP XI.M33, 

―Selective Leaching of Materials,‖ to manage loss of material due to selective leaching for this 

component group. The applicant stated that this item was not applicable because there are no 

ESF system piping, piping components, and piping elements fabricated from gray cast iron and 

exposed to soil. The staff reviewed LRA Sections 2.3.2 and 3.2 and confirmed that the 

applicant‘s LRA does not have any AMR results for the ESF systems that include gray cast iron 

piping, piping components, and piping elements exposed to soil. The staff also noted that a 

search of the applicant‘s USAR did not find any evidence of gray cast iron piping, piping 

components, and piping elements in the ESF exposed to soil. Based on its review of the LRA 

and USAR, the staff confirmed that there are no in-scope gray cast iron piping, piping 

components, and piping elements exposed to soil in the ESF systems and, therefore, finds the 

applicant‘s determination acceptable.

3.2.2.1.13 Loss of Material Due to Selective Leaching

LRA Table 3.2.1, item 3.2.1-44 addresses gray cast iron motor coolers exposed to treated 

water. The GALL Report recommends the use of GALL AMP XI.M33, ―Selective Leaching of 

Materials,‖ to manage loss of material due to selective leaching for this component group. The 

applicant stated that this item is not applicable because there are no ESF system components 

fabricated from gray cast iron and exposed to treated water. The staff reviewed LRA 

Sections 2.3.2 and 3.2 and confirmed that the applicant‘s LRA does not have any AMR results 

for the ESF systems that include gray cast iron motor coolers exposed to treated water. The 

staff also noted that a search of the applicant‘s USAR did not find any evidence of gray cast iron 

motor coolers in the ESF systems exposed to treated water. Based on its review of the LRA and 

USAR, the staff confirmed that there are no in-scope gray cast iron motor coolers exposed to 

treated water in the ESF systems and, therefore, finds the applicant‘s determination acceptable.

3.2.2.1.14 Loss of Fracture Toughness Due to Thermal Aging Embrittlement

LRA Table 3.2.1, item 3.2.1-47 addresses the loss of fracture toughness due to thermal aging 

embrittlement of CASS Class 1 piping, piping components, and piping elements exposed to 

reactor coolant greater than 250 °C (482 °F). The AMR items corresponding to item 3.2.1-47 are 

described in LRA Tables 3.2.2-2 and 3.2.2-3, and include CASS Class 1 valves in safety 

injection and RHR systems of the ESF systems. The applicant stated that these AMR items 

were consistent with the GALL Report item for component, material, environment, and aging 

effect, but a program different than GALL AMP XI.M12, ―Thermal Aging Embrittlement of Cast 

Austenitic Stainless Steel,‖ is credited to manage the aging effects. The applicant stated that the 

program consists of the ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, with 

an exception. The applicant further stated that this program is consistent with GALL 

AMP XI.M12. 
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The staff reviewed LRA item 3.2.1-47 in comparison with GALL Report Volume 1, Table 2, 

ID 47. In its review of the LRA, the staff noted that the generic note for the AMR items was E, 

which means that the component, material, environment, and aging effect/mechanism are 

consistent with the GALL Report but a different AMP is credited to manage the aging effects. In 

its review, the staff found that the LRA AMR items were consistent with the GALL Report in 

component, material, environment, and aging effect. The applicant stated that the loss of 

fracture toughness of CASS valves in the safety injection and RHR systems is managed by the 

ASME Section XI ISI, Subsections IWB, IWC, and IWD Program, which takes exception to 

GALL AMP XI.M1 in that a different edition of the ASME Code Section XI is used. The staff 

reviewed the applicant‘s ASME Section XI ISI, Subsections IWB, IWC, and IWD Program and 

its evaluation is documented in SER Section 3.0.3.2.1. The applicant further stated in LRA 

Tables 3.2.2-2 and 3.2.2-3 that it is permissible to use the ASME Section XI ISI, Subsections 

IWB, IWC, and IWD Program because it is consistent with GALL AMP XI.M12. The staff found 

this acceptable because GALL AMP XI.M12 states that based on the assessment documented 

in the letter dated May 19, 2000, from Christopher Grimes, NRC, to Douglas Walters, NEI (LRA 

Reference 4.8-27), for CASS Class 1 pump casings and valve bodies and bonnets exposed to 

reactor coolant greater than 250 °C (482 °F), screening for susceptibility to thermal aging is not 

required, and the existing ASME Code Section XI ISI requirements are adequate. 

Based on its review of the program to manage the loss of fracture toughness due to thermal 

aging embrittlement of CASS Class 1 valves in the safety injection and RHR systems of the 

ESF systems, the staff finds that all program elements are consistent with GALL AMP XI.M12, 

―Thermal Aging Embrittlement of Cast Austenitic Stainless Steel,‖ and, therefore, acceptable. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.1.15 Cracking Due to Stress-Corrosion Cracking

LRA Table 3.2.1, item 3.2.1-48 addresses the cracking due to SCC of austenitic stainless steel 

components, from the ESF systems, that are exposed to treated borated water greater than 

60 °C (140 °F). The AMR items corresponding to item 3.2.1-48 include piping and valves in the 

safety injection system (Table 3.2.2-2) and piping, piping components and elements, and heat 

exchangers in the RHR system (Table 3.2.2-3). The applicant stated that the cracking due to 

SCC of these stainless steel components is managed by the WCP Program, which is a 

plant-specific AMP, and the Primary Water Chemistry Program. The applicant further stated that 

the program is consistent with the GALL Report. 

The staff reviewed LRA Table 3.2.1, item 3.2.1-48 in comparison with the GALL Report,

Volume 1, Table 2, ID 48. In its review, the staff noted that the LRA AMR items were consistent 

with the GALL Report in component, material, environment, and aging effect. The staff noted 

that for these AMR items, the GALL Report recommends the Primary Water Chemistry Program 

to manage the effects of cracking due to SCC. Consequently, the applicant‘s program is 

consistent with the GALL Report and, therefore, acceptable. However, the generic notes in LRA 

Tables 3.2.2-2 and 3.2.2-3 are confusing. Note A is listed for the Primary Water Chemistry 

Program and note E is listed for the WCP Program. Consistency note A means that the program 

is consistent with the GALL Report because the Primary Water Chemistry Program is used to 

manage the aging effects, whereas note E means that a different program, the WCP Program, 

is being credited to manage the aging effects. For these items, the use of the WCP Program 
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should be considered an additional program that provides inspection capabilities beyond what is 

specified in the GALL Report. The staff finds that the AMP proposed by the applicant is at least 

as comprehensive as that recommended in the GALL Report. On the basis of its review, the 

staff determines that the applicant‘s proposed program is acceptable for managing the cracking 

due to SCC in austenitic stainless steel ESF components. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.1.16 Galvanized Steel Ducting Exposed to Air-Indoor Controlled (External)

LRA Table 3.2.1, item 3.2.1-51 addresses galvanized steel ducting exposed to air-indoor 

controlled (external) and states that there are no aging effects or mechanisms and that no AMP 

is recommended. The GALL Report, Table V, item V.F-1 (EP-14) recommends that there is no 

aging effect or aging mechanism and that no AMP is recommended for this component group 

and, therefore, the staff finds the applicant‘s determination acceptable.

3.2.2.1.17 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

of Stainless Steel Heat Exchanger Components Exposed to Raw Water

LRA Table 3.2.1, item 3.2.1-39 addresses stainless steel heat exchanger components exposed 

to raw water which are being managed for loss of material/pitting, crevice, and 

microbiologically-influenced corrosion by the WCP Program. This item was used in LRA 

Table 3.3.2-3, ―Auxiliary Systems – Spent Fuel Pool Cooling – Aging Management Evaluation,‖

for AMR items for the SFP heat exchanger tubes and spent fuel heat exchanger tubesheet, and 

Table 3.3.2-9, ―Auxiliary Systems – Chemical and Volume Control – Aging Management 

Evaluation,‖ for AMR items for the boric acid evaporator distillate sample cooler tubing. The 

applicant cited generic note H indicating that for the component, material, and environment 

combination listed, the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is stainless steel piping, piping components, and piping elements exposed to raw water

and noted that the GALL Report recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water 

System,‖ to monitor the aging effect of loss of material due to loss of material due to pitting, 

crevice, and microbiologically-influenced corrosion.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff noted that both the SFP cooling heat exchanger and boric acid 

evaporator distillate sample cooler tubing are nonsafety-related components and, therefore, do 

not fall under the scope of the GALL Report recommended program. The staff finds the 

applicant‘s proposal acceptable because the applicant has: (1) identified an applicable aging 

effect, (2) selected an AMP with an appropriate scope for the component under consideration, 

and (3) chosen an AMP which contains appropriate inspection techniques to identify that aging 

effect. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2 and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 
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Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.1.18 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-49 addresses the loss of material due to pitting and crevice 

corrosion of stainless steel piping, piping components, piping elements, and tanks exposed to 

primary treated water. The LRA credits the Primary Water Chemistry Program and WCP 

Program to manage this aging effect for stainless steel piping, piping components, piping 

elements, and tanks. The GALL Report recommends GALL AMP XI.M2, ―Water Chemistry,‖ to 

ensure that these aging effects are adequately managed. In LRA Table 3.2.1, the applicant 

assigned each component two items, one in which the Primary Water Chemistry Program is 

credited and the other in which the WCP Program is credited. The applicant stated that all the 

items for which the Water Chemistry Program is credited are fully consistent with the GALL 

Report, citing generic note A. The applicant cited generic note E for all the items for which the 

WCP Program is credited, indicating that the LRA AMR is consistent with the GALL Report item 

for material, environment, and aging effect except that a different AMP is credited.

The staff reviewed the applicant‘s Primary Water Chemistry and WCP programs, and its 

evaluations are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. In its 

review of LRA item 3.2.1-49, the staff noted that the GALL Report does not recommend that the 

effectiveness of the Water Chemistry Program be confirmed by an inspection program to 

manage the effects of loss of material on stainless steel piping, piping components, piping 

elements, and tanks. The staff also noted that the applicant proposed to manage the aging of 

the components under consideration through the use of its Primary Water Chemistry Program, 

which is consistent with that recommended by the GALL Report. In addition, the applicant 

proposed to use the WCP Program, which is an inspection program, to supplement the Primary 

Water Chemistry Program, in addition to the recommendations in the GALL Report. The staff 

finds that the AMPs proposed by the applicant are in addition to those recommended by the 

GALL Report and, therefore, acceptable.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions 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 That Are Consistent with the GALL Report, for Which Further 

Evaluation Is Recommended

LRA Section 3.2.2.2 provides further evaluation of aging management as recommended by the 

GALL Report for the ESF components. The applicant provided information concerning how it will 

manage the following aging effects:

● cumulative fatigue damage

● loss of material due to cladding breach

● loss of material due to pitting and crevice corrosion
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● reduction of heat transfer due to fouling

● 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

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, ―Definitions.‖ 

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 Breach

LRA Section 3.2.2.2.2 refers to Table 3.2-1, item 3.2.1-2 and addresses steel pump casings 

with stainless steel cladding exposed to treated borated water which are being managed for loss 

of material due to cladding breach. The applicant stated that the cladding failures described in 

the GALL Report were based on NRC IN 94-63, concerning high-head safety injection pumps at 

North Anna Power Station. According to the applicant, the failures at North Anna were related to 

manufacturing at the Pacific Pump Division of Dresser Industries and not related to aging; 

whereas the applicant‘s pumps were manufactured by Sulzer Bingham. The applicant stated 

that since there was no OE related to loss of material due to cladding breach in Sulzer Bingham 

pumps, this item was not applicable.

The staff reviewed LRA Section 3.2.2.2.2 against the criteria in SRP-LR Section 3.2.2.2.2, which 

states that loss of material due to cladding breach could occur in PWR steel pump casings with 

stainless steel cladding exposed to treated borated water and that the GALL Report 

recommends further evaluation of a plant-specific AMP to ensure this aging effect is adequately 

managed. Acceptance criteria are described in the SRP-LR, Appendix A.1, ―Aging Management 

Review – Generic.‖ 

The staff reviewed USAR Table 6.2-6, ―Safety Injection Pump Design Parameters,‖ and noted 

that the safety injection pumps are carbon steel forgings with stainless steel cladding. Contrary 

to the applicant‘s position that this item was not applicable, the staff did not consider the lack of 

OE related to loss of material due to cladding breach in Sulzer Bingham pumps as a sufficient 

basis to ensure that this aging effect is managed. By letter dated December 3, 2009, the staff 

issued RAI 3.2.2.2.2-1 requesting that the applicant provide a plant-specific AMP to ensure that 

the loss of material due to cladding breach is adequately managed. 

In its response dated January 21, 2010, the applicant stated that a VT-1 visual examination of 

one safety injection pump will be performed prior to the period of extended operation to ensure 

there are no signs of cracking in stainless steel cladding or corrosion. The applicant also stated 

that NRC IN 94-63, upon which this item is based, describes visible rust-like stains as being 

indicative of a cladding breach and corrosion of the underlying carbon steel casing material. The 

applicant further stated that Commitment No. 37, covering the above visual examination, will be 

added to LRA Appendix A, USAR Table A6.0-1. 
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Based on its review, the staff finds the applicant‘s response to RAI 3.2.2.2.2-1 acceptable 

because the noted visual examination for one of the two safety injection pumps will identify any 

corrosion of the underlying carbon steel, in the unlikely event of a cladding breach. Therefore, 

the staff finds that managing the loss of material due to cladding breach for steel pump casings 

with stainless steel cladding exposed to treated borated water through a visual examination 

prior to the period of extended operation is an acceptable plant-specific program which will 

provide reasonable assurance that this aging effect is adequately managed. The staff‘s concern 

described in RAI 3.2.2.2.2-1 is resolved. 

Based on the applicant‘s commitment, the staff concludes that the applicant‘s program meets 

SRP-LR Section 3.2.2.2.2 criteria. For those items that apply to LRA Section 3.2.2.2.2, the staff 

concludes 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion

Item 1. LRA Section 3.2.2.2.3.1 refers to Table 3.2.1, item 3.2.1-3 and addresses loss of 

material due to pitting and crevice corrosion from stainless steel containment isolation piping 

and component internal surfaces exposed to treated water. The applicant stated that these 

components are evaluated for aging management in their respective mechanical systems.

The staff reviewed LRA Section 3.2.2.2.3.1 against the criteria in SRP-LR Section 3.2.2.2.3.1, 

which states that loss of material due to pitting and crevice corrosion could occur for the internal 

surfaces of stainless steel containment isolation piping, piping components, and piping elements 

exposed to treated water. The GALL Report recommends the use of GALL AMP XI.M2, ―Water 

Chemistry,‖ augmented by further evaluation to verify the effectiveness of the program to 

manage the effects of aging for this component group. The GALL Report states that the existing 

AMP relies on monitoring and control of water chemistry to mitigate degradation. The GALL 

Report also states that control of water chemistry does not preclude loss of material due to 

pitting and crevice corrosion at locations of stagnant flow conditions and that the effectiveness 

of the chemistry control program should be verified to ensure that corrosion does not occur. The 

GALL Report recommends further evaluation of programs to verify the effectiveness of the 

chemistry control program and notes that a one-time inspection of selected components at 

susceptible locations is an acceptable method to determine whether an aging effect is not 

occurring or an aging effect is progressing very slowly such that the component‘s intended 

function will be maintained during the period of extended operation.

The staff reviewed AMR items associated with LRA Table 3.2.1, item 3.2.1-3 and the 

mechanical systems into which the components that are intended to be evaluated using this 

GALL Report item were placed. The staff noted that for some mechanical systems where 

stainless steel components are exposed to treated water, the LRA only credits the use of the 

Primary Water Chemistry Program and is not augmented by an inspection program to verify the 

effectiveness of the Primary Water Chemistry Program. The staff finds that if the components 

which were intended to be evaluated as part of this item are evaluated as part of the associated 

mechanical system, they may be subjected to aging management by only the Primary Water 

Chemistry Program and not by a combination of the Primary Water Chemistry Program and a 

program to verify the effectiveness of the chemistry control program, as recommended by the 

GALL Report. This approach may not adequately manage aging because the effectiveness of 

the Primary Water Chemistry Program may not be confirmed in all instances. By letter dated 
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August 28, 2009, the staff issued RAI 3.2.2.2.3.1-1 requesting that the applicant evaluate 

components meeting the definition of this table, under the guidance of this table, as opposed to 

including these components in their parent mechanical system for evaluation.

In its response dated September 28, 2009, the applicant stated that for all of the piping and 

valves under consideration, when aging management is performed under the system to which 

the piping and valves belong, aging management will be performed in accordance with both the 

Primary Water Chemistry Program and WCP Program. Subsequent review of the LRA by the 

staff confirmed that all items where stainless steel containment isolation piping, piping 

components, and piping elements internal surfaces are exposed to treated water and subject to 

loss of material due to general, pitting, and crevice corrosion are managed for aging using both 

the Primary Water Chemistry and WCP programs. The applicant‘s WCP Program encompasses 

GALL AMP XI.M32, ―One-Time Inspection,‖ and performs visual inspections of selected 

components during maintenance. The staff reviewed the applicant‘s Primary Water Chemistry 

Program and WCP Program and its evaluations are documented in SER Sections 3.0.3.1.9 and 

3.0.3.2.19, respectively. The staff finds the applicant‘s response acceptable because the 

applicant‘s Water Chemistry Program and WCP Program are consistent with the ―Water 

Chemistry‖ and ―One-Time Inspection‖ programs as defined in the GALL Report, which are 

recommended by the GALL Report to manage the effects of loss of material for stainless steel 

containment isolation piping and component internal surfaces exposed to treated water.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.3.1 criteria. For those items that apply to LRA Section 3.2.2.2.3.1, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. This item is not applicable to KPS. See SER Section 3.2.2.1.3.

Item 3. This item is applicable to BWRs only. See SER Section 3.2.2.1.1. 

Item 4. LRA Table 3.2-1, item 3.2.1-6 and LRA Section 3.2.2.2.3.4 address loss of material due 

to pitting and crevice corrosion in piping, piping components, and piping elements exposed to 

lubricating oil. The applicant stated that loss of material for stainless steel and copper alloy 

piping components exposed to lubricating oil is managed by the Lubricating Oil Analysis 

Program. The WCP Program will provide a verification of the effectiveness of the Lubricating Oil 

Analysis Program to manage loss of material due to crevice and pitting corrosion through 

examination of stainless steel and copper alloy components.

The staff reviewed LRA Section 3.2.2.2.3.4 against the criteria in SRP-LR Section 3.2.2.2.3.4, 

which 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage loss of material due to pitting 

and crevice corrosion in copper alloy and stainless steel piping, piping components, and piping 

elements exposed to lubricating oil. The staff noted that the applicant has credited the WCP 

Program in lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 

2009, the applicant amended its LRA so that its WCP Program will be consistent with GALL 

AMP XI.M32. The staff determined that the applicant‘s WCP Program will manage the aging 

effects of cracking, loss of material, and reduction of heat transfer through program inspections 

that provide verification of the effectiveness of the Lubricating Oil Analysis Program where: 

(a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or (c) 

the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for identification of these potential aging effects and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 

and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.2.2.2.3.4, the staff finds the applicant‘s use of the Lubricating Oil Analysis 

Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.3.4 criteria. For those items that apply to LRA Section 3.3.2.2.3.4, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 5. This item is not applicable to KPS. See SER Section 3.2.2.1.4.

Item 6. LRA Section 3.2.2.2.3.6 refers to Table 3.2.1, item 3.2.1-8 and addresses stainless steel 

piping exposed to internal condensation or moist air, which are being managed for loss of 

material due to pitting and crevice corrosion by the WCP Program. 

The staff reviewed LRA Section 3.2.2.2.3.6 against the criteria in SRP-LR Section 3.2.2.2.3.6, 

which states that loss of material from pitting and crevice corrosion could occur for stainless 

steel piping, piping components, piping elements, and tanks exposed to internal condensation. 

The GALL Report recommends further evaluation of a plant-specific AMP to ensure that these 

aging effects are adequately managed. Acceptance criteria are described in the SRP-LR BTP 

RSLB-1. The staff reviewed the applicant‘s WCP Program and its evaluation is documented in 

SER Section 3.0.3.2.19. 

In its review of components associated with LRA item 3.2.1-8, the staff finds the applicant‘s 

proposal to manage aging using the WCP Program acceptable because this AMP contains 
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appropriate inspection procedures to detect loss of material from the interior surfaces of piping 

and tanks. In addition, a staff concern related to selection and frequency of inspections is 

addressed in RAI B2.1.32-2 and the staff‘s evaluation of the RAI response is documented in 

SER Section 3.3.2.2.13.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.3.6 criteria. For those items that apply to LRA Section 3.2.2.2.3.6, 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 

functions 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

Item 1. LRA Section 3.2.2.2.4.1 refers to Table 3.2.1, item 3.2.1-9 and addresses the reduction 

of heat transfer due to fouling for copper alloy heat exchanger tubes exposed to lubricating oil in 

the EDG system. The applicant stated that this aging effect is managed by the Lubricating Oil 

Analysis Program. The applicant also stated that the WCP Program will confirm the 

effectiveness of the Lubricating Oil Analysis Program by visually inspecting internal surfaces of 

components constructed of typical system materials and exposed to typical system 

environments, including stagnant locations.

The staff reviewed LRA Section 3.2.2.2.4.1 against the criteria in SRP-LR Section 3.2.2.2.4.1, 

which states that reduction of heat transfer due to fouling could occur for steel, stainless steel, 

and copper alloy heat exchanger tubes exposed to lubricating oil. The GALL Report 

recommends the use of the Lubricating Oil Analysis Program, augmented by further evaluation 

to verify the effectiveness of the program to manage the effects of reduction of heat transfer due 

to fouling for steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating 

oil. The SRP-LR states that the existing AMP relies on monitoring and controlling lube oil 

chemistry to mitigate the reduction of heat transfer due to fouling and that control of lube oil 

contaminants may not always be fully effective in precluding fouling. Therefore, the SRP-LR 

also states that the effectiveness of lubricating oil control should be verified to ensure that 

corrosion does not occur and notes that a one-time inspection of selected components at 

susceptible locations is an acceptable method for determining that this aging effect is not 

occurring. 

The staff evaluated the applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

review is documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff finds the 

applicant‘s use of the Lubricating Oil Analysis Program, in conjunction with effectiveness 

verification through the WCP Program, acceptable to manage the reduction of heat transfer due 

to fouling because: (1) these AMPs are consistent with the recommended programs in SRP-LR 

Section 3.2.2.2.4.1 and the GALL Report, (2) the Lubricating Oil Analysis Program periodically 

samples the oil to confirm oil quality, and (3) the WCP Program verifies effectiveness by 

inspecting heat transfer surfaces for fouling. 

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.4.1 criteria. For those items that apply to LRA Section 3.2.2.2.4.1, 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 

functions 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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Item 2. LRA Section 3.2.2.2.4.2 refers to Table 3.2.1, item 3.2.1-10 and addresses the reduction 

of heat transfer due to fouling for stainless steel heat exchanger tubes exposed to treated water 

in the containment vessel internal spray pump, RHR, and safety injection gland seal heat 

exchangers. The applicant stated that this aging effect is managed by the Primary Water 

Chemistry Program. The applicant further stated that the WCP Program will confirm the 

effectiveness of the Primary Water Chemistry Program by visually inspecting internal surfaces 

of components constructed of typical system materials and exposed to typical system 

environments, including stagnant locations. 

The staff reviewed LRA Section 3.2.2.2.4.2 against the criteria in SRP-LR Section 3.2.2.2.4.2, 

which states that the reduction of heat transfer due to fouling may occur for stainless steel heat 

exchanger tubes exposed to treated water, and that management of this aging effect relies on 

water chemistry control. The GALL Report recommends the use of the Primary Water Chemistry 

Program, augmented by further evaluation to verify the effectiveness of the program to manage 

the effects of reduction of heat transfer due to fouling for stainless steel heat exchanger tubes 

exposed to treated water. As noted in the SRP-LR, since control of water chemistry may not 

always have been adequate to preclude fouling, the GALL Report recommends that the 

effectiveness of the water chemistry control program be verified to ensure that reduction of heat 

transfer due to fouling is not occurring. The SRP-LR notes that a one-time inspection is an 

acceptable method to ensure that reduction of heat transfer is not occurring and that the 

components‘ intended functions will be maintained during the period of extended operation. The 

staff noted the discussion in GALL AMP XI.M2, ―Water Chemistry,‖ relative to water chemistry 

programs being generally effective in removing impurities, except in low flow or stagnant flow 

areas.

The staff evaluated the applicant‘s Primary Water Chemistry Program and WCP Program and 

its review is documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff finds 

the applicant‘s use of the Primary Water Chemistry Program, in conjunction with effectiveness 

verification through the WCP Program, acceptable to manage the reduction of heat transfer due 

to fouling because: (1) these AMPs are consistent with the recommended programs in SRP-LR 

Section 3.2.2.2.4.2 and the GALL Report, (2) the Primary Water Chemistry Program periodically 

monitors and controls contaminants below levels known to cause a reduction in heat transfer, 

and (3) the WCP Program verifies effectiveness by inspecting heat transfer surfaces for fouling.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2 2.2.4.2 criteria. For those items that apply to LRA Section 3.2.2.2.4.2, 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 

functions 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

LRA Table 3.2.1, item 3.2.1-11 is for BWRs only, it is not applicable to KPS. See SER 

Section 3.2.2.1.1.

3.2.2.2.6 Loss of Material Due to Erosion

LRA Table 3.2.1, item 3.2.1-12 is not applicable to KPS. See SER Sections 3.2.2.1.1 and 

3.2.2.2.6.
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3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling

LRA Table 3.2.1, item 3.2.1-13 is for BWRs only, it is not applicable to KPS. See SER 

Section 3.2.2.1.1.

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion

Item 1. LRA Section 3.2.2.2.8.1 and Table 3.2-1, item 3.2.1-14 are applicable to BWRs only. 

See SER Section 3.2.2.1.1.

Item 2. LRA Section 3.2.2.2.8.2 refers to Table 3.2.1, item 3.2.1-15 and addresses loss of 

material due to general, pitting, and crevice corrosion from steel containment isolation piping, 

piping components, and piping elements internal surfaces exposed to treated water. The 

applicant stated that these components are evaluated for aging management in their respective 

mechanical systems.

The staff reviewed LRA Section 3.2.2.2.8.2 against the criteria in SRP-LR Section 3.2.2.2.8.2, 

which states that loss of material due to general, pitting, and crevice corrosion could occur for 

the internal surfaces of steel containment isolation piping, piping components, and piping 

elements exposed to treated water. The GALL Report recommends the use of GALL 

AMP XI.M2, ―Water Chemistry,‖ augmented by further evaluation to verify the effectiveness of 

the program to manage the effects of aging for this component group. The GALL Report states 

that the existing AMP relies on monitoring and control of water chemistry to mitigate degradation 

and that control of water chemistry does not preclude loss of material due to general, pitting, 

and crevice corrosion at locations of stagnant flow conditions. The GALL Report also states that 

the effectiveness of the water chemistry control program should be verified to ensure that 

corrosion is not occurring. The GALL Report recommends further evaluation of programs to 

verify the effectiveness of the water chemistry control program and notes that a one-time 

inspection of selected components at susceptible locations is an acceptable method to 

determine whether an aging effect is not occurring or an aging effect is progressing very slowly 

such that the component‘s intended function will be maintained during the period of extended 

operation.

The staff reviewed the AMR items associated with LRA Table 3.2.1, item 3.2.1-15 and the 

mechanical systems into which the components that are intended to be evaluated using this 

GALL Report item were placed. The staff noted that for some mechanical systems where 

stainless steel components are exposed to treated water, the LRA only credits the use of the 

Primary Water Chemistry Program and is not augmented by an inspection program to verify the 

effectiveness of the Primary Water Chemistry Program. The staff finds that if the components 

which were intended to be evaluated as part of this item are evaluated as part of the associated 

mechanical system, they may be subjected to aging management by only the Primary Water 

Chemistry Program and not by a combination of the Primary Water Chemistry Program and a 

program to verify the effectiveness of the water chemistry control program, as recommend by 

the GALL Report. This approach may not adequately manage aging because the effectiveness 

of the Primary Water Chemistry Program may not be verified in all instances deemed necessary 

by the GALL Report. By letter dated August 28, 2009, the staff issued RAI 3.2.2.2.8.2-1 

requesting that the applicant evaluate components meeting the definition of this table, under the 

guidance of this table, as opposed to including these components in their parent mechanical 

system for evaluation.
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In its response dated September 28, 2009, the applicant stated that for all of the piping and 

valves under consideration, when aging management is performed under the system to which 

the piping and valves belong, aging management will be performed in accordance with the 

Primary Water Chemistry and WCP programs. Subsequent review of the LRA by the staff 

confirmed that all items where steel containment isolation piping, piping components, and piping 

elements internal surfaces are exposed to treated water and subject to loss of material due to 

general, pitting, and crevice corrosion, are managed for aging using both the Primary Water 

Chemistry and WCP programs. The applicant‘s WCP Program encompasses GALL 

AMP XI.M32, ―One-Time Inspection Program,‖ and performs visual inspections of selected 

components during maintenance. The staff reviewed the applicant‘s Primary Water Chemistry 

Program and WCP Program and its evaluations are documented in SER Sections 3.0.3.1.9 and 

3.0.3.2.19, respectively. The staff finds the applicant‘s response acceptable because the 

applicant‘s Primary Water Chemistry Program and WCP Program are consistent with the ―Water 

Chemistry‖ and ―One-Time Inspection‖ programs as defined in the GALL Report, which are 

recommended by the GALL Report to manage the effects of loss of material for stainless steel 

containment isolation piping and component internal surfaces exposed to treated water.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.8.2 criteria. For those items that apply to LRA Section 3.2.2.2.8.2, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 3. LRA Section 3.2.2.2.8.3 and Table 3.2-1, item 3.2.1-16 address loss of material due to 

general, pitting, and crevice corrosion in piping, piping components, and piping elements 

exposed to lubricating oil. The applicant stated that loss of material for steel and cast iron piping 

components exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The 

WCP Program will provide a verification of the effectiveness of the Lubricating Oil Analysis 

Program to manage loss of material due to general, pitting, and crevice corrosion through the 

examination of steel and cast iron components.

The staff reviewed LRA Section 3.2.2.2.8.3 against the criteria in SRP-LR Section 3.2.2.2.8.3, 

which 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 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 
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program will be capable of preserving an environment that will not promote loss of material and 

the reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the loss of material due to 

general, pitting, and crevice corrosion in steel piping, piping components, and piping elements 

exposed to lubricating oil. The staff noted that the applicant has credited the WCP Program in

lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the 

applicant amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Lubricating Oil Analysis Program 

where: (a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable of identifying these potential aging effects and that the sample size and location will 

be based on an assessment of materials, environments, plausible aging effects, and OE. On the 

basis that the applicant‘s AMPs are consistent with those recommended in SRP-LR 

Section 3.2.2.2.8.3, the staff finds the applicant‘s use of the Lubricating Oil Analysis Program 

and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.8.3 criteria. For those items that apply to LRA Section 3.2.2.2.8.3, 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 

functions 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 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff‘s evaluation of the applicant‘s QA program.

3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.2.2-1 through 3.2.2-3, the staff reviewed additional details of AMR results for 

material, environment, AERM, and AMP combinations not consistent with or not addressed in 

the GALL Report.

3.2.2.3.1 Stainless Steel Components Subject to Loss of Material Due to Pitting, Crevice, and 

Microbiologically-Influenced Corrosion Exposed to Raw Water (Internal)

LRA Table 3.2.2-2 addresses piping fabricated from stainless steel exposed to raw water 

(internal) subject to the loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion. The applicant credited the WCP Program for aging management of loss of material 

for the components described above. The AMR items cite generic note H, which indicates that 

the aging effect is not in the GALL Report for this component, material, and environment 

combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 
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applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR items discussed in this section are crediting the portion of the WCP 

Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will 

perform inspections of components during surveillance and maintenance activities to provide for 

the detection of degradation prior to the loss of intended function and will require that the extent 

of the inspection and its results be documented even when no signs of aging degradation are 

found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions 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 Loss of Material Due to General, Pitting, and Crevice Corrosion and Loss of Material 

Due to General, Pitting, Crevice, and Boric Acid Corrosion

LRA Table 3.2.1, item 3.2.1-33 addresses loss of material due to general, pitting, and crevice 

corrosion for steel encapsulation components exposed to air-indoor uncontrolled (internal). LRA 

Table 3.2.1, item 3.2.1-46 also addresses loss of material due to general, pitting, crevice, and 

boric acid corrosion for steel encapsulation components exposed to air with borated water 

leakage (internal).

The LRA credits the WCP Program to manage loss of material for steel valve enclosures in an 

air-indoor uncontrolled (internal) environment only in the safety injection system for 

item 3.2.1-33. The LRA credits the WCP Program to manage loss of material for steel valve 

enclosures in an air-moist (internal) environment only in the safety injection system for 

item 3.2.1-46.

For both items 3.2.1-33 and 3.2.1-46, the GALL Report recommends GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,‖ to manage 

this aging effect. 

By letter dated April 13, 2009, the applicant supplemented its LRA with additional information 

related to the WCP Program. In its letter, the applicant provided a comparison between the 
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program elements of the WCP Program and GALL AMP XI.M38, ―Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components.‖ The staff reviewed this 

comparison and noted that the applicant‘s program will be performing periodic visual inspections 

of in-scope components during maintenance and surveillance activities, consistent with the 

recommendations of GALL AMP XI.M38. 

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR items discussed in this section are crediting the portion of the WCP 

Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of steel to 

detect loss of material. The staff further determined that this program will perform inspections of 

components during surveillance and maintenance activities to provide for the detection of 

degradation prior to the loss of intended function and will require that the extent of the 

inspection and inspection results be documented even when no signs of aging degradation are 

found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

acceptable.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.2.2.3.3 Loss of Material Due to Selective Leaching of Steel and Copper Components

In LRA Tables 3.2.2-2, 3.3.2-8, and 3.3.2-19, the applicant stated that steel, including gray cast 

iron, and copper piping, piping components and piping elements exposed to lube oil are being 

managed for loss of material due to selective leaching by the Selective Leaching of Materials 

Program. The AMR line items cite generic note H, indicating that for the line item(s), the aging 

effect is not in the GALL Report for this component, material, and environment combination.

The staff reviewed all AMR result line items in the GALL Report where the component and 

material is steel, including gray cast iron, and copper piping, piping components, and piping 

elements exposed to lube oil and confirmed that this aging effect does not have an entry in the 

GALL Report for this component, material, and environment combination. 
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The staff reviewed the applicant‘s Selective Leaching of Materials Program and its evaluation is 

documented in SER Section 3.0.3.1.12. The staff finds the applicant‘s currently proposed use of 

this AMP to manage the aging effects for these AMR line items acceptable because: (1) the 

applicant‘s program includes examinations that will determine whether loss of material due to 

selective leaching is occurring from a sample population, (2) the examinations being performed 

will consist of a visual examination supplemented by mechanical testing, such as scraping or 

chipping, to detect if loss of material due to selective leaching has occurred, and (3) results of 

the examinations will be evaluated to determine acceptability of the component, and in cases of 

failure to meet criteria, a suitable expansion in scope of inspection.

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 addressed in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.2.2.3.4 Loss of Material Due to Microbiologically-Influenced Corrosion for Stainless Steel and 

Steel

In LRA Table 3.2.2-1, the applicant stated that the stainless steel containment spray pump 

gland seal coolers (tubing) exposed to treated water-closed-cycle cooling (external) and steel 

containment spray pump gland seal coolers (shell) exposed to treated water-closed-cycle 

cooling (internal) are being managed for loss of material due to MIC. In LRA Table 3.2.2-2, the 

applicant stated that the stainless steel safety injection pump gland seal coolers (tubing) 

exposed to treated water-closed-cycle cooling (external) and steel safety injection pump gland 

seal coolers (shell) exposed to treated water-closed-cycle cooling (internal) are being managed 

for loss of material due to MIC. In LRA Table 3.2.2-3, the applicant stated that the stainless steel 

residual heat exchangers (tubes and tubesheet) and shaft seal heat exchangers (tubing) 

exposed to treated water-closed-cycle cooling (external) and steel residual heat exchanger and 

shaft seal heat exchanger shells exposed to treated water-closed-cycle cooling (internal) are 

being managed for loss of material due to MIC. The applicant credited the Closed-Cycle Cooling 

Water System Program and the WCP Program to manage this aging effect for the components 

described above. The AMR items cite generic note H, which indicates that the aging effect is not 

in the GALL Report for this component, material, and environment combination.

The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff further determined that the performance of these systems are 

monitored to verify the effectiveness of the chemistry controls, which include system operation 

monitoring, system testing, heat exchanger thermal performance testing, heat exchanger tube 

eddy current testing, and pump performance testing. 

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

would be consistent with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff determined the 

applicant‘s WCP Program will manage the aging effects of loss of material through program 

inspections that provide verification of the effectiveness of Closed-Cycle Cooling Water System 

Program. The staff also determined that these inspections will be performed by using NDE 
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techniques that are effective and capable of identifying these potential aging effects, and that 

the sample size and location will be based on an assessment of materials, environments, 

plausible aging effects, and OE. Based on its review, the staff finds the applicant‘s use of the 

programs identified above acceptable because the chemistry control will provide an 

environment that is not conducive for loss of material to occur and the applicant will verify the 

effectiveness of the chemistry control with performance monitoring and examinations performed 

by its WCP 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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.3.5 Loss of Material Due to General, Pitting, and Crevice Corrosion for Steel

In LRA Table 3.2.2-1, the applicant stated that the steel caustic additive filter housing, caustic 

additive recirculation and fill pump, caustic additive standpipe, caustic additive fill tank, and 

piping and valves exposed to treated water-primary are being managed for loss of material due 

general, pitting, and crevice corrosion by the Primary Water Chemistry Program and WCP 

Program. The AMR line items cite generic note H, indicating that for the line items, the aging 

effect is not in the GALL Report for this component, material, and environment combination.

The staff reviewed the applicant‘s Primary Water Chemistry Program and WCP Program; these 

evaluations are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff 

determined that the Primary Water Chemistry Program includes periodic monitoring and control 

of contaminants such as chloride, fluoride, dissolved oxygen, and sulfate concentrations below 

specified levels that may result in loss of material and the program also maintains water quality 

(pH and conductivity). The staff further determined that the applicant‘s program specifies 

sampling and analysis frequencies and corrective actions if specified limits are exceeded. The 

staff determined the applicant‘s WCP Program will manage the aging effects of loss of material 

through program inspections that provide verification of the effectiveness of Primary Water 

Chemistry Program. The staff further determined that these inspections will be performed by 

using NDE techniques that are effective and capable of identifying these potential aging effects, 

and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE. Based on its review, the staff finds the 

applicant‘s use of the programs identified above acceptable because the chemistry control will 

provide an environment that is not conducive for loss of material to occur, and the applicant will 

verify the effectiveness of the chemistry control with examinations performed by its WCP 

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 functions 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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3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions 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 system components and component groups, comprised into the following systems:

● new fuel storage system

● spent fuel storage system

● spent fuel pool cooling system

● fuel handling system

● cranes (excluding fuel handling) system

● service water system

● component cooling system

● station and instrument air system

● chemical and volume control system

● control room air conditioning system

● auxiliary building air conditioning system

● auxiliary building special ventilation and steam exclusion system

● auxiliary building ventilation system

● reactor building ventilation system

● turbine building and screenhouse ventilation system

● shield building ventilation system

● technical support center ventilation system

● fire protection system

● diesel generator system

● circulating water system

● gaseous waste processing and discharge system

● liquid waste processing and discharge system

● radiation monitoring system

● makeup and demineralized water system

● service water pretreatment system

● miscellaneous drains and sumps system

● miscellaneous gas system

● potable water system

● primary sampling system
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3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary system components and component 

groups. LRA Table 3.3.1, ―Summary of Aging Management Programs for Auxiliary Systems 

Evaluated in Chapter VII of NUREG 1801,‖ is a summary comparison of the applicant‘s AMRs 

with those evaluated in the GALL Report for the auxiliary system components and component 

groups.

The applicant‘s AMRs evaluated and incorporated applicable plant-specific and industry OE in 

the determination of AERMs. The plant-specific evaluation included issue reports and 

discussions with appropriate site personnel to identify AERMs. The applicant‘s review of 

industry OE included a review of the GALL Report and OE issues identified since the issuance 

of the GALL Report.

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 auxiliary system components, within the 

scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended functions 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 AMPs to confirm the applicant‘s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant‘s 

AMPs and related documentation and to verify the applicant‘s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff‘s evaluations of the AMPs are documented in SER Section 3.0.3.

The staff reviewed the AMRs to confirm the applicant‘s claim that certain identified 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 had identified the appropriate GALL Report AMRs. Details of 

the staff‘s evaluation are discussed in SER Sections 3.3.2.1 and 3.3.2.2.

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The 

review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff‘s evaluation are discussed in SER Section 3.3.2.3.

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant‘s OE 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.
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Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel cranes –

structural girders 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-1)

Cumulative 

fatigue damage

TLAA to be 

evaluated for 

structural girders 

of cranes. See 

SRP-LR, 

Section 4.7 for 

generic guidance 

for meeting the 

requirements of 

10 CFR 

54.21(c)(1)

Yes TLAA 4.7.1 Fatigue is a TLAA

(See SER 

Sections 3.3.2.2.1 

and 4.7.1)

Steel and stainless 

steel piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

air-indoor 

uncontrolled, 

treated borated 

water or treated 

water

(3.3.1-2)

Cumulative 

fatigue damage

TLAA, evaluated 

in accordance with 

10 CFR 54.21(c)

Yes TLAA 4.3 Fatigue is a TLAA

(See SER 

Sections 3.3.2.2.1 

and 4.3)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water

(3.3.1-3)

Reduction of 

heat transfer 

due to fouling

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate solution 

> 60 °C (140 °F)

(3.3.1-4)

Cracking due to

SCC

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel and 

stainless clad steel 

heat exchanger 

components 

exposed to treated 

water > 60 °C 

(140 °F)

(3.3.1-5)

Cracking due to 

SCC

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel 

diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to diesel 

exhaust

(3.3.1-6)

Cracking due to 

SCC

A plant-specific 

AMP is to be 

evaluated.

Yes WCP Program Consistent with the 

GALL Report
Aging Management Review Results

3-277

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

non-regenerative 

heat exchanger 

components 

exposed to treated 

borated water 

> 60 °C (140 °F)

(3.3.1-7)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a 

plant-specific 

verification 

program. An 

acceptable 

verification 

program is to 

include 

temperature and 

radioactivity 

monitoring of the 

shell side water 

and eddy current 

testing of tubes.

Yes Primary Water 

Chemistry 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.4.1)

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

borated water 

> 60 °C (140 °F)

(3.3.1-8)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a 

plant-specific 

verification 

program. The 

AMP is to be 

augmented by 

verifying the 

absence of 

cracking due to 

SCC and cyclic 

loading. A 

plant-specific AMP 

is to be evaluated.

Yes Primary Water 

Chemistry 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.4.2)

Stainless steel 

high-pressure pump 

casing in PWR 

chemical and 

volume control 

system (CVCS)

(3.3.1-9)

Cracking due to 

SCC and cyclic 

loading

Water Chemistry 

and a 

plant-specific 

verification 

program. The 

AMP is to be 

augmented by 

verifying the 

absence of 

cracking due to 

SCC and cyclic 

loading. A 

plant-specific AMP 

is to be evaluated.

Yes WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.4.3)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-10)

Cracking due to 

SCC and cyclic 

loading

Bolting Integrity. 

The AMP is to be 

augmented by 

appropriate 

inspection to 

detect cracking if 

the bolts are not 

otherwise 

replaced during 

maintenance.

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.2.4.4)
Aging Management Review Results

3-278

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomer seals and 

components 

exposed to 

air-indoor 

uncontrolled 

(internal/external)

(3.3.1-11)

Hardening and 

loss of strength 

due to elastomer 

degradation

A plant-specific 

AMP is to be 

evaluated.

Yes External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.5.1)

Elastomer lining 

exposed to treated 

water or treated 

borated water

(3.3.1-12)

Hardening and 

loss of strength 

due to elastomer 

degradation

A plant-specific 

AMP that 

determines and 

assesses the 

qualified life of the

linings in the 

environment is to 

be evaluated.

Yes Not applicable 

to KPS

Not applicable

(See SER 

Section 3.3.2.1.1)

Boral, boron steel 

spent fuel storage 

racks 

neutron-absorbing 

sheets exposed to 

treated water or 

treated borated 

water

(3.3.1-13)

Reduction of 

neutronabsorbing 

capacity and 

loss of material 

due to general 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Plant-specific 

surveillance 

commitments 

for boron 

carbide and 

Boral

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.6)

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.3.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.7.1)

Steel RCP oil 

collection system 

piping, tubing, and 

valve bodies 

exposed to 

lubricating oil

(3.3.1-15)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.7.1)

Steel RCP oil 

collection system 

tank exposed to 

lubricating oil

(3.3.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection to 

evaluate the 

thickness of the 

lower portion of 

the tank.

Yes Fire Protection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.7.1)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.3.1-17)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable

(See SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-279

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

steel diesel engine 

exhaust piping, 

piping components, 

and piping elements 

exposed to diesel 

exhaust

(3.3.1-18)

Loss of 

material/general 

(steel only), 

pitting, and 

crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.7.3)

Steel (with or 

without coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil

(3.3.1-19)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Buried Piping and 

Tanks 

Surveillance or 

Buried Piping and 

Tanks Inspection

Yes Buried Piping 

and Tanks 

Inspection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.2.2.2.8)

Steel piping, piping 

components, piping 

elements, and tanks 

exposed to fuel oil

(3.3.1-20)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion and 

fouling

Fuel Oil Chemistry 

and One-Time 

Inspection

Yes Fuel Oil 

Chemistry 

Program, Fuel 

Oil Tank 

Inspections 

Program, and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.9.1)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil

(3.3.1-21)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion and 

fouling

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.9.2)

Steel with elastomer 

lining or stainless 

steel cladding 

piping, piping 

components, and 

piping elements 

exposed to treated 

water and treated 

borated water

(3.3.1-22)

Loss of material 

due to pitting 

and crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation)

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.2.10.1)

Stainless steel and 

steel with stainless 

steel cladding heat 

exchanger 

components 

exposed to treated 

water

(3.3.1-23)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-280

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.3.1-24)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Copper alloy HVAC 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(external)

(3.3.1-25)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes External 

Surfaces 

Monitoring 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.10.3)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.3.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.10.4)

Stainless steel 

HVAC ducting and 

aluminum HVAC 

piping, piping 

components, and 

piping elements 

exposed to 

condensation

(3.3.1-27)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes External 

Surfaces 

Monitoring 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.10.5)

Copper alloy fire 

protection piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal)

(3.3.1-28)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Fire Protection 

Program, WCP 

Program, and 

Compressed 

Air Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.10.6)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil

(3.3.1-29)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific 

AMP is to be 

evaluated.

Yes Buried Piping 

and Tanks 

Inspection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.10.7)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate solution

(3.3.1-30)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-281

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.3.1-31)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

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 

microbiologically

-influenced 

corrosion

Fuel Oil Chemistry 

and One-Time 

Inspection

Yes Fuel Oil 

Chemistry 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.12.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.3.1-33)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis 

Program and 

WCP Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.12.2)

Elastomer seals and 

components 

exposed to 

air-indoor 

uncontrolled 

(internal or external)

(3.3.1-34)

Loss of material 

due to wear

A plant-specific 

AMP is to be 

evaluated.

Yes WCP Program 

and External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.2.13)

Steel with stainless 

steel cladding pump 

casing exposed to 

treated borated 

water

(3.3.1-35)

Loss of material 

due to cladding 

breach

A plant-specific 

AMP is to be 

evaluated. 

Reference NRC 

IN 94-63, ―Boric 

Acid Corrosion of 

Charging Pump 

Casings Caused 

by Cladding 

Cracks.‖

Yes Not applicable 

to KPS

KPS does not have 

centrifugal charging 

pumps

(See SER 

Section 3.3.2.2.14)

Boraflex spent fuel 

storage racks 

neutron-absorbing 

sheets exposed to 

treated water

(3.3.1-36)

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation

Boraflex 

Monitoring

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60 °C 

(140 °F)

(3.3.1-37)

Cracking due to 

SCC and 

IGSCC

BWR Reactor 

Water Cleanup 

System

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-282

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60 °C 

(140 °F)

(3.3.1-38)

Cracking due to 

SCC

BWR 

Stress-Corrosion 

Cracking and 

Water Chemistry

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel BWR 

spent fuel storage 

racks exposed to 

treated water 

> 60 °C (140 °F)

(3.3.1-39)

Cracking due to 

SCC

Water Chemistry No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Steel tanks in diesel 

fuel oil system 

exposed to 

air-outdoor 

(external)

(3.3.1-40)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Aboveground 

Steel Tanks

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.1.2)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-41)

Cracking due to 

cyclic loading 

and SCC

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-42)

Loss of material 

due to general 

corrosion

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel bolting and 

closure bolting 

exposed to 

air-indoor 

uncontrolled 

(external) or 

air-outdoor 

(external)

(3.3.1-43)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel compressed 

air system closure 

bolting exposed to 

condensation

(3.3.1-44)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel closure bolting 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-45)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Bolting Integrity No Bolting 

Integrity 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-283

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

stainless clad steel 

piping, piping 

components, piping 

elements, and heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water > 60 °C 

(140 °F)

(3.3.1-46)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report

Steel piping, piping 

components, piping 

elements, tanks, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-47)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report

Steel piping, piping 

components, piping 

elements, tanks, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-48)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report

Stainless steel, 

steel with stainless 

steel cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-49)

Loss of material 

due to 

microbiologically

-influenced 

corrosion

Closed-Cycle 

Cooling Water 

System

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water

(3.3.1-50)

Loss of material 

due to pitting 

and crevice 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report
Aging Management Review Results

3-284

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to 

closed-cycle cooling 

water

(3.3.1-51)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report

Steel, stainless 

steel, and copper 

alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.3.1-52)

Reduction of 

heat transfer 

due to fouling

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

Program and 

WCP Program

Consistent with the 

GALL Report

Steel compressed 

air system piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal)

(3.3.1-53)

Loss of material 

due to general 

and pitting 

corrosion

Compressed Air 

Monitoring

No Compressed 

Air Monitoring 

Program

Consistent with the 

GALL Report

Stainless steel 

compressed air 

system piping, 

piping components, 

and piping elements 

exposed to internal 

condensation

(3.3.1-54)

Loss of material 

due to pitting 

and crevice 

corrosion

Compressed Air 

Monitoring

No Compressed 

Air Monitoring 

Program

Consistent with the 

GALL Report

Steel ducting 

closure bolting 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-55)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No Bolting 

Integrity 

Program

Consistent with the 

GALL Report

Steel HVAC ducting 

and components 

external surfaces 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-56)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-285

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping and 

components 

external surfaces 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-57)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Steel external 

surfaces exposed to 

air-indoor 

uncontrolled 

(external), 

air-outdoor 

(external), and 

condensation 

(external)

(3.3.1-58)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report (Two 

exceptions are 

covered in SER 

Section 3.3.2.23)

Steel heat 

exchanger 

components 

exposed to 

air-indoor 

uncontrolled 

(external) or 

air-outdoor 

(external)

(3.3.1-59)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

air-outdoor 

(external)

(3.3.1-60)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

External Surfaces 

Monitoring

No External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Elastomer fire 

barrier penetration 

seals exposed to 

air-outdoor or 

air-indoor 

uncontrolled

(3.3.1-61)

Increased 

hardness, 

shrinkage, and 

loss of strength 

due to 

weathering

Fire Protection No Fire Protection 

Program

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-62)

Loss of material 

due to pitting 

and crevice 

corrosion

Fire Protection No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Steel fire-rated 

doors exposed to 

air-outdoor or 

air-indoor 

uncontrolled

(3.3.1-63)

Loss of material 

due to wear

Fire Protection No Fire Protection 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-286

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil

(3.3.1-64)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Fire Protection 

and Fuel Oil 

Chemistry

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Reinforced concrete 

structural fire 

barriers – walls, 

ceilings, and floors 

exposed to 

air-indoor 

uncontrolled

(3.3.1-65)

Concrete 

cracking and 

spalling due to 

aggressive 

chemical attack 

and reaction 

with aggregates

Fire Protection 

and Structures 

Monitoring

No Fire Protection 

Program and 

Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers – walls, 

ceilings, and floors 

exposed to 

air-outdoor

(3.3.1-66)

Concrete 

cracking and 

spalling due to 

freeze thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates

Fire Protection 

and Structures 

Monitoring

No Fire Protection 

Program and 

Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers – walls, 

ceilings, and floors 

exposed to 

air-outdoor or 

air-indoor 

uncontrolled

(3.3.1-67)

Loss of material 

due to corrosion 

of embedded 

steel

Fire Protection 

and Structures 

Monitoring

No Fire Protection 

Program and 

Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-68)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion and 

fouling

Fire Water System No Fire Protection 

Program and 

External 

Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-69)

Loss of material 

due to pitting 

and crevice 

corrosion and 

fouling

Fire Water System No Fire Protection 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-287

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-70)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion and 

fouling

Fire Water System No Fire Protection 

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to moist air 

or condensation 

(internal)

(3.3.1-71)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No WCP Program,

Compressed 

Air Monitoring 

Program, and 

Fire Protection 

Program

Consistent with the 

GALL Report

(See SER 

Sections 3.3.2.1.3 

and 3.3.2.1.4)

Steel HVAC ducting 

and components 

internal surfaces 

exposed to 

condensation 

(internal)

(3.3.1-72)

Loss of material 

due to general, 

pitting, crevice, 

and (for drip 

pans and drain 

lines) 

microbiologically

-influenced 

corrosion

Inspection of 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.3.2.1.4)

Steel crane 

structural girders in 

load handling 

system exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-73)

Loss of material 

due to general 

corrosion

Inspection of 

Overhead Heavy 

Load and Light 

Load (Related to 

Refueling) 

Handling Systems

No Inspection of 

Overhead 

Heavy Load 

and Refueling 

Handling 

Systems 

Program

Consistent with the 

GALL Report

Steel cranes – rails 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-74)

Loss of material 

due to wear

Inspection of 

Overhead Heavy 

Load and Light

Load (Related to 

Refueling) 

Handling Systems

No Inspection of 

Overhead 

Heavy Load 

and Refueling 

Handling 

Systems 

Program

Consistent with the 

GALL Report

Elastomer seals and 

components 

exposed to raw 

water

(3.3.1-75)

Hardening and 

loss of strength 

due to elastomer 

degradation; 

loss of material 

due to erosion

Open-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.3.2.3.29)
Aging Management Review Results

3-288

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

(without 

lining/coating or with 

degraded 

lining/coating) 

exposed to raw 

water

(3.3.1-76)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, 

fouling, and 

lining/coating 

degradation

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program and 

Compressed

Air Systems 

Monitoring 

Program

Consistent with the 

GALL Report

Steel heat 

exchanger 

components 

exposed to raw 

water

(3.3.1-77)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report

Stainless steel, 

Ni-alloy, and copper 

alloy piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-78)

Loss of material 

due to pitting 

and crevice 

corrosion

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water

(3.3.1-79)

Loss of material 

due to pitting 

and crevice 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report

Stainless steel and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-80)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Open-Cycle 

Cooling Water 

System

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water

(3.3.1-81)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-289

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy heat 

exchanger 

components 

exposed to raw 

water

(3.3.1-82)

Loss of material 

due to pitting, 

crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report

Stainless steel and 

copper alloy heat 

exchanger tubes 

exposed to raw 

water

(3.3.1-83)

Reduction of 

heat transfer 

due to fouling

Open-Cycle 

Cooling Water 

System

No Open-Cycle 

Cooling Water 

System 

Program

Consistent with the 

GALL Report

Copper alloy 

> 15% Zn piping, 

piping components, 

piping elements, 

and heat exchanger 

components 

exposed to raw 

water, treated 

water, or 

closed-cycle cooling 

water

(3.3.1-84)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Selective 

Leaching of 

Materials 

Program

Consistent with the 

GALL Report

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil, raw 

water, treated 

water, or 

closed-cycle cooling 

water

(3.3.1-85)

Loss of material 

due to selective 

leaching

Selective 

Leaching of 

Materials

No Selective 

Leaching of 

Materials 

Program

Consistent with the 

GALL Report

Structural steel 

(new fuel storage 

rack assembly) 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-86)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Structures 

Monitoring 

Program

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)

Boraflex spent fuel 

storage racks 

neutron-absorbing 

sheets exposed to 

treated borated 

water

(3.3.1-87)

Reduction of 

neutronabsorbing 

capacity due to 

boraflex 

degradation

Boraflex 

Monitoring

No Not applicable 

to KPS

Not applicable to 

KPS

(See SER 

Section 3.3.2.1.1)
Aging Management Review Results

3-290

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum and 

copper alloy 

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.3.1-88)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program

Consistent with the 

GALL Report

Steel bolting and 

external surfaces 

exposed to air with 

borated water 

leakage

(3.3.1-89)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program

Consistent with the 

GALL Report

Stainless steel and 

steel with stainless 

steel cladding 

piping, piping 

components, piping 

elements, tanks, 

and fuel storage 

racks exposed to 

treated borated 

water > 60 °C 

(140 °F)

(3.3.1-90)

Cracking due to 

SCC

Water Chemistry No WCP Program, 

Primary Water 

Chemistry 

Program, and 

ASME 

Section XI ISI 

(IWB, IWC, 

and IWD) 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.1.5)

Stainless steel and 

steel with stainless 

steel cladding 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water

(3.3.1-91)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No WCP Program 

and Primary 

Water 

Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.3.2.1.7)

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to 

air-indoor 

uncontrolled

(3.3.1-92)

None None No None Consistent with the 

GALL Report

(See SER 

Section 3.3.2.1.6)

Glass piping 

elements exposed 

to air, air-indoor 

uncontrolled 

(external), fuel oil, 

lubricating oil, raw 

water, treated 

water, and treated 

borated water

(3.3.1-93)

None None No None Consistent with the 

GALL Report
Aging Management Review Results

3-291

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel and 

Ni-alloy piping, 

piping components, 

and piping elements 

exposed to 

air-indoor 

uncontrolled 

(external)

(3.3.1-94)

None None No None Consistent with the 

GALL Report

Steel and aluminum 

piping, piping 

components, and 

piping elements 

exposed to 

air-indoor controlled 

(external)

(3.3.1-95)

None None No None Consistent with the 

GALL Report

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.3.1-96)

None None No None Consistent with the 

GALL Report

Steel, stainless 

steel, aluminum, 

and copper alloy 

piping, piping 

components, and 

piping elements 

exposed to gas

(3.3.1-97)

None None No None Consistent with the 

GALL Report

Steel, stainless 

steel, and copper 

alloy piping, piping 

components, and 

piping elements 

exposed to dried air

(3.3.1-98)

None None No None Consistent with the 

GALL Report

Stainless steel and 

copper alloy 

< 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.3.1-99)

None None No None Consistent with the 

GALL Report

The staff‘s review of the auxiliary system component groups followed several approaches. One 

approach, documented in SER Section 3.3.2.1, discusses the staff‘s review of AMR results for 

components the applicant indicated are consistent with the GALL Report and require no further 

evaluation. Another approach, documented in SER Section 3.3.2.2, discusses the staff‘s review 

of AMR results for components the applicant indicated are consistent with the GALL Report and 
Aging Management Review Results

3-292

for which further evaluation is recommended. A third approach, documented in SER 

Section 3.3.2.3, discusses the staff‘s review of AMR results for components 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 system components is 

documented in SER Section 3.0.3.

3.3.2.1 AMR Results That Are 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 system components:

● ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

● Bolting Integrity Program

● Boric Acid Corrosion Program

● Buried Piping and Tanks Inspection Program

● Closed-Cycle Cooling Water System Program

● Compressed Air Monitoring Program

● External Surfaces Monitoring Program

● Fire Protection Program

● Fuel Oil Chemistry Program

● Fuel Oil Tanks Inspection Program

● Inspection of Overhead Heavy Load and Refueling Handling Systems Program

● Lubricating Oil Analysis Program

● Open-Cycle Cooling Water System Program

● Primary Water Chemistry Program

● Secondary Water Chemistry Program

● Selective Leaching of Materials Program

● Work Control Process Program

LRA Tables 3.3.2-1 through 3.3.2-29 summarize AMRs for the auxiliary 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 had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item describing how the information in the 

tables aligns with the information in the GALL Report. The staff reviewed those AMRs with 

notes A through E, which indicate how the AMR was 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 Report 

AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 

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 AMP 

identified in the GALL Report. The staff reviewed these line items to verify consistency with the 

GALL Report and that it had reviewed and accepted the identified exceptions to the GALL 
Aging Management Review Results

3-293

Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had the same material, 

environment, aging effect, and AMP as the component under review. The staff reviewed these 

line items to verify consistency with the GALL Report. The staff also determined whether the 

AMR line item of the different component applied 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 AMP identified in the GALL Report. The staff reviewed these line items 

to verify consistency with the GALL Report. The staff confirmed whether the AMR line item of 

the different component was applicable to the component under review and whether the 

exceptions to the GALL Report AMPs had been reviewed and accepted by the staff. The staff 

also determined whether the AMP identified by the applicant was consistent with the AMP 

identified in the GALL Report 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 a different AMP is credited. The staff reviewed these line 

items to verify consistency with the GALL Report and determined whether the identified AMP 

would manage the aging effect consistent with the AMP identified in the GALL Report, 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, it did verify that the material presented in 

the LRA was applicable and that the applicant had identified the appropriate GALL Report 

AMRs. The staff‘s evaluation is discussed below.

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 

auxiliary systems‘ 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 3.3.1, the applicant‘s references to the GALL Report are 

acceptable and no further staff review is required.

3.3.2.1.1 AMR Results Identified as Not Applicable

LRA Table 3.3.1, items 3.3.1-3, 3.3.1-4, 3.3.1-5, 3.3.1-17, 3.3.1-23, 3.3.1-24, 3.3.1-30, 3.3.1-31, 

3.3.1-36 through -39, and 3.3.1-49 discuss the applicant‘s determination on GALL AMR items 

that are applicable only to BWR-designed reactors. In the applicant‘s AMR discussions for these 

items, no additional information is provided. The staff confirmed that these AMR items in 

Table 1 of the GALL Report, Volume 1 are only applicable to BWR-designed reactors, and that 

KPS is a PWR with a dry ambient containment. Based on this determination, the staff finds that 
Aging Management Review Results

3-294

the applicant has provided an acceptable basis for concluding that AMR items 3.3.1-3, 3.3.1-4, 

3.3.1-5, 3.3.1-17, 3.3.1-23, 3.3.1-24, 3.3.1-30, 3.3.1-31, 3.3.1-36 through -39, and 3.3.1-49 in 

Table 1 of the GALL Report, Volume 1 are not applicable to KPS.

LRA Table 3.3.1, item 3.3.1-12 addresses elastomer lined components in the SFP cooling 

system 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 due to hardening and 

loss of strength for this component group. The applicant stated that this item is not applicable 

because there are no in-scope lined components exposed to treated water or treated borated 

water in its SFP cooling and cleanup system. The staff reviewed LRA Sections 2.3.1 and 3.3 

and confirmed that the applicant‘s LRA does not have any AMR results for the spent fuel system 

that include elastomer lined components exposed to treated water or treated borated water. The 

staff also noted that a search of the applicant‘s USAR failed to find any evidence of elastomer 

lined components in the SFP cooling or cleanup systems. Based on its review of the LRA and 

USAR, the staff confirmed that there are no in-scope elastomer lined components exposed to 

treated water or treated borated water in the spent fuel cooling and cleanup system and, 

therefore, finds the applicant‘s determination acceptable.

LRA Table 3.3.1, item 3.3.1-62 addresses aluminum piping, piping components, and piping 

elements exposed to raw water. The GALL Report recommends the use of GALL AMP XI.M26, 

―Fire Protection,‖ to manage loss of material due to pitting and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because the applicant‘s 

fire protection system does not contain aluminum piping, piping components, and piping 

elements exposed to raw water. The staff reviewed LRA Sections 2.3 and 3.3 and confirmed 

that the applicant‘s LRA does not have any AMR results for the fire protection system that 

include aluminum piping, piping components, and piping elements exposed to raw water. The 

staff also noted that a search of the applicant‘s USAR did not find any evidence of aluminum 

piping, piping components, and piping elements in the fire protection systems exposed to raw 

water. Based on its review of the LRA and USAR, the staff confirmed that there are no in-scope 

aluminum piping, piping components, and piping elements exposed to raw water in the fire 

protection systems and, therefore, finds the applicant‘s determination acceptable.

LRA Table 3.3.1, item 3.4.1-64 addresses steel piping, piping components, and piping elements 

exposed to fuel oil. The GALL Report recommends the use of GALL AMP XI.M26, ―Fire 

Protection,‖ and GALL AMP XI.M30, ―Fuel Oil Chemistry,‖ to manage loss of material due to 

pitting and crevice corrosion for this component group. The applicant stated that this item is not 

applicable because the applicant‘s fire protection system does not contain steel piping, piping 

components, and piping elements exposed to fuel oil. The staff reviewed LRA Sections 2.3 and 

3.3 and confirmed that the applicant‘s LRA does not have any AMR results for the fire protection 

system that include steel piping, piping components, and piping elements exposed to fuel oil. 

The staff also noted that a search of the applicant‘s USAR did not find any evidence of steel 

piping, piping components, and piping elements in the fire protection systems exposed to fuel 

oil. Based on its review of the LRA and USAR, the staff confirmed that there are no in-scope 

steel piping, piping components, and piping elements exposed to fuel oil in the fire protection 

systems and, therefore, finds the applicant‘s determination acceptable.

LRA Table 3.3.1, item 3.3.1-86 refers to a loss of material due to general, pitting, and crevice 

corrosion for structural steel in new fuel storage rack assemblies exposed to air-indoor 

uncontrolled (external). The applicant stated that this item is not applicable because the new 

fuel storage rack assemblies are composed of stainless steel. The staff reviewed LRA 
Aging Management Review Results

3-295

Sections 2.3.1 and 3.3, and the applicant‘s USAR, and confirmed the applicant‘s statement. 

Based on its review of the LRA and USAR, the staff finds the applicant‘s determination 

acceptable.

LRA Table 3.3.1, item 3.3.1-87 refers to a reduction of neutron-absorbing capacity due to 

boraflex degradation in spent fuel storage rack neutron-absorbing sheets composed of boraflex 

and exposed to treated borated water. The applicant stated that this item is not applicable 

because there is no boraflex in the spent fuel storage racks. The applicant uses boron carbide 

and Boral for neutron absorption. The staff reviewed LRA Sections 2.3.1 and 3.3, and the 

applicant‘s USAR, and confirmed the applicant's statement. Based on its review of the LRA and 

USAR, the staff finds the applicant‘s determination acceptable.

3.3.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion in Diesel Generator 

Expansion Tanks

LRA Table 3.3.1, item 3.3.1-40 and associated AMRs in LRA Table 3.3.2-19 address loss of 

material due to general, pitting, and crevice corrosion in the diesel generator expansion tanks 

surfaces exposed to outdoor air.

The LRA credits the External Surfaces Monitoring Program to manage this aging effect for the 

diesel generator expansion tanks. The GALL Report recommends GALL AMP XI.M29, 

―Aboveground Steel Tanks,‖ to manage this aging effect. The AMR item in Table 3.3.2-19, that 

references GALL Report Table 3, item 40, cites generic note A, indicating that the AMR item is 

consistent with the GALL Report component, material, environment, aging effect, and AMP. The 

staff noted that the correct generic note reference should have been E. 

The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. The staff reviewed the applicant‘s AMR item associated 

with item 3.3.1-40 and noted that the applicant credited GALL Report AMR item VII.H1-11 in 

LRA Table 3.3.2-19. The GALL Report recommends using GALL AMP XI.M29, ―Aboveground 

Steel Tanks,‖ to manage this aging effect. 

The staff noted that there are differences between GALL AMP XI.M36, ―External Surfaces 

Monitoring,‖ and GALL AMP XI.M29, ―Aboveground Steel Tanks.‖ GALL AMP XI.M36 is a 

condition based monitoring program, while GALL AMP XI.M29 is a preventive maintenance 

program. Both GALL AMPs XI.M36 and XI.M29 include visual inspections and periodic 

walkdowns, with sampling allowed. GALL AMP XI.M29 recommends caulking or sealant be 

applied to the perimeter of the interface between the tank and its slab or foundation. In contrast, 

GALL AMP XI.M36 includes no preventive measures against corrosion. In the ―parameters 

monitored or inspected‖ program element, GALL AMP XI.M29 recommends the inspection of 

caulking and sealant while GALL AMP XI.M36 discusses inspection of bare surfaces, paint, and 

insulation. In addition to differences in the visual inspections, GALL AMP XI.M29 also 

recommends UT to determine the thickness of the tank bottom, when the tank bottom is in 

contact with the ground to ensure significant degradation is not occurring. By letter dated 

December 3, 2009, the staff issued RAI 3.3.2.1-1 requesting that the applicant identify the

location of the expansion tanks, including type of foundation, accessibility of the tanks for full 

visual inspections, and frequency of those inspections. 

In its response dated January 21, 2010, the applicant stated that the expansion tanks include 

the jacket water expansion tanks for the EDG and for the TSC diesel generator. The applicant 

also stated that, for the EDG, the tank is located about 8 feet above the skid of the diesel 
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generator in the basement of the administration building. For the TSC diesel generator, the 

jacket water expansion tank is located on a steel frame about 7 feet above the roof of the TSC 

building. The applicant further stated that both diesel generators are operated on a monthly 

basis to satisfy technical and surveillance requirements, during which time an external visual 

examination is conducted.

The staff finds the applicant‘s response acceptable because the expansion tanks are elevated 

and, therefore, do not have foundations where moisture collection would be a concern. The staff 

finds that the inspection performed, in accordance with the External Surfaces Monitoring 

Program, is consistent with the GALL Report recommendations for aboveground steel tanks that 

are not in contact with the soil or concrete. The staff‘s concern described in RAI 3.3.2.1-1 is 

resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-71 addresses loss of material due to general, pitting, and crevice 

corrosion for steel piping, piping components, and piping elements exposed to moist air or 

condensation (internal).

The LRA credits the Fire Protection Program to manage this aging effect for steel CO2 storage 

tank, Halon cylinders, odorizers, and retarding chambers in LRA Table 3.3.2-18. The LRA 

credits the Compressed Air Monitoring program to manage this aging effect for steel air dryers, 

compressor casings, filter housings, piping, traps, and valves in Table 3.3.2-19. The GALL

Report recommends GALL AMP XI.M38, ―Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,‖ to manage this aging effect. The AMR items that reference 

this item cite generic note E, indicating that the AMR items are consistent with the GALL Report 

material, environment, and aging effect, but a different AMP is credited. The staff noted that for 

one AMR item, the applicant referenced generic note A. The staff noted that this was a 

typographical error and, by letter dated January 21, 2010, the applicant amended its LRA to 

state that these items cite generic note E.

GALL AMP XI.M38 recommends periodic visual inspections of the internal surface of 

components when accessible during performance of maintenance or surveillance activities. The 

staff noted that the steel CO2 storage tank, Halon cylinders, odorizers, and retarding chambers 

are in the Halon and CO2 fire protection system. The staff reviewed the Fire Protection Program, 

which provides for periodic visual inspection and performance testing of the Halon and CO2

system components for managing loss of material due to corrosion. The staff‘s review of the 

Fire Protection Program and its evaluation is documented in SER Section 3.0.3.2.8. On the 

basis that periodic visual inspections are performed, the staff finds that the Fire Protection 

Program will adequately manage loss of material due to general, pitting, and crevice corrosion 

of fire protection system steel Halon and CO2 components exposed to an air-moist internal 

environment during the period of extended operation.

GALL AMP XI.M38 recommends periodic visual inspections of the internal surface of 

components when accessible during performance of maintenance or surveillance activities. The 

staff noted that the steel air dryers, compressor casings, filter housings, piping, traps, and 
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valves are in the air starting subsystem for the EDGs, so the applicant has proposed the 

Compressed Air Monitoring Program. The staff reviewed the Compressed Air Monitoring 

Program, which includes periodic visual inspections of internal surfaces of air dryers, 

compressor casings, filter housings, piping, traps, and valves for loss of material due to 

corrosion, for monitoring of system air quality in accordance with industry standards and 

guidelines. The staff‘s review of the Compressed Air Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.6. On the basis that periodic visual inspections of internal 

surfaces of air dryers, compressor casings, filter housings, piping, traps, and valves are 

performed, the staff finds that the Compressed Air Monitoring Program will adequately manage 

loss of material due to general, pitting, and crevice corrosion of instrument and control air 

system steel air dryers, compressor casings, filter housings, piping, traps, and valves exposed 

to an air-moist internal environment through the period of extended operation.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.1.4 Loss of Material Due to General, Pitting, and Crevice Corrosion and (For Drip Pans 

and Drain Lines) Due to Microbiologically-Influenced Corrosion

LRA Table 3.3.1, item 3.3.1-71 addresses loss of material due to general, pitting, and crevice 

corrosion for steel piping, piping components, and piping elements exposed to moist air or 

condensation (internal). LRA Table 3.3.1, item 3.3.1-72 also addresses loss of material due to 

general, pitting, crevice, and (for drip pans and drain lines) microbiologically-influenced 

corrosion for steel HVAC ducting and components internal surfaces exposed to condensation 

(internal).

The LRA credits the WCP Program to manage the respective aging effect for steel components 

in an air-moist (internal or external) environment only in the following systems for item 3.3.1-71: 

● diesel generator system

● fire protection system

● gaseous waste processing and discharge system

● liquid waste processing and discharge system

● miscellaneous drains and sumps system

● miscellaneous gas system

● reactor building ventilation system

● shield building ventilation system

The LRA also credits the WCP Program to manage the respective aging effect for steel 

components in an air-moist (internal or external) environment only in the following systems for 

item 3.3.1-72: 

● auxiliary building air conditioning system

● auxiliary building special ventilation and steam exclusion system

● auxiliary building ventilation system

● control room air conditioning system

● reactor building ventilation system
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● technical support center ventilation system

● turbine building and screenhouse ventilation system

For both items 3.3.1-71 and 3.3.1-72, the GALL Report recommends GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,‖ to manage 

this aging effect.

By letter dated April 13, 2009, the applicant supplemented its LRA with additional information 

related to the WCP Program. The applicant provided a comparison between the program 

elements of the WCP Program and GALL AMP XI.M38, ―Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components.‖ The staff reviewed this comparison and noted 

that the applicant‘s program will be performing periodic visual inspections of in-scope 

components during maintenance and surveillance activities, consistent with the 

recommendations of GALL AMP XI.M38.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR items discussed in this section are crediting the portion of the WCP 

Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of steel in 

order to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) require that the extent of 

the inspection and inspection results be documented, even when no signs of aging degradation 

are found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

acceptable.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions 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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3.3.2.1.5 Cracking Due to Stress-Corrosion Cracking

LRA Table 3.3.1, item 3.3.1-90 describes the cracking due to SCC of austenitic stainless steel 

components, from the auxiliary systems, that were exposed to treated borated water greater 

than 60 °C (140 °C). The AMR items corresponding to item 3.3.1-90 include piping/tubing, 

piping elements, tanks, evaporator, distillate cooler, evaporator condenser, excess letdown heat 

exchanger, feed preheater, seal water heat exchanger, and valves in the CVCS (Table 3.3.2-9) 

and tubing, valves, filter housings, flow indicators, and sample heat exchangers in the primary 

sampling system (Table 3.3.2-29). The applicant stated that the cracking due to SCC of these 

stainless steel components is managed by the ASME Section XI ISI, Subsections IWB, IWC, 

and IWD Program; the WCP Program, which is a plant-specific program; and the Primary Water 

Chemistry Program. The applicant further stated that the program is consistent with the GALL 

Report. 

The staff reviewed LRA item 3.2.1-90 in comparison with the GALL Report Volume 1, Table 3, 

ID 90. In its review, the staff found that the LRA AMR items were consistent with the GALL 

Report in component, material, environment, and aging effect. The staff noted that for these 

AMR items, the GALL Report recommends GALL AMP XI.M2, ―Water Chemistry,‖ to manage 

the effects of cracking due to SCC. Consequently, the applicant‘s program is consistent with the 

GALL Report and, therefore, acceptable. However, the generic notes in Tables 3.3.2-9 and 

3.3.2-29 are confusing. Note A is listed for the Primary Water Chemistry Program and note E is 

listed for the WCP Program. Consistency note A means that the program is consistent with the 

GALL Report because the Primary Water Chemistry Program is used to manage the aging 

effects, whereas note E means that a different program, the WCP Program, is being credited to 

manage the aging effects. For these items, the use of the WCP Program should be considered 

an additional program that provides inspection capabilities beyond what is specified in the GALL 

Report. The staff finds that the AMP proposed by the applicant is at least as comprehensive as 

that recommended in the GALL Report.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.6 Galvanized Steel Piping, Piping Components, and Piping Elements Exposed to 

Air-Indoor Uncontrolled

LRA Table 3.3.1, item 3.3.1-92 addresses galvanized steel piping, piping components, and

piping elements exposed to air-indoor uncontrolled and states that there are no aging effects or 

mechanisms, and no AMP is recommended. The GALL Report, Table VII, item VII.J-6 (AP-13) 

recommends that there is no aging effect or aging mechanism and that no AMP is 

recommended for this component group and, therefore, the staff finds the applicant‘s 

determination acceptable.

3.3.2.1.7 Loss of Material Due to Pitting and Crevice Corrosion of Stainless Steel Piping, Piping 

Components, Piping Elements, and Steel with Stainless Steel Cladding Exposed to Treated 

Borated Water

LRA Table 3.3.1, item 3.3.1-91 addresses stainless steel piping, piping components, piping 

elements, and steel with stainless steel cladding exposed to treated borated water which are

being managed for loss of material due to pitting and crevice corrosion. The LRA credits the 
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Primary Water Chemistry Program and WCP Program to manage this aging effect for this 

component group. The GALL Report recommends GALL AMP XI.M2, ―Water Chemistry,‖ to 

ensure that these aging effects are adequately managed. In Table 3.3.1, the applicant assigned 

each component two items, one in which the Primary Water Chemistry Program is credited and 

another in which the WCP Program is credited. The applicant stated that all the items for which 

the Primary Water Chemistry Program is credited are fully consistent with the GALL Report, 

citing generic note A. The applicant also stated that all the items for which the WCP Program is 

credited are consistent with the GALL Report in all respects except a different AMP is credited, 

citing generic note E.

The staff reviewed the applicant‘s Primary Water Chemistry Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. In its 

review of components associated with item 3.3.1-91 assigned generic note E, the staff noted 

that the GALL Report does not recommend that the effectiveness of the Primary Water 

Chemistry Program be confirmed by an inspection program. The staff also noted that the 

applicant proposed to manage the aging of the components under consideration using the 

Primary Water Chemistry Program, as is recommended by the GALL Report. In addition, the 

applicant proposed to use the WCP Program, which is an inspection program, to supplement 

the Primary Water Chemistry Program, in excess of the recommendations in the GALL Report. 

The staff finds that the AMPs proposed by the applicant are in excess of those recommended 

by the GALL Report and are, therefore, acceptable.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, Fouling, and Lining-Coating Degradation of Steel Piping, Piping Components, and 

Piping Elements Exposed to Raw Water

LRA Table 3.3.1, item 3.3.1-76 addresses steel piping, piping components, and piping elements 

exposed to raw water which are being managed for loss of material due to general, pitting, 

crevice, and microbiologically-influenced corrosion, fouling, and lining-coating degradation by 

the Open-Cycle Cooling Water System, WCP, and Compressed Air Monitoring programs. The 

applicant cited two generic notes: (1) generic note B indicating that the items are consistent with 

the GALL Report item for component, material, environment, and aging effect, but the AMP 

takes some exceptions to the GALL Report AMP; and (2) generic note E indicating that the item 

is consistent with the GALL Report item for material, environment, and aging effect, but a 

different AMP is credited.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is steel piping, piping components, and piping elements exposed to raw water and noted 

that the GALL Report recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ to 

manage the aging effects of loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion, fouling, and lining/coating degradation.

The staff reviewed the applicant‘s Open-Cycle Cooling Water System, WCP, and Compressed 

Air Monitoring programs and its evaluations are documented in SER Sections 3.0.3.2.14, 

3.0.3.2.19, and 3.0.3.2.6, respectively. The LRA credits the Open-Cycle Cooling Water System 

Program for safety-related generic note B items. In its review of components associated with 
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LRA item 3.3.1-76, for which the applicant assigned generic note B, the staff noted that the AMP 

recommended by the GALL Report is intended for use with coated or lined components, while at 

least some of the components under consideration are unlined. The staff also noted that the 

inspection procedures and intervals recommended in the GALL Report may be inadequate 

because unlined steel components exposed to raw water are expected to corrode at a much 

higher rate than lined components. The staff previously identified this issue in its audit of the 

applicant‘s Open-Cycle Cooling Water Program and issued RAI B2.1.23-1 by letter dated 

July 13, 2009. In its response dated August 17, 2009, the applicant addressed components of 

its program which are designed to account for the higher corrosion rate expected for unlined 

piping. The staff found the applicant‘s response acceptable and its evaluation is found in SER 

Section 3.0.3.2.14.

The LRA credits the Compressed Air Monitoring Program for one item in LRA Table 3.3.2-19, 

consisting of traps in the diesel generator system, citing generic note E. Given that the 

components are listed as traps and are associated with the diesel generator air system, their 

inclusion in the compressed air system is reasonable. The staff finds the applicant‘s use of the 

Compressed Air Monitoring Program to manage the aging of these components acceptable 

because this program is a multifaceted program which will both mitigate and detect corrosion on 

the internal surfaces of traps.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.9 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion of 

Stainless Steel and Copper Piping, Piping Components, and Piping Elements Exposed to Raw 

Water

LRA Table 3.3.1, item 3.3.1-80 addresses stainless steel and copper piping, piping components, 

and piping elements exposed to raw water which are being managed for loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion by the WCP and Structures 

Monitoring programs. The applicant cited generic note E indicating that the item is consistent 

with the GALL Report item for material, environment, and aging effect, but a different AMP is 

credited.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is stainless steel and copper piping, piping components, and piping elements exposed to 

raw water and noted that the GALL Report recommends GALL AMP XI.M20, ―Open-Cycle 

Cooling Water System,‖ to monitor the aging effects of loss of material due to pitting, crevice, 

and microbiologically-influenced corrosion.

The staff reviewed the applicant‘s WCP and Structures Monitoring programs and its evaluations 

are documented in SER Sections 3.0.3.2.19 and 3.0.3.2.18, respectively. In its review of LRA 

item 3.3.1-80, the staff noted that there are two items associated with this LRA item that cite 

generic note E, which are sumps in the RCV system (LRA Table 3.5.2-1) and trash grills 

anchorage in the intake structure system (LRA Table 3.5.2-11). The staff finds the use of the 

Structures Monitoring Program acceptable for the sumps in the RCV system because the 

sumps addressed in LRA Table 3.5.2-1 are structural and these sumps would not benefit from 
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the aging management activities contained in the Open-Cycle Cooling Water Program other 

than by visual inspection, which is included in the Structures Monitoring Program. It is not, 

however, clear to the staff that the trash grills anchorage addressed in LRA Table 3.5.2-11 

would not benefit from the aging management activities associated with the Open-Cycle Cooling 

Water Program. For example, it is not clear to the staff that an accumulation of mussels or 

clams on these anchorages would not obstruct water flow to the trash grills. It is, therefore, not 

clear to the staff that these anchors should not be subject to biocide applications and detailed 

inspections for the presence of biofouling organisms, as contained in the Open-Cycle Cooling 

Water Program. By letter dated January 4, 2010, the staff issued RAI 3.3.2.1-3 requesting that 

the applicant provide sufficient information concerning the configuration of the trash grills 

anchorage to permit the staff to conclude that issues associated with biofouling or other 

degradation issues, addressed by the Open-Cycle Cooling Water Program but not addressed by 

the Structures Monitoring Program, are not significant or propose to manage this aging using 

the Open-Cycle Cooling Water or equivalent AMP.

In its response dated February 2, 2010, the applicant stated that:

The trash grilles and their anchorage are associated with the Intake Structure. As 

described in the LRA Section 2.4.2.10, the intake structure is located 

approximately 1,600 feet from the shore of Lake Michigan at a water depth of 

15 feet. The Intake Structure consists of a submerged cluster of three 22-foot 

diameter steel inlet cones and trash grilles. The inlet cones are installed with the 

upper end located one foot above the lake bottom. The trash grilles are located 

at the top of each cone in a horizontal configuration. The trash grilles are 

anchored to, and supported by, a reinforced concrete ring foundation that is 

constructed on the outside perimeter of each inlet cone. The reinforced concrete 

ring foundation is supported by select riprap laid below the lakebed. The trash 

grille anchorage consists of stainless steel anchor bolts, with one end embedded 

in the ring foundation and the other end fastened to the top of the trash grille.

The Structures Monitoring Program, described in LRA Appendix B, 

Section B2.1.31, manages the aging effects of the inlet cones, the trash grilles, 

and the trash grille anchorage as indicated in LRA Table 3.5.2-11. The Structures 

Monitoring Program provides for periodic underwater visual inspection and 

cleaning of these structural elements. The program inspects for loss of material 

and the accumulation of biofouling, including zebra mussels and other organic 

macro-fouling. Additionally, since the trash grille anchorage is located on the 

outside perimeter of the inlet cones, an accumulation of bio-fouling on the 

anchorages will not obstruct water flow into the trash grilles and inlet cones. 

Biocide applications would be impractical at this location and would provide no 

additional benefit beyond the visual inspections performed by the Structures 

Monitoring Program.

The staff finds the applicant‘s proposed AMP acceptable because the Structures Monitoring 

Program inspects for the accumulation of biofouling material, in addition to loss of material, and 

biocide applications would not be effective at the location of the intake structure due to dilution 

into Lake Michigan.

For line items for which the applicant cited generic note H, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. 
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The staff finds the applicant‘s proposal acceptable because the applicant has: (1) identified an 

applicable aging effect, (2) selected an AMP with an appropriate scope for the component under 

consideration, and (3) chosen an AMP which contains appropriate inspection techniques to 

identify that aging effect. In addition, a staff concern related to selection and frequency of 

inspections is addressed in RAI B2.1.32-2 and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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 That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended

LRA Section 3.3.2.2 provides further evaluation of aging management, as recommended by the 

GALL Report, for the auxiliary system components. The applicant provided information 

concerning how it will manage the following aging effects:

● 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 microbiologically-influenced 

corrosion

● loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion 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 microbiologically-influenced corrosion

● loss of material due to wear

● loss of material due to cladding breach
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For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant‘s evaluations to determine whether they 

adequately address those issues. In addition, the staff reviewed the applicant‘s further 

evaluations against the criteria 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

Fatigue is an age-related degradation mechanism caused by cyclic stressing of a component by 

either mechanical or thermal stresses. LRA Section 3.3.2.2.1 states that TLAAs are evaluated in 

accordance with 10 CFR 54.21(c)(1) and that the evaluations of this TLAA are addressed in 

Sections 4.3 and 4.7.1. This is consistent with SRP-LR Section 3.3.2.2.1 and is, therefore, 

acceptable.

3.3.2.2.2 Reduction of Heat Transfer Due to Fouling

LRA Section 3.3.2.2.2 and Table 3.3.1, item 3.3.1-3 are applicable to BWRs only and, therefore, 

not applicable to KPS. See SER Section 3.3.2.1.1.

3.3.2.2.3 Cracking Due to Stress-Corrosion Cracking

Item 1. LRA Section 3.3.2.2.3.1 and Table 3.3.1, item 3.3.1-4 are applicable to BWRs only and, 

therefore, not applicable to KPS. See SER Section 3.3.2.1.1.

Item 2. LRA Section 3.3.2.2.3.2 and Table 3.3.1, item 3.3.1-5 are applicable to BWRs only and, 

therefore, not applicable to KPS. See SER Section 3.3.2.1.1.

Item 3. LRA Section 3.3.2.2.3.3 refers to Table 3.3-1, item 3.3.1-6 and addresses cracking due 

to SCC in stainless steel diesel engine exhaust piping, piping components, and piping elements. 

The LRA states that cracking due to SCC is managed by the WCP Program. The applicant 

stated that this program includes visual inspections of the internal surfaces of the diesel engine 

exhaust piping on a recurring basis.

The staff reviewed LRA Section 3.3.2.2.3.3 against the criteria in SRP-LR Section 3.3.2.2.3.3, 

which 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. Acceptance criteria are described in the SRP-LR, BTP RLSB-1.

The staff reviewed the applicant‘s WCP Program and its review is documented in SER 

Section 3.0.3.1.19. The applicant stated that visual inspections will be performed on the internal 

surfaces of the diesel exhaust piping components during opportunities provided by the WCP 

Program. However, the staff noted that the applicant did not describe how cracking due to SCC 

would be identified by the WCP Program. Specifically, the applicant did not define what type of 

visual inspection will be performed to manage this aging effect. By letter dated December 3, 

2009, the staff issued RAI 3.3.2.2.3.3-1 requesting additional information on the frequency and 

type of inspections performed by the WCP Program. 

In its response dated January 21, 2010, the applicant stated that surveillance and maintenance 

activities for diesel exhaust gas components will be identified and internal surface inspections 
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will be performed for each material and environment combination managed by the WCP 

Program. The applicant also stated that the stainless steel diesel generator exhaust flexible 

connections will be components that are selected for periodic enhanced VT-1 inspections to 

monitor for evidence of cracking in the interior surfaces of the components under the periodic 

condition monitoring basis of the WCP Program. The staff finds this response acceptable 

because the stainless steel diesel engine exhaust piping exposed to diesel exhaust will be 

internally inspected by visual examination as part of the WCP Program. In addition, a staff 

concern related to selection and frequency of inspections is addressed in RAI B2.1.32-2 and 

documented in SER Section 3.3.2.2.13. The staff‘s concern described in RAI 3.3.2.2.3.3-1 is 

resolved. 

The staff finds use of the WCP Program to manage the aging effect of cracking acceptable 

because: (1) it is consistent with the recommendation in SRP-LR Section 3.3.2.2.3.3 that a 

plant-specific AMP be used to manage cracking in stainless steel diesel engine exhaust piping 

components, and (2) the applicant will periodically examine the internal surfaces of the stainless 

steel diesel exhaust gas components and flexible connections using an enhanced VT-1 under 

the WCP Program, which is an appropriate method to detect cracking. 

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.3.3 criteria. For those items that apply to LRA Section 3.3.2.2.3.3, 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 

functions 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

Item 1. LRA Section 3.3.2.2.4.1 refers to Table 3.3.1, item 3.3.1-07 and addresses cracking due 

to SCC in stainless steel components in the non-regenerative heat exchanger exposed to 

treated borated water greater than 60 °C (140 °F). The applicant stated that this aging effect is 

managed by the Primary Water Chemistry Program. In addition, the applicant stated that the 

effectiveness of that program is confirmed by the WCP Program, by: (1) monitoring the 

temperature, radioactivity, and surge tank level of the component cooling system, which cools 

the letdown heat exchanger and (2) taking corrective actions if designated thresholds are 

exceeded. 

The staff reviewed LRA Section 3.3.2.2.4.1 against the criteria in SRP-LR Section 3.3.2.2.4.1, 

which states that cracking could occur in stainless steel components in the non-regenerative 

heat exchanger exposed to treated borated water greater than 60 °C (140 °F). The GALL 

Report recommends the use of the water chemistry program augmented by a plant-specific 

verification program to manage the effects of cracking due to SCC in stainless steel 

components in non-regenerative heat exchangers exposed to treated borated water greater 

than 60 °C (140 °F). The SRP-LR states that although the existing AMP relies on monitoring 

and control of primary water chemistry to manage cracking due to SCC, the effectiveness of the 

water chemistry control program should be verified to ensure that cracking is not occurring. The 

SRP-LR also states that an acceptable verification program includes monitoring of the shell side 

water temperature and radioactivity, and eddy current testing of heat exchanger tubes. 

The staff evaluated the applicant‘s Primary Water Chemistry Program and WCP Program and 

its review is documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff noted 

that the effectiveness of the Primary Water Chemistry Program is verified through the WCP 
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Program, which will manage the aging effects of cracking through inspections using NDE 

techniques that have been determined to be effective for the identification of these potential 

aging effects. The staff also noted that in the event the temperature, radioactivity, or surge tank 

level of the component cooling system exceeds a designated threshold, the applicant will initiate 

corrective action to evaluate the cause and extent of the condition. The staff finds the 

applicant‘s use of the Primary Water Chemistry Program, in conjunction with effectiveness 

verification through the WCP Program, acceptable to manage cracking due to SCC because: 

(1) these AMPs are consistent with the recommended programs in SRP-LR Section 3.3.2.2.4.1 

and the GALL Report, (2) the Primary Water Chemistry Control Program periodically monitors 

and controls contaminants below levels known to result in cracking, and (3) the WCP Program 

verifies effectiveness by monitoring designated operational parameters and performing NDE 

inspections.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.4.1 criteria. For those items that apply to LRA Section 3.3.2.2.4.1, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.3.2.2.4.2 refers to Table 3.3-1, item 3.3.1-8 and addresses cracking due 

to SCC in stainless steel components of the regenerative heat exchanger that are exposed to 

treated borated water greater than 60 °C (140 °F). This section states that the aging effect is 

managed by the Primary Water Chemistry Program and that the effectiveness of this program is 

verified by the WCP Program, which will verify the absence of cracking through visual 

inspections of components fabricated of the same materials in similar environments.

The staff reviewed LRA Section 3.3.2.2.4.2 against the criteria in SRP-LR Section 3.3.2.2.4.2, 

which states that cracking could occur in stainless steel components in the regenerative heat 

exchanger exposed to treated borated water greater than 60 °C (140 °F). The GALL Report 

recommends the use of the water chemistry program augmented by a plant-specific verification 

program to manage the effects of cracking in stainless steel components in regenerative heat 

exchangers exposed to treated borated water greater than 60 °C (140 °F). The SRP-LR states 

that although the existing AMP relies on monitoring and control of primary water chemistry to 

manage cracking due to SCC, the effectiveness of the water chemistry control program should 

be verified to ensure that cracking is not occurring. The SRP-LR also states that acceptance 

criteria for a plant-specific AMP are described in SRP-LR, BTP RLSB-1. 

The staff evaluated the applicant‘s Primary Water Chemistry Program and WCP Program and 

its review is documented in SER Sections 3.0.3.1.9 and 3.0.3.2.19, respectively. The staff noted 

that the effectiveness of the Primary Water Chemistry Program is verified through the WCP 

Program, which credits either VT-1 or enhanced VT-1 visual inspection methods for the 

detection of cracking. The staff finds the applicant‘s use of the Primary Water Chemistry 

program, in conjunction with effectiveness verification through the WCP Program, acceptable to 

manage cracking due to SCC because: (1) these AMPs are consistent with the recommended 

programs in SRP-LR Section 3.3.2.2.4.2 and the GALL Report, (2) the Primary Water Chemistry 

Program periodically monitors and controls contaminants below levels known to result in 

cracking, and (3) the WCP Program verifies effectiveness by performing NDE inspections.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3 2.2.4.2 criteria. For those items that apply to LRA Section 3.3.2.2.4.2, the 
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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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 3. LRA Section 3.3.2.2.4.3 addresses cracking due to cyclic loading that could occur in the 

stainless steel positive displacement pump casing of the high-pressure pumps in the CVCS. 

The applicant stated that cracking due to SCC is not an AERM because the casings are not 

exposed to temperatures greater than 60 °C (140 °F), the threshold for SCC to occur. Cracking 

of the charging pumps due to cyclic loading is managed by the WCP Program.

The staff reviewed LRA Section 3.3.2.2.4.3 against the criteria in SRP-LR Section 3.3.2.2.4.3, 

which states that cracking due to SCC and cyclic loading could occur for the stainless steel 

pump casing for the PWR high-pressure pumps in the CVCS. The existing AMP relies on the 

monitoring and control of 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 the water chemistry control program 

should be verified to ensure that cracking is not occurring. 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.

LRA Table 3.3.1, item 3.3.1-9 describes the cracking due to SCC and cyclic loading of the 

austenitic stainless steel positive displacement pump casing of the high-pressure pumps in the 

CVCS. The applicant stated that this aging effect is managed by the WCP Program. The 

applicant further stated that the program is consistent with the GALL Report. 

The staff reviewed LRA item 3.3.1-9 in comparison with the GALL Report Volume 1, Table 3, 

ID 9. The staff found that for this AMR item, the SRP-LR states that the existing AMP relies on 

the monitoring and control of primary water chemistry to manage the effects of cracking due to 

SCC. However, control of water chemistry does not preclude cracking due to SCC and cyclic 

loading. Therefore, the GALL Report recommends the primary water chemistry program to be 

augmented by a plant-specific verification program. In its review, the staff noted that the 

applicant stated that cracking due to SCC of these components is not an AERM because the 

casings are not exposed to temperatures greater than 60 °C (140 °F), the threshold for SCC to 

occur. The applicant further stated that the cracking of charging pumps due to cyclic loading is 

managed by the WCP Program. In its review, the staff noted that the WCP Program provides an 

opportunity to visually inspect the internal surfaces of components, such as pump casings, 

during preventive and corrective maintenance activities. In addition, the staff finds that the 

applicant‘s WCP Program is an acceptable alternative to GALL AMP XI.M32, ―One-Time 

Inspection,‖ for the purpose of verifying the effectiveness of water chemistry control. The staff 

reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff finds this to be consistent with the GALL Report and, therefore, 

acceptable. 

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.4.3 criteria. For those items that apply to LRA Section 3.3.2.2.4.3, 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 

functions 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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Item 4. LRA Section 3.3.2.2.4.4 refers to LRA Table 3.3.1, item 3.3.1-10 and addresses 

high-strength steel closure bolting exposed to air with steam or water leakage. The GALL 

Report recommends GALL AMP XI.M18, ―Bolting Integrity,‖ to manage cracking due to SCC 

and cyclic loading for this component group. The applicant stated that this item is not applicable 

because the bolting for the high-pressure charging pump pressure head is not fabricated from 

high-strength steel. Based on this statement, the staff was unclear as to whether the applicant 

had other high-strength structural steel closure bolting in the auxiliary systems that required 

aging management. By letter dated July 13, 2009, the staff issued RAI B2.1.5-4 requesting that 

the applicant provide additional information to justify why SRP-LR Section 3.3.2.2.4.4 is not 

applicable.

In its response dated August 17, 2009, the applicant stated that there is no high-strength steel 

closure bolting exposed to air with steam or water leakage in the auxiliary systems.

The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed that the applicant‘s LRA does not 

have any AMR results for the auxiliary systems that include high-strength steel closure bolting 

exposed to air with steam or water leakage. The staff also noted that a search of the applicant‘s 

USAR and the Audit Report did not find any evidence of high-strength steel closure bolting in 

the auxiliary systems exposed to air with steam or water leakage. Based on its review of the 

LRA, Audit Report, and USAR, the staff confirmed that there are no in-scope high-strength steel 

closure bolting exposed to air with steam or water leakage in the auxiliary systems and, 

therefore, finds the applicant‘s determination acceptable. The staff‘s concern described in 

RAI B2.1.5-4 is resolved.

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

Item 1. LRA Section 3.3.2.2.5 refers to LRA Table 3.3.1, item 3.3.1-11 and addresses 

degradation of elastomer seals and components of heating and ventilation systems exposed to 

an air-indoor uncontrolled environment which are being managed for hardening and loss of 

strength by the External Surfaces Monitoring Program. 

The staff reviewed LRA Section 3.3.2.2.5.1 against the criteria in SRP-LR Section 3.3.2.2.5.1, 

which states that hardening and loss of strength due to elastomer degradation could 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. The GALL 

Report recommends acceptance criteria which are described in SRP-LR, BTP RLSB-1.

The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. In its review of components subordinate to item 3.3.1-11 

for which the applicant assigned generic note E, the staff noted that the External Surfaces 

Monitoring Program proposes to manage the aging of elastomeric materials through the use of 

visual inspections. The staff also noted that the aging effects being considered are hardening 

and loss of strength. Given that changes in material properties of elastomeric materials are not 

always accompanied by a change in appearance, the staff is unaware of how a visual inspection 

will detect the aging effects under consideration. The staff further noted that item 3.3.1-11 

includes both internal and external surfaces of elastomers. Finally, the staff noted that a search 

of components subordinate to item 3.3.1-11 reveals only items associated with external 

surfaces. Given the nature of the components listed, it appears that most, if not all, of these 

items should have an additional item associated with their internal surface. By letter dated 

October 13, 2009, the staff issued RAI 3.2.2.5.1-1 requesting that the applicant: (1) clarify how a 
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visual inspection will detect changes in hardness and strength of elastomeric materials, or 

propose an alternate AMP which includes manual manipulation of the elastomeric material, and 

(2) explain the apparent lack of AMR items in item 3.3.1-11 associated with internal surfaces.

In its letter dated November 13, 2009, the applicant responded to RAI 3.2.2.5.1-1; the response 

incorporates part of the applicant‘s response to RAI B2.1.10-1 dated August 17, 2009, as 

clarification on its visual inspections. In that response to RAI B2.1.10-1, the applicant stated that 

the External Surfaces Monitoring Program includes the ―scratch, sniff, and stretch‖ technique 

described in the EPRI Aging Assessment Field Guide, which entails detection of surface 

material degradation and hardening by scratching, odor changes possibly indicating degradation 

by sniffing, and elastomer hardening or cracking by stretching. The staff finds this acceptable 

because aging issues such as changes in hardness and strength may be discovered using this 

approach. The applicant addressed the staff‘s question regarding the lack of AMR entries for 

internal surfaces in item 3.3.1-11 by citing LRA Tables 3.3.2-10 through 3.3.2-17. A review of 

these tables indicated that the internal surfaces of elastomers cited generic note H. The items 

that cite generic note H will be managed by the WCP Program. The staff reviewed the 

applicant‘s WCP Program and its evaluation is documented in SER Section 3.0.3.2.19. The staff 

finds this approach acceptable because based on the response to RAI B2.1.32-2 documented in 

SER Section 3.3.2.2.13, the AMP contains appropriate provisions for selection and frequency of 

inspections for the components under consideration. Based on its response dated 

September 25, 2009, to a concern raised during a public meeting, the applicant has chosen an 

AMP which contains appropriate inspection techniques (e.g., visual examination and physical 

manipulation of the elastomers). The staff‘s concern described in RAI 3.2.2.5.1-1 is resolved.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.5.1 criteria. For those items that apply to LRA Section 3.3.2.2.5.1, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.3.2.2.5.2 and Table 3.3.1, item 3.3.1-12 are not applicable to KPS. See 

SER Section 3.3.2.1.1.

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion

Issue 1: Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion (Boron Carbide Plates)

Summary of Technical Information in the Application. LRA Section 3.3.2.2.6 addresses 

reduction of neutron-absorbing capacity and loss of material due to general corrosion in the 

neutron-absorbing boron carbide plates of spent fuel storage racks exposed to treated or 

borated water as AERMs. Additionally, the applicant stated that plant-specific OE shows no 

degradation of boron carbide plates in the spent fuel storage racks exposed to borated water. 

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in 

LRA Section 3.3.2.2.6 on the rationale for not requiring an AMP against the staff‘s 

recommended regulatory criteria in SRP-LR Section 3.3.2.2.6 and in GALL AMR item VII.A2-5

of the GALL Report, Volume 2. 
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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 LRA Section 3.3.2.2.6 in which the applicant evaluated if a reduction of 

neutron-absorbing capacity or loss of material might occur in the neutron-absorbing boron 

carbide plates of the spent fuel storage racks at KPS due to general corrosion. The staff 

questioned the rationale provided by the applicant for not requiring an AMP for the boron 

carbide plates. In RAI 3.3.2.2.6-1 dated July 7, 2009, the staff requested that the applicant 

provide additional details on boron carbide plates in the SFP.

In its response dated August 6, 2009, the applicant stated that the initial racks were installed in 

1978 and in the early 1980s, vent holes were drilled to prevent wall deflection. In the mid-1980s, 

additional racks were installed. The applicant also stated that coupons associated with each 

rack installation were installed into the pool and are always placed in an area that is expected to 

have the highest neutron flux relative to the spent fuel rods. The applicant stated that the 

coupons are tested every 3 years for neutron attenuation (blackness testing), visual examination 

(for cracking, blistering, and surface finish), and thickness measurement. The applicant stated 

that the coupons have been blackness tested since 1982 and that degradation has not been 

detected. The applicant stated that the acceptance criterion for the coupons is a minimum 

B-10 areal density of 0.086 grams per square centimeter (gm/cm2), and that, if this acceptance 

criterion is not met or any abnormalities are noted, those results will be documented in the 

corrective action program. In addition, the applicant stated that the following actions are also 

required: (1) the spent fuel rack loading pattern is evaluated, (2) one or more of the coupons are 

sent to an independent lab for B-10 areal density evaluation, and (3) the test results are 

evaluated to determine acceptability of use of the spent fuel racks. In addition, the applicant 

stated that the criticality analysis of record has 7.996 percent subcritical margin. 

The applicant also provided supplemental information in a letter dated January 21, 2010. As a 

supplement to RAI 3.3.2.2.6-1, the applicant made a commitment, stating that the Boron 

Carbide Surveillance Program, which includes neutron attenuation testing, will continue to be 

performed during the period of extended operation every 3 years. 

The staff has reviewed the response to RAI 3.3.2.2.6-1 and the supplemental information. The 

staff finds it to be representative and acceptable to have two sets of coupons to represent the 

different manufacture and installation of the racks. The staff also finds the 3 year frequency of 

inspection, acceptance criteria, and corrective actions, along with the subcritical margin, to be 

acceptable since this would provide reasonable assurance that degradation would be detected 

before the criticality analysis of record became non-conservative. If degradation were to occur 

between surveillance periods, the subcriticality margin would provide assurance that the SFP 

would remain subcritical. Therefore, the staff has reasonable assurance that the Boron Carbide 

Surveillance Program will be able to detect any degradation of the racks in a timely manner and 

has sufficient margin in the criticality analysis of record to provide additional assurance, if 

degradation were to occur between surveillances, that subcriticality will be maintained. In 

addition, the staff finds the commitment to be acceptable since the applicant is committing to 

perform testing every 3 years, which will include neutron attenuation testing. This provides 

additional assurance that degradation would be detected, monitored, and trended in the period 

of extended operation.
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The applicant also provided some OE in the response to RAI 3.3.2.2.6-1, in the form of the 

results of the areal density/blackness testing of each coupon since 1982. Also, in response to 

the Palisades OE with degraded boron carbide, the applicant responded that it inspected a fuel 

storage rack that was removed from the pool for maintenance and did not find any degradation 

or conditions similar to those found at Palisades. 

The staff reviewed the OE and finds it to be acceptable. The areal density results of all of the 

coupons provide the staff with reasonable assurance that the onset of degradation of the 

neutron-absorbing capacity of the boron carbide would be detected. Additionally, the applicant‘s 

actions, in response to the Palisades OE, provide the staff with reasonable assurance that it has 

appropriate processes in place to evaluate future OE and take appropriate actions. 

After reviewing the applicant‘s response, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.6 criteria. For those items that apply to LRA Section 3.3.2.2.6, the staff 

concludes 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Commitment. The applicant made an additional commitment to LRA Appendix A, Commitment 

No. 38, in a letter dated January 21, 2010, stating that the Boron Carbide Surveillance Program, 

which includes neutron attenuation testing, will continue to be performed during the period of 

extended operation every 3 years.

The staff finds this acceptable since it gives reasonable assurance that the neutron-absorbing 

capacity will be adequately managed during the period of extended operation.

Conclusion. On the basis of its review of the LRA, RAI responses, and commitments, the staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

Issue 2: Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion (Boral Plates) 

Summary of Technical Information in the Application. LRA Section 3.3.2.2.6 addresses 

reduction of neutron-absorbing capacity and loss of material due to general corrosion in the 

neutron-absorbing Boral plates of spent fuel storage racks exposed to treated or borated water 

as AERMs. Additionally, Holtec and industry coupon testing did not exhibit any degradation of 

Boral plates.

Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information in 

LRA Section 3.3.2.2.6 on the rationale for not requiring an AMP against the staff‘s 

recommended regulatory criteria in SRP-LR Section 3.3.2.2.6 and in GALL AMR item VII.A2-5 

of the GALL Report, Volume 2. 

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.
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The staff reviewed LRA Section 3.3.2.2.6 in which the applicant evaluated if a reduction of 

neutron-absorbing capacity and loss of material might occur in the neutron-absorbing sheets of 

the spent fuel storage racks at KPS due to general corrosion. The staff questioned the rationale 

provided by the applicant for not requiring an AMP for the neutron-absorbing capacity and loss 

of material. In RAIs 3.3.2.2.6-2 and 3.3.2.2.6-3 dated July 7, 2009, the staff requested that the 

applicant provide additional details on the Boral plates in the SFP.

The applicant responded to RAIs 3.3.2.2.6-2 and 3.3.2.2.6-3 in letters dated August 6, 2009, 

and January 21, 2010. In its response, the applicant stated:

A review of plant specific and industry operating experience did not identify any 

reason to conclude that degradation of the capability of the Boral spent fuel 

storage rack neutron absorber to perform its intended function would be 

expected with continued service. However, absent an additional basis to support 

that degradation will not occur in the future, Kewaunee will establish a 

surveillance program to monitor the performance of the Boral neutron absorber 

during the period of extended operation or, alternatively, will reperform the Spent 

Fuel Pool Criticality Analysis such that no credit is taken for Boral in the spent 

fuel storage racks.

The surveillance program for these racks will consist of a periodic determination 

of the areal density of the Boral neutron absorber using an in-situ inspection 

technique (such as the currently available BADGER system). The initial test of 

Boral areal density will be performed prior to 2017 on at least five storage cells...

Selection of the cells to be tested will consider those cells that are known to have 

routinely been occupied with spent fuel. This will ensure that the test results will 

either bound or be fully representative of the untested rack cells. The surveillance 

program will be performed every 10 years following the initial testing. Kewaunee 

will continue to monitor industry operating experience related to Boral, and any 

necessary actions will be initiated through the Corrective Action Program. 

The applicant also reaffirmed this program through Commitment No. 39 which states, ―A 

surveillance program will be implemented to perform verification that the Boral spent fuel 

storage rack neutron absorber B-10 areal density is maintained within the bounds of the spent 

fuel pool criticality analysis. Alternatively, the criticality analysis for the spent fuel pool will be 

revised to eliminate credit for the Boral neutron absorber material.‖

The staff reviewed the responses and Commitment No. 39, and has found them to be 

acceptable. The formation of a Boral surveillance program, that will periodically monitor the 

Boral neutron absorber areal density and maintain the areal density within the bounds of the 

SFP criticality analysis in the period of extended operation, provides reasonable assurance that 

degradation of the Boral neutron-absorbing capability will be detected. The selection of the 

routinely occupied cells for testing provides reasonable assurance that the Boral 

neutron-absorbing material tested would bound or be fully representative of the untested rack 

cells. A frequency of 10 year inspections is acceptable since: (1) the Boral at KPS has been in 

service less than 10 years, (2) has a subcritical margin of 5.58 percent, and (3) KPS would 

continue to monitor industry OE. Therefore, the program is found to be acceptable. The 

commitment provides reasonable assurance that the program will be instituted and performed in 

the period of extended operation. Alternatively, if the applicant chooses to no longer credit Boral 
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for neutron-absorbing capability, then this program will no longer be necessary, which is also 

acceptable to the staff.

After reviewing the applicant‘s response, the staff concludes that the applicant‘s responses and 

programs meet SRP-LR Section 3.3.2.2.6 criteria. For those items that apply to LRA 

Section 3.3.2.2.6, the staff concludes 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 functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Commitment. The applicant made an additional commitment to LRA Appendix A, Commitment 

No. 39 in a letter dated January 21, 2010, which states, ―A surveillance program will be 

implemented to perform verification that the Boral spent fuel storage rack neutron absorber B-10 

areal density [is] maintained within the bounds of the spent fuel pool criticality analysis. 

Alternatively, the criticality analysis for the spent fuel pool will be revised to eliminate credit for 

the Boral neutron absorber material.‖ 

The staff finds this acceptable since it gives reasonable assurance that the neutron-absorbing 

capacity will be adequately managed in the period of extended operation.

Conclusion. On the basis of its review of the LRA, RAI responses, and commitments, the staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended functions will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion

Item 1. LRA Section 3.3.2.2.7.1 and Table 3.3.1, items 3.3.1-14, 3.3.1-15, and 3.3.1-16 address 

loss of material due to general, pitting, and crevice corrosion that may occur in piping, piping 

components, and piping elements. The applicant stated that loss of material for steel 

components exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The 

WCP Program will provide a verification of the effectiveness of the Lubricating Oil Analysis 

Program to manage loss of material due to general, pitting, and crevice corrosion through the 

examination of steel components associated with item 3.3.1-14. The applicant further stated that 

the Fire Protection Program or the WCP Program will manage loss of material due to general, 

pitting, and crevice corrosion of steel RCP oil collection subsystem components

(i.e., items 3.3.1-15 and 3.3.1-16).

The staff reviewed LRA Section 3.3.2.2.7.1 against the criteria in SRP-LR Section 3.3.2.2.7.1, 

which states that loss of material due to general, pitting, and crevice corrosion may occur in 

steel piping, piping components, and piping elements, including tubing, valves, and tanks in the 

RCP oil collection system, 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 the 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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Furthermore, SRP-LR 3.3.2.2.7.1 states that corrosion may occur at locations in the RCP oil 

collection tank where water from washdowns may accumulate. The GALL Report recommends

further evaluation to verify the effectiveness of the lubricating oil 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 noted that for compressors (housing, oil pump, oil sight glass, and oil strainer), tubing, 

and valves in LRA Table 3.3.2-8, ―Station and Instrument Air System‖; and for filter housings, 

flexible connections, oil sumps, oilers, piping, pumps (lube oil), strainer housings, tubing, and 

valves in LRA Table 3.3.2-19, ―Diesel Generator System,‖ which referenced LRA Table 3.3.1, 

item 3.3.1-14, the applicant credited the Lubricating Oil Analysis Program, which is 

supplemented by the WCP Program to manage loss of material due to general, pitting, and 

crevice corrosion. The staff reviewed the applicant‘s Lubricating Oil Analysis Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, 

respectively. The staff determined that the Lubricating Oil Analysis Program includes periodic 

sampling and analysis of lubricating oil to determine if contaminants, such as particulates, 

metals, and water, are present. The staff noted that the presence of these impurities in the 

lubricating oil can create an environment that is conducive to age-related degradation, such as 

loss of material and reduction of heat transfer. The staff determined that the activities performed 

as part of this program will be capable of preserving an environment that will not promote loss of 

material and reduction of heat transfer. The staff finds that these activities are consistent with 

the recommendations in the GALL Report and will adequately manage general, pitting, and 

crevice corrosion and fouling in steel piping, piping components, and piping elements exposed 

to lubricating oil. By letter dated September 25, 2009, the applicant amended its LRA so that its 

WCP Program will be consistent with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff 

determined that the applicant‘s WCP Program will manage the aging effects of cracking, loss of 

material, and reduction of heat transfer through program inspections that provide verification of 

the effectiveness of the Lubricating Oil Analysis Program where: (a) an aging effect is not 

expected to occur but the data is insufficient to rule it out with reasonable confidence; (b) an 

aging effect is expected to progress very slowly in the specified environment, but the local 

environment may be more adverse than generally expected; or (c) the characteristics of the 

aging effect include a long incubation period. The staff further determined that these inspections 

will be performed by using NDE techniques that are effective and capable for identification of 

these potential aging effects, and that the sample size and location will be based on an 

assessment of materials, environments, plausible aging effects, and OE. On the basis that the 

applicant‘s AMPs are consistent with those recommended in SRP-LR Section 3.3.2.2.7.1, the 

staff finds the applicant‘s use of the Lubricating Oil Analysis Program and WCP Program 

acceptable.

The staff noted that for steel flame arrestor, piping, and valves in LRA Table 3.3.2-18, ―Fire 

Protection System,‖ which referenced LRA Table 3.3.1, item 3.3.1-15, the applicant credited the 

WCP Program to manage loss of material due to general, pitting, and crevice corrosion. By 

letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program will 

also be consistent with GALL AMP XI.M38, ―Inspection of Internal Surfaces of Miscellaneous 

Piping and Ducting Components.‖ The staff reviewed the applicant‘s WCP Program and its 

evaluation is documented in SER Section 3.0.3.2.19. The staff determined that this program will 

manage the aging effects of loss of material for the in-scope SCs through inspections 

implemented in accordance with the work management process, which will perform visual 

inspections of components fabricated of steel to detect loss of material. The staff further 

determined that this program will: (1) perform inspections of components during surveillance 
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and maintenance activities to provide for the detection of degradation prior to the loss of 

intended function and (2) require that the extent of the inspection and inspection results be 

documented, even when no signs of aging degradation are found, so that there is a meaningful 

trending of aging effects. The staff noted that the visual inspection techniques are established 

and are capable of detecting loss of material due to corrosion by the presence of localized 

discoloration and surface irregularities, such as rust, scale, deposits, surface pitting, surface 

discontinuities, and coating degradation. On the basis of periodic visual inspections being 

performed during surveillance and maintenance activities of these components by the WCP 

Program, the staff finds the applicant‘s use of the WCP Program acceptable.

The staff noted that for the RCP oil collection tank in LRA Table 3.3.2-18, ―Fire Protection 

System,‖ which referenced LRA Table 3.3.1, item 3.3.1-16, the applicant credited the Fire 

Protection Program to manage loss of material due to general, pitting, and crevice corrosion. 

The staff reviewed the applicant‘s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.8. By letter dated August 17, 2009, the applicant responded to 

RAI B.2.1.11-2, which is documented in SER Section 3.0.3.2.8. In its response, the applicant 

stated that the RCP oil collection system is designed to capture any oil leakage from RCP 

bearings which is collected in the RCP oil collection tank for disposal. The applicant further 

stated that this steel tank is exposed internally to an air environment and is also exposed to the 

lubricating oil from oil leakage of the RCP bearings. The staff noted that since this lubricating oil 

is meant for disposal and is from oil leakage, the Lubricating Oil Analysis Program will not be 

effective in managing aging. Therefore, the applicant stated that a specific visual inspection will 

be performed on the internal surfaces of the RCP oil collection tank prior to the period of 

extended operation to ensure that significant degradation is not occurring. The staff noted that a 

visual inspection is capable of detecting loss of material due to corrosion. The staff determined 

that the specific visual inspection of the internal surfaces of the RCP oil collection tank, prior to 

the period of extended operation, will be capable of detecting loss of material due to corrosion 

and will confirm that significant degradation is not occurring.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.7.1 criteria. For those items that apply to LRA Section 3.3.2.2.7.1, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.3.2.2.7.2 and Table 3.3.1, item 3.3.1-17 are applicable to BWRs only 

and, therefore, not applicable to KPS. See SER Section 3.3.2.1.1.

Item 3. LRA Section 3.3.2.2.7.3 refers to LRA Table 3.3-1, item 3.3.1-18 and addresses loss of 

material due to general (steel only), pitting, and crevice corrosion in stainless steel and steel 

diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust. The 

applicant stated that the aging effects are being managed by the WCP Program. 

The staff reviewed LRA Section 3.3.2.2.7.3 against the criteria in SRP-LR Section 3.3.2.2.7.3, 

which 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. Acceptance criteria are described 

in the SRP-LR, BTP RLSB-1.
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The staff reviewed the applicant‘s WCP Program and its review is documented in SER 

Section 3.0.3.1.19. In the LRA, the applicant stated that the WCP Program performs visual 

inspection of diesel generator exhaust gas components to manage the effects of aging due to 

the loss of material. However, the applicant did not state the sample size of the components that 

will be inspected or the frequency at which the inspections will be conducted. By letter dated 

December 3, 2009, the staff issued RAI B2.1.32-2 requesting that the applicant provide 

information on the sample size and frequency of inspections of the diesel generator exhaust 

piping components for the loss of material. The applicant responded on January 21, 2010. The 

staff‘s evaluation of the applicant‘s response is documented in SER Section 3.3.2.2.13.

The staff finds the applicant‘s use of the WCP Program acceptable to manage the aging effect 

of loss of material because the steel and stainless steel diesel engine exhaust piping exposed to 

diesel exhaust will be internally inspected by visual examination, and the applicant will consider 

material, environmental, OE, and other factors in selecting the locations and frequency of 

inspections.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.7.3 criteria. For those items that apply to LRA Section 3.3.2.2.7.3, 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 

functions 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

LRA Section 3.3.2.2.8 refers to Table 3.3.1, item 3.3.1-19 and addresses loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion for steel components 

exposed to soil. The applicant stated that this aging effect is managed by the Buried Piping and 

Tanks Inspection Program. 

The staff reviewed LRA Section 3.3.2.2.8 against the criteria in SRP-LR Section 3.3.2.2.8, which 

states that loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion could occur for steel (with or without coating or wrapping) piping, piping components, 

and piping elements buried in soil. The GALL Report recommends that the effectiveness of the 

applicant‘s buried piping and tanks inspection program should be evaluated to verify the 

effectiveness of the aging effects and OE. The staff reviewed the applicant‘s Buried Piping and 

Tanks Inspection Program and its evaluation is documented in SER Section 3.0.3.2.4. 

In its review of components associated with LRA item 3.3.1-19, for which the applicant assigned 

generic note C (i.e., bolting and EDG fuel oil storage tie down straps), the staff noted that the 

components listed do not meet the precise definition of the GALL Report. The staff accepts the 

applicant‘s proposal that these components can be addressed under this item because they are 

made of the same materials, are subject to the same aging effects, and those aging effects can 

be detected by the same inspection methods as the components included in this GALL Report 

item. The staff accepts that the components under consideration are sufficiently similar to those 

actually included in the GALL Report so as not to render them inconsistent.

GALL AMP XI.M34 recommends the use of coatings and or wrapping under the ―preventive 

actions‖ program element description; however, in its review of LRA Table 3.1.1, item 3.3.1-19, 

the staff noted that the component mentioned is ―steel (with or without coating or wrapping).‖ By 
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letter dated August 28, 2009, the staff issued RAI 3.3.2.2.8-1 requesting that the applicant 

confirm that all buried steel piping is coated or wrapped, or propose an AMP appropriate for 

bare steel piping. The staff also requested that the applicant confirm that the plant has no buried 

piping meeting the criteria of GALL Report Volume 2, Table VII.C1-18.

In its response dated September 28, 2009, the applicant stated that all buried steel piping within 

the scope of license renewal is coated and wrapped. The applicant also stated that there is no 

buried steel piping in the open-cycle cooling water system, so GALL Report item VII.C3-09 is 

not applicable. 

The staff finds the applicant‘s response to RAI 3.3.2.2.8-1 acceptable because the applicant 

demonstrated that LRA item 3.3.1-19 and LRA Section 3.3.2.2.8 are consistent with the 

corresponding items in the GALL Report. The staff‘s concern described in RAI 3.3.2.2.8-1 is 

resolved.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.8 criteria. For those 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 

functions 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, and Microbiologically-Influenced 

Corrosion and Fouling

Item 1. LRA Section 3.3.2.2.9.1 and Table 3.3.1, item 3.3.1-20 address loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion and fouling in applicable 

diesel generator system steel piping, piping components, and piping elements exposed to fuel 

oil. The applicant stated that the loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion for steel piping components and tanks exposed to fuel oil 

is managed by the Fuel Oil Chemistry Program. The applicant further stated that the Fuel Oil 

Tank Inspections Program will inspect the internal surfaces of buried fuel oil storage tanks. The 

WCP Program will provide a verification of the effectiveness of the Fuel Oil Chemistry Program 

to manage loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion through the examination of steel piping components and tanks exposed to fuel oil. 

The staff reviewed LRA Section 3.3.2.2.9.1 against the criteria in SRP-LR Section 3.3.2.2.9.1, 

which states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion and fouling may occur in steel piping, piping components, 

piping elements, and tanks exposed to fuel oil. The existing AMP relies on monitoring and 

control of 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 the 

AMP 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, crevice, and 

microbiologically-influenced corrosion and fouling to verify the effectiveness of the AMP. 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 applicant‘s Fuel Oil Chemistry Program, Fuel Oil Tank Inspections 

Program, and WCP Program; these evaluations are documented in SER Sections 3.0.3.2.10, 
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3.0.3.2.11, and 3.0.3.2.19, respectively. The staff determined that the Fuel Oil Chemistry 

Program includes periodic sampling and analysis of fuel oil to determine if contaminants, such 

as particulates, microbiological organisms, and water, are present. The staff also determined 

that this program verifies the quality of new fuel oil prior to introducing it into the fuel oil storage 

tanks. The staff noted that the presence of these impurities in the fuel oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material. The 

staff finds that these activities 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 and fouling in steel piping, piping components, and piping 

elements exposed to fuel oil. The staff determined that the Fuel Oil Tank Inspections Program

includes activities to periodically drain, clean, and inspect the internal surfaces of fuel oil storage 

tanks. The staff further determined that this program performs visual inspections of the tank 

bottoms to inspect for oil and scale accumulation, and that this program also provides for UT of 

the tank bottom to ensure that the minimum wall thickness is maintained and degradation is not 

occurring. The staff noted that the applicant has credited the WCP Program in lieu of GALL 

AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the applicant 

amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Fuel Oil Chemistry Program 

where: (a) an aging effect is not expected to occur but the data are insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for identification of these potential aging effects, and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 

and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.3.2.2.9.1, the staff finds the applicant‘s use of the Fuel Oil Chemistry 

Program, Fuel Oil Tank Inspections Program, and WCP Program acceptable.

Based on its review and the programs identified above, the staff concludes that the applicant‘s 

programs meet SRP-LR Section 3.3.2.2.9.1 criteria. For those items that apply to LRA 

Section 3.3.2.2.9.1, 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 functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.3.2.2.9.2 and Table 3.3.1, item 3.3.1-21 address loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion that may occur in heat 

exchanger components. The applicant stated that loss of material for carbon steel components 

exposed to lubricating oil is managed by the Lubricating Oil Analysis Program. The WCP 

Program will provide a verification of the effectiveness of the Lubricating Oil Analysis Program to 

manage loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion through the examination of carbon steel components.

The staff reviewed LRA Section 3.3.2.2.9.2 against the criteria in SRP-LR Section 3.3.2.2.9.2, 

which states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion and fouling may occur in steel heat exchanger 
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components 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage general, pitting, crevice, and 

microbiologically-influenced corrosion and fouling in steel heat exchanger components exposed 

to lubricating oil. The staff noted that the applicant has credited the WCP Program in lieu of 

GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the applicant 

amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Lubricating Oil Analysis Program 

where: (a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for identification of these potential aging effects, and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 

and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.3.2.2.9.2, the staff finds the applicant‘s use of the Lubricating Oil Analysis 

Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.9.2 criteria. For those items that apply to LRA Section 3.3.2.2.9.2, 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 

functions 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

Item 1. LRA Section 3.3.2.2.10.1 and Table 3.3.1, item 3.3.1-22 address elastomer lined steel or 

stainless steel clad piping, piping components, or piping elements exposed to treated water or 

treated borated water. The GALL Report recommends further evaluation of a program to 

manage loss of material from pitting and crevice corrosion to verify the effectiveness of the 
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water chemistry program. A one-time inspection of selected components at susceptible 

locations is an acceptable method to ensure that corrosion is not occurring and that component 

intended functions will be maintained during the period of extended operation. The applicant 

stated that this item is not applicable because it has no elastomer lined steel or stainless steel 

clad piping, piping components, or piping elements exposed to treated water or treated borated 

water in the auxiliary systems. The staff reviewed LRA Sections 2.3.3 and 3.3 and confirmed 

that the applicant‘s LRA does not have any AMR results for the auxiliary systems that include 

elastomer lined steel or stainless steel clad piping, piping components, or piping elements 

exposed to treated water or treated borated water. The staff also noted that a search of the 

applicant‘s USAR did not find any evidence of elastomer lined steel or stainless steel clad 

piping, piping components, or piping elements in the auxiliary systems exposed to treated water 

or treated borated water. Based on its review of the LRA and USAR, the staff confirmed that 

there are no in-scope elastomer lined steel or stainless steel clad piping, piping components, or 

piping elements exposed to treated water or treated borated water in the auxiliary systems and, 

therefore, finds the applicant‘s determination acceptable.

Item 2. LRA Section 3.3.2.2.10.2 and Table 3.3.1, items 3.3.1-23 and 3.3.1-24 are applicable to 

BWRs only and, therefore, are not applicable to KPS. See SER Section 3.3.2.1.1.

Item 3. LRA Section 3.3.2.2.10.3 states that the applicant will credit the External Surfaces 

Monitoring Program and the WCP Program to manage loss of material due to pitting and crevice 

corrosion of copper alloy piping, piping components, and piping elements exposed to 

condensation (external) in the auxiliary building ventilation system, circulating water system, 

component cooling system, control room air conditioning system, potable water system, reactor 

building ventilation system, service water system, service water pretreatment system, shield 

building ventilation system, TSC ventilation system, and the turbine building and screenhouse 

ventilation system. The applicant further stated that the WCP Program is credited for those 

components to detect loss of material due to corrosion on copper components when some 

component disassembly is required in order to inspect the component.

The staff reviewed LRA Section 3.3.2.2.10.3 and Table 3.3.1, item 3.3.1-25 against the criteria 

in SRP-LR Section 3.3.2.2.10.3, which 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 reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) require that the extent of 

the inspection and inspection results be documented, even when no signs of aging degradation 

are found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

acceptable.
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The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. The staff determined that the External Surfaces 

Monitoring Program, which includes periodic visual inspections of external surfaces performed 

during system walkdowns, will adequately manage the loss of material due to pitting and crevice 

corrosion for copper alloy piping, piping components, and piping elements exposed to an 

external condensation environment addressed by this AMR. The staff noted that a visual 

inspection will be capable of identifying degradation on the external surface that will present 

itself in signs of corrosion, corrosion byproducts, coating degradation, discoloration on the 

surface, scale/deposits, and pits and surface discontinuities that are indicative of loss of 

material. On the basis of periodic visual inspections being performed during system walkdowns 

of these components by the External Surfaces Monitoring Program, the staff finds the 

applicant‘s use of the External Surfaces Monitoring Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.10.3 criteria. For those items that apply to LRA Section 3.3.2.2.10.3, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 4. LRA Section 3.3.2.2.10.4 addresses loss of material due to pitting and crevice corrosion 

that may occur in piping, piping components, and piping elements. The applicant stated that 

loss of material for copper alloy components exposed to lubricating oil is managed by the 

Lubricating Oil Analysis Program. The WCP Program will provide a verification of the 

effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to pitting 

and crevice corrosion through the examination of copper alloy components.

The staff reviewed LRA Section 3.3.2.2.10.4 and Table 3.3.1, item 3.3.1-26 against the criteria 

in SRP-LR Section 3.3.2.2.10.4, which 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 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 the lubricating oil programs. A one-time inspection of selected components 

at susceptible locations is an acceptable method to ensure that corrosion is not occurring and 

that component intended functions will be maintained during the period of extended operation.

The staff reviewed the applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage loss of material due to pitting 

and crevice corrosion in copper alloy piping, piping components, and piping elements exposed 

to lubricating oil. The staff noted that the applicant has credited the WCP Program in lieu of 
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GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the applicant 

amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Lubricating Oil Analysis Program 

where: (a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for identification of these potential aging effects, and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 

and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.3.2.2.10.4, the staff finds the applicant‘s use of the Lubricating Oil Analysis 

Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.10.4 criteria. For those items that apply to LRA Section 3.3.2.2.10.4, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 5. LRA Section 3.3.2.2.10.5 addresses loss of material due to pitting and crevice corrosion 

in aluminum and stainless steel ducting components exposed to condensation. The applicant 

stated that the External Surfaces Monitoring Program and WCP Program will manage loss of 

material due to pitting and crevice corrosion for aluminum and stainless steel components 

exposed to condensation.

The staff reviewed LRA Section 3.3.2.2.10.5 and Table 3.3.1, item 3.3.1-27 against the criteria 

in SRP-LR Section 3.3.2.2.10.5, which 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 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 reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

aluminum and stainless steel to detect loss of material. The staff further determined that this 

program will: (1) perform inspections of components during surveillance and maintenance 

activities to provide for the detection of degradation prior to the loss of intended function and 

(2) require that the extent of the inspection and inspection results be documented, even when 

no signs of aging degradation are found, so that there is a meaningful trending of aging effects. 

The staff noted that the visual inspection techniques are established and are capable of 

detecting loss of material due to corrosion by the presence of localized discoloration and 

surface irregularities, such as rust, scale, deposits, surface pitting, surface discontinuities, and 

coating degradation. On the basis of periodic visual inspections being performed during 

surveillance and maintenance activities of these components by the WCP Program, the staff 

finds the applicant‘s use of the WCP Program acceptable.
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The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. The staff determined that the External Surfaces 

Monitoring Program, which includes periodic visual inspections of external surfaces performed 

during system walkdowns, is adequate to manage loss of material due to pitting and crevice 

corrosion for stainless steel piping, piping components, and piping elements exposed to an 

external condensation environment addressed by this AMR. The staff noted that a visual 

inspection will be capable of identifying degradation on the external surface that will present 

itself in signs of corrosion, corrosion byproducts, coating degradation, discoloration on the 

surface, scale/deposits, and pits and surface discontinuities that are indicative of loss of 

material. On the basis of periodic visual inspections being performed during system walkdowns 

of these components by the External Surfaces Monitoring Program, the staff finds the 

applicant‘s use of the External Surfaces Monitoring Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.10.5 criteria. For those items that apply to LRA Section 3.3.2.2.10.5, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 6. LRA Section 3.3.2.2.10.6 refers to Table 3.3-1, item 3.3.1-28 and addresses the loss of 

material due to pitting and crevice corrosion of copper alloy fire protection components exposed 

to internal condensation. The applicant stated that copper alloy components in the fire 

protection, waste gas compressor, and various ventilation systems, that are intermittently wetted 

or exposed to condensation, are managed for loss of material due to pitting and crevice 

corrosion by either the WCP Program or the Fire Protection Program. The applicant also stated 

that the loss of material due to pitting and crevice corrosion for copper alloy components 

exposed to condensation in the diesel generator and station and instrument air systems are 

managed by the Compressed Air Monitoring Program. 

The staff reviewed LRA Section 3.3.2.2.10.6 against the criteria in SRP-LR Section 3.3.2.2.10.6, 

which states that loss of material due to pitting and crevice corrosion could occur for copper 

alloy fire protection system piping, piping components, and piping elements exposed to internal 

condensation and the GALL Report recommends further evaluation of a plant-specific AMP to 

ensure that these aging effects are adequately managed. The staff noted that the applicant 

identified two GALL Report recommended AMPs, the Fire Protection and Compressed Air 

Monitoring programs, and a plant-specific program, the WCP Program, to manage the effects of 

aging due to loss of material on the ventilation, station and instrument air, diesel generator, 

waste gas compressor, and fire protection system copper alloy piping, piping components, and 

piping elements. The staff finds that LRA Section 3.3.2.2.10.6 is consistent with SRP-LR 

Section 3.3.2.2.10.6. 

The staff reviewed the 25 AMR items associated with item 3.3.1-28 in LRA Tables 3.3.2-8, 

3.3.2-10, 3.3.2-12 through 3.3.2-19, and 3.3.2-21 for copper alloy piping, piping components, 

and piping elements exposed to moist air or internal condensation. The 25 AMR items are for air 

handling unit cooling coils or fins, containment fan coil units, shroud cooling units, air 

conditioning unit condensers or fins, after coolers, fire hydrants, hose valve head, tubing, and 

valves. These components provide the function of heat transfer or pressure boundary. The 

25 AMR items cite generic note E, which indicates that they are consistent with the GALL 

Report item for material, environment, and aging effect, but a different AMP is credited or the 

GALL Report identifies a plant-specific AMP. 
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The applicant stated that it will use the WCP Program to manage the aging effects of copper 

alloy cooling fans, coils, fins and after coolers, which accounted for 16 of the 25 AMR items. The 

staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The WCP Program credits periodic surveillance, visual inspections, and 

maintenance to manage the effects of aging. The staff noted that aging effects due to 

condensation of the components covered under the WCP Program could be detected by 

periodic visual inspections. The staff finds that the applicant has identified an appropriate 

program to manage the aging effects of these 16 AMR items because visual inspections will 

detect the aging effect and the selection and frequency of inspections is addressed in the 

applicant‘s response to RAI B2.1.32-2. The staff‘s review of RAI B2.1.32-2 is documented in 

SER Section 3.3.2.2.13. 

The applicant stated that it will use the Compressed Air Monitoring Program to manage the 

aging effects of copper alloy after coolers, piping, tubing, and valves in the station and 

instrument air and diesel generator systems, which accounted for 7 of the 25 AMR items. The 

staff reviewed the applicant‘s Compressed Air Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.6. The Compressed Air Monitoring Program credits visual 

inspections and periodic testing to manage the effects of aging. The staff noted that the aging 

effect of loss of material for these items could be identified by visual inspection. The staff also 

noted that in the applicant‘s response to RAI B2.1.9-2, documented in SER Section 3.0.3.2.6, 

the applicant stated that an air dryer is maintained in service on a continuous basis during air 

compressor operation, so as to remove moisture from the incoming compressed air, and the air 

receivers are checked daily for accumulation of condensation. The staff finds that the applicant 

has identified an appropriate program to manage the aging effects for these 7 AMR items 

because visual inspections will detect the aging effects and condensation is minimized by the 

Compressed Air Monitoring Program. 

The applicant stated that it will use the Fire Protection Program to manage the effects of aging 

of the remaining 2 AMR items, copper alloy fire hydrants and hose valve heads. The staff 

reviewed the applicant‘s Fire Protection Program and its evaluation is documented in SER 

Section 3.0.3.2.8. The Fire Protection Program credits periodic inspections to detect the effects 

of aging. The staff noted that the aging effect of loss of material for these items could be 

identified by visual inspection. The staff also noted that the applicant credited the WCP Program 

to perform inspections within the Fire Protection Program. A staff concern related to selection 

and frequency of inspections, related to the WCP Program, is addressed in the applicant‘s 

response and the staff‘s review of RAI B2.1.32-2, documented in SER Section 3.3.2.2.13. The 

staff finds that the applicant has identified an appropriate program to manage the aging effects 

of fire hydrants and the hose valve heads because visual inspections will detect the aging effect 

and the applicant will implement appropriate criteria for selection and frequency of inspections.

Based on the programs identified, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.10.6 criteria. For those items that apply to LRA Section 3.3.2.2.10.6, 

the staff concludes 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 7. LRA Section 3.3.2.2.10.7 refers to Table 3.3.1, item 3.3.1-29 and addresses loss of 

material due to pitting and crevice corrosion for stainless steel piping, piping components, and 

piping elements exposed to soil. The applicant stated that this aging effect is managed by the 

Buried Piping and Tanks Inspection Program. 
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The staff reviewed LRA Section 3.3.2.2.10.7 against the criteria in SRP-LR Section 3.3.2.2.10.7, 

which 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 these aging effects are 

adequately managed. Acceptance criteria are described in SRP-LR, BTP RLSB-1. The staff 

reviewed the applicant‘s Buried Piping and Tanks Inspection Program and its evaluation is 

documented in SER Section 3.0.3.2.4.

The GALL AMP XI.M34 program description does not include stainless steel; however, in its 

review of LRA Table 3.3.1, item 3.3.1-29, the staff found that the material for the components is 

stainless steel. By letter dated August 28, 2009, the staff issued RAI 3.3.2.2.10.7-1 requesting 

that the applicant confirm whether the buried stainless steel piping is wrapped, coated, or bare 

and, if coated or wrapped, justify how the proposed AMP will adequately manage its aging.

In its response dated September 28, 2009, the applicant stated that the answer to this RAI was 

contained in its response to RAI B2.1.7, which was transmitted by letter dated August 17, 2009. 

The staff reviewed the response to this RAI. In its response, the applicant stated that the 

stainless steel piping under consideration: (1) is a vent line which was installed in 2003, 

(2) consists of approximately 30 feet of 2 inch nominal ASTM A-312 schedule 80 pipe, (3) is 

completely buried except for about 3 feet, and (4) is coated and wrapped. The applicant also 

stated that even though the material for this line was not in the GALL AMP, its failure was highly 

unlikely due to the design of the piping, recent installation, and planned inspections.

The staff finds the applicant‘s response to RAI 3.3.2.2.10.7-1 acceptable because there is an 

exceptionally small probability that the pipe under consideration will fail based on its design 

(i.e., pipe need not retain any pressure) and planned inspections. The staff‘s concern described 

in RAI 3.3.2.2.10.7-1 is resolved.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.10.7 criteria. For those items that apply to LRA Section 3.3.2.2.10.7, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 8. LRA Section 3.3.2.2.10.8 and Table 3.3.1, item 3.3.1-30 are applicable to BWRs only 

and, therefore, not applicable to KPS. See SER Section 3.3.2.1.1.

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion

LRA Section 3.3.2.2.11 and Table 3.3.1, item 3.3.1-31 are applicable to BWRs only and, 

therefore, not applicable to KPS. See SER Section 3.3.2.1.1. 

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

Item 1. LRA Section 3.3.2.2.12.1 addresses loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion in stainless steel and copper alloy piping, piping 

components, and piping elements exposed to fuel oil. The applicant stated that there are no 

aluminum components exposed to fuel oil. The applicant stated that loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion for diesel generator system stainless 

steel and copper alloy piping, piping components, and piping elements exposed to fuel oil is 
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managed by the Fuel Oil Chemistry Program. The applicant stated that the WCP Program will 

provide a verification of the effectiveness of the Fuel Oil Chemistry Program to manage loss of 

material due to pitting, crevice, and microbiologically-influenced corrosion through the 

examination of stainless steel and copper alloy piping, piping components, and piping elements 

exposed to fuel oil. 

The staff reviewed LRA Section 3.3.2.2.12.1 and Table 3.3.1, item 3.3.1-32 against the criteria 

in SRP-LR Section 3.3.2.2.12.1, which states that loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling may occur in stainless steel, aluminum, and 

copper alloy piping, piping components, and piping elements exposed to fuel oil. The existing 

AMP relies on monitoring and control of fuel oil contamination to manage the loss of material 

due to corrosion or fouling. The effectiveness of the AMP 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 pitting, crevice, and microbiologically-influenced corrosion to 

verify the effectiveness of the AMP. 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 applicant‘s Fuel Oil Chemistry Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.2.10 and 3.0.3.2.19, respectively. The staff 

determined that the Fuel Oil Chemistry Program includes periodic sampling and analysis of fuel 

oil to determine if contaminants, such as particulates, microbiological organisms, and water, are 

present. The staff also determined that this program verifies the quality of new fuel oil prior to 

introducing it into the fuel oil storage tanks. The staff noted that the presence of these impurities 

in the fuel oil can create an environment that is conducive to age-related degradation, such as 

loss of material and reduction of heat transfer. The staff determined that the activities performed 

as part of this program will be capable of preserving an environment that will not promote loss of 

material. The staff finds that these activities are consistent with the recommendations in the 

GALL Report and will adequately manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion in stainless steel and copper alloy piping, piping 

components, and piping elements exposed to fuel oil. The staff noted that the applicant has 

credited the WCP Program in lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated 

September 25, 2009, the applicant amended its LRA so that its WCP Program will be consistent 

with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff determined that the applicant‘s WCP 

Program will manage the aging effects of cracking, loss of material, and reduction of heat 

transfer through program inspections that provide verification of the effectiveness of the Fuel Oil 

Chemistry Program where: (a) an aging effect is not expected to occur but the data are 

insufficient to rule it out with reasonable confidence; (b) an aging effect is expected to progress 

very slowly in the specified environment, but the local environment may be more adverse than 

generally expected; or (c) the characteristics of the aging effect include a long incubation period. 

The staff further determined that these inspections will be performed by using NDE techniques 

that are effective and capable for identification of these potential aging effects, and that the 

sample size and location will be based on an assessment of materials, environments, plausible 

aging effects, and OE. On the basis that the applicant‘s AMPs are consistent with those 

recommended in SRP-LR Section 3.3.2.2.12.1, the staff finds the applicant‘s use of the Fuel Oil 

Chemistry Program and WCP Program acceptable.

Based on a review of the programs identified above, the staff concludes that the applicant‘s 

programs meet SRP-LR Section 3.3.2.2.12.1 criteria. For those items that apply to LRA 

Section 3.3.2.2.12.1, 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 
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the intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.3.2.2.12.2 addresses loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion that may occur in stainless steel piping, piping 

components, and piping elements exposed to a lubricating oil environment. The applicant stated 

that loss of material for stainless steel components exposed to lubricating oil is managed by the 

Lubricating Oil Analysis Program. The WCP Program will provide a verification of the 

effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to pitting, 

crevice, and microbiologically-influenced corrosion through the examination of stainless steel 

components. The applicant further stated that loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion for stainless steel components, associated with the RCP 

oil collection subsystem exposed to a lubricating oil environment, is managed by the Fire 

Protection and WCP programs.

The staff reviewed LRA Section 3.3.2.2.12.2 and Table 3.3.1, item 3.3.1-33 against the criteria 

in SRP-LR Section 3.3.2.2.12.2, which states that loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion 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 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion in stainless steel piping, piping 

components, and piping elements exposed to lubricating oil. The staff noted that the applicant 

has credited the WCP Program in lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter 

dated September 25, 2009, the applicant amended its LRA so that its WCP Program will be 

consistent with GALL AMP XI.M32. The staff determined that the applicant‘s WCP Program will 

manage the aging effects of cracking, loss of material, and reduction of heat transfer through 

program inspections that provide verification of the effectiveness of the Lubricating Oil Analysis 

Program where: (a) an aging effect is not expected to occur but the data is insufficient to rule it 

out with reasonable confidence; (b) an aging effect is expected to progress very slowly in the 

specified environment, but the local environment may be more adverse than generally 

expected; or (c) the characteristics of the aging effect include a long incubation period. The staff 

further determined that these inspections will be performed by using NDE techniques that are 

effective and capable for identification of these potential aging effects, and that the sample size 
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and location will be based on an assessment of materials, environments, plausible aging 

effects, and OE. On the basis that the applicant‘s AMPs are consistent with those 

recommended in SRP-LR Section 3.3.2.2.12.2, the staff finds the applicant‘s use of the 

Lubricating Oil Analysis Program and WCP Program acceptable.

The staff noted that for the stainless steel drip plan and enclosures in LRA Table 3.3.2-18, 

which referenced LRA Table 3.3.1, item 3.3.1-33, the applicant credited the Fire Protection 

Program to manage loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion. The staff reviewed the applicant‘s Fire Protection Program and its evaluation is 

documented in SER Section 3.0.3.2.8. The staff noted that the applicant‘s Fire Protection 

Program includes periodic inspection of the fire suppression system and as part of the 

inspection, it includes examination of equipment condition. The staff finds that loss of material 

due to pitting, crevice, and microbiologically-influenced corrosion can be adequately managed 

by periodic inspections.

The staff noted that for stainless steel flexible hoses in LRA Table 3.3.2-18, ―Fire Protection 

System,‖ which referenced LRA Table 3.3.1, item 3.3.1-33, the applicant credited the WCP 

Program to manage loss of material due to pitting, crevice, and microbiologically-influenced 

corrosion. By letter dated September 25, 2009, the applicant amended its LRA so that its WCP 

Program will also be consistent with GALL AMP XI.M38, ―Inspection of Internal Surfaces of 

Miscellaneous Piping and Ducting Components.‖ The staff reviewed the applicant‘s WCP 

Program and its evaluation is documented in SER Section 3.0.3.2.19. The staff determined that 

this program will manage the aging effects of loss of material for the in-scope SCs through 

inspections implemented in accordance with the work management process, which will perform 

visual inspections of components fabricated of steel to detect loss of material. The staff further 

determined that this program will: (1) perform inspections of components during surveillance 

and maintenance activities to provide for the detection of degradation prior to the loss of 

intended function and (2) require that the extent of the inspection and inspection results be 

documented even when no signs of aging degradation are found so that there is a meaningful 

trending of aging effects. The staff noted that the visual inspection techniques are established 

and are capable of detecting loss of material due to corrosion by the presence of localized 

discoloration and surface irregularities, such as rust, scale, deposits, surface pitting, surface 

discontinuities, and coating degradation. On the basis of periodic visual inspections being 

performed during surveillance and maintenance activities of these components by the WCP 

Program, the staff finds the applicant‘s use of the WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.12.2 criteria. For those items that apply to LRA Section 3.3.2.2.12.2, 

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 

functions 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

LRA Section 3.3.2.2.13 refers to Table 3.3.1, item 3.3.1-34 and addresses loss of material due 

to the wear of elastomer seals and components exposed internally or externally to indoor 

uncontrolled air. The applicant stated that this aging effect is managed by the WCP Program 

and the External Surfaces Monitoring Program.
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The staff reviewed LRA Section 3.3.2.2.13 against the criteria in SRP-LR Section 3.3.2.2.13, 

which states that loss of material due to wear could occur in the elastomer seals and 

components exposed internally or externally to indoor uncontrolled air. The GALL Report 

recommends further evaluation of a plant-specific AMP to ensure that these aging effects are 

adequately managed. Acceptance criteria are described in SRP-LR, BTP RLSB-1. The staff 

reviewed the applicant‘s WCP and External Surfaces Monitoring programs and its evaluation is 

documented in SER Sections 3.0.3.2.19 and 3.0.3.2.7, respectively.

In its review, the staff noted that the External Surfaces Monitoring and the WCP programs 

propose to manage the aging of elastomeric materials through the use of visual inspections and 

physical manipulations. The staff finds the use of these programs to manage the aging of these 

components acceptable because the visual inspection and physical manipulation techniques 

included are capable of detecting loss of material due to wear on the components under 

consideration. While the staff concurs that wear of elastomeric materials can be detected 

through visual inspections, the proposed AMPs do not provide sufficient information concerning 

the details of the inspection, frequency of inspection, and sample size to allow the staff to 

conclude that the use of these programs will effectively manage the aging of the elastomeric 

materials under consideration. By letter dated December 3, 2009, the staff issued RAI B2.1.32-2 

requesting that the applicant clarify: (1) why the visual examinations of those components that 

are scheduled for periodic maintenance are considered to be representative of those 

components that may not be inspected during the period of extended operation, (2) how the 

results of the inspections will be applied to the population of components that may not be 

inspected under the program if aging is detected in the inspected components, and (3) how 

potential aging in the non-inspected components will be addressed.

In its response dated January 21, 2010, the applicant stated that:

For each material-environment combination, sufficient internal surfaces 

inspections will be performed during scheduled surveillance and maintenance 

activities to provide an overall assessment of any aging degradation that may be 

occurring. A review of the scheduled surveillance and maintenance activities will 

be performed to select activities that will provide a set of inspections that will be 

representative of the components in the program. The review will consider 

component materials; operating environments; industry and plant-specific 

operating experience; engineering evaluations of equipment performance; and 

susceptibility to aging due to time in service, severity of operating conditions, and 

lowest design margins.

The selected scheduled surveillance and maintenance activities will be 

performed on a repetitive basis. The use of recurring surveillance and 

maintenance activities provides the ability to detect aging of the 

material-environment combination prior to loss of function.

Aging detected during the Internal Surfaces Monitoring program inspections will 

be documented and evaluated for applicability to similar components [(]i.e., same 

material environment combinations) within the total component population in 

accordance with the Corrective Action Program. An engineering review will be 

performed to evaluate the condition, the extent of the condition, and the need for 

corrective actions. The extent of the condition may require the inspection of 

additional plant equipment. 
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Implementation of the Internal Surfaces Monitoring program at Kewaunee will 

require Engineering personnel to: (1) review the program inspection results to 

identify any new aging effects not previously considered, (2) monitor and/or 

perform walk down activities to verify adequate identification and documentation 

of aging effects and initiation of corrective actions, (3) perform trending of 

inspection results, and (4) review site operating experience through the plant 

corrective action program to ensure that aging effects are addressed.

The combination of the Corrective Action Program evaluations and the 

engineering reviews discussed above provides reasonable assurance that the 

impact of identified aging will be considered for non-inspected components.

The staff finds the applicant‘s response to RAI B2.1.32-2 acceptable because: (1) the applicant 

will perform sufficient inspections for each material-environment combination to provide an 

overall assessment of any aging degradation that may be occurring; (2) the selection of 

inspections will consider materials, operating environments, industry and plant-specific OE, 

engineering evaluations of equipment performance, and susceptibility to aging due to time in 

service, severity of operating conditions, and lowest design margins; (3) recurring surveillance 

and maintenance activities provides the ability to detect aging of the material-environment 

combination prior to the loss of function; and (4) inspection results will be trended. The staff‘s 

concern described in RAI B2.1.32-2 is resolved.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.13 criteria. For those items that apply to LRA Section 3.3.2.2.13, 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

functions 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

LRA Section 3.3.2.2.14 addresses pump cladding failures in charging pumps that have steel 

casings with stainless steel cladding, when exposed to treated water as described in NRC 

IN 94-63, ―Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks.‖ This 

Information Notice describes a cladding breach of the centrifugal charging pumps at North Anna 

Power Station. The GALL Report recommends further evaluation of a plant-specific AMP to 

manage the aging of this component group. The applicant stated that this line item is not 

applicable because its charging pumps are positive displacement pumps manufactured by Ajax 

Iron Works with charging pump pressure heads that are stainless steel, not steel with stainless 

steel cladding as described in the IN. 

The staff reviewed AMR items associated with LRA Table 3.3.1, item 3.3.1-35. The staff also 

noted that LRA Section 3.2.2.2.6 implies that the safety injection pumps are centrifugal. The 

staff further noted that if any of these pumps have stainless steel cladding, then this item should 

be considered. By letter dated October 13, 2009, the staff issued RAI 3.3.2.2.14-1 requesting 

that the applicant confirm whether the safety injection pumps are steel with stainless steel 

cladding. Furthermore, if the safety injection pumps have stainless steel cladding, the staff 

requested that the applicant confirm either that the issue of loss of material due to cladding 

breach is being managed, or that it is not applicable to these pumps.
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In its response dated November 13, 2009, the applicant stated that the safety injection pumps 

are steel with stainless steel cladding but that the safety injection pumps are not 

interchangeable with the charging pumps. The staff finds the applicant‘s determination that this 

item is not applicable acceptable because the materials of construction of the charging pumps 

do not match the criteria for the AMR item. The potential for cracking and subsequent corrosion 

of the safety injection pumps are addressed in SER Section 3.2.2.2.2. The staff‘s concern 

described in RAI 3.3.2.2.14-1 is resolved.

Based on the programs identified, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.3.2.2.14 criteria. For those line items that apply to LRA Section 3.3.2.2.14, 

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 

functions 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 Nonsafety-Related Components

SER Section 3.0.4 provides the staff‘s evaluation of the applicant‘s QA program.

3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.3.2-1 through 3.3.2-29, the staff reviewed additional details of 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 3.3.2-29, 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 concerning how the 

aging effects will be managed. 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 had 

demonstrated that the aging effects will be adequately managed so that the intended functions 

will be maintained consistent with the CLB during the period of extended operation. The staff‘s 

evaluation is discussed in the following sections as required by 10 CFR 54.21(a)(3).

3.3.2.3.1 Loss of Material Due to Erosion from the Internal or External Surfaces of Steel Piping, 

Piping Components, Piping Elements, and Heat Exchanger Components Exposed to Raw 

Water

In LRA Tables 3.3.2-3, 3.3.2-8, 3.3.2-9, 3.3.2-20, 3.3.2-21, 3.3.2-22, 3.3.2-25, and 3.3.2-26, the 

applicant stated that the internal or external surfaces of steel piping, piping components, piping 

elements, and heat exchanger components exposed to raw water are being managed for loss of 

material due to erosion by the WCP Program. The AMR items cite generic note H, indicating 
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that for the component, material, and environment combination listed, the aging effect being 

considered is not evaluated in the GALL Report.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is the internal or external surfaces of steel piping, piping components, piping elements, and 

heat exchanger components exposed to raw water. The staff confirmed that there are no entries 

for this component, material, and environment where the aging effect is loss of material due to 

erosion. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review, the staff noted that the portion of the WCP Program being 

employed is that which claims consistency with GALL AMP XI.M38, ―Inspection of Internal 

Surfaces of Miscellaneous Piping and Ducting.‖ The staff also noted that the program 

description for the WCP Program states that it is applicable to piping, piping components, and 

ducting. The scope of the GALL Report AMP states that it is also applicable to piping, piping 

elements, and ducting components in an internal environment (such as indoor uncontrolled air, 

condensation, and steam). The staff further noted that some of the components under 

consideration are heat exchangers exposed to raw water and that those heat exchangers 

exposed to raw water fall outside the scope of both the WCP Program and the GALL Report 

AMP. 

Also during its review, the staff noted that GL 89-13 applies to some raw water systems. The 

aging of systems to which GL 89-13 applies must be managed using the Open-Cycle Cooling 

Water Program. Based on the information provided, it is apparent that most of the components 

under consideration (e.g., drain systems) are outside the scope of GL 89-13 and that the use of 

the WCP Program is acceptable because it contains inspection techniques which will identify 

loss of material due to erosion. However, it is not apparent that GL 89-13 does not apply to any 

of the components under consideration. By letter dated January 4, 2010, the staff issued 

RAI 3.3.2.3-6 requesting that the applicant: (1) take an exception to the WCP Program to 

include heat exchanger components in the scope of the AMP, or (2) justify why such an 

exception is unnecessary and confirm that GL 89-13 does not apply to any of the components 

under consideration.

In its response dated February 2, 2010, the applicant stated that the inclusion of heat exchanger 

components within the WCP Program falls under the ―other components‖ provision of both the 

LRA Internal Surfaces Monitoring Program (subordinate to the WCP Program) and GALL 

AMP XI.M38, ―Inspection of Internal Surfaces of Miscellaneous Piping and Ducting.‖ The 

applicant also stated that none of the components under the scope of the WCP Program are 

within the scope of GL 89-13. The staff finds the applicant‘s currently proposed AMP acceptable 

because: (1) the heat exchanger components are within the scope of the GALL Report AMP, 

(2) the inspection techniques necessary to identify erosion in piping will also identify erosion in 

heat exchangers, and (3) items under the WCP Program scope are not within the scope of 

GL 89-13. The staff‘s concern described in RAI 3.3.2.3-6 is resolved. In addition, a staff concern 

related to selection and frequency of inspections is addressed in RAI B2.1.32-2 and the staff‘s 

evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 
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maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.2 Loss of Material Due to General, Pitting, Crevice, Galvanic, and 

Microbiologically-Influenced Corrosion, as well as Fouling from the Internal Surfaces of Steel 

Heat Exchanger Components Exposed to Raw Water

In LRA Tables 3.3.2-3, 3.3.2-8, and 3.3.2-9, the applicant stated that internal surfaces of steel 

heat exchanger components exposed to raw water are being managed for loss of material due 

to general, pitting, crevice, galvanic, and microbiologically-influenced corrosion by the WCP 

Program. The AMR items cite generic note H, indicating that for the component, material, and 

environment combination listed, the aging effect being considered is not evaluated in the GALL 

Report.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is internal surfaces of steel heat exchanger components exposed to raw water. The staff 

noted that the entries recommend GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ for 

this component, material, and environment where the aging effect is loss of material due to 

general, pitting, crevice, galvanic, and microbiologically-influenced corrosion. The applicant 

stated that safety-related systems will be managed by the Open-Cycle Cooling Water System 

Program and nonsafety-related components will be managed by the WCP Program. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff also noted that for these components in LRA Table 3.3.1, item 3.3.1-77, the GALL Report 

recommends the use of the Open-Cycle Cooling Water Program. The staff further noted that the 

components under consideration are nonsafety-related components. As a result, use of the 

Open-Cycle Cooling Water Program is not appropriate, as this AMP is limited to components in 

safety-related systems which transfer heat to the ultimate heat sink. Given that the use of the 

Open-Cycle Cooling Water Program is not appropriate, the staff finds the applicant‘s use of the 

WCP Program acceptable because this AMP contains visual inspection procedures which are 

appropriate for the detection of loss of material, fouling, and coating degradation on the internal 

surfaces of piping components. In addition, a staff concern related to selection and frequency of 

inspections is addressed in RAI B2.1.32-2 and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.3 Steel, Stainless Steel, and Copper Alloy Components Exposed to Raw Water, Aging 

Effect – Loss of Material Due to Erosion and Microbiologically-Influenced Corrosion

In LRA Tables 3.3.2-6, 3.3.2-7, 3.3.2-10, 3.3.2-11, 3.3.2-13, 3.3.2-14, 3.3.2-19, and 3.3.2-20, 

the applicant stated that steel, stainless steel, and copper alloy components exposed to raw 

water have an aging effect of loss of material due to erosion and MIC and that the aging effect 

will be managed by the Open-Cycle Cooling Water System Program. The AMR items cite 
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generic note H, indicating that for the component, material, and environment combination listed, 

the aging effect being considered is not included in the GALL Report.

The staff reviewed all AMR result lines in the GALL Report where the materials type is steel, 

stainless steel, and copper alloy components and confirmed that there are no entries for this 

material where the aging effect is erosion when the environment is raw water. The applicant 

used generic note H for some AMR items for stainless steel where the aging effect is MIC. The 

staff noted that the GALL Report does have a line item, VII.H2-18, for stainless steel 

components exposed to raw water having an aging effect of MIC. Nevertheless, the applicant 

credited its Open-Cycle Cooling Water System Program and the GALL Report recommends 

GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ therefore, the LRA AMR items meet 

the intent of the GALL Report. 

The staff considers the Open-Cycle Cooling Water System Program to be an appropriate 

program for aging management of loss of material due to erosion in raw water because the 

program is designed to detect both corrosion and fouling of components exposed to raw water 

through the combined use of inspections and performance tests. Testing and inspection 

frequencies are adjusted based on findings.

On the basis of its review, the staff finds that the applicant 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 for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.4 Exterior Surfaces of Non-Metallic Materials Exposed to Uncontrolled Indoor Air and 

Interior Surfaces of Non-Metallic Materials Exposed to Raw Water, Dry Air, Lube Oil, and Inert 

Gas

In LRA Tables 3.3.2-6, 3.3.2-8, 3.3.2-19, and 3.3.2-27, the applicant stated that the exterior 

surfaces of non-metallic materials exposed to uncontrolled indoor air and the interior surfaces of 

non-metallic materials exposed to raw water, dry air, lube oil, and inert gas have no aging effect 

and that no AMP is required. The AMR items cite generic note H, indicating that for the 

component, material, and environment combination listed, the aging effect being considered is 

not evaluated in the GALL Report.

The staff reviewed all AMR result items in the GALL Report where the material type is 

non-metallic materials and confirmed that there are no entries for this component/material and 

environment. The staff also noted that there is no distinct definition for non-metallic material in 

the GALL Report, Chapter IX. The staff further noted that many polymeric materials are 

adversely affected by oxidizers (e.g., chlorine), ultraviolet (UV) light, and high temperatures. 

Based on the information provided, the staff cannot conclude that aging effects will not occur to 

the combination of materials and environments under consideration. By letter dated October 13, 

2009, the staff issued RAI 3.3.2.3-3 requesting that the applicant identify the specific material 

under consideration and justify why this material is not subject to aging under the conditions 

being considered.

In its response dated November 13, 2009, the applicant stated that non-metallic materials in 

LRA Table 3.3.2-6 are PVC and polyvinylidene fluoride associated with the service water 

chlorination system, and are exposed on their interior surfaces to solutions of sodium 
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hypochlorite and exterior surfaces to air-indoor uncontrolled. The applicant also stated that it 

conducted an OE search for this combination of materials and environment and identified 

instances in which cracking was observed. The applicant revised the aging effect for these 

materials from none to cracking and will manage aging by the WCP Program. The staff finds 

this approach acceptable because the applicant has identified an appropriate aging effect and 

the proposed AMP contains inspection techniques designed to identify cracking on the internal 

surfaces of piping.

The applicant stated that the non-metallic material in LRA Table 3.3.2-8 are polycarbonate 

bowls for lubricators and oilers associated with the station and instrument air system and is 

exposed on its interior surfaces to lubricating oil and dried air. The applicant conducted an OE 

search for this combination of material and environment and failed to find any instances of 

aging. The results of this search are consistent with the staff‘s knowledge of this material and 

environment. The staff finds the applicant‘s proposal, that no aging effect exists for this 

combination of material and environment and that no aging management is required, acceptable 

because the material environment combination under consideration is commonly employed and 

no evidence of aging has been detected.

The applicant stated that the non-metallic material in LRA Table 3.3.2-19 is polycarbonate filter 

housings in the diesel generator starting air system and is exposed on its interior surfaces to 

dried air. The applicant conducted an OE search for this combination of material and 

environment and failed to find any instances of aging. The results of this search are consistent 

with the staff‘s knowledge of this material and environment. The staff finds the applicant‘s 

proposal, that no aging effect exists for this combination of materials and environment and that 

no aging management is required, acceptable because the material environment combination 

under consideration is commonly employed and no evidence of aging has been detected.

The applicant stated that the non-metallic material in LRA Table 3.3.2-27 is polyethylene flexible 

tubing used to connect a nitrogen bottle to an instrument air dryer and is exposed on its interior 

surfaces to inert nitrogen gas. The applicant conducted an OE search for this combination of 

material and environment and failed to find any instances of aging. The results of this search 

are consistent with the staff‘s knowledge of this material and environment. The staff finds the 

applicant‘s proposal, that no aging effect exists for this combination of material and environment 

and that no aging management is required, acceptable because the material environment 

combination under consideration is commonly employed and no evidence of aging has been 

detected.

The applicant stated that the external surfaces of all the materials described above are exposed 

to air. The staff agrees with the applicant that aging of these materials due solely to exposure to 

air is unlikely. The applicant also evaluated other sources of potential degradation to which 

these materials could be exposed. The applicant evaluated the potential for degradation due to 

chemical contaminants in the air, such as sulfur dioxide, high temperature (greater than 95 °F), 

and exposure to oxidizing agents (e.g., UV radiation or ozone). The staff finds that these are the 

appropriate effects to examine. The applicant stated, and the staff concurs, that degradation 

due to chemical contaminants is unlikely due to the rural location of the plant. The applicant 

stated and, based on recommendations in the GALL Report, the staff concurs, that exposure of 

these materials to temperatures less than 95 °F is unlikely to cause aging. The applicant stated, 

and the staff concurs, that the primary source of ozone to which these materials may be 

exposed is electrical equipment and that the remote location of these materials from ozone 

producing equipment will eliminate this issue. The applicant stated that UV radiation is not a 

source of aging because these materials are located indoors and because a review of plant 
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experience indicated that UV radiation from fluorescent lighting was not sufficient to cause 

degradation. The staff concurs with the applicant that the absence of exposure of these 

materials to sunlight substantially eliminates the potential for aging due to UV radiation. The 

staff does, however, believe that in some instances, UV radiation from fluorescent lighting can 

cause aging. The staff accepts the applicant‘s review of plant operating history as evidence that, 

in this location, the intensity of the fluorescent lighting is not sufficient to cause aging in the 

materials under consideration. Based on the above, the staff finds the applicant‘s approach to 

manage the aging of the non-metallic components under consideration acceptable. The staff‘s 

concern described in RAI 3.3.2.3-3 is resolved. 

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.5 Steel, Stainless Steel, and Copper Alloy Components Exposed to Raw Water, Aging 

Effect – Loss of Material Due to Erosion and Microbiologically-Influenced Corrosion

In LRA Tables 3.3.2-6, 3.3.2-7, 3.3.2-10, 3.3.2-11, 3.3.2-13, 3.3.2-14, 3.3.2-19, and 3.3.2-20, 

the applicant stated that steel, stainless steel, and copper alloy components exposed to raw 

water have an aging effect of loss of material due to erosion and MIC and that the aging effect 

will be managed by the Open-Cycle Cooling Water System Program. The AMR items cite 

generic note H, indicating that for the component, material, and environment combination listed, 

the aging effect being considered is not included in the GALL Report.

The staff reviewed all AMR result lines in the GALL Report where the materials type is steel, 

stainless steel, and copper alloy components and confirmed that there are no entries for this 

material where the aging effect is erosion when the environment is raw water. The applicant 

used generic note H for some AMR items for stainless steel where the aging effect is MIC. The 

staff noted that the GALL Report does have a line item, VII.H2-18, for stainless steel 

components exposed to raw water having an aging effect of MIC. Nevertheless, the applicant 

credited its Open-Cycle Cooling Water System Program and the GALL Report recommends 

GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ therefore, the LRA AMR line items 

meet the intent of the GALL Report. 

The staff considers the Open-Cycle Cooling Water System Program to be an appropriate 

program for aging management of loss of material due to erosion in raw water because the 

program is designed to detect both corrosion and fouling of components exposed to raw water 

through the combined use of inspections and performance tests. Testing and inspection 

frequencies are adjusted based on findings.

On the basis of its review, the staff finds that the applicant 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 for these 

components will be adequately managed so that their intended functions 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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3.3.2.3.6 Loss of Material Due to Microbiologically-Influenced Corrosion from the Internal 

Surfaces of Stainless Steel Piping, Piping Components, and Piping Elements Exposed to Raw 

Water

In LRA Tables 3.3.2-6 and 3.3.2-20, the applicant stated that internal surfaces of stainless steel 

piping, piping components, and piping elements exposed to raw water are being managed for

loss of material due to MIC by the WCP and Open-Cycle Cooling Water System programs. The 

AMR items generally cite generic note H, indicating that for the component, material, and 

environment combination listed, the aging effect being considered is not evaluated in the GALL 

Report. However, there are some items that cite generic note E, indicating that the item is 

consistent with the GALL Report item for material, environment, and aging effect, but a different 

AMP is credited or the GALL Report identifies a plant-specific AMP. Some cite generic note B, 

indicating that the item is consistent with the GALL Report item for component, material, 

environment, and aging effect, but the AMP takes some exceptions to the GALL Report AMP. 

The applicant also stated that components that are nonsafety-related are managed by the WCP 

Program, and components that are safety-related are managed by the Open-Cycle Cooling 

Water System Program.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

noted that there are several GALL Report items that address stainless steel components 

exposed to raw water with an aging effect of MIC, all of which recommend the use of the 

Open-Cycle Cooling Water System Program. The staff also noted that nonsafety-related 

components are not typically addressed within the scope of the Open-Cycle Cooling Water 

Program because the components do not transfer heat to the ultimate heat sink. Therefore, the 

staff finds the use of the WCP Program acceptable because this AMP contains procedures for 

visual inspection of the interiors of pipes which are appropriate for the detection of loss of 

material due to exposure to raw water. However, it is not clear to the staff that this distinction will 

be met in all cases. By letter dated December 16, 2009, the staff issued RAI 3.3.2.3-5 

requesting that the applicant confirm that the Open-Cycle Cooling Water Program will be used 

for all safety-related systems, and that the WCP Program will be used only for nonsafety-related 

systems.

In its response dated January 21, 2010, the applicant stated that components that are 

nonsafety-related are managed by the WCP Program, and components that are safety-related 

are managed by the Open-Cycle Cooling Water System Program. The staff finds the applicant‘s 

proposed AMPs acceptable because the appropriate AMPs are being used to manage the AMR 

items based on their function and both use appropriate techniques to inspect for the aging 

mechanism. The staff‘s concern described in RAI 3.3.2.3-5 is resolved. In addition, a staff 

concern related to selection and frequency of inspections is addressed in RAI B2.1.32-2, and 

the staff‘s evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.7 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion, 

as well as Fouling from the Internal Surfaces of Copper Alloy Piping, Piping Components, and 

Piping Elements Exposed to Raw Water

In LRA Table 3.3.2-6, the applicant stated that internal surfaces of copper alloy piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to pitting, crevice, and microbiologically-influenced corrosion, as well as fouling by the WCP 

and Open-Cycle Cooling Water System programs. When the AMP credited in the LRA is the 

WCP Program, the AMR items cite generic note H, indicating that for the component, material, 

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report. When the AMP credited in the LRA is the Open-Cycle Cooling Water System 

Program, generic note B is cited, indicating that the item is consistent with the GALL Report 

item for component, material, environment, and aging effect, but the AMP takes some 

exceptions to the GALL Report AMP. The applicant stated that components that are 

nonsafety-related are managed by the WCP Program, and components that are safety-related 

are managed by the Open-Cycle Cooling Water System Program.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of copper alloy piping, piping components, and piping 

elements exposed to raw water. The staff noted that the entries recommend GALL AMP XI.M20, 

―Open-Cycle Cooling Water System,‖ for this component, material, and environment where the 

aging effect is loss of material due to pitting, crevice, and microbiologically-influenced corrosion. 

As noted above, the applicant stated that safety-related systems will be managed by the 

Open-Cycle Cooling Water System Program, and nonsafety-related components will be 

managed by the WCP Program. This review confirmed that the applicant‘s use of generic 

notes B and H are acceptable.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

reviewed LRA Table 3.3.1, item 3.3.1-81 against SRP-LR Table 3.3-1, item 81, which 

recommends the use of GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ and found 

them consistent because the notes to LRA Table 3.3.2-6 state that components that are 

nonsafety-related are managed by the WCP Program, and components that are safety-related 

are managed by the Open-Cycle Cooling Water System Program. In a revision to the 

application, AMR line items that were proposed to be managed by the WCP Program were 

changed from a reference of generic note E to generic note H. The staff finds the use of the 

WCP Program acceptable to manage the aging of the nonsafety-related components because 

the program contains inspection procedures appropriate for detecting the loss of material from 

the inside surfaces of piping exposed to raw water. In addition, a staff concern related to 

selection and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation 

of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.8 Loss of Material Due to Pitting and Crevice Corrosion, as well as Fouling from the 

Internal Surfaces of Stainless Steel Piping, Piping Components, and Piping Elements Exposed 

to Raw Water

In LRA Table 3.3.2-6, the applicant stated that internal surfaces of stainless steel piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to pitting and crevice corrosion, as well as fouling by the WCP or Open-Cycle Cooling 

Water System programs. When the AMP credited in the LRA is the WCP Program, the AMR 

items cite generic note H, indicating that for the component, material, and environment 

combination listed, the aging effect being considered is not evaluated in the GALL Report. 

When the AMP credited in the LRA is the Open-Cycle Cooling Water System Program, generic 

note B is cited, indicating that the item is consistent with the GALL Report item for component, 

material, environment, and aging effect, but the AMP takes some exceptions to the GALL 

Report AMP. 

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is internal surfaces of stainless steel piping, piping components, and piping elements 

exposed to raw water and noted that the entries recommend GALL AMP XI.M20, ―Open-Cycle 

Cooling Water System,‖ for this component, material, and environment where the aging effect is 

loss of material due to pitting and crevice corrosion, as well as fouling. The applicant stated that 

safety-related systems will be managed by the Open-Cycle Cooling Water System Program, 

and nonsafety-related components will be managed by the WCP Program. This review 

confirmed that the applicant‘s use of generic notes B and H are acceptable.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

reviewed LRA Table 3.3.1, item 3.3.1-79 against SRP-LR Table 3.3-1, item 79, which 

recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ and found them 

consistent because components that are nonsafety-related will be managed by the WCP 

Program, and components that are safety-related will be managed by the Open-Cycle Cooling 

Water System Program. In a revision to the application, AMR items that were proposed to be 

managed by the WCP Program were changed from a reference of generic note E to generic 

note H. The staff finds the use of the WCP Program acceptable to manage the aging of the 

nonsafety-related components because the WCP Program contains inspection procedures 

appropriate for detecting loss of material from the inside surfaces of piping exposed to raw 

water. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.9 Loss of Material Due to Erosion from the Internal Surfaces of Copper Alloy and Steel 

Piping, Piping Components, and Piping Elements Exposed to Raw Water

In LRA Tables 3.3.2-6, 3.3.2-15, and 3.3.2-20, the applicant stated that internal surfaces of 

copper alloy and steel piping, piping components, and piping elements exposed to raw water 

are being managed for loss of material due to erosion by the WCP or Open-Cycle Cooling 

Water System programs. The AMR items cite generic note H, indicating that for the component, 

material, and environment combination listed, the aging effect being considered is not evaluated 

in the GALL Report.

The staff reviewed all AMR result items in the GALL Report where the material and component 

type is internal surfaces of copper alloy and steel piping, piping components, and piping 

elements exposed to raw water and confirmed that there are no entries for this component, 

material, and environment where the aging effect is loss of material due to erosion. 

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluations are documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The 

applicant stated that safety-related components will be managed by the Open-Cycle Cooling 

Water System Program, and nonsafety-related components will be managed by the WCP 

Program. The staff finds the use of the WCP and Open-Cycle Cooling Water System programs 

acceptable to manage aging of this component group because both programs contain 

inspection procedures appropriate for detecting loss of material from the inside surfaces of 

piping exposed to raw water. In addition, a staff concern related to selection and frequency of 

inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.10 Loss of Strength Due to Hydrolysis from the Exterior Surfaces of Non-Metallic Filters 

and Regulators Exposed to Dry Air

In LRA Table 3.3.2-8, the applicant stated that the exterior surfaces of non-metallic filters and 

regulators exposed to dry air are being managed for loss of strength due to hydrolysis by the 

WCP Program. The AMR item cites generic note H, indicating that for the component, material, 

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is non-metallic filters and regulators exposed to dry air. The staff confirmed that 

there are no entries for this component/material and environment where the aging effect is loss 

of strength due to hydrolysis.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR items, the staff noted that the aging effect identified 

by the applicant is applicable for this combination of component, material, and environment. The 

staff noted that the LRA AMP specifically addresses paper filter elements used in the 
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compressed air system. The staff finds acceptable the applicant‘s assertion, that visual 

inspection, as included in the WCP Program, is sufficient to manage aging of these filters. The 

staff also notes, however, that the entry in LRA Table 3.3.2-8 includes both filters and regulators 

and that the material is listed as ―Non-Metallic‖ rather than paper. While the staff suspects that 

this item refers only to paper filters, it could also refer to some unidentified non-metallic material 

contained in either a filter or a regulator. Additionally, the staff noted that, with the exception of 

elastomeric materials, the scope of the WCP Program is limited to the internal surfaces of 

components. This appears to be in conflict with the component under consideration as the 

environment is specified to be external. The staff was unclear as to whether the applicant was 

referring to the external surface of the filter but that the filter is contained in another, larger, 

enclosure, which actually makes the external surface of the filter an internal surface of the filter 

assembly. By letter dated December 16, 2009, the staff issued RAI 3.3.2.3-4 requesting that the 

applicant: (a) confirm that this item refers to only paper filters; (b) if necessary, precisely define 

the other materials and components included in this item; (c) if necessary, justify the use of the 

WCP Program for these materials and components; (d) confirm that the WCP Program is used 

for this component because the external surface of the filter is an internal surface or a larger 

assembly; and (e) if necessary, justify the use of the WCP Program for external surfaces. 

In its response dated January 21, 2010, the applicant stated that the entry in LRA Table 3.3.2-8 

for non-metallic material refers only to the paper (cellulose) filter element of the filter/regulators 

component type. The filter element is located internally to the filter/regulator assembly. The 

internal surfaces monitoring inspections of the WCP Program are used to manage aging effects 

for the filter element because the filter/regulator assembly must be disassembled to inspect the 

paper filter element. 

The staff finds the applicant‘s response acceptable because the item is paper and located inside 

a larger assembly and, therefore, does need to be inspected when the filter/regulator assembly 

is disassembled. The staff‘s concern described in RAI 3.3.2.3-4 is resolved. In addition, a staff 

concern related to selection and frequency of inspections is addressed in RAI B2.1.32-2, and 

the staff‘s evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.11 Change in Material Properties Due to Thermal Exposure from the External Surfaces 

of Elastomeric Hoses Exposed to Uncontrolled Indoor Air

In LRA Tables 3.3.2-8 and 3.3.2-27, the applicant stated that external surfaces of elastomeric 

hoses exposed to uncontrolled indoor air are being managed for change in material properties 

due to thermal exposure by the WCP Program. The AMR line items cite generic note H, 

indicating that for the component, material, and environment combination listed, the aging effect 

being considered is not evaluated in the GALL Report. 

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is external surfaces of elastomeric hoses exposed to uncontrolled indoor air.

The staff confirmed that there are no entries for this component, material, and environment 

where the aging effect is change in material properties due to thermal exposure. 
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The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes both visual inspections and 

physical manipulation of elastomers. The staff also noted that the WCP Program also includes 

the external surfaces of elastomers. The staff further noted that the combined use of visual 

inspections and physical manipulations is capable of detecting changes in material properties of 

elastomers. The staff finds the applicant‘s proposal acceptable because the applicant: 

(1) identified an applicable aging effect, (2) selected an AMP with an appropriate scope for the 

component under consideration, and (3) has chosen an AMP which contains appropriate 

inspection techniques to identify that aging effect. In addition, a staff concern related to selection 

and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.12 Cracking Due to Thermal Exposure from the External Surfaces of Elastomeric Hoses 

Exposed to Uncontrolled Indoor Air

In LRA Tables 3.3.2-8 and 3.3.2.27, the applicant stated that external surfaces of elastomeric 

hoses exposed to uncontrolled indoor air are being managed for cracking due to thermal 

exposure by the WCP Program. The AMR line items cite generic note H, indicating that for the 

component, material, and environment combination listed, the aging effect being considered is 

not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is external surfaces of elastomeric hoses exposed to uncontrolled indoor air. 

The staff confirmed that there are no entries for this component, material, and environment 

where the aging effect is cracking due to thermal exposure. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes both visual inspections and 

physical manipulation of elastomers. The staff additionally noted that the WCP Program also 

includes the external surfaces of elastomers, and that the combined use of visual inspections 

and physical manipulations is capable of detecting cracking of elastomers. The staff finds the 

applicant‘s proposal acceptable because the applicant: (1) identified an applicable aging effect, 

(2) selected an AMP with an appropriate scope for the component under consideration, and 

(3) has chosen an AMP which contains appropriate inspection techniques to identify that aging 

effect. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 
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Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.13 Auxiliary Systems – Station and Instrument Air

In LRA Tables 3.3.2-8 and 3.3.2-19, the applicant stated that aluminum components exposed to 

dried air has no aging effect and that no AMP is required. The AMR line items cite generic 

note H, indicating that the aging effect is not evaluated in the GALL Report for this component, 

material, and environment combination.

The staff reviewed all AMR result lines in the GALL Report where the material is aluminum and 

confirmed that there are no entries for this material where the environment is dried air. 

The staff notes that the GALL Report recommends that aluminum piping exposed to indoor 

uncontrolled and controlled air is not subject to aging and that an AMP is not required. Based on 

this recommendation and the fact that dried air is no more aggressive toward aluminum than 

indoor air, the staff determines that the applicant‘s proposal, that no aging effects will result from 

exposing aluminum to dried air and that no AMP is required, is appropriate.

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 for these 

components will be adequately managed so that the intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3). 

3.3.2.3.14 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, Fouling, and Lining-Coating Degradation of Steel Piping, Piping Components, and 

Piping Elements Exposed to Raw Water

In LRA Tables 3.3.2-8, 3.3.2-19, and 3.3.2-20, the applicant stated that steel piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to general, pitting, crevice, and microbiologically-influenced corrosion, fouling, and 

lining-coating degradation by the WCP Program. The AMR items cite generic note H, indicating 

that for the component, material, and environment combination listed, the aging effect being 

considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is steel piping, piping components, and piping elements exposed to raw water.

The staff noted that the entries recommend GALL AMP XI.M20, ―Open-Cycle Cooling Water 

System,‖ for this component, material, and environment where the aging effect is loss of 

material due to general, pitting, crevice, and microbiologically-influenced corrosion, fouling, and 

lining-coating degradation. The applicant stated that safety-related systems will be managed by 

the Open-Cycle Cooling Water System Program, and nonsafety-related components will be 

managed by the WCP Program. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 
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staff noted that the components under consideration are nonsafety-related components. As a 

result, the use of the Open-Cycle Cooling Water Program is not appropriate as this AMP is 

limited to components in safety-related systems which transfer heat to the ultimate heat sink. 

Given that the use of the Open-Cycle Cooling Water Program is not appropriate, the staff finds 

the applicant‘s use of the WCP Program acceptable because this AMP contains visual 

inspection procedures which are appropriate for the detection of loss of material, fouling, and 

coating degradation on the internal surfaces of piping components. In addition, a staff concern 

related to selection and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s 

evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.15 Loss of Material Due to General and Pitting Corrosion from the Internal Surfaces of 

Steel Piping, Piping Components, and Piping Elements Exposed to Moist Air

In LRA Table 3.3.2-8, the applicant stated that internal surfaces of steel piping, piping 

components, and piping elements exposed to moist air are being managed for loss of material 

due to general and pitting corrosion by the WCP Program. The AMR line items cite generic 

note H, indicating that for the component, material, and environment combination listed, the 

aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the internal surfaces of steel piping, piping components, and piping elements 

exposed to moist air. The staff confirmed that there are no entries for this component, material, 

and environment where the aging effect is general and pitting corrosion. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment and 

that for these components in LRA Table 3.3.1, item 3.3.1-53, corresponding to SRP-LR 

Table 3.3-1, item 53 (exposure to condensation-internal versus moist air), the GALL Report 

recommends the use of GALL AMP XI.M24, ―Compressed Air Monitoring,‖ because the 

components under consideration are included in the station and instrument air system. The staff 

also noted that both the Compressed Air Monitoring Program, recommended by the GALL 

Report, and the WCP Program, as proposed by the applicant, contain inspection procedures 

appropriate for the detection of loss of material due to corrosion on the internal surfaces of 

piping. The staff further noted, however, that the Compressed Air Monitoring Program contains 

many aspects, in addition to piping inspections, to manage aging. Given the additional aging 

management controls contained in the Compressed Air Monitoring Program, it is not clear to the 

staff that the aging of these compressed air components can be adequately managed solely 

through the visual inspections contained in the WCP Program. By letter dated December 16, 

2009, the staff issued RAI 3.3.2.3-8 requesting that the applicant justify the use of the WCP 

Program for compressed air system components, or adopt an AMP containing all aspects of the 

Compressed Air Monitoring Program recommended by the GALL Report.
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In its response dated January 21, 2010, the applicant stated that the components for the item in 

question are traps that provide a drain path for condensed moisture in the system and,

therefore, the air quality controls of the Compressed Air Monitoring Program would not be 

effective. The staff finds the applicant‘s currently proposed AMP acceptable because the WCP 

Program is capable of detecting the aging effects by visual inspections. The staff‘s concern 

described in RAI 3.3.2.3-8 is resolved. In addition, a staff concern related to selection and 

frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI 

response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.16 Interior Surfaces of Elastomeric Materials Exposed to Inert Gas

In LRA Tables 3.3.2-8 and 3.3.2-27, the applicant stated that interior surfaces of elastomeric 

materials exposed to inert gas have no aging effect associated with this combination of material 

and environment and that no AMP is required. The AMR line items cite generic note H, 

indicating that for the component, material, and environment combination listed, the aging effect 

being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material/component 

type is interior surfaces of elastomeric materials exposed to inert gas and confirmed that there 

are no entries for this component/material and environment. However, in its review of these 

items, the staff noted that mechanisms other than the nature of the gas in contact with the 

interior surfaces of elastomeric materials (e.g., temperature and vibration) could cause aging of 

those materials. Based on the numerous causes for aging of elastomeric materials, the staff 

cannot conclude from the information provided that the components under consideration will not 

undergo aging. By letter dated October 13, 2009, the staff issued RAI 3.3.2.3.-1 requesting that 

the applicant include these components in an appropriate AMP or provide sufficient information 

to allow the staff to conclude that, under the circumstances being considered, no aging will 

occur.

In its response dated November 13, 2009, the applicant stated that no aging was expected on 

the internal surfaces of the hoses under consideration because the internal environment was 

nitrogen (dry gas). The applicant also stated that the external surfaces of these hoses were 

exposed to air. The applicant further stated that aging of the hoses due to exposure to air was 

possible and that it would be managed through the use of the WCP Program. The staff reviewed 

the applicant‘s WCP Program and its evaluation is documented in SER Section 3.0.3.2.19. This 

AMP contains specific inspection procedures to detect aging of elastomers on both internal and 

external surfaces. The staff finds the applicant‘s approach to managing the aging of these hoses 

acceptable because: (1) no aging is expected on the inner surface of the hose due to its 

exposure to a dry inert gas, and (2) aging which occurs from the exterior of the hose will be 

managed by the WCP Program, which contains requirements for visual inspection of the 

exterior surfaces of the hoses. The staff‘s concern described in RAI 3.3.2.3-1 is resolved. In 

addition, a staff concern related to selection and frequency of inspections is addressed in the 

applicant‘s response, and the staff‘s evaluation of RAI B2.1.32-2 is documented in SER 

Section 3.3.2.2.13.
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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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.17 Changes in Material Properties and Cracking of the Exterior Surfaces of Elastomeric 

Materials Exposed to Uncontrolled Indoor Air

In LRA Tables 3.3.2-10 through 3.3.2-17, the applicant stated that exterior surfaces of 

elastomeric materials exposed to uncontrolled indoor air are being managed for changes in 

material properties and cracking by the External Surfaces Monitoring Program. The AMR line 

items cite generic note H, indicating that for the component, material, and environment 

combination listed, the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material/component 

type is exterior surfaces of elastomeric materials exposed to uncontrolled indoor air and 

confirmed that there are no entries for this component/material and environment.

The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. In its review of these items, the staff noted that the 

proposed AMP uses visual inspection to identify aging. The staff also noted that identification of 

cracking in elastomers may be difficult using only visual inspection techniques. The staff further 

noted that changes in material properties, such as hardness and elasticity, cannot be reliably 

identified using only visual inspection techniques. By letter dated October 13, 2009, the staff 

issued RAI 3.3.2.3.-1 requesting that the applicant propose an AMP which includes visual 

inspection and manual manipulation of a sufficient number or area of elastomeric material at a 

sufficient inspection frequency to adequately detect cracking or changes in the material 

properties of those materials.

In its response dated November 13, 2009, the applicant cited its response to RAI B2.1.10-1. In 

that response, the applicant stated that the External Surfaces Monitoring Program includes the 

―scratch, sniff, and stretch‖ technique described in the EPRI Aging Assessment Field Guide, 

which entails detection of surface material degradation and hardening by scratching, odor 

changes possibly indicating degradation by sniffing, and elastomer hardening or cracking by 

stretching. The staff finds this acceptable because aging issues, such as changes in hardness 

and strength, may be discovered using this approach. The applicant also stated that inspections 

of accessible elastomeric components were routinely conducted and inspections of ventilation 

system components were conducted at least once per refueling cycle. The staff finds this 

acceptable because aging issues, such as changes in hardness and strength, may be 

discovered using this approach, and the frequency and extent of inspections are adequate. The 

staff‘s concern described in RAI 3.3.2.3-1 is resolved.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.18 Reduction in Heat Transfer Due to Fouling from the Exterior Surfaces of Aluminum 

Cooling and Condenser Fins Exposed to Moist Air

In LRA Tables 3.3.2-10, 3.3.2-13, 3.3.2-15, 3.3.2-17, and 3.3.2-19, the applicant stated that 

exterior surfaces of aluminum cooling and condenser fins exposed to moist air are being 

managed for reduction in heat transfer due to fouling by the WCP Program. The AMR line items 

cite generic note H, indicating that for the component, material, and environment combination 

listed, the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is exterior surfaces of aluminum cooling and condenser fins exposed to moist 

air. The staff confirmed that there are no entries for this component, material, and environment 

where the aging effect is reduction in heat transfer due to fouling. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP only includes visual inspections of internal 

surfaces. The staff additionally noted that the environment listed for these items is external 

moist air. The staff further noted that visual inspections, as contained in the proposed AMP, are 

capable of identifying reduction in heat transfer due to fouling. Finally, the staff noted that the 

fins under consideration are contained in a larger structure. Since these fins may be inspected 

only when the larger structure is open for inspection, they are functionally internal surfaces to 

the larger structure. The staff finds the use of the WCP Program acceptable for managing this 

aging because: (1) the applicant identified an applicable aging effect, (2) appropriate visual 

inspections are included in the proposed AMP, and (3) the fins under consideration are 

functionally internal surfaces falling within the scope of the proposed AMP. In addition, a staff 

concern related to selection and frequency of inspections is addressed in RAI B2.1.32-2, and 

the staff‘s evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.19 Hardening and Loss of Strength Due to Elastomer Degradation from the Internal 

Surfaces of Elastomeric Flexible Connections Exposed to Moist Air and Uncontrolled Indoor Air

In LRA Tables 3.3.2-10 through 3.3.2-17, the applicant stated that internal surfaces of 

elastomeric flexible connections exposed to moist air and uncontrolled indoor air are being 

managed for hardening and loss of strength due to elastomer degradation by the WCP 

Program. The AMR line items cite generic note H, indicating that for the component, material, 

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of elastomeric flexible connections exposed to moist air and 

uncontrolled indoor air. The staff confirmed that there are no entries for this component, 
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material, and environment where the aging effect is hardening and loss of strength due to 

elastomer degradation. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes both visual inspections and 

physical manipulation of elastomers. The staff further noted that the combined use of visual 

inspections and physical manipulations are capable of detecting hardening and loss of strength 

of elastomers. The staff finds the applicant‘s proposal acceptable because the applicant has 

identified an applicable aging effect and has chosen an AMP which contains appropriate 

inspection techniques to identify that aging effect. In addition, a staff concern related to selection 

and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.20 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, as well as Fouling from the Internal Surfaces of Steel Piping, Piping Components, 

and Piping Elements Exposed to Raw Water

In LRA Tables 3.3.2-13, 3.3.2-14, 3.3.2-15, 3.3.2-17, 3.3.2-21, 3.3.2-22, 3.3.2-25, 3.3.2-26, and 

3.3.2.18, the applicant stated that internal surfaces of steel piping, piping components, and 

piping elements exposed to raw water are being managed for loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion, as well as fouling by the WCP 

Program. The AMR line items cite generic note H, indicating that for the component, material, 

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of steel piping, piping components, and piping elements 

exposed to raw water. The staff noted that the GALL Report recommends either a plant-specific 

AMP or GALL AMP XI.M27, ―Fire Water System,‖ for this component, material, and environment 

where the aging effect is loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion, as well as fouling. The staff also noted that the 

components under consideration are generally waste and drain systems. The staff further noted 

that none of these systems are safety-related and none are related directly to fire protection. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff finds the proposed AMP acceptable to manage aging for these components as it contains 

internal inspection techniques suitable for detecting corrosion or fouling on the internal surfaces 

of piping systems. In addition, a staff concern related to selection and frequency of inspections 

is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in 

SER Section 3.3.2.2.13.
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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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.21 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion, 

as well as Fouling from the Internal Surfaces of Copper Alloy Piping, Piping Components, and 

Piping Elements Exposed to Raw Water

In LRA Table 3.3.2-15, the applicant stated that internal surfaces of copper alloy piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to pitting, crevice, and microbiologically-influenced corrosion, as well as fouling by the WCP 

or Open-Cycle Cooling Water System programs. When the AMP credited in the LRA is the WCP 

Program, the AMR line items cite generic note H, indicating that for the component, material, 

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report. When the AMP credited in the LRA is the Open-Cycle Cooling Water System 

Program, generic note B is cited, indicating that the item is consistent with the GALL Report 

item for component, material, environment, and aging effect, but the AMP takes some 

exceptions to the GALL Report AMP. The applicant stated that components that are 

nonsafety-related are managed by the WCP Program, and components that are safety-related 

are managed by the Open-Cycle Cooling Water System Program.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of copper alloy piping, piping components, and piping 

elements exposed to raw water. The staff noted that the entries recommend GALL AMP XI.M20, 

―Open-Cycle Cooling Water System,‖ for this component, material, and environment where the 

aging effect is loss of material due to pitting, crevice, and microbiologically-influenced corrosion, 

as well as fouling. As noted above, the applicant stated that safety-related systems will be 

managed by the Open-Cycle Cooling Water System Program, and nonsafety-related 

components will be managed by the WCP Program. This review confirmed that the applicant‘s 

use of generic notes B and H are acceptable.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

reviewed LRA Table 3.3.1, item 3.3.1-82 against SRP-LR Table 3.3-1, item 82, which 

recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ and found them 

consistent because the notes in LRA Table 3.3.2-15 state that components that are 

nonsafety-related are managed by the WCP and components that are safety-related are 

managed by the Open-Cycle Cooling Water System Program. In a revision to the application, 

AMR line items that were proposed to be managed by the WCP Program were changed from a 

reference of generic note E to generic note H. The staff finds the use of the WCP Program 

acceptable to manage aging of the nonsafety-related components because the WCP Program 

contains inspection procedures appropriate for detecting loss of material from the inside 

surfaces of piping exposed to raw water. In addition, a staff concern related to selection and 

frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI 

response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 
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Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.22 Loss of Heat Transfer Due to Fouling from the Internal Surfaces of Copper Alloy 

Heat Exchanger Tubes Exposed to Raw Water

In LRA Table 3.3.2-15, the applicant stated that internal surfaces of copper alloy heat exchanger 

tubes exposed to raw water are being managed for loss of heat transfer due to fouling by the 

WCP or Open-Cycle Cooling Water System programs. When the AMP credited in the LRA is the 

WCP Program, the AMR line items cite generic note H, indicating that for the component, 

material, and environment combination listed, the aging effect being considered is not evaluated 

in the GALL Report. When the AMP credited in the LRA is the Open-Cycle Cooling Water 

System Program, generic note B is cited, indicating that the item is consistent with the GALL 

Report item for component, material, environment, and aging effect, but the AMP takes some 

exceptions to the GALL Report AMP. 

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of copper alloy piping, piping components, and piping 

elements exposed to raw water. The staff noted that the entries recommend GALL AMP XI.M20, 

―Open-Cycle Cooling Water System,‖ for this component, material, and environment where the 

aging effect is loss of material due to pitting, crevice, and microbiologically-influenced corrosion, 

as well as fouling. The applicant stated that safety-related systems will be managed by the 

Open-Cycle Cooling Water System Program, and nonsafety-related components will be 

managed by the WCP Program. This review confirmed that the applicant‘s use of generic 

notes B and H are acceptable.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

reviewed LRA Table 3.3.1, item 3.3.1-83 against SRP-LR Table 3.3-1, item 83, which 

recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ and found them 

consistent because components that are nonsafety-related will be managed by the WCP 

Program and components that are safety-related will be managed by the Open-Cycle Cooling 

Water System Program. In a revision to the application, AMR line items that were proposed to 

be managed by the WCP Program were changed from a reference of generic note E to generic 

note H. The staff finds the use of the WCP Program acceptable to manage the aging of 

nonsafety-related components because the WCP Program contains inspection procedures 

appropriate for detecting loss of material from the inside surfaces of piping exposed to raw 

water. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.23 Loss of Material Due to General Corrosion from the Internal and External Surfaces of 

Steel Components Exposed to Uncontrolled Indoor Air

In LRA Tables 3.3.2-17 and 3.3.2-28, the applicant stated that the internal and external surfaces 

of steel components exposed to uncontrolled indoor air are being managed for loss of material 

due to general corrosion by the WCP Program. The AMR line items cite generic note H. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff also noted that the scope of the LRA AMP for metallic materials is limited to internal 

surfaces. The staff further noted that the visual inspections included in the AMP are capable of 

detecting loss of material due to general corrosion. The staff, therefore, finds the applicant‘s 

proposal to manage the loss of material from the internal surfaces of these components under 

consideration in LRA Table 3.3.2-28 acceptable because the components are within the scope 

of the AMP and appropriate inspection methods are included in the proposed AMP. However, 

the staff questions the use of the WCP Program for the management of the loss of material from 

the external surfaces of the compressor included in LRA Table 3.3.2-17, because external 

surfaces are not within the scope of the proposed AMP. By letter dated January 4, 2010, the 

staff issued RAI 3.3.2.3-7 requesting that the applicant justify the use of the WCP Program for 

external surfaces, or select an AMP which is appropriate for use on external surfaces.

In its response dated February 2, 2010, the applicant stated that the WCP Program includes the 

Internal Surfaces Monitoring Program under its scope. The applicant also stated that the 

applicable items in LRA Table 3.3.2-17 were under the inspection scope of the Internal Surfaces 

Monitoring Program because they are the external surfaces of subcomponents within the air 

conditioning unit‘s outer housings and, thus, require disassembly to inspect. The staff finds the 

applicant‘s response acceptable because given the position of the components, the WCP 

Program is the appropriate AMP. In addition, a staff concern related to selection and frequency 

of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.24 Loss of Material or Microbiologically-Influenced Corrosion of Stainless Steel Tubing, 

Valves, and Strainers Exposed to Raw Water

LRA Table 3.3.2-18 summarizes results of the AMRs for fire protection systems. In LRA 

Table 3.3.2-18, the applicant stated that for stainless steel tubing, valves, and strainers exposed 

to raw water, the aging effects of loss of material or MIC are not evaluated in the GALL Report. 

The applicant stated that these components are managed by the Fire Protection Program. The 

applicant referenced generic note H for these items, indicating that the aging effect of this 

component, material, and environment combination is not evaluated in the GALL Report. 

The staff evaluated the applicant‘s claim that the aging effect for this component, material, and 

environment combination is not evaluated in the GALL Report. The staff reviewed all AMR result 
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lines in the GALL Report and found none where the material is stainless steel, the environment 

is raw water, and the aging effect is loss of material or MIC. The staff confirmed that the 

applicant‘s use of generic footnote H is acceptable. The staff evaluated the use of stainless 

steel strainers, tubing, and valves in a raw water environment and noted that the material 

generally performs satisfactorily in a raw water environment without excessive corrosion or loss 

of material. 

The staff reviewed the applicant‘s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.8. The staff noted that the applicant‘s Fire Protection Program includes 

periodic flushing and chemical treatment of the water-based fire suppression system. The staff 

also noted that it is an industry practice to examine the equipment condition of water-based fire 

suppression system components during periodic flushing and after chemical treatment. The staff 

finds that loss of material or MIC can, therefore, be adequately managed by periodic flushing 

and chemical treatment. The staff further noted that the applicant has identified an appropriate 

program to manage the aging effects of stainless steel strainers, tubing, and valves. 

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 concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.25 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion from the Internal 

Surfaces of Aluminum Flame Arrestors, Hoods, and Caps Exposed to Outdoor Air

In LRA Table 3.3.2-19, the applicant stated that internal surfaces of aluminum flame arrestors, 

hoods, and caps exposed to outdoor air are being managed for loss of material due to pitting, 

crevice, and galvanic corrosion by the WCP Program. The AMR items cite generic note H, 

indicating that for the component, material, and environment combination listed, the aging effect 

being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of aluminum flame arrestors, hoods, and caps exposed to 

outdoor air. The staff confirmed that there are no entries for this component, material, and 

environment where the aging effect is loss of material due to pitting, crevice, and galvanic 

corrosion. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes visual inspection of internal 

surfaces. The staff further noted that visual inspections are capable of detecting loss of material 

due to pitting, crevice, and galvanic corrosion. The staff finds the applicant‘s proposal 

acceptable because the applicant has identified an applicable aging effect and has chosen an 

AMP which contains appropriate inspection techniques to identify those aging effects. In 

addition, a staff concern related to selection and frequency of inspections is addressed in 

RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 
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Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.26 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion from the Internal Surfaces of Steel Piping, Piping Components, and Piping Elements 

Exposed to Treated Closed-Cycle Cooling Water

In LRA Table 3.3.2-19, the applicant stated that internal surfaces of steel piping, piping 

components, and piping elements exposed to treated closed-cycle cooling water are being 

managed for loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion by the WCP Program. The AMR line items cite generic note B, indicating that the item 

is consistent with the GALL Report for component, material, environment, and aging effect, but 

the AMP takes some exceptions to the GALL Report AMP and generic note H, indicating that for 

the component, material, and environment combination listed, the aging effect being considered 

is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of steel piping, piping components, and piping elements 

exposed to treated closed-cycle cooling water. The staff noted that for Table 3.3.1, 

item 3.3.1-47, GALL AMP XI.M21, ―Closed-Cycle Cooling Water System,‖ is recommended for 

this component, material, and environment where the aging effect is loss of material due to 

general, pitting, crevice, and microbiologically-influenced corrosion. The staff also noted that 

note 3 for LRA Table 3.3.2-19 states that:

Aging effects for the internal surfaces of the TSC diesel generator cooling water 

components are managed by the Work Control Process. Aging effects for the 

internal surfaces of the emergency diesel generator cooling water components 

are managed by the Closed Cycle Cooling Water System aging management 

program, which is confirmed by the Work Control Process.

The staff further noted that the EDG is a safety-related component and the TSC diesel 

generator is not. The staff agrees with the applicant that it is appropriate to manage the aging of 

components in the EDG which are exposed to treated water using the Closed-Cycle Cooling 

Water System Program. The staff also agrees with the applicant that it is not appropriate to 

manage the aging of components of the TSC generator using the Closed-Cycle Cooling Water 

System Program because the scope of this AMP is limited to safety-related components. This 

review confirmed that the applicant‘s use of generic notes B and H are acceptable.

The staff finds the applicant‘s proposal to manage aging using the portion of the WCP Program 

which is consistent with GALL AMP XI.M38, ―Inspection of Internal Surfaces of Miscellaneous 

Piping and Ducting Components,‖ acceptable because: (1) the scope of this AMP includes 

internal surfaces of piping and ducting components not included in other AMPs, and (2) the 

WCP Program contains visual inspection techniques appropriate to the identification of loss of 

material for these components. In addition, a staff concern related to selection and frequency of 

inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 
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Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.27 Loss of Material Due to Pitting and Crevice Corrosion from the Internal Surfaces of 

Stainless Steel Piping, Piping Components, and Piping Elements Exposed to Raw Water

In LRA Table 3.3.2-20, the applicant stated that internal surfaces of stainless steel piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to pitting and crevice corrosion by the WCP and Open-Cycle Cooling Water System 

programs. When the AMP credited in the LRA is the WCP Program, the AMR line items cite 

generic note H, indicating that for the component, material, and environment combination listed, 

the aging effect being considered is not evaluated in the GALL Report. When the AMP credited 

in the LRA is the Open-Cycle Cooling Water System Program, generic note B is cited, indicating 

that the item is consistent with the GALL Report item for component, material, environment, and 

aging effect, but the AMP takes some exceptions to the GALL Report AMP.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of stainless steel piping, piping components, and piping 

elements exposed to raw water. The staff noted that these items recommend GALL 

AMP XI.M20, ―Open-Cycle Cooling Water System,‖ for this component, material, and 

environment where the aging effect is loss of material due to pitting and crevice corrosion. The 

applicant stated that safety-related systems will be managed by the Open-Cycle Cooling Water 

System Program, and nonsafety-related components will be managed by the WCP Program. 

This review confirmed that the applicant‘s use of generic notes B and H are acceptable.

The staff reviewed the applicant‘s WCP and Open-Cycle Cooling Water System programs and 

its evaluation is documented in SER Sections 3.0.3.2.19 and 3.0.3.2.14, respectively. The staff 

reviewed LRA Table 3.3.1, item 3.3.1-78 against SRP-LR Table 3.3-1, item 78, which 

recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ and found them 

consistent because components that are nonsafety-related will be managed by the WCP 

Program and components that are safety-related will be managed by the Open-Cycle Cooling 

Water System Program. In a revision to the application, AMR line items that were proposed to 

be managed by the WCP Program were changed from a reference of generic note E to generic 

note H. The staff finds the use of the WCP Program acceptable to manage the aging of the 

nonsafety-related components because the WCP Program contains inspection procedures 

appropriate for detecting loss of material from the inside surfaces of piping exposed to raw 

water. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions 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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3.3.2.3.28 Loss of Material Due to Microbiologically-Influenced Corrosion of Stainless Steel 

Piping, Piping Components, and Piping Elements Exposed to Soil

In LRA Table 3.3.2-20, the applicant stated that stainless steel piping, piping components, and 

piping elements exposed to soil have an aging effect of loss of material due to MIC and that the 

aging effect will be managed by the Buried Piping and Tanks Inspection Program. The AMR line 

item cites generic note H, indicating that the aging effect for this component, material, and 

environmental combination is not in the GALL Report.

The staff reviewed all AMR result lines in the GALL Report where the material is stainless steel 

piping, piping components, and piping elements and confirmed that there are no entries for this 

material where the environment is soil. The staff reviewed the applicant‘s Buried Piping and 

Tanks Inspection Program and its evaluation is documented in SER Section 3.0.3.2.4.

The GALL AMP XI.M34 program description does not include stainless steel; however, in its 

review of LRA Table 3.3.2-20, the staff found that the material for the components is stainless 

steel. By letter dated August 28, 2009, the staff issued RAI 3.3.2.3.20-1 requesting that the 

applicant confirm whether the buried stainless steel piping is wrapped, coated, or bare and, if 

coated or wrapped, justify how the proposed AMP will adequately manage its aging.

In its response dated September 28, 2009, the applicant stated that the answer to this RAI was 

contained in its response to RAI B2.1.7 which was transmitted by letter dated August 17, 2009. 

The staff reviewed the response to this RAI, in which the applicant stated that the stainless steel 

piping under consideration is a vent line which: (1) was installed in 2003, (2) consists of 

approximately 20 feet of 2 inch nominal ASTM A-312 schedule 80 pipe, (3) is all buried except 

for about 3 feet, and (4) is coated and wrapped. The applicant also stated that even though the 

material for this line was not in the GALL Report AMP, its failure was highly unlikely due to the 

design of the piping, recent installation, and planned inspections.

The staff finds the applicant‘s response to RAI 3.3.2.3.20-1 acceptable because there is an 

exceptionally small probability that the pipe under consideration will fail based on its design 

(i.e., pipe need not retain any pressure) and planned inspections. The staff‘s concern described 

in RAI 3.3.2.3.20-1 is resolved.

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 for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.29 Hardening and Loss of Strength Due to Elastomer Degradation from the Internal 

Surfaces of Elastomeric Hoses and Flow Elements Exposed to Raw Water

In LRA Tables 3.3.2-22 and 3.3.2-26 and Table 3.3.1, item 3.3.1-75, the applicant stated that 

internal surfaces of elastomeric hoses and flow elements exposed to raw water are being 

managed for hardening and loss of strength due to elastomer degradation by the WCP 

Program. The AMR line items cite generic note H, indicating that for the component, material,

and environment combination listed, the aging effect being considered is not evaluated in the 

GALL Report.
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The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of elastomeric hoses and flow elements exposed to raw 

water. The staff confirmed that there are no entries for this component, material, and 

environment where the aging effect is hardening and loss of strength due to elastomer 

degradation. The staff notes that GALL Report Table VII.C1, item 1 does address elastomers 

exposed to raw water with an aging effect of hardening and loss of strength due to elastomer 

degradation and recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water System.‖ The 

staff also noted that neither of these systems, liquid waste processing and discharge, nor 

miscellaneous drains and sumps, transfer heat to the ultimate heat sink and, therefore, they do 

not fall under the scope of this GALL Report recommended program. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 

identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes both visual inspections and 

physical manipulation of elastomers. The staff further noted that the combined use of visual 

inspections and physical manipulations are capable of detecting hardening and loss of strength 

of elastomers. The staff finds the applicant‘s proposal acceptable because the applicant has 

identified an applicable aging effect and has chosen an AMP which contains appropriate 

inspection techniques to identify that aging effect. In addition, a staff concern related to selection 

and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.30 Loss of Material Due to Erosion from the Internal Surfaces of Elastomeric Hoses and 

Flow Elements Exposed to Raw Water

In LRA Tables 3.3.2-22 and 3.3.2.1-26, the applicant stated that internal surfaces of elastomeric 

hoses and flow elements exposed to raw water are being managed for loss of material due to 

erosion by the WCP Program. The AMR line items cite generic note H, indicating that for the 

component, material, and environment combination listed, the aging effect being considered is 

not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is internal surfaces of elastomeric hoses and flow elements exposed to raw 

water. The staff confirmed that there are no entries for this component, material, and 

environment where the aging effect is loss of material due to erosion. The staff notes that GALL 

Report Table VII.C1, item 2, does address elastomers exposed to raw water with an aging effect 

of loss of material due to erosion and recommends GALL AMP XI.M20, ―Open-Cycle Cooling 

Water System.‖ The staff also noted that neither of these systems, liquid waste processing and 

discharge, and miscellaneous drains and sumps, transfer heat to the ultimate heat sink and, 

therefore, they do not fall under the scope of this GALL Report recommended program. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of the AMR line items, the staff noted that the aging effect 
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identified by the applicant is applicable for this combination of component, material, and 

environment. The staff also noted that the LRA AMP includes both visual inspections and 

physical manipulation of elastomers. The staff further noted that the combined use of visual 

inspections and physical manipulations are capable of detecting loss of material from 

elastomers. The staff finds the applicant‘s proposal acceptable because the applicant has 

identified an applicable aging effect and has chosen an AMP which contains appropriate 

inspection techniques to identify that aging effect. In addition, a staff concern related to selection 

and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.3.31 Stainless Steel Components Exposed to Air-Indoor Controlled (External)

LRA Tables 3.3.2-10 and 3.3.2-11 address temperature elements fabricated from stainless steel 

exposed to air-indoor controlled (external) that do not have an aging effect, therefore, an AMP is 

not required. The AMR items cite generic note H, which indicates that the aging effect is not in 

the GALL Report for this component, material, and environment combination.

The staff reviewed LRA Table 3.0-1, ―Service Environments,‖ and noted that the applicant 

defines air-indoor controlled as ―air-conditioned plant areas where the temperature and humidity 

levels are controlled. Condensation does not typically occur in an air-indoor controlled 

environment.‖ The staff noted the GALL Report, Chapter IX defines air-indoor controlled as ―the 

environment to which the specified internal or external surface of the component or structure is 

exposed: indoor air in a humidity controlled (e.g., air conditioned) environment.‖ The staff 

determined that the applicant‘s environment is consistent with the environment described in the 

GALL Report.

The staff reviewed the GALL Report, Section VII.J and noted that GALL AMR item VII.J-15 

states that piping, piping components, and piping elements fabricated of stainless steel that are 

exposed to air-indoor uncontrolled (external) do not experience an AERM. The staff noted that 

the air-indoor controlled is humidity controlled, which will preclude the formation of condensation 

which can occur in an air-indoor uncontrolled environment. Based on its review, the staff finds 

that stainless steel components exposed to air-indoor that is humidity controlled, which 

precludes the formation of condensation, do not experience an AERM because it is more 

conservative than the recommendation of GALL AMR item VII.J-15. The staff finds the applicant 

has appropriately determined that stainless steel exposed to air-indoor controlled (external) 

does not have an AERM.

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 functions 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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3.3.2.3.32 Stainless Steel Components Subject to Loss of Material Due to Erosion Exposed to 

Raw Water 

LRA Table 3.3.2-3 addresses the SFP heat exchanger tubes and tubesheet fabricated from 

stainless steel exposed to raw water (external), which are subject to loss of material due to 

erosion. LRA Table 3.3.2-9 addresses the boric acid evaporator distillate sample cooler tubing 

fabricated from stainless steel exposed to raw water (external), which is subject to loss of 

material due to erosion. LRA Table 3.3.2-21 addresses orifices, piping, strainer housings, and 

valves fabricated from stainless steel exposed to raw water (external), which are subject to loss 

of material due to erosion. LRA Table 3.3.2-22 addresses tanks, pumps, filter housings, flow 

elements, flow orifices, flow transmitters, piping, strainer housings, tubing, and valves fabricated 

from stainless steel exposed to raw water (internal), which are subject to loss of material due to 

erosion. LRA Table 3.3.2-23 addresses radiation detectors fabricated from stainless steel 

exposed to raw water (internal), which are subject to loss of material due to erosion. LRA 

Table 3.3.2-25 addresses flow elements, mixers (static), and piping fabricated from stainless 

steel exposed to raw water (internal), which are subject to loss of material due to erosion. LRA 

Table 3.3.2-26 addresses piping, orifices, pumps, and valves fabricated from stainless steel 

exposed to raw water (internal), which are subject to loss of material due to erosion. The 

applicant credited the WCP Program for aging management of loss of material for the 

components described above. The AMR items cite generic note H, which indicates that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 

for the detection of degradation prior to the loss of intended function and (2) require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 

deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

acceptable.
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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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.33 Stainless Steel Components Subject to Loss of Material Due to Pitting and Crevice 

Corrosion Exposed to Air-Outdoor, Air-Moist, Raw Water, and Treated Water-Closed-Cycle 

Cooling

LRA Table 3.3.2-14 addresses the containment fan coil unit drip pan exposed to raw water 

(external) and piping exposed to raw water (internal) fabricated from stainless steel, which are 

subject to loss of material due to pitting and crevice corrosion. LRA Table 3.3.2-18 addresses 

flexible hoses, valves, and tubing fabricated from stainless steel exposed to air-moist (internal), 

which are subject to loss of material due to pitting and crevice corrosion. LRA Table 3.3.2-19 

addresses flame arrestor, hoods, and caps exposed to air-outdoor (internal) and flexible

connections and sight glass components exposed to treated water-closed-cycle cooling 

(internal) fabricated from stainless steel, which are subject to loss of material due to pitting and 

crevice corrosion. LRA Table 3.3.2-20 addresses flow elements, flow indicators, piping, and 

tubing fabricated from stainless steel exposed to raw water (internal), which are subject to loss 

of material due to pitting and crevice corrosion. LRA Table 3.3.2-21 addresses filter housings, 

orifices, piping, tubing, and valves fabricated from stainless steel exposed to air-moist (internal), 

which are subject to loss of material due to pitting and crevice corrosion. LRA Table 3.3.2-22 

addresses the distillate cooler (shell only), the evaporator condenser (shell only), the waste 

evaporator sample cooler (shell only), level switches, piping, and tubing fabricated from 

stainless steel exposed to air-moist (internal), which are subject to loss of material due to pitting 

and crevice corrosion. LRA Table 3.3.2-23 addresses radiation detectors, tubing, and valves 

fabricated from stainless steel exposed to air-moist (internal), which are subject to loss of 

material due to pitting and crevice corrosion. LRA Table 3.3.2-26 addresses piping and valves 

fabricated from stainless steel exposed to air-moist (internal), which are subject to loss of 

material due to pitting and crevice corrosion. LRA Table 3.3.2-27 addresses hoses fabricated 

from stainless steel exposed to air-moist (internal), which are subject to loss of material due to 

pitting and crevice corrosion. The applicant credited the WCP Program for aging management 

of loss of material for the components described above. The AMR items cite generic note H, 

which indicates that the aging effect is not in the GALL Report for this component, material, and 

environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program, and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 
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management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 

for the detection of degradation prior to the loss of intended function and (2) require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.34 Copper Alloy Components Subject to Loss of Material Due to Erosion and Loss of 

Material Due to Pitting, Crevice, Galvanic, and Microbiologically-Influenced Corrosion and 

Fouling Exposed to Raw Water

LRA Table 3.3.2-8 addresses aftercooler (tubes) fabricated from copper alloy exposed to raw 

water (external), which are subject to loss of material due to erosion and loss of material due to 

pitting, crevice, galvanic, and microbiologically-influenced corrosion and fouling. LRA 

Table 3.3.2-20 addresses valves fabricated from copper alloy exposed to raw water (internal), 

which are subject to loss of material due to erosion. LRA Table 3.3.2-21 addresses heat 

exchanger (tubes) fabricated from copper alloy exposed to raw water (external) and valves 

fabricated from copper alloy exposed to raw water (internal), which are subject to loss of 

material due to erosion. LRA Table 3.3.2-25 addresses valves fabricated from copper alloy 

exposed to raw water (internal), which are subject to loss of material due to erosion. 

The applicant credited the WCP Program for aging management of loss of material for the 

components described above. The AMR items cite generic note H, which indicates that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 
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of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) require that the extent of 

the inspection and its results be documented even when no signs of aging degradation are 

found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 

deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.35 Copper Alloy Components Subject to Loss of Material Due to Pitting, Crevice, and 

Microbiologically-Influenced Corrosion and Fouling Exposed to Raw Water

LRA Table 3.3.2-20 addresses flow indicators, tubing, and valves fabricated from copper alloy 

exposed to raw water (internal), which are subject to loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling. LRA Table 3.3.2-21 addresses heat 

exchanger (tubes) fabricated from copper alloy exposed to raw water (external) and valves 

fabricated from copper alloy exposed to raw water (internal), which are subject to loss of 

material due to pitting, crevice, and microbiologically-influenced corrosion and fouling. LRA 

Table 3.3.2-25 addresses tubing and valves fabricated from copper alloy exposed to raw water 

(internal), which are subject to loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling. LRA Table 3.3.2-28 addresses piping and 

valves fabricated from copper alloy exposed to raw water (internal), which are subject to loss of 

material due to pitting, crevice, and microbiologically-influenced corrosion and fouling. The 

applicant credited the WCP Program for aging management of loss of material for the 

components described above. The AMR items cite generic note H, which indicates that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.
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The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) require that the extent of 

the inspection and its results be documented even when no signs of aging degradation are 

found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 

deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.36 Copper Alloy Components Subject to Reduction of Heat Transfer Due to Fouling 

Exposed to Raw Water and Air-Moist

LRA Table 3.3.2-8 addresses aftercooler (tubes) fabricated from copper alloy exposed to raw 

water (external), which are subject to reduction of heat transfer due to fouling. LRA 

Table 3.3.2-10 addresses air handling units (cooling coils/fins) fabricated from copper alloy 

exposed to air-moist (external), which are subject to reduction of heat transfer due to fouling. 

LRA Table 3.3.2-13 addresses fan coil units (cooling coils/fins) fabricated from copper alloy 

exposed to air-moist (external), which are subject to reduction of heat transfer due to fouling. 

LRA Table 3.3.2-14 addresses containment fan coil units (cooling coils) fabricated from copper 

alloy exposed to air-moist (external) and shroud cooling coils (cooling coils) fabricated from 

copper alloy exposed to air-indoor uncontrolled (external), which are subject to reduction of heat 

transfer due to fouling. LRA Table 3.3.2-15 addresses fan coil units (cooling coils/fins) fabricated 

from copper alloy exposed to air-moist (external), which are subject to reduction of heat transfer 

due to fouling. LRA Table 3.3.2-17 addresses air conditioning units (battery room cooling 

coils/fins and condenser/fins) fabricated from copper alloy exposed to air-moist (external), which 

are subject to reduction of heat transfer due to fouling. The applicant credited the WCP Program 

for aging management of loss of material for the components described above. The AMR items 

cite generic note H, which indicates that the aging effect is not in the GALL Report for this 

component, material, and environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 
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determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect reduction of heat transfer due to fouling. The staff further determined that this 

program will: (1) perform inspections of components during surveillance and maintenance 

activities to provide for the detection of degradation prior to the loss of intended function and 

(2) require that the extent of the inspection and its results be documented even when no signs 

of aging degradation are found so that there is a meaningful trending of aging effects. The staff 

noted that the visual inspection techniques are established and are capable of detecting 

reduction of heat transfer due to fouling by indications of any fouling (buildup from whatever 

source) on the surface of these components. On the basis of periodic visual inspections being 

performed during surveillance and maintenance activities of these components by the WCP 

Program, the staff finds the applicant‘s use of the WCP Program 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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.37 Stainless Steel Components Subject to Loss of Material Due to Fretting Exposed to 

Raw Water and Treated Water-Closed-Cycle Cooling

LRA Table 3.3.2-3 addresses the SFP heat exchanger tubes fabricated from stainless steel 

exposed to raw water (external), which are subject to loss of material due to fretting. LRA 

Table 3.3.2-9 addresses the letdown heat exchanger tubes fabricated from stainless steel 

exposed to treated water-closed-cycle cooling (external), which are subject to loss of material 

due to fretting. The applicant credited the WCP Program for aging management of loss of 

material for the components described above. The AMR items cite generic note H, which 

indicates that the aging effect is not in the GALL Report for this component, material, and 

environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 
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stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 

for the detection of degradation prior to the loss of intended function and (2) require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 

deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.38 Stainless Steel Components Subject to Loss of Material Due to Pitting, Crevice, and 

Microbiologically-Influenced Corrosion and Fouling Exposed to Raw Water

LRA Table 3.3.2-3 addresses the SFP heat exchanger tubes and tubesheet fabricated from 

stainless steel exposed to raw water (external), which are subject to loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion and fouling. LRA Table 3.3.2-9 

addresses the boric acid evaporator distillate sample cooler tubing fabricated from stainless 

steel exposed to raw water (external), which is subject to loss of material due to pitting, crevice, 

and microbiologically-influenced corrosion and fouling. LRA Tables 3.3.2-21, 3.3.2-22, 3.3.2-23, 

3.3.2-25, and 3.3.2-26 address piping, piping components, piping elements, heat exchanger 

components, radiation detectors, and tanks exposed to raw water which are subject to loss of 

material due to pitting, crevice, and microbiologically-influenced corrosion. The applicant 

credited the WCP Program for aging management of loss of material for the components 

described above. The AMR items cite generic note H, which indicates that the aging effect is not 

in the GALL Report for this component, material, and environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 
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for the detection of degradation prior to the loss of intended function and (2) require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 

deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.39 Copper Alloy Components Subject to Loss of Material Due to Pitting, Crevice, 

Galvanic, and Microbiologically-Influenced Corrosion Exposed to Treated Water-Closed-Cycle 

Cooling and Air-Outdoor

LRA Table 3.3.2-19 addresses radiator (tubes) fabricated from copper alloy exposed to treated 

water-closed-cycle cooling (internal), which are subject to loss of material due to pitting, crevice, 

galvanic, and microbiologically-influenced corrosion, and radiator (tubes) fabricated from copper 

alloy exposed to air-outdoor (external), which are subject to loss of material due to pitting and 

crevice corrosion. The applicant credited the WCP Program for aging management of loss of 

material for the components described above. The AMR items cite generic note H, which 

indicates that the aging effect is not in the GALL Report for this component, material, and 

environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) require that the extent of 

the inspection and its results be documented even when no signs of aging degradation are 

found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 
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scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.40 Stainless Steel Components Subject to Loss of Material Due to 

Microbiologically-Influenced Corrosion and Loss of Material Due to Pitting and Crevice 

Corrosion and Fouling Exposed to Raw Water and Treated Water-Closed-Cycle Cooling

LRA Table 3.3.2-6 addresses filter housings (service water to chlorination pumps) and flexible 

hoses fabricated from stainless steel exposed to raw water (internal), which are subject to loss 

of material due to pitting, crevice, and microbiologically-influenced corrosion and fouling. LRA 

Table 3.3.2-9 addresses boric acid evaporator distillate sample cooler (tubing) fabricated from 

stainless steel exposed to raw water (external), which is subject to loss of material due to MIC. 

LRA Table 3.3.2-19 addresses flexible connections (including braided lines) and sight glasses 

fabricated from stainless steel exposed to treated water-closed-cycle cooling water (internal), 

which are subject to loss of material due to MIC. LRA Table 3.3.2-20 addresses flow elements, 

flow indicators, piping, and tubing fabricated from stainless steel exposed to raw water 

(internal), which are subject to loss of material due to MIC. The applicant credited the WCP 

Program for aging management of loss of material for the components described above. The 

AMR items cite generic note H, which indicates that the aging effect is not in the GALL Report 

for this component, material, and environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 

for the detection of degradation prior to the loss of intended function and (2) require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

erosion by the presence of localized discoloration and surface irregularities, such as rust, scale, 
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deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.41 Stainless Steel and Copper Alloy Components Subject to Loss of Material Due to 

Pitting and Crevice Corrosion Exposed to Air-Outdoor (External) 

LRA Table 3.3.2-18 addresses fire hydrants and hose valve heads fabricated from copper alloy 

exposed to air-outdoor (external), which are subject to loss of material due to pitting and crevice 

corrosion. LRA Table 3.3.2-19 addresses flame arrestors, hoods, caps, flexible connections 

(including braided lines), and sight glasses fabricated from stainless steel exposed to 

air-outdoor (external), which are subject to loss of material due to pitting and crevice corrosion. 

LRA Table 3.3.2-20 addresses piping fabricated from stainless steel exposed to air-outdoor 

(external), which are subject to loss of material due to pitting and crevice corrosion. The 

applicant credited the External Surfaces Monitoring Program for aging management of loss of 

material due to pitting and crevice corrosion in an air-outdoor (external) environment for the 

components described above. The AMR items cite generic note H, which indicates that the 

aging effect is not in the GALL Report for this component, material, and environment 

combination.

The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. The staff determined that the External Surfaces 

Monitoring Program, which includes periodic visual inspections of external surfaces performed 

during system walkdowns, is adequate to manage loss of material due to pitting and crevice 

corrosion for stainless steel and copper alloy components exposed to an external condensation 

environment addressed by this AMR. The staff noted that a visual inspection will be capable of 

identifying degradation on the external surface that will present itself in signs of corrosion, 

corrosion byproducts, coating degradation, discoloration on the surface, scale/deposits, and pits 

and surface discontinuities that are indicative of loss of material. On the basis of periodic visual 

inspections being performed during system walkdowns of these components by the External 

Surfaces Monitoring Program, the staff finds the applicant‘s use of the External Surfaces 

Monitoring Program 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 functions 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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3.3.2.3.42 Copper Alloy Components Exposed to Air-Indoor Controlled (Internal)

In LRA Table 3.3.2-10, the applicant stated that tubing fabricated from copper alloy material

exposed to air-indoor controlled (internal) does not have an aging effect, therefore, an AMP is 

not required. The AMR items cite generic note H, which indicates that the aging effect is not in 

the GALL Report for this component, material, and environment combination.

During its review, the staff noted that the LRA did not provide a justification as to why copper 

exposed to air-indoor controlled (internal) does not have an aging effect. By letter dated 

August 28, 2009, the staff issued RAI 3.3.2.3.10-1 requesting that the applicant: (1) describe the 

environmental conditions that exist in the internal environment of these components and 

(2) justify why these components are not subject to an AERM when exposed to air-indoor 

controlled (internal).

In its response dated September 28, 2009, the applicant stated that the air-indoor controlled 

(internal) environment for copper alloy tubing was incorrectly included in LRA Table 3.3.2-10. 

The applicant further stated that the correct environment for this component is air-moist 

(internal) and the aging effect of loss of material due to pitting and crevice corrosion will be 

managed by the WCP Program, which is already included in the LRA. The staff‘s evaluation of 

this AMR line item is documented in SER Section 3.3.2.2.10.6. 

Based on its review, the staff finds the applicant‘s response to RAI 3.3.2.3.10-1 acceptable 

because the applicant has identified and corrected the error, and aging management for copper 

alloy tubing is provided by the WCP Program and is evaluated in SER Section 3.3.2.2.10.6. The 

staff‘s concern described in RAI 3.3.2.3.10-1 is resolved.

On the basis of its review, the staff finds that the applicant has appropriately amended its LRA 

to identify the correct environment for copper alloy tubing in LRA Table 3.3.2-10 and has 

proposed the WCP Program for aging management as evaluated in SER Section 3.3.2.2.10.6.

3.3.2.3.43 Loss of Material Due to Microbiologically-Influenced Corrosion for Stainless Steel 

and Steel

In LRA Table 3.3.2-7, the applicant stated that the stainless steel flow elements, flow orifices, 

piping, strainer housings, tubing and valves, and steel component cooling heat exchangers 

(shell), component cooling pumps and surge tank, piping, tubing, and valves exposed to treated 

water-closed-cycle cooling (internal) are being managed for loss of material due to MIC. The 

applicant further stated, in LRA Table 3.3.2-7, that steel component cooling heat exchangers 

(tubesheets) exposed to treated water-closed-cycle cooling (external) are being managed for 

loss of material due to MIC. In LRA Table 3.3.2-9, the applicant stated that the stainless steel 

distillate cooler (tubing and tubesheet), excess letdown heat exchanger (tubing and tubesheet), 

letdown heat exchanger (tubes and tubesheet), and seal water heat exchanger (tubes and 

tubesheet) exposed to treated water-closed-cycle cooling (external) and the steel shells for the 

distillate cooler, excess letdown heat exchanger, letdown heat exchanger, and seal water heat 

exchanger exposed to treated water-closed-cycle cooling (internal) are being managed for loss 

of material due to MIC. In LRA Table 3.3.2-9, the applicant stated that the stainless steel 

evaporator condenser (channel head, tubesheet, and tubing) and vent condenser (channel 

head, tubesheet, and tubes) exposed to treated water-closed-cycle cooling (internal) are being 

managed for loss of material due to MIC. In LRA Table 3.3.2-10, the applicant stated that the 

stainless steel piping and chiller pumps and steel expansion tanks, piping, and valves exposed

to treated water-closed-cycle cooling (internal) are being managed for loss of material due to 
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MIC. In LRA Table 3.3.2-19, the applicant stated that the stainless steel tubing and valves and 

steel diesel generator cooling water heat exchangers (shell), lube oil coolers (lube oil cooler 

channel head), turbocharger aftercoolers (channel head, tubes, tubesheet), piping, tubing, and 

valves exposed to treated water-closed-cycle cooling (internal) are being managed for loss of 

material due to MIC. In LRA Table 3.3.2-21, the applicant stated that the steel heat exchanger 

channel heads and tubesheets exposed to treated water-closed-cycle cooling (internal) are 

being managed for loss of material due to MIC. In LRA Table 3.3.2-29, the applicant stated that 

the steel and stainless steel sample heat exchanger shells exposed to treated 

water-closed-cycle cooling (internal) and stainless steel sample heat exchangers tubes exposed 

to treated water-closed-cycle cooling (external) are being managed for loss of material due to 

MIC. The applicant credited the Closed-Cycle Cooling Water System Program and the WCP 

Program to manage this aging effect for the components described above. The AMR items cite 

generic note H, which indicates that the aging effect is not in the GALL Report for this 

component, material, and environment combination.

The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff further determined that the performance of these systems are 

monitored to verify the effectiveness of the chemistry controls, which include system operation 

monitoring, system testing, heat exchanger thermal performance testing, heat exchanger tube 

eddy current testing, and pump performance testing. 

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff determined that the 

applicant‘s WCP Program will manage the aging effects of loss of material through program 

inspections that provide verification of the effectiveness of the Closed-Cycle Cooling Water 

System Program. The staff also determined that these inspections will be performed by using 

NDE techniques that are effective and capable for the identification of these potential aging 

effects, and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE. Based on its review, the staff finds the 

applicant‘s use of the programs identified above acceptable because the chemistry control will 

provide an environment that is not conducive for loss of material to occur and the applicant will 

verify the effectiveness of the chemistry control with performance monitoring and examinations 

performed by its WCP 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 functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.44 Loss of Material Due to Microbiologically-Influenced Corrosion for Copper Alloy

In LRA Table 3.3.2-7, the applicant stated that the copper alloy tubing and valves exposed to 

treated water-closed-cycle cooling (internal) and component cooling heat exchangers (tubes) 

exposed to treated water-closed-cycle cooling (external) are being managed for loss of material 

due to MIC. In LRA Table 3.3.2-10, the applicant stated that the copper alloy air handling units 

(cooling coils/fins) exposed to treated water-closed-cycle cooling (internal) are being managed 
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for loss of material due to MIC. In LRA Table 3.3.2-19, the applicant stated that the copper alloy 

diesel generator cooling water heat exchangers (tubes and tubesheets) exposed to treated 

water-closed-cycle cooling (external) and lube oil coolers (tubesheets and tubes), tubing, and 

valves exposed to treated water-closed-cycle cooling (internal) are being managed for loss of 

material due to MIC. In LRA Table 3.3.2-21, the applicant stated that the copper alloy heat 

exchangers (tubes) exposed to treated water-closed-cycle cooling (internal) are being managed 

for loss of material due to MIC. The applicant credited the Closed-Cycle Cooling Water System 

Program and the WCP Program to manage this aging effect for the components described 

above. The AMR items cite generic note H, which indicates that the aging effect is not in the 

GALL Report for this component, material, and environment combination.

The staff reviewed the applicant‘s Closed-Cycle Cooling Water System Program and WCP 

Program and its evaluations are documented in SER Sections 3.0.3.2.5 and 3.0.3.2.19, 

respectively. The staff determined that the Closed-Cycle Cooling Water System Program

includes chemistry control and performance monitoring. The staff also determined that the 

program establishes appropriate corrosion control and chemistry specifications, including the 

use of inhibitors. The staff further determined that the performance of these systems are 

monitored to verify the effectiveness of the chemistry controls, which include system operation 

monitoring, system testing, heat exchanger thermal performance testing, heat exchanger tube 

eddy current testing, and pump performance testing. 

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection.‖ The staff determined that the 

applicant‘s WCP Program will manage the aging effects of loss of material through program 

inspections that provide verification of the effectiveness of the Closed-Cycle Cooling Water 

System Program. The staff also determined that these inspections will be performed by using 

NDE techniques that are effective and capable for the identification of these potential aging 

effects, and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE. Based on its review, the staff finds the 

applicant‘s use of the programs identified above acceptable because the chemistry control will 

provide an environment that is not conducive for loss of material to occur and the applicant will 

verify the effectiveness of the chemistry control with performance monitoring and examinations

performed by its WCP 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 functions 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 ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions 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 Aging Management of Steam and Power Conversion Systems

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 the following 

systems:

● turbine system

● main steam and steam dump system

● bleed steam system

● feedwater system

● condensate system

● steam generator blowdown treatment system

● auxiliary feedwater system

● air removal system

● heater and moisture separator drains system

● heating steam system

● main generator (mechanical) and auxiliaries system

● secondary sampling system

● turbine oil purification system

● turbine room traps and drains 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. In LRA Table 3.4.1, ―Summary of Aging Management Programs for 

Steam and Power Conversion System Evaluated in Chapter VIII of NUREG-1801,‖ the applicant 

provided a summary comparison of its AMRs to those evaluated in the GALL Report for steam 

and power conversion system components and component groups.

The applicant‘s AMRs evaluated and incorporated plant-specific and industry OE in the 

determination of AERMs from plant-specific condition reports and discussions with site 

personnel and from the GALL Report and issues identified since its publication.

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 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 functions 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 AMPs to confirm the applicant‘s claim that certain AMPs 

were consistent with the GALL Report. The purpose of this audit was to examine the applicant‘s 

AMPs and related documentation and to verify the applicant‘s claim of consistency with the 

corresponding GALL Report AMPs. The staff did not repeat its review of the matters described 

in the GALL Report. The staff‘s evaluations of the AMPs are documented in SER Section 3.0.3.
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The staff reviewed the AMRs to confirm the applicant‘s claim that certain identified 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 had identified the appropriate GALL Report AMRs. Details of 

the staff‘s evaluation are discussed in SER Sections 3.4.2.1 and 3.4.2.2.

The staff also reviewed the AMRs not consistent with or not addressed in the GALL Report. The 

review evaluated whether all plausible aging effects were identified and whether the aging 

effects listed were appropriate for the combination of materials and environments specified. 

Details of the staff‘s evaluation are discussed in SER Section 3.4.2.3.

For components which the applicant claimed were not applicable or required no aging 

management, the staff reviewed the AMR line items and the plant‘s OE 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 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.4.1-1)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA Fatigue is a TLAA

(See SER 

Sections 3.4.2.2.1 and 

4.3 )

Steel piping, piping 

components, and 

piping elements 

exposed to steam

(3.4.1-2)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.2.1)

Steel heat exchanger 

components exposed 

to treated water

(3.4.1-3)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.2.1)

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water

(3.4.1-4)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.2.1)

Steel heat exchanger 

components exposed 

to treated water

(3.4.1-5)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel and stainless 

steel tanks exposed 

to treated water

(3.4.1-6)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program, 

Primary Water 

Chemistry 

Program, and 

Secondary Water 

Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Sections 3.4.2.2.2.1 and 

3.4.2.2.7.1)

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil

(3.4.1-7)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis Program 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.2.2)

Steel piping, piping 

components, and 

piping elements 

exposed to raw water

(3.4.1-8)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion and 

fouling

Plant-specific Yes Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.2.3)

Stainless steel and 

copper alloy heat 

exchanger tubes 

exposed to treated 

water

(3.4.1-9)

Reduction of 

heat transfer due 

to fouling

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.4.1)

Steel, stainless steel, 

and copper alloy heat 

exchanger tubes 

exposed to 

lubricating oil

(3.4.1-10)

Reduction of 

heat transfer due 

to fouling

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis Program 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.4.2)

Buried steel piping, 

piping components, 

piping elements, and 

tanks (with or without 

coating or wrapping) 

exposed to soil

(3.4.1-11)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection

No (for Buried 

Piping and 

Tanks 

Surveillance)

Yes (for Buried 

Piping and 

Tanks 

Inspection)

Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.2.5.1)

Steel heat exchanger 

components exposed 

to lubricating oil

(3.4.1-12)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologicallyinfluenced 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis Program 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.5.2)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel piping, 

piping components, 

piping elements 

exposed to steam

(3.4.1-13)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection

Yes Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)

Stainless steel piping, 

piping components, 

piping elements, 

tanks, and heat 

exchanger 

components exposed 

to treated water 

> 60 °C (140 °F)

(3.4.1-14)

Cracking due to 

SCC

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.6)

Aluminum and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water

(3.4.1-15)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.7.1)

Stainless steel piping, 

piping components, 

and piping elements; 

tanks; and heat 

exchanger 

components exposed 

to treated water

(3.4.1-16)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry 

and One-Time 

Inspection

Yes WCP Program, 

Primary Water 

Chemistry 

Program, and 

Secondary Water 

Chemistry 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.7.1)

Stainless steel piping, 

piping components, 

and piping elements 

exposed to soil

(3.4.1-17)

Loss of material 

due to pitting and 

crevice corrosion

Plant-specific Yes Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.2.7.2)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil

(3.4.1-18)

Loss of material 

due to pitting and 

crevice corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis Program 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.7.3)

Stainless steel piping, 

piping components, 

piping elements, and 

heat exchanger 

components exposed 

to lubricating oil

(3.4.1-19)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Lubricating Oil 

Analysis and 

One-Time 

Inspection

Yes Lubricating Oil 

Analysis Program 

and WCP 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.4.2.2.8)

Steel tanks exposed 

to air-outdoor 

(external)

(3.4.1-20)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Aboveground Steel 

Tanks

No Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)
Aging Management Review Results

3-375

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.4.1-21)

Cracking due to 

cyclic loading 

and SCC

Bolting Integrity No Bolting Integrity

Program

Consistent with the 

GALL Report

Steel bolting and 

closure bolting 

exposed to air with 

steam or water 

leakage, air-outdoor 

(external), or 

air-indoor 

uncontrolled 

(external)

(3.4.1-22)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion; loss of 

preload due to 

thermal effects, 

gasket creep, 

and 

self-loosening

Bolting Integrity No Bolting Integrity 

Program

Consistent with the 

GALL Report

Stainless steel piping, 

piping components, 

and piping elements 

exposed to closedcycle cooling water 

> 60 °C (140 °F)

(3.4.1-23)

Cracking due to 

SCC

Closed-Cycle 

Cooling Water 

System

No Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)

Steel heat exchanger 

components exposed 

to closed-cycle 

cooling water

(3.4.1-24)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.4.2.3.7)

Stainless steel piping, 

piping components, 

piping elements, and 

heat exchanger 

components exposed 

to closed-cycle 

cooling water

(3.4.1-25)

Loss of material 

due to pitting and 

crevice corrosion

Closed-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.4.2.3.7)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water

(3.4.1-26)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.4.2.3.7)

Steel, stainless steel, 

and copper alloy heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water

(3.4.1-27)

Reduction of 

heat transfer due 

to fouling

Closed-Cycle 

Cooling Water 

System

No Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)
Aging Management Review Results

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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel external 

surfaces exposed to 

air-indoor 

uncontrolled 

(external), 

condensation 

(external), or 

air-outdoor (external)

(3.4.1-28)

Loss of material 

due to general 

corrosion

External Surfaces 

Monitoring

No External Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.4.1-29)

Wall thinning due 

to 

flow-accelerated 

corrosion

Flow-Accelerated 

Corrosion

No Flow-Accelerated 

Corrosion 

Program

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

air-outdoor (internal) 

or condensation 

(internal)

(3.4.1-30)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

No WCP Program Consistent with the 

GALL Report

Steel heat exchanger 

components exposed 

to raw water

(3.4.1-31)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.4.2.3.8)

Stainless steel and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to raw water

(3.4.1-32)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion

Open-Cycle 

Cooling Water 

System

No WCP Program Consistent with the 

GALL Report

(See SER 

Section 3.4.2.3.8)

Stainless steel heat 

exchanger 

components exposed 

to raw water

(3.4.1-33)

Loss of material 

due to pitting, 

crevice, and 

microbiologicallyinfluenced 

corrosion and 

fouling

Open-Cycle 

Cooling Water 

System

No Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)

Steel, stainless steel, 

and copper alloy heat 

exchanger tubes 

exposed to raw water

(3.4.1-34)

Reduction of 

heat transfer due 

to fouling

Open-Cycle 

Cooling Water 

System

No Not applicable to 

KPS

Not applicable to KPS

(See SER 

Section 3.4.2.1.1)
Aging Management Review Results

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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy 

> 15% Zn piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water, raw water, or 

treated water

(3.4.1-35)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Selective 

Leaching of 

Materials Program

Consistent with the 

GALL Report

Gray cast iron piping, 

piping components, 

and piping elements 

exposed to soil, 

treated water, or raw 

water

(3.4.1-36)

Loss of material 

due to selective 

leaching

Selective Leaching 

of Materials

No Selective 

Leaching of 

Materials Program

Consistent with the 

GALL Report

Steel, stainless steel, 

and Ni-based alloy 

piping, piping 

components, and 

piping elements 

exposed to steam

(3.4.1-37)

Loss of material 

due to pitting and 

crevice corrosion

Water Chemistry No WCP Program, 

Secondary Water 

Chemistry 

Program, and/or 

Steam Generator 

Tube Integrity 

Program

Consistent with the 

GALL Report

(See SER 

Sections 3.4.2.1.2 and 

3.4.2.1.3)

Steel bolting and 

external surfaces 

exposed to air with 

borated water 

leakage

(3.4.1-38)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion

No Boric Acid 

Corrosion 

Program

Consistent with the 

GALL Report

Stainless steel piping, 

piping components, 

and piping elements 

exposed to steam

(3.4.1-39)

Cracking due to 

SCC

Water Chemistry No WCP Program 

and Secondary 

Water Chemistry 

Program

Consistent with the 

GALL Report

Glass piping 

elements exposed to 

air, lubricating oil, raw 

water, and treated 

water

(3.4.1-40)

None None No None Consistent with the 

GALL Report

Stainless steel, 

copper alloy, and 

Ni-alloy piping, piping 

components, and 

piping elements 

exposed to air-indoor 

uncontrolled 

(external)

(3.4.1-41)

None None No None Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to air-indoor 

controlled (external)

(3.4.1-42)

None None No None Consistent with the 

GALL Report

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.4.1-43)

None None No None Consistent with the 

GALL Report

Steel, stainless steel, 

aluminum, and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to gas

(3.4.1-44)

None None No None Consistent with the 

GALL Report

The staff‘s review of the steam and power conversion system component groups followed 

several approaches. One approach, documented in SER Section 3.4.2.1, discusses the staff‘s 

review of AMR results for components the applicant indicated are consistent with the GALL 

Report and require no further evaluation. Another approach, documented in SER 

Section 3.4.2.2, discusses the staff‘s review of AMR results for components 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, discusses the staff‘s review of AMR 

results for components 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 That Are 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:

● Bolting Integrity Program

● Boric Acid Corrosion Program

● External Surfaces Monitoring Program

● Flow-Accelerated Corrosion Program

● Lubricating Oil Analysis Program

● Secondary Water Chemistry Program

● Selective Leaching of Materials Program

● Work Control Process Program

LRA Tables 3.4.2-1 through 3.4.2-14 summarize the AMRs for the steam and power conversion 

system components and indicate AMRs claimed to be consistent with the GALL Report.
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For component groups evaluated in the GALL Report for which the applicant had claimed 

consistency and for which the GALL Report does not recommend further evaluation, the staff 

performed an audit and review to determine whether the plant-specific components in these 

GALL Report component groups were bounded by the GALL Report evaluation.

The applicant provided a note for each AMR line item. The notes describe how the information 

in the tables aligns with the information in the GALL Report. The staff audited those AMRs with 

notes A through E, which indicate how the AMR was 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 Report 

AMP. The staff audited these line items to verify consistency with the GALL Report and the 

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 AMP 

identified in the GALL Report. The staff audited these line items to verify consistency with the 

GALL Report and confirmed that it had reviewed and accepted the identified exceptions to the 

GALL Report AMPs. The staff also determined whether the AMP identified by the applicant was 

consistent with the AMP identified in the GALL Report 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 AMP identified by the GALL Report. This note indicates that the applicant 

was unable to find a listing of some system components in the GALL Report; however, the 

applicant identified a different component in the GALL Report that had 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 and determined whether the AMR line 

item of the different component applied 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 AMP identified in the GALL Report. The staff audited these line items to 

verify consistency with the GALL Report and confirmed whether the AMR line item of the 

different component was applicable to the component under review. The staff confirmed 

whether it had reviewed and accepted the exceptions to the GALL Report AMPs. It also 

determined whether the AMP identified by the applicant was consistent with the AMP identified 

in the GALL Report 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 a different AMP is credited. The staff audited these line items 

to verify consistency with the GALL Report, and determined whether the identified AMP would 

manage the aging effect consistent with the AMP identified in the GALL Report 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.
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On the basis of its audit and review, the staff determines that, for AMRs not requiring further 

evaluation, as identified in LRA Table 3.2.1, the applicant‘s references to the GALL Report are 

acceptable and no further staff review is required.

3.4.2.1.1 AMR Results Identified as Not Applicable

LRA Table 3.4.1, items 3.4.1-5 and 3.4.1-13 discuss the applicant‘s determination on the GALL

Report AMR line items that are applicable only to BWR-designed reactors. In the applicant‘s 

AMR discussions for these line items, no additional information is provided. The staff confirmed 

that these AMR line items in Table 1 of the GALL Report, Volume 1 are only applicable to 

BWR-designed reactors and that KPS is a PWR with a dry ambient containment. Based on this 

determination, the staff finds that the applicant has provided an acceptable basis for concluding 

that AMR items 3.4.1-5 and 3.4.1-13 in Table 1 of the GALL Report, Volume 1 are not 

applicable to KPS.

LRA Table 3.4.1, item 3.4.1-20 addresses steel tanks exposed to air-outdoor (external). The 

GALL Report recommends the use of GALL AMP XI.M29, ―Aboveground Steel Tanks,‖ to 

manage loss of material, general, pitting, and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because there are no steam and power 

conversion system steel tanks exposed to an air-outdoor (external) environment. The staff 

reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the applicant‘s LRA does not have any 

AMR results for the steam and power conversion systems that include steel tanks exposed to 

air-outdoor. The staff also noted that a search of the applicant‘s USAR did not find any evidence 

of in-scope steel tanks in the steam and power conversion systems exposed to air-outdoor. 

Based on its review of the LRA and USAR, the staff confirmed that there are no in-scope steel 

tanks exposed to air-outdoor in the steam and power conversion systems and, therefore, finds 

the applicant‘s determination acceptable. 

LRA Table 3.4.1, item 3.4.1-23 addresses stainless steel piping, piping components, and piping 

elements exposed to closed-cycle cooling water greater than 60 °C (140 °F). The GALL Report 

recommends the use of GALL AMP XI.M21, ―Closed-Cycle Cooling Water System,‖ to manage 

cracking due to SCC for this component group. The applicant stated that this item is not 

applicable because there are no steam and power conversion system components exposed to a 

closed-cycle cooling water environment greater than 60 °C (140 °F). The staff reviewed LRA 

Sections 2.3.4 and 3.4 and confirmed that the applicant‘s LRA does not have any AMR results 

for the steam and power conversion system that include stainless steel piping, piping 

components, and piping elements exposed to closed-cycle cooling water greater than 60 °C 

(140 °F). The staff also noted that a search of USAR Chapter 10, ―Steam and Power 

Conversion System,‖ did not find any evidence of stainless steel piping, piping components, and 

piping elements in the steam and power conversion system exposed to closed-cycle cooling 

water greater than 60 °C (140 °F). Based on its review of the LRA and USAR, the staff 

confirmed that there are no in-scope stainless steel piping, piping components, and piping 

elements exposed to closed-cycle cooling water greater than 60 °C (140°F) and, therefore, finds 

the applicant‘s determination acceptable.

LRA Table 3.4.1, item 3.4.1-27 addresses steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to closed-cycle cooling water. The GALL Report recommends the use 

of GALL AMP XI.M21, ―Closed-Cycle Cooling Water System,‖ to manage the reduction of heat 

transfer due to fouling for this component group. The applicant stated that this item is not 

applicable because there are no steel, stainless steel, or copper alloy heat exchanger tubes 

exposed to a closed-cycle cooling water environment that perform a heat transfer intended 
Aging Management Review Results

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function per 10 CFR 54.4(a). The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that 

the applicant‘s LRA does not have any AMR results for the steam and power conversion system 

that include steel, stainless steel, or copper alloy heat exchanger tubes exposed to a 

closed-cycle cooling water environment that perform a heat transfer intended function per 

10 CFR 54.4(a). The staff also noted that a search of USAR Chapter 10, ―Steam and Power 

Conversion System,‖ did not find any evidence of steel, stainless steel, or copper alloy heat 

exchanger tubes exposed to a closed-cycle cooling water environment that perform a heat 

transfer intended function per 10 CFR 54.4(a). Based on its review of the LRA and USAR, the 

staff confirmed that there are no in-scope steel, stainless steel, or copper alloy heat exchanger 

tubes exposed to a closed-cycle cooling water environment that perform a heat transfer 

intended function per 10 CFR 54.4(a) and, therefore, finds the applicant‘s determination 

acceptable.

LRA Table 3.4.1, item 3.4.1-33 addresses stainless steel heat exchanger components exposed 

to raw water. The GALL Report recommends the use of GALL AMP XI.M20, ―Open-Cycle 

Cooling Water System,‖ to manage loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion and fouling for this component group. The applicant 

stated that this line item is not applicable because there are no stainless steel heat exchanger 

components exposed to a raw water environment. The staff reviewed LRA Sections 2.3.4 and 

3.4 and confirmed that the applicant‘s LRA does not have any AMR results for the steam and 

power conversion systems that include stainless steel heat exchanger components exposed to 

raw water. The staff also noted that a search of the applicant‘s USAR did not find any evidence 

of stainless steel heat exchanger components in the steam and power conversion systems 

exposed to raw water. Based on its review of the LRA and USAR, the staff confirmed that there 

are no in-scope stainless steel heat exchanger components exposed to raw water in the steam 

and power conversion systems and, therefore, finds the applicant‘s determination acceptable.

LRA Table 3.4.1, item 3.4.1-34 addresses steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to raw water. The GALL Report recommends the use of GALL 

AMP XI.M20, ―Open-Cycle Cooling Water System,‖ to manage reduction of heat transfer due to 

fouling for this component group. The applicant stated that this line item is not applicable 

because there are no steel, stainless steel, or copper alloy heat exchanger components 

exposed to a raw water environment that have a heat transfer intended function per 

10 CFR 54.4(a). The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the 

applicant‘s LRA does not have any AMR results for the steam and power conversion systems 

that include steel, stainless steel, and copper alloy heat exchanger tubes exposed to raw water. 

The staff also noted that a search of the applicant‘s USAR did not find any evidence of steel, 

stainless steel, and copper alloy heat exchanger tubes in the steam and power conversion 

systems exposed to raw water. Based on its review of the LRA and USAR, the staff confirmed 

that there are no in-scope steel, stainless steel, and copper alloy heat exchanger tubes exposed 

to raw water in the steam and power conversion systems and, therefore, finds the applicant‘s 

determination acceptable.

3.4.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion of Steel, Stainless Steel, and 

Nickel-Based Alloy Piping, Piping Components, and Piping Elements Exposed to Steam

LRA Table 3.4.1, item 3.4.1-37 addresses the loss of material due to pitting and crevice 

corrosion of steel, stainless steel, and Ni-based alloy piping, piping components, and piping 

elements exposed to steam. As used in the Table 2 line items subordinate to item 3.4.1-37, the 

environment is expanded to include treated secondary water. Additionally, components were 

expanded to include heat exchangers, specifically in Tables 3.3.2-9 and 3.3.2-10.
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This SER entry does not include items subordinate to item 3.4.1-37, which addresses steam 

generator components of Table 3.1.2-4. Those steam generator components are addressed in 

SER Section 3.4.2.1.3 below.

The LRA credits the Secondary Water Chemistry and WCP programs to manage this aging 

effect for steel, stainless steel, and Ni-based alloy piping, piping components, and piping and 

heat exchanger components. The GALL Report recommends the water chemistry program to 

manage this aging effect. Additionally, for some of the AMR line items, the GALL Report 

recommends the use of the one-time inspection program. The AMR line items cite generic 

notes: (1) A, indicating that the line item is consistent with the GALL Report item for component, 

material, environment, and aging effect and the LRA AMP is consistent with the GALL Report 

AMP; (2) C, indicating that the component is different, but consistent with the GALL Report item 

for material, environment, and aging effect and the LRA AMP is consistent with the GALL 

Report AMP; and (3) E, indicating that the LRA AMR is consistent with the GALL Report item for 

material, environment, and aging effect, but a different AMP is credited. The applicant proposed 

that all the items for which the Secondary Water Chemistry Program is credited are either fully 

consistent with the GALL Report (generic note A) or fully consistent with the GALL Report 

except for the component (generic note C). The applicant proposed that all the items for which 

the WCP Program is credited are consistent with the GALL Report in all respects except a 

different AMP is credited (generic note E).

The staff reviewed the applicant‘s Secondary Water Chemistry and WCP programs and its 

evaluation is documented in SER Sections 3.0.3.1.11 and 3.0.3.2.19, respectively. The staff 

finds the applicant‘s proposal for managing the aging of these components acceptable because: 

(1) all the components included in item 3.4.1-37 citing generic note C are subject to similar 

aging effects and lose material at similar rates when compared to components specifically 

included in item 3.4.1-37, (2) the Secondary Water Chemistry Program ensures that chemistry 

parameters are maintained consistent with minimizing corrosion, and (3) the WCP Program was 

developed in part to perform inspections to confirm the effectiveness of the chemistry control 

program by inspecting susceptible internal surfaces of components, such as those in stagnant 

flow locations.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion of Nickel-Alloy Components 

Exposed to Treated Water and/or Steam 

This section discusses those items of LRA Table 3.4.1, item 3.4.1-37 not addressed in 

Section 3.4.2.1.2 above. 

LRA Table 3.4.1, item 3.4.1-37 and LRA Table 3.1.2-4 address AMR items for the loss of 

material due to pitting and crevice corrosion for Ni-alloy components exposed to treated water 

and/or steam-secondary for the following seven steam generator components:

● feedwater inlet ring J nozzles

● feedwater nozzle (and Ni-alloy cladding)

● feedwater nozzle thermal sleeve

● steam nozzle flow restrictor
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● tube bundle support hardware

● tube plugs

● tube and sleeves

The staff reviewed LRA Table 3.1.2-4 and noted that for the two aging effects described in the 

SRP-LR and LRA Table 3.1.1, items 3.1.1-72 and 3.1.1-74, the applicant identified the aging 

effect of cracking but proposed loss of material due to pitting and crevice corrosion for these 

seven components, instead of loss of material due to fretting and wear (item 3.1.1-72) and loss 

of material due to crevice corrosion and fretting (item 3.1.1-74).

Although the GALL Report does not have a corresponding AMR for these seven steam 

generator components, the staff finds the applicant‘s identification of aging effects acceptable 

according to the selection criteria of the applicant. However, the applicant stated it would 

manage the aging effect of loss of material due to pitting and crevice corrosion using the 

Secondary Water Chemistry Program, described by the AMP for SRP-LR and LRA 

item 3.4.1-37, without providing any explanation or justification for the adequacy of this program.

The staff noted that the specific item described in the LRA from the SRP-LR and the GALL 

Report (e.g., SP-18) relates to aging management of Ni-alloy components exposed to dry 

steam, whereas the seven components listed above are exposed to treated water and/or 

steam-secondary, as indicated in LRA Table 3.1.2-4. For example, the staff noted that the tube 

plugs are clearly not exposed to dry steam. But, in spite of this environmental inconsistency with 

the GALL Report, the applicant stated that this AMP is consistent with the GALL Report in all 

aspects (note A) for five of these seven steam generator components.

The staff considers that the environment identified in LRA Table 3.4.1, item 3.4.1-37 (e.g., dry 

steam) is not appropriate for the seven steam generator components listed above in accordance 

with the environment they are exposed (i.e., treated water and/or steam-secondary). The staff 

also finds that the applicant did not provide enough information to verify whether the Secondary 

Water Chemistry Program is sufficient to manage the aging effect of loss of material due to 

pitting and crevice corrosion for these components, or whether, alternatively, the applicant 

should use a condition monitoring or an ISI program to confirm that the Secondary Water 

Chemistry Program is achieving its preventive purposes.

By letter dated November 20, 2009, the staff issued RAI B2.1.30-16 requesting that the 

applicant explain why its credited program for aging management for the seven steam generator 

components listed above is appropriate, when the environment associated with LRA 

item 3.4.1-37 (e.g., dry steam) and that to which these components are exposed (e.g., treated 

water and/or steam-secondary) are different. The staff also requested that the applicant: 

(1) justify why it considers the Secondary Water Chemistry Program sufficient to manage the 

loss of material due to pitting and crevice corrosion for these components, without any other 

condition monitoring or ISI-based program to confirm its effectiveness; or (2) describe its plans 

to implement a condition monitoring or ISI-based program.

In its response dated December 28, 2009, the applicant stated that the dry steam environment 

was combined with the treated water and/or steam-secondary environment for the purposes of 

AMRs because the potential aging effects are the same. The applicant also stated that the loss 

of material due to pitting and crevice corrosion for the Ni-based alloy feedwater inlet ring J 

nozzles, feedwater nozzle (and Ni-alloy cladding), feedwater nozzle thermal sleeve, steam 

nozzle flow restrictor, tube bundle support hardware, tube plugs, and tube and sleeves is 

adequately managed by the Secondary Water Chemistry Program. According to the applicant, 
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the Secondary Water Chemistry Program includes specifications for chemical species, 

sampling, and analysis frequencies, and corrective actions for control of the environment to 

which surfaces of components are exposed. The applicant also explained that, additionally, this 

program maintains water quality (pH and conductivity) in accordance with industry guidelines, 

as described in LRA Section B2.1.28. However, the applicant further stated that in response to 

staff concerns, the Steam Generator Tube Integrity Program will be conservatively credited as 

an additional AMP for the components listed above, with the exception of the steam nozzle flow 

restrictor, to provide verification that the loss of material due to pitting and crevice corrosion 

does not occur.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-16 acceptable for 

the feedwater inlet ring J nozzles, feedwater nozzle (and Ni-alloy cladding), feedwater nozzle 

thermal sleeve, tube bundle support hardware, tube plugs, and tube and sleeves because: 

(a) the applicant amended its LRA to credit its Steam Generator Tube Integrity Program to verify 

Secondary Water Chemistry Program effectiveness, and (b) this program is adequate to verify 

that loss of material due to pitting and crevice corrosion in these components exposed to treated 

water and/or steam-secondary does not occur.

In its response dated December 28, 2009, the applicant further stated that for the steam nozzle 

flow restrictor, the Secondary Water Chemistry Program alone will adequately manage the loss 

of material due to pitting and crevice corrosion. As the applicant further explained, this 

component is exposed to a dry steam environment, which is less corrosive than treated water 

as stated in NUREG-1833, ―Technical Bases for Revision to the License Renewal Guidance 

Documents,‖ item SP-18.

Based on its review, the staff finds the applicant‘s response to RAI B2.1.30-16 acceptable for 

the steam nozzle flow restrictor because the environment of this component and the program as 

cited by the applicant are adequate and consistent with the GALL Report technical bases.

Accordingly, in its response dated December 28, 2009, the applicant amended its LRA to 

include the following paragraphs to LRA Table 3.4.1, item 3.4.1-37:

Consistent with NUREG-1801.

For the steam generator steam nozzle restrictor, loss of material due to pitting 

and crevice corrosion is managed by the Secondary Water Chemistry program.

For the steam generator feedwater inlet ring J nozzles, feedwater nozzle (and 

nickel alloy cladding), feedwater nozzle thermal sleeve, tube bundle support 

hardware, tube plugs, and tube and sleeves, loss of material due to pitting and 

crevice corrosion is managed by the Secondary Water Chemistry program and 

the Steam Generator Tube Integrity program since the environment is secondary 

treated water and not steam.

The staff finds this change to LRA Table 3.4.1, item 3.4.1-37 acceptable because it correctly 

describes the programs the applicant credited for managing the aging effect of loss of material 

due to pitting and crevice corrosion in steam generator secondary-side components, for which 

the staff has identified another environment than the one originally selected in the LRA.
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Based on its review, the staff found that the applicant has adequately addressed the issues in 

RAI B2.1.30-16 and amended its LRA appropriately. The staff‘s concern described in 

RAI B2.1.30-16 is resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions 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 That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended

LRA Section 3.4.2.2 provides further evaluation of aging management, as recommended by the 

GALL Report for the steam and power conversion system components. The applicant provided 

information concerning how it will manage the following aging effects:

● cumulative fatigue damage

● loss of material due to general, pitting, and crevice corrosion

● loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion and fouling

● reduction of heat transfer due to fouling

● loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion

● cracking due to SCC

● loss of material due to pitting and crevice corrosion

● loss of material due to pitting, crevice, and microbiologically-influenced corrosion

● loss of material due to general, pitting, crevice, and galvanic corrosion

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the GALL Report and for which the GALL Report recommends further 

evaluation, the staff audited and reviewed the applicant‘s evaluations to determine whether they 

adequately address those issues and reviewed the applicant‘s further evaluations against the 

criteria in SRP-LR Section 3.4.2.2. The staff‘s review of the applicant‘s further evaluations 

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. An applicant 

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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3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

Item 1. LRA Section 3.4.2.2.2.1 refers to Table 3.4.1, items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 3.4.1-6 

and addresses steel piping, piping components, and piping elements exposed to steam or 

treated water, steel heat exchanger components exposed to treated water, and steel and 

stainless steel tanks exposed to treated water, which are being managed for the loss of material 

due to general, pitting, and crevice corrosion by the Secondary Water Chemistry Program. The 

applicant stated that the effectiveness of the Secondary Water Chemistry Program will be 

verified by the WCP Program.

The staff reviewed LRA Section 3.4.2.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.2.1, 

which states that loss of material due to general, pitting, and crevice corrosion could occur for 

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 GALL Report recommends GALL AMP XI.M2, ―Water Chemistry,‖ and states that 

the AMP be augmented by verifying the effectiveness of water chemistry control. The GALL 

Report states that a one-time inspection (GALL AMP XI.M32) of selected components at 

susceptible locations is an acceptable method to ensure that corrosion is not occurring and that 

component intended functions will be maintained during the period of extended operation.

The staff reviewed the applicant‘s Secondary Water Chemistry and WCP programs and its 

evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.2.19, respectively. The staff 

also reviewed AMR items associated with LRA Table 3.4.1, items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 

3.4.1-6, which are associated with LRA Section 3.4.2.2.2.1. In its review, the staff noted that the 

applicant assigned each component two line items, one in which the Secondary Water 

Chemistry AMP is credited and the other in which the WCP Program is credited. The applicant 

proposed that all the items for which the Water Chemistry program is credited are fully 

consistent with the GALL Report. The applicant proposed that all the items for which the WCP 

Program is credited are consistent with the GALL Report in all respects except a different AMP 

is credited, citing generic note E. The applicant stated that the WCP Program provides the 

opportunity to inspect the internal surfaces of components constructed of typical system 

materials and exposed to typical system environments, including stagnant locations, during 

preventive and corrective maintenance activities on an ongoing basis. The applicant also stated 

that the WCP Program provides input to the corrective action program if aging effects are 

identified. The applicant further stated that the corrective action program will evaluate the cause 

and extent of the condition and, if required, recommend enhancements to ensure continued 

effectiveness of the Secondary Water Chemistry Program.

In its review of components associated with LRA items 3.4.1-2, 3.4.1-3, 3.4.1-4, and 3.4.1-6, for 

which the applicant assigned generic note E, the staff noted that the GALL Report differentiates 

between treated water and steam, while the environment indicated in the LRA is ―treated water 

and/or steam.‖ The staff also noted that, in this case, the AMPs recommended by the GALL 

Report are identical for water and steam so that the distinction is inconsequential. The staff finds 

the use of the WCP Program acceptable to confirm the adequacy of the Secondary Water 

Chemistry Program because the WCP Program has been proposed by the applicant and 

evaluated by the staff to be consistent with the One-Time Inspection Program, which is 

recommended by the GALL Report. In addition, a staff concern related to the selection and 

frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.
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Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.2.1 criteria. For those line items that apply to LRA Section 3.4.2.2.2.1, 

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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.4.2.2.2.2 and Table 3.4.1, item 3.4.1-7 address loss of material due to 

general, pitting, and crevice corrosion that may occur in piping, piping components, and piping 

elements. The applicant stated that loss of material for steel components exposed to lubricating 

oil is managed by the Lubricating Oil Analysis Program. The WCP Program will provide a 

verification of the effectiveness of the Lubricating Oil Analysis Program to manage loss of 

material due to general, pitting, and crevice corrosion through the examination of steel 

components.

The staff reviewed LRA Section 3.4.2.2.2.2 against the criteria in SRP-LR Section 3.4.2.2.2.2, 

which 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 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the loss of material due to 

general, pitting, and crevice corrosion in steel piping, piping components, and piping elements 

exposed to lubricating oil. The staff noted that the applicant has credited the WCP Program in

lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the 

applicant amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Lubricating Oil Analysis Program 

where: (a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for the identification of these potential aging effects and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 
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and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.4.2.2.2.2, the staff finds the applicant‘s use of the Lubricating Oil Analysis 

Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.2.2 criteria. For those line items that apply to LRA Section 3.4.2.2.2.2, 

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 

functions 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

LRA Section 3.4.2.2.3 refers to Table 3.4-1, item 3.4.1-8 and addresses steel piping, piping 

components, and piping elements exposed to raw water. The applicant stated that for this item, 

the only source of raw water to the steam and power conversion systems is the service water 

system (raw water) backup supply source for the AFW pumps. The applicant also stated that 

the backup water source is maintained isolated from the AFW system by normally closed 

motor-operated valves. The applicant further stated that the backup water supply piping and 

components are evaluated for the effects of aging with the service water system in LRA 

Section 3.3, ―Aging Management of Auxiliary Systems.‖ Based on the above, the applicant 

stated that the AFW pump suction piping was not evaluated for aging effects due to the backup 

water supply environment. The staff reviewed the LRA and USAR and did not find any evidence 

of in-scope steel piping, piping components, and piping elements exposed to raw water in the 

steam and power conversion systems, except for the backup supply source for the AFW pumps.

The staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3, which 

states that loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion and fouling could 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. The GALL Report states that 

acceptance criteria are described in SRP-LR, BTP RLSB-1.

In its review of LRA Section 3.4.2.2.3, the staff noted that the applicant stated that the auxiliary 

feed pump suction piping was not evaluated for aging effects due to the backup water supply 

environment. By letter dated October 13, 2009, the staff issued RAI 3.4.2.2.3-1 requesting that 

the applicant confirm that the entire AFW system will be evaluated for aging and to modify this 

AMR item and other AMR items as appropriate to allow the staff to confirm that each portion of 

the AFW system is being evaluated through the use of appropriate AMPs and AMR items.

In its response dated November 13, 2009, the applicant stated that the entire auxiliary feed 

water system, including the AFW pump suction piping downstream of the normally closed 

motor-operated valves, was evaluated for aging effects due to exposure to the treated water 

from the condensate storage tank, as indicated for the component type ―pipe‖ in LRA 

Table 3.4.2-7. The staff finds this response acceptable because all parts of the AFW system 

were evaluated for aging effects and because the most appropriate environment was selected 

for each portion of the system. The staff‘s concern described in RAI 3.4.2.2.3-1 is resolved.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.2.3 criteria. For those items that apply to LRA Section 3.4.2.2.2.3, the 
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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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling

Item 1. LRA Section 3.4.2.2.4.1 refers to Table 3.4.1, item 3.4.1-09, which addresses the 

reduction of heat transfer due to fouling for stainless steel and copper alloy heat exchanger 

tubes exposed to treated water. The applicant stated that this aging effect will be managed by 

the Secondary Water Chemistry Program and that this AMP‘s effectiveness will be confirmed by 

the WCP Program. The applicant also stated that the WCP Program will visually inspect the 

internal surfaces of components constructed of typical system materials and exposed to typical 

environments, including stagnant locations. 

The staff reviewed LRA Section 3.4.2.2.4.1 against the criteria in SRP-LR Section 3.4.2.2.4.1, 

which states that reduction of heat transfer due to fouling may occur in stainless steel and 

copper alloy heat exchanger tubes exposed to treated water, and that management of this aging 

effect relies on water chemistry control. The GALL Report recommends the use of the water 

chemistry program augmented by a plant-specific verification program to manage the effects of 

fouling on stainless steel and copper alloy heat exchanger tubes exposed to treated water. As 

noted in the SRP-LR, since control of water chemistry may not always have been adequate to 

preclude fouling, the GALL Report recommends that the effectiveness of the chemistry control 

program be verified to ensure that the reduction of heat transfer due to fouling does not occur. A 

one-time inspection is noted as an acceptable method to ensure that the reduction of heat 

transfer is not occurring and that the components‘ intended functions will be maintained during 

the period of extended operation. The staff noted that GALL AMP XI.M2, ―Water Chemistry,‖ 

indicates that water chemistry programs can be generally effective in removing impurities, 

except in low flow or stagnant flow areas.

The staff evaluated the applicant‘s Secondary Water Chemistry Program and WCP Program 

and its review is documented in SER Section 3.0.3.1.11 and Section 3.0.3.2.19, respectively. 

The staff noted that the effectiveness of the Secondary Water Chemistry Program is verified 

through the WCP Program, which will visually inspect the internal surfaces of components 

constructed of typical system materials and exposed to typical system environments, including 

stagnant locations. The staff finds the applicant‘s use of the Secondary Water Chemistry 

Program, in conjunction with verification through the WCP Program, acceptable to manage the 

reduction of heat transfer due to fouling because: (1) these AMPs are consistent with the 

recommended programs in SRP-LR Section 3.4.2.2.4.1 and the GALL Report, (2) the 

Secondary Water Chemistry Program periodically monitors and controls contaminants below 

levels known to result in a reduction in heat transfer, and (3) the WCP Program verifies 

effectiveness by inspecting heat transfer surfaces for fouling.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.4.1 criteria. For those items that apply to LRA Section 3.4.2.2.4.1, 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 

functions 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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Item 2. LRA Section 3.4.2.2.4.2 refers to Table 3.4.1, item 3.4.1-10, which addresses the 

reduction of heat transfer due to fouling for steel, stainless steel, and copper alloy heat 

exchanger tubes exposed to lubricating oil. The applicant stated that the reduction of heat 

transfer due to fouling for applicable components is managed by the Lubricating Oil Analysis 

Program. The applicant also stated that the WCP Program will confirm the effectiveness of the 

Lubricating Oil Analysis Program by visually inspecting the internal surfaces of components 

constructed of typical system materials and exposed to typical system environments, including 

stagnant locations.

The staff reviewed LRA Section 3.4.2.2.4.2 against the criteria in SRP-LR Section 3.4.2.2.4.2, 

which states that loss of heat transfer due to fouling could occur for steel, stainless steel, and 

copper alloy heat exchanger tubes exposed to lubricating oil. The GALL Report recommends 

the use of the lubricating oil analysis program and further evaluation to verify the effectiveness 

of the lubricating oil programs. The SRP-LR notes that the existing AMP relies on monitoring 

and control of lube oil chemistry to mitigate the reduction of heat transfer due to fouling; 

however, control of lube oil contaminants may not always be fully effective in precluding 

corrosion. A one-time inspection of selected components at susceptible locations is an 

acceptable method to determine that corrosion is not occurring and that the intended functions 

will be maintained during the period of extended operation.

The staff evaluated the applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

review is documented in SER Section 3.0.3.1.4 and Section 3.0.3.2.19, respectively. The staff 

finds the applicant‘s use of the Lubricating Oil Analysis Program, in conjunction with 

effectiveness verification through the WCP Program, is acceptable to manage the reduction of 

heat transfer due to fouling because: (1) these AMPs are consistent with the recommended 

programs in SRP-LR Section 3.4.2.2.4.2 and the GALL Report, (2) the Lubricating Oil Analysis 

Program periodically samples the oil to confirm oil quality, and (3) the WCP Program verifies 

effectiveness by inspecting heat transfer surfaces for fouling.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.2.2.2.4.2 criteria. For those items that apply to LRA Section 3.2.2.2.4.2, 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 

functions 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

Item 1. LRA Section 3.4.2.2.5.1 and Table 3.4.1, item 3.4.1-11 addresses buried steel piping, 

piping components, piping elements and tanks (with or without coating or wrapping) exposed to 

soil. The GALL Report recommends the Buried Piping and Tanks Inspection Program to 

manage the loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion for this component group. The applicant stated that this item is not applicable because 

there are no in-scope components constructed of steel piping exposed to soil in the steam and 

power conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that 

the applicant‘s LRA does not have any AMR results for the steam and power conversion 

systems that include steel exposed to soil. The staff also reviewed the USAR to verify the same. 

Based on its review of the LRA and USAR, the staff confirmed that the applicant‘s plant does 

not have any in-scope components constructed of steel exposed to soil in the steam and power 

conversion systems and, therefore, finds the applicant‘s determination acceptable.
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Item 2. LRA Section 3.4.2.2.5.2 and LRA Table 3.4.1, item 3.4.1-12 address the loss of material 

due to general, pitting, crevice, and microbiologically-influenced corrosion that may occur in 

steel heat exchanger components exposed to lubricating oil. The applicant stated that the loss 

of material for carbon steel components exposed to lubricating oil is managed by the Lubricating 

Oil Analysis Program. The WCP Program will provide a verification of the effectiveness of the 

Lubricating Oil Analysis Program to manage loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion through the examination of carbon steel components.

The staff reviewed LRA Section 3.4.2.2.5.2 against the criteria in SRP-LR Section 3.4.2.2.5.2 

which states that loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion may occur in steel heat exchanger components 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the 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 has credited the WCP 

Program in lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 

2009, the applicant amended its LRA so that its WCP Program will be consistent with GALL 

AMP XI.M32, ―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program 

will manage the aging effects of cracking, loss of material, and reduction of heat transfer 

through program inspections that provide verification of the effectiveness of the Lubricating Oil 

Analysis Program where: (a) an aging effect is not expected to occur but the data is insufficient 

to rule it out with reasonable confidence; (b) an aging effect is expected to progress very slowly 

in the specified environment, but the local environment may be more adverse than generally 

expected; or (c) the characteristics of the aging effect include a long incubation period. The staff 

further determined that these inspections will be performed by using NDE techniques that are 

effective and capable for identification of these potential aging effects and that the sample size 

and location will be based on an assessment of materials, environments, plausible aging 

effects, and OE. On the basis that the applicant‘s AMPs are consistent with those 

recommended in SRP-LR Section 3.4.2.2.5.2, the staff finds the applicant‘s use of the 

Lubricating Oil Analysis Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.5.2 criteria. For those items that apply to LRA Section 3.4.2.2.5.2, the 
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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 

functions 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

LRA Section 3.4.2.2.6 addresses cracking due to SCC for applicable components exposed to a 

treated water and/or steam environment, which is managed by the Secondary Water Chemistry 

Program. The applicant stated that in lieu of a one-time inspection, the WCP Program is used to 

provide confirmation of the effectiveness of the Secondary Water Chemistry Program. The 

applicant further stated that the WCP Program provides the opportunity to visually inspect the 

internal surfaces of components constructed of typical system materials and exposed to typical 

system environments, including stagnant locations, during preventive and corrective 

maintenance activities on an ongoing basis. Furthermore, the WCP Program provides input to 

the corrective action program if aging effects are identified. The applicant stated that the 

corrective action program would evaluate the cause and extent of the condition and, if required, 

recommend enhancements to ensure the continued effectiveness of the Secondary Water 

Chemistry Program.

The staff reviewed LRA Section 3.4.2.2.6 against the criteria in SRP-LR Section 3.4.2.2.6, which 

states that cracking due to SCC could occur in the stainless steel piping, piping components, 

piping elements, tanks, and heat exchanger components exposed to treated water greater than 

60 °C (140 °F), and for stainless steel piping, piping components, and piping elements exposed 

to steam. The existing AMP relies on monitoring and control of water chemistry to manage the 

effects of cracking due to SCC. However, high concentrations of impurities at crevices and 

locations of stagnant flow conditions could cause SCC. Therefore, the GALL Report 

recommends that the effectiveness of the water chemistry control program should be verified to 

ensure that SCC does not occur. A one-time inspection of selected components at susceptible 

locations is an acceptable method to ensure that SCC is not occurring and that component 

intended functions will be maintained during the period of extended operation.

LRA Table 3.4.1, item 3.4.1-14 describes the cracking due to SCC of stainless steel 

components, from the steam and power conversion system, that were exposed to treated water 

greater than 60 °C (140 °F) and/or steam. The AMR items corresponding to item 3.4.1-14 

include piping/tubing, piping elements, tanks, and heat exchanger components (Tables 3.4.2-2 

through 3.4.2-6, 3.4.2-10, and 3.4.2-12). The applicant stated that cracking due to SCC of these 

stainless steel components is managed by the Secondary Water Chemistry Program and WCP 

Program, which is a plant-specific program. The applicant further stated that the programs are 

consistent with the GALL Report. 

The staff reviewed LRA item 3.4.1-14 in comparison with the GALL Report Volume 1 Table 4, 

ID 14. The staff noted that for these AMR items, the SRP-LR states that the existing AMP relies 

on monitoring and control of water chemistry to manage the effects of cracking due to SCC. 

However, high concentrations of impurities at crevices and locations of stagnant flow conditions 

could cause SCC. Therefore, the GALL Report recommends that the effectiveness of the 

Secondary Water Chemistry Control Program should be verified. The GALL Report further 

states that a one-time inspection of selected components at susceptible locations is an 

acceptable method to ensure that SCC is not occurring. In its review, the staff found that the 

applicant stated that the WCP Program provides an opportunity to visually inspect the internal 

surfaces of components constructed of typical system materials and exposed to typical system 
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environments, including stagnant locations during preventive and corrective maintenance 

activities. In addition, the staff finds that the applicant‘s WCP Program is an acceptable 

alternative to GALL AMP XI.M32, ―One-Time Inspection,‖ for the purpose of verifying the 

effectiveness of water chemistry control. The staff reviewed the applicant‘s Secondary Water 

Chemistry Program and WCP Program and its evaluations are documented in SER 

Sections 3.0.3.1.11 and 3.0.3.2.19, respectively. The staff, therefore, finds that the applicant‘s 

proposed AMP is equivalent to that recommended in the GALL Report.

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 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 

functions 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

Item 1. LRA Section 3.4.2.2.7.1 refers to Table 3.4.1, items 3.4.1-6, 3.4.1-15, and 3.4.1-16 and 

addresses steel and stainless steel tanks; aluminum and copper alloy piping, piping 

components, and piping; stainless steel piping, piping components, and piping elements; tanks; 

and heat exchanger components exposed to treated water, which are being managed for loss of 

material due to general (steel only), pitting, and crevice corrosion by the WCP Program and 

either the Secondary Water Chemistry or Primary Water Chemistry program, as appropriate. 

The applicant stated that the effectiveness of the Primary Water Chemistry and the Secondary 

Water Chemistry programs will be confirmed by the WCP Program.

The staff reviewed LRA Section 3.4.2.2.7.1 against the criteria in SRP-LR Section 3.4.2.2.7.1, 

which states that loss of material due to pitting and crevice corrosion could occur for stainless 

steel, aluminum, and copper alloy piping, piping components, and piping elements and for 

stainless steel tanks and heat exchanger components exposed to treated water. The GALL 

Report recommends that GALL AMP XI.M2, ―Water Chemistry,‖ be used to manage the effects 

of the loss of material due to general, pitting, and crevice corrosion. The GALL Report also 

states that control of water chemistry does not preclude corrosion at locations of stagnant flow 

conditions. Therefore, the GALL Report recommends that the effectiveness of the water 

chemistry program be verified to ensure that corrosion is not occurring. The GALL Report 

further states that 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 applicant‘s Primary Water Chemistry, Secondary Water Chemistry, and 

WCP programs and its evaluations are document in SER Sections 3.0.3.1.9, 3.0.3.1.11, and 

3.0.3.2.19, respectively. The applicant stated that the WCP Program provides the opportunity to 

visually inspect the internal surfaces of components constructed of typical system materials and 

exposed to typical system environments, including stagnant locations, during preventive and 

corrective maintenance activities on an ongoing basis. The applicant also stated that the WCP 

Program provides input to the corrective action program if aging effects are identified. The 

applicant further stated that the corrective action program will evaluate the cause and extent of 

the condition and, if required, recommend enhancements to ensure continued effectiveness of 

both chemistry control programs. The staff also reviewed AMR items associated with LRA 

Table 3.4.1, items 3.4.1-6, 3.4.1-15, and 3.4.1-16, which are associated with LRA 

Section 3.4.2.2.7.1. In its review, the staff noted that for these items the applicant assigned each 
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component two items, one in which the Primary or Secondary Water Chemistry Program is 

credited and the other in which the WCP Program is credited. The applicant proposed that 

nearly all the items for which the Water Chemistry Program is credited are fully consistent with 

the GALL Report. In a few instances, a different, but related component, is listed and the 

applicant cited generic note C. The applicant proposed that all the items for which the WCP 

Program is credited are consistent with the GALL Report in all respects except a different AMP 

is credited, citing generic note E.

In its review of components associated with LRA items 3.4.1-6, 3.4.1-15, and 3.4.1-16, for which 

the applicant cited generic note C (i.e., pump oil cooler tubes, cooler coil and tubesheet, 

evaporator heat exchanger shell), the staff noted that these items do not strictly meet the 

definition of piping, piping components, or piping elements. The staff also noted that these 

components are subject to the loss of material from the same mechanisms and at roughly the 

same rate as piping such that an inspection program suitable for piping is expected to be 

suitable for these components. The staff finds that the components under consideration are 

sufficiently similar to those actually included in the GALL Report so as not to render them 

inconsistent with the GALL Report. 

In its review of other components associated with LRA items 3.4.1-6, 3.4.1-15, and 3.4.1-16, for 

which the applicant assigned generic note E, the staff noted that the GALL Report differentiates 

between treated water and steam, while the environment indicated in the application is ―treated 

water and/or steam.‖ The staff also noted that, in this case, the AMPs recommended by the 

GALL Report are identical for water and steam so that the distinction is inconsequential. The 

staff finds the use of the WCP Program to confirm the adequacy of the Water Chemistry 

Program acceptable because the WCP Program has been proposed by the applicant and 

evaluated by the staff to be consistent with the One-Time Inspection Program, which is 

recommended by the GALL Report. In addition, a staff concern related to the selection and 

frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.7.1 criteria. For those items that apply to LRA Section 3.4.2.2.7.1, 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 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 2. LRA Section 3.4.2.2.7.2 and Table 3.4.1, item 3.4.1-17 addresses stainless steel piping, 

piping components, and piping elements exposed to soil. The GALL Report recommends further 

evaluation of a plant-specific AMP to manage the effects of pitting and crevice corrosion for this 

component group. The applicant stated that this item is not applicable because there are no 

in-scope components constructed of stainless steel exposed to soil in the steam and power 

conversion systems. The staff reviewed LRA Sections 2.3.4 and 3.4 and confirmed that the 

applicant‘s LRA does not have any AMR results for the steam and power conversion systems 

that include stainless steel exposed to soil. The staff also reviewed the USAR to verify the 

same. Based on its review of the LRA and USAR, the staff confirmed that the applicant‘s plant 

does not have any in-scope components constructed of stainless steel exposed to soil in the 

steam and power conversion systems and, therefore, finds the applicant‘s determination 

acceptable.
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Item 3. LRA Section 3.4.2.2.7.3 addresses the loss of material due to pitting and crevice 

corrosion that may occur in piping, piping components, and piping elements. The applicant 

stated that loss of material for copper alloy components exposed to lubricating oil is managed 

by the Lubricating Oil Analysis Program. The WCP Program will provide a verification of the 

effectiveness of the Lubricating Oil Analysis Program to manage loss of material due to pitting 

and crevice corrosion through the examination of copper alloy components.

The staff reviewed LRA Section 3.4.2.2.7.3 against the criteria in SRP-LR Section 3.4.2.2.7.3, 

which 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 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the loss of material due to 

pitting and crevice corrosion in copper alloy piping, piping components, and piping elements 

exposed to lubricating oil. The staff noted that the applicant has credited the WCP Program in

lieu of GALL AMP XI.M32, ―One-Time Inspection.‖ By letter dated September 25, 2009, the 

applicant amended its LRA so that its WCP Program will be consistent with GALL AMP XI.M32, 

―One-Time Inspection.‖ The staff determined that the applicant‘s WCP Program will manage the 

aging effects of cracking, loss of material, and reduction of heat transfer through program 

inspections that provide verification of the effectiveness of the Lubricating Oil Analysis Program 

where: (a) an aging effect is not expected to occur but the data is insufficient to rule it out with 

reasonable confidence; (b) an aging effect is expected to progress very slowly in the specified 

environment, but the local environment may be more adverse than generally expected; or 

(c) the characteristics of the aging effect include a long incubation period. The staff further 

determined that these inspections will be performed by using NDE techniques that are effective 

and capable for identification of these potential aging effects and that the sample size and 

location will be based on an assessment of materials, environments, plausible aging effects, 

and OE. On the basis that the applicant‘s AMPs are consistent with those recommended in 

SRP-LR Section 3.4.2.2.7.3, the staff finds the applicant‘s use of the Lubricating Oil Analysis 

Program and WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.7.3 criteria. For those items that apply to LRA Section 3.4.2.2.7.3, 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 
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functions 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

LRA Section 3.4.2.2.8 addresses loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion that may occur in piping, piping components, and piping 

elements and heat exchanger components. The applicant stated that loss of material for 

stainless steel components exposed to lubricating oil is managed by the Lubricating Oil Analysis 

Program. The WCP Program will provide a verification of the effectiveness of the Lubricating Oil 

Analysis Program to manage loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion through the examination of stainless steel components.

The staff reviewed LRA Section 3.4.2.2.8 against the criteria in SRP-LR Section 3.4.2.2.8, which 

states that loss of material due to pitting, crevice, and microbiologically-influenced corrosion 

may occur in stainless steel piping, piping components, and piping elements and heat 

exchanger components 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 the 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 applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the loss of material due to 

pitting, crevice, and microbiologically-influenced corrosion in stainless steel piping, piping 

components, and piping elements and heat exchanger components exposed to lubricating oil. 

The staff noted that the applicant has credited the WCP Program in lieu of GALL AMP XI.M32, 

―One-Time Inspection.‖ By letter dated September 25, 2009, the applicant amended its LRA so 

that its WCP Program will be consistent with GALL AMP XI.M32, ―One-Time Inspection.‖ The 

staff determined that the applicant‘s WCP Program will manage the aging effects of cracking, 

loss of material, and reduction of heat transfer through program inspections that provide 

verification of the effectiveness of the Lubricating Oil Analysis Program where: (a) an aging 

effect is not expected to occur but the data is insufficient to rule it out with reasonable 

confidence; (b) an aging effect is expected to progress very slowly in the specified environment, 

but the local environment may be more adverse than generally expected; or (c) the 

characteristics of the aging effect include a long incubation period. The staff further determined 

that these inspections will be performed by using NDE techniques that are effective and capable 

for identification of these potential aging effects and that the sample size and location will be 

based on an assessment of materials, environments, plausible aging effects, and OE. On the 
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basis that the applicant‘s AMPs are consistent with those recommended in SRP-LR 

Section 3.4.2.2.8, the staff finds the applicant‘s use of the Lubricating Oil Analysis Program and 

WCP Program acceptable.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.4.2.2.8 criteria. For those items that apply to LRA Section 3.4.2.2.8, 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 

functions 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

LRA Section 3.4.2.2.9 and Table 3.4.1, item 3.4.1-5 are only applicable to BWRs and, therefore, 

not applicable to KPS. See SER Section 3.4.2.1.1.

3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff‘s evaluation of the applicant‘s QA program.

3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.4.2-1 through 3.4.2-14, the staff reviewed additional details of AMR results for 

material, environment, AERM, and AMP combinations not consistent with or not addressed in 

the GALL Report.

In LRA Tables 3.4.2-1 through 3.4.2-14, 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 concerning how the 

aging effects will be managed. 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 had 

demonstrated that the aging effects will be adequately managed so that the intended functions 

will be maintained consistent with the CLB during the period of extended operation. The staff‘s 

evaluation is discussed in the following sections.

3.4.2.3.1 Interior Surfaces of Steel Components Exposed to Hydraulic Oil

In LRA Table 3.4.2-1, the applicant stated that the interior surfaces of steel components 

exposed to hydraulic oil have no aging effect. The applicant also stated that no AMP is required. 

The AMR line items cite generic note H, indicating that the component, material, and 

environment combination listed is not addressed in the GALL Report.
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The staff reviewed all AMR result line items in the GALL Report where the material is steel and 

the environment is fuel oil or lubricating oil. The staff noted that the GALL Report recommends 

the consideration of the aging effects of loss of material. The staff also noted that in each case 

the GALL Report recommends AMPs consisting of monitoring oil chemistry coupled with an 

inspection program. Based on these recommendations in the GALL Report, the staff must also 

consider that loss of material for steel components exposed to hydraulic oil may be possible. By 

letter dated December 16, 2009, the staff issued RAI 3.4.2.3-3 requesting that the applicant 

select an AMP appropriate for the management of aging in steel components exposed to 

hydraulic oil or to justify why aging of steel components in hydraulic oil is not possible.

In its response dated January 21, 2010, the applicant stated that the hydraulic oil environment is 

specifically electro-hydraulic control (EHC) fluid and that based on a review of plant-specific OE, 

water pooling is not expected to occur in the EHC system due to high standards for fluid quality 

in this system. The staff noted that the applicant performs monthly EHC fluid samples in which 

the water content in the sample is determined. The staff also noted that in order for corrosion to 

occur, there must be water contamination as well as separation and pooling of the water. In its 

response to RAI 3.4.2.3.1, dated September 28, 2009, the applicant stated that the stainless 

steel EHC reservoir is the most likely component to experience the water separation and 

pooling, therefore, loss of material due to pitting and crevice corrosion will be managed by the 

Lubricating Oil Analysis Program and its effectiveness will be confirmed by the WCP Program. 

The staff reviewed the applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

noted that it is reasonable to state that the reservoir will be the most likely component to 

experience water separation and pooling. The staff further noted if water contamination or 

corrosion products are present, they will settle to the bottom of the reservoir where the monthly 

sample is being taken from.

The staff finds the applicant‘s response to RAI 3.4.2.3.1-3 acceptable because: (1) the applicant 

currently performs monthly sampling of the EHC fluid and is able to determine if there is water 

contamination, and (2) the applicant has credited its Lubricating Oil Analysis Program to 

manage loss of material and will confirm its effectiveness with the WCP Program for license 

renewal. The staff‘s concern described in RAI 3.4.2.3.1-3 is resolved.

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. The staff finds that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that their intended functions will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.2 Stainless Steel and Copper Alloy Components Exposed to Hydraulic Oil (Internal)

LRA Table 3.4.2-1 addresses: (1) copper alloy tubing, valves, and EHC system oil coolers and 

(2) stainless steel piping, tubing, valves, and EHC reservoirs exposed to an internal hydraulic oil 

environment that do not have an AERM, therefore, an AMP is not required. The AMR items cite 

generic note H, which indicates that the aging effect is not in the GALL Report for this 

component, material, and environment combination.

The staff reviewed LRA Table 3.0-1, ―Service Environments,‖ which states that moisture and 

water pooling are not assumed in a hydraulic oil environment. The staff also noted that the LRA 

did not provide a basis as to why these copper alloy and stainless steel components exposed to 

hydraulic oil (internal) do not have an aging effect, or why moisture and water pooling are not 
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assumed in a hydraulic oil environment. By letter dated August 28, 2009, the staff issued 

RAI 3.4.2.3.1-1 requesting that the applicant provide its basis for stating that: (1) moisture and 

water pooling are not assumed in a hydraulic oil environment, and (2) copper alloy and stainless 

steel components exposed to hydraulic oil do not have an AERM. Alternatively, the staff 

requested that the applicant provide an appropriate program for aging management.

In its response dated September 28, 2009, the applicant stated that this hydraulic oil 

environment is specifically EHC fluid. The applicant further stated that the statement that 

moisture and water pooling are not assumed in a hydraulic oil environment was based on a 

review of plant-specific OE and discussions with the station personnel. The staff noted that the 

applicant performs monthly EHC fluid samples in which the water content in the sample is 

determined. The staff noted that in order for corrosion to occur, there must be water 

contamination as well as separation and pooling of the water. The applicant stated that the 

stainless steel EHC reservoir is the most likely component to experience the water separation 

and pooling, therefore, loss of material due to pitting and crevice corrosion will be managed by 

the Lubricating Oil Analysis Program and its effectiveness will be confirmed by the WCP 

Program. The staff noted that it is reasonable to state that the reservoir will be the most likely 

component to experience water separation and pooling. The staff further noted if water 

contamination or corrosion products are present, they will settle to the bottom of the reservoir 

where the monthly sample is being taken from.

Based on its review, the staff finds the applicant‘s response to RAI 3.4.2.3.1-1 acceptable 

because: (1) the applicant currently performs monthly sampling of the EHC fluid and is able to 

determine if there is water contamination, and (2) the applicant has credited its Lubricating Oil 

Analysis Program to manage loss of material and will confirm its effectiveness with the WCP 

Program for license renewal. The staff‘s concern described in RAI 3.4.2.3.1-1 is resolved.

The staff reviewed the applicant‘s Lubricating Oil Analysis Program and WCP Program and its 

evaluations are documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively. The staff 

determined that the Lubricating Oil Analysis Program includes periodic sampling and analysis of 

lubricating oil to determine if contaminants, such as particulates, metals, and water, are present. 

The staff noted that the presence of these impurities in the lubricating oil can create an 

environment that is conducive to age-related degradation, such as loss of material and 

reduction of heat transfer. The staff determined that the activities performed as part of this 

program will be capable of preserving an environment that will not promote loss of material and 

reduction of heat transfer. The staff finds that these activities are consistent with the 

recommendations in the GALL Report and will adequately manage the loss of material in copper 

alloy and stainless steel piping, piping components, and piping elements exposed to lubricating 

oil. The staff determined that the applicant‘s WCP Program will provide verification of the 

effectiveness of the Lubricating Oil Analysis Program where: (a) an aging effect is not expected 

to occur but the data is insufficient to rule it out with reasonable confidence; (b) an aging effect 

is expected to progress very slowly in the specified environment, but the local environment may 

be more adverse than generally expected; or (c) the characteristics of the aging effect include a 

long incubation period. The staff further determined that these inspections will be performed by 

using NDE techniques that are effective and capable for identification of these potential aging 

effects and that the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE.

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 functions 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 Stainless Steel Components Subject to Loss of Material Due to Pitting, Crevice and 

Microbiologically-Influenced Corrosion Exposed to Air-Moist and Treated Water-Closed-Cycle 

Cooling

LRA Table 3.4.2-2 addresses flex connections, piping, and rupture discs fabricated from 

stainless steel exposed to air-moist (internal), which are subject to loss of material due to pitting 

and crevice corrosion. LRA Table 3.4.2-3 addresses expansion joints and piping fabricated from 

stainless steel exposed to air-moist (internal), which are subject to loss of material due to pitting 

and crevice corrosion. LRA Table 3.4.2-6 addresses rupture discs fabricated from stainless 

steel exposed to air-moist (internal), which are subject to loss of material due to pitting and 

crevice corrosion. LRA Table 3.4.2-12 addresses coolers (shell of sample coolers), feedwater 

sample line chiller (evaporator tank and recirculating pump), piping, tubing, and valves 

fabricated from stainless steel exposed to treated water-closed-cycle cooling (internal), which 

are subject to loss of material due to pitting, crevice, and microbiologically-influenced corrosion. 

The applicant credited the WCP Program for managing the loss of material for the components 

described above. The AMR items cite generic note H, which indicates that the aging effect is not 

in the GALL Report for this component, material, and environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of 

stainless steel to detect loss of material. The staff further determined that this program will: 

(1) perform inspections of components during surveillance and maintenance activities to provide 

for the detection of degradation prior to the loss of intended function and (2) will require that the 

extent of the inspection and its results be documented even when no signs of aging degradation 

are found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 
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adequately managed so that the intended functions will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.4 Copper Alloy Components Subject to Loss of Material Due to Pitting, Crevice, and 

Microbiologically-Influenced Corrosion and Loss of Material Due to Erosion Exposed to Raw 

Water (Internal) 

LRA Table 3.4.2-10 addresses heating coils fabricated from copper alloy exposed to raw water 

(internal), which are subject to loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion. LRA Table 3.4.2-11 addresses generator hydrogen 

coolers (coils) fabricated from copper alloy exposed to raw water (internal), which are subject to 

loss of material due to pitting, crevice, and microbiologically-influenced corrosion and loss of 

material due to erosion. The applicant credited the WCP Program for aging management of loss 

of material for the components described above. The AMR items cite generic note H, which 

indicates that the aging effect is not in the GALL Report for this component, material, and 

environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) will require that the extent 

of the inspection and its results be documented even when no signs of aging degradation are 

found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions 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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3.4.2.3.5 Copper Alloy Components Subject to Loss of Material Due to Pitting, Crevice, 

Galvanic, and Microbiologically-Influenced Corrosion Exposed to Treated Water-Closed-Cycle 

Cooling 

LRA Table 3.4.2-12 addresses tubing and valves fabricated from copper alloy exposed to 

treated water-closed-cycle cooling (internal) which are subject to the loss of material due to 

pitting, crevice, galvanic, and microbiologically-influenced corrosion. The applicant credited the 

WCP Program for managing the loss of material for the components described above. The AMR 

items cite generic note H, which indicates that the aging effect is not in the GALL Report for this 

component, material, and environment combination.

By letter dated September 25, 2009, the applicant amended its LRA so that its WCP Program 

will be consistent with GALL AMP XI.M32, ―One-Time Inspection,‖ and GALL AMP XI.M38, 

―Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.‖ The 

applicant clarified the details of how this amendment would affect LRA Section 3 and stated that 

if the WCP Program is credited for aging management without a corresponding chemistry 

control program being credited for that particular AMR line item, then the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program is the intended program 

that is being credited to manage the identified aging effect as a stand-alone program. The staff 

determined that those AMR line items discussed in this section are crediting the portion of the 

WCP Program that corresponds to GALL AMP XI.M38 as a stand-alone program.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. The staff determined that this program will manage the aging effects of loss 

of material for the in-scope SCs through inspections implemented in accordance with the work 

management process, which will perform visual inspections of components fabricated of copper 

alloy to detect loss of material. The staff further determined that this program will: (1) perform 

inspections of components during surveillance and maintenance activities to provide for the 

detection of degradation prior to the loss of intended function and (2) will require that the extent 

of the inspection and its results be documented even when no signs of aging degradation are 

found, so that there is a meaningful trending of aging effects. The staff noted that the visual 

inspection techniques are established and are capable of detecting loss of material due to 

corrosion by the presence of localized discoloration and surface irregularities, such as rust, 

scale, deposits, surface pitting, surface discontinuities, and coating degradation. On the basis of 

periodic visual inspections being performed during surveillance and maintenance activities of 

these components by the WCP Program, the staff finds the applicant‘s use of the WCP Program 

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 functions 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 Exterior Surfaces of Non-Metallic Materials Exposed to Uncontrolled Indoor Air and 

Interior Surfaces of Non-Metallic Materials Exposed to Treated Water or Steam

In LRA Table 3.4.2-12, the applicant stated that the interior surfaces of non-metallic materials 

exposed to treated water or steam and the exterior surfaces of non-metallic materials exposed 

to uncontrolled indoor air have no aging effect and that no AMP is required. The AMR line items 
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cite generic note H, indicating that for the component, material, and environment combination 

listed, the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material type is 

non-metallic materials exposed to treated water or steam and confirmed that there are no 

entries for this component/material and environment. The staff noted that there is not a distinct 

definition for non-metallic material in GALL Report Chapter IX. The staff also noted that many 

polymeric materials are adversely affected by oxidizers (e.g., chlorine), UV light, and high 

temperatures. Based on the information provided, the staff cannot conclude that no aging 

effects will occur to the combination of materials and environments under consideration. By 

letter dated October 13, 2009, the staff issued RAI 3.4.2.3.12-1 requesting that the applicant 

identify the specific material under consideration and justify why this material is not subject to 

aging under the conditions being considered.

In its response dated November 13, 2009, the applicant stated that the non-metallic materials in 

the LRA Table 3.4.2-12 are polysulfone, polyethersulfone, and PVC in the secondary sampling 

system and are exposed on their interior surfaces to sample fluids from chemistry-controlled 

secondary plant systems. The applicant also stated that, these materials are not exposed to 

chemical contaminants or temperatures greater than 95 °F. The staff finds the applicant‘s 

proposal, that these materials are not subject to aging and that no aging management is 

required, acceptable because: (1) these materials are not known to degrade in pure water, 

(2) chemical contaminants which could cause material degradation are not expected to be 

present, and (3) the GALL Report indicates that thermal aging is not expected at temperatures 

below 95 °F.

The applicant stated that the external surfaces of all the materials described above are exposed 

to air. The staff agrees with the applicant that aging of these materials due solely to exposure to 

air is unlikely. The applicant also evaluated other sources of potential degradation to which 

these materials could be exposed. The applicant evaluated the potential for degradation due to 

chemical contaminants in the air (e.g., sulfur dioxide), high temperature (greater than 95 °F), 

and exposure to oxidizing agents (e.g., UV radiation or ozone). The staff finds that these are the 

appropriate effects to examine. The applicant stated, and the staff concurs, that degradation 

due to chemical contaminants is unlikely due to the rural location of the plant. The applicant 

stated and, based on recommendations in the GALL Report, the staff concurs that exposure of 

these materials to temperatures less than 95 °F is unlikely to cause aging. The applicant stated, 

and the staff concurs, that the primary source of ozone to which these materials may be 

exposed is electrical equipment and that the remote location of these materials from ozone 

producing equipment will eliminate this issue. The applicant also stated that UV radiation is not 

a source of aging because these materials are located indoors and because a review of plant 

experience indicated that UV radiation from fluorescent lighting was not sufficient to cause 

degradation. The staff concurs with the applicant that the absence of exposure of these 

materials to sunlight substantially eliminates the potential for aging due to UV radiation. 

However, the staff does believe that, in some instances, UV radiation from fluorescent lighting 

can cause aging. The staff accepts the applicant‘s review of plant operating history as evidence 

that, in this location, the intensity of the fluorescent lighting is not sufficient to cause aging in the 

materials under consideration. Based on the above, the staff finds the applicant‘s approach to 

manage the aging of the non-metallic components under consideration acceptable. The staff‘s 

concern described in RAI 3.4.2.3.12 is resolved. 
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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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.3.7 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion from the 

Internal Surfaces of Steel and Stainless Steel Piping, Piping Components, Piping Elements, and 

Heat Exchanger Components Exposed to Treated Closed-Cycle Cooling Water

In LRA Table 3.4.2-12, the applicant stated that the internal surfaces of steel and stainless steel 

piping, piping components, piping elements, and heat exchanger components exposed to 

treated closed-cycle cooling water are being managed for loss of material due to general, 

pitting, crevice, and galvanic corrosion by the WCP Program. The AMR line items cite generic 

note H, indicating that for the component, material, and environment combination listed, the 

aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the internal surfaces of steel and stainless steel piping, piping components, 

piping elements, and heat exchanger components exposed to treated closed-cycle cooling 

water and noted that the GALL Report recommends GALL AMP XI.M21, ―Closed-Cycle Cooling 

Water System,‖ for this component, material, and environment where the aging effect is loss of 

material due to general, pitting, crevice, and galvanic corrosion. The staff also noted that the 

components in LRA Table 3.4.2-12 are nonsafety-related and, therefore, the Closed-Cycle 

Cooling Water System Program is not appropriate. However, contrary to the applicant‘s 

assertion, the staff further noted that the aging effect being considered has been evaluated in 

the GALL Report for the components, materials, and environment combination listed, which 

corresponds to SRP-LR Table 3.4.1 items 24, 25, and 26. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff finds the applicant‘s proposal to manage this aging, through the use of that portion of the

WCP which is consistent with GALL AMP XI.M38, ―Inspection of Internal Surfaces of 

Miscellaneous Piping and Ducting Components,‖ acceptable because: (1) the scope of this AMP 

includes internal surfaces of piping and ducting components not included in other AMPs, and 

(2) the WCP Program contains visual inspection techniques appropriate for the identification of 

loss of material for these components. In addition, a staff concern related to the selection and 

frequency of inspections is addressed in RAI B 2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

On the basis of its review, the staff concludes that the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that their intended 

functions 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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3.4.2.3.8 Loss of Material Due to General, Pitting, Crevice, Galvanic, and 

Microbiologically-Influenced Corrosion, as well as Fouling from the Internal Surfaces of Steel 

Heat Exchanger Components Exposed to Raw Water

In LRA Tables 3.4.2-1, 3.4.2-4, 3.4.2-9, 3.4.2-10, 3.4.2-11, and 3.4.2-12, the applicant stated 

that the internal surfaces of steel heat exchanger components exposed to raw water are being 

managed for loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion by the WCP Program. The AMR line items cite generic 

note H, indicating that for the component, material, and environment combination listed, the 

aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the internal surfaces of steel heat exchanger components exposed to raw 

water and noted that the GALL Report recommends GALL AMP XI.M20, ―Open-Cycle Cooling 

Water System,‖ for this component, material, and environment where the aging effect is loss of 

material due to general, pitting, crevice, galvanic, and microbiologically-influenced corrosion. 

The staff also noted that the components in LRA Tables 3.4.2-1, 3.4.2-4, 3.4.2-9, 3.4.2-10, 

3.4.2-11, and 3.4.2-12 are nonsafety-related and, therefore, the Open-Cycle Cooling Water 

System Program is not appropriate. However, contrary to the applicant‘s assertion, the staff 

further noted that the aging effect being considered has been evaluated in the GALL Report for 

the components, materials, and environment combination listed, which corresponds to SRP-LR 

Table 3.4.1, items 31 and 32.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. Given 

that the use of the Open-Cycle Cooling Water System Program is not appropriate, the staff finds 

the applicant‘s use of the WCP Program acceptable as this AMP contains visual inspection 

procedures which are appropriate for the detection of loss of material due to corrosion on the 

internal surfaces of heat exchanger components. In addition, a staff concern related to the 

selection and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation 

of the RAI response is documented in SER Section 3.3.2.2.13.

On the basis of its review, the staff concludes that the applicant has demonstrated that the 

effects of aging for these components will be adequately managed so that their intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.4.2.3.9 Loss of Material Due to Erosion from the Internal Surfaces of Steel Heat Exchanger 

Components Exposed to Raw Water

In LRA Tables 3.4.2-1, 3.4.2-4, 3.4.2-9, 3.4.2-10, 3.4.2-11, and 3.4.2-12, the applicant stated 

that the internal surfaces of steel heat exchanger components exposed to raw water are being 

managed for loss of material due to erosion by the WCP Program. The AMR line items cite 

generic note H, indicating that for the component, material, and environment combination listed, 

the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the internal surfaces of steel heat exchanger components exposed to raw 

water and confirmed that there are no entries for this component, material, and environment 

where the aging effect is loss of material due to erosion. 
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The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff also noted that the components under consideration are nonsafety-related components. As 

a result, the use of the Open-Cycle Cooling Water System Program is not appropriate as this 

AMP is limited to components in safety-related systems which transfer heat to the ultimate heat 

sink. Given that the use of the Open-Cycle Cooling Water System Program is not appropriate, 

the staff finds the applicant‘s use of the WCP Program acceptable because this AMP contains 

visual inspection procedures which are appropriate for the detection of erosion on the internal 

surfaces of heat exchanger components. In addition, a staff concern related to the selection and 

frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the 

RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.3.10 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, as well as Fouling from the Internal Surfaces of Steel Piping, Piping Components, 

and Piping Elements Exposed to Raw Water

In LRA Table 3.4.2-10, the applicant stated that the internal surfaces of steel piping, piping 

components, and piping elements exposed to raw water are being managed for loss of material 

due to general, pitting, crevice, and microbiologically-influenced corrosion by the WCP Program. 

The AMR line items cite generic note H, indicating that for the component, material, and 

environment combination listed, the aging effect being considered is not evaluated in the GALL 

Report.

The staff reviewed all AMR result line items in the GALL Report where the component, material,

and environment type is internal surfaces of steel piping, piping components, and piping 

elements exposed to raw water, and noted that the GALL Report recommends GALL 

AMP XI.M20, ―Open-Cycle Cooling Water System,‖ where the aging effect is loss of material 

due to general, pitting, crevice, and galvanic corrosion, or GALL AMP XI.M27, ―Fire Water 

System,‖ where the aging effect is loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion, as well as fouling. The staff also noted that the 

components in LRA Table 3.4.2-10 are nonsafety-related and, therefore, the Open-Cycle 

Cooling Water System Program is not appropriate. The staff further noted that the components 

are not associated with the fire protection system and that, therefore, the Fire Water System 

Program would also not be an appropriate program to manage aging for these components.

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. Given 

that the use of the Fire Water System and Open-Cycle Cooling Water System programs are not 

appropriate, the staff concurs with the applicant‘s use of the WCP Program as this AMP 

contains visual inspection procedures which are appropriate for the detection of loss of material 

on the steel piping, piping components, and piping elements. In addition, a staff concern related 
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to the selection and frequency of inspections is addressed in RAI B2.1.32-2, and the staff‘s 

evaluation of the RAI response is documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.3.11 Loss of Material Due to Microbiologically-Influenced Corrosion from the Internal 

Surfaces of Steel Heat Exchanger Components Exposed to Treated Closed-Cycle Cooling 

Water

In LRA Table 3.4.2-12, the applicant stated that internal surfaces of steel heat exchanger 

components exposed to treated closed-cycle cooling water are being managed for loss of 

material due to MIC by the WCP Program. The AMR line items cite generic note H, indicating 

that for the component, material, and environment combination listed, the aging effect being 

considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the internal surfaces of steel heat exchanger components exposed to treated 

closed-cycle cooling water and confirmed that there are no entries for this component, material, 

and environment where the aging effect is loss of material due to MIC. 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff also noted that these components are nonsafety-related components. The staff finds the 

applicant‘s proposal, to manage aging using the portion of the WCP Program which is 

consistent with GALL AMP XI.M38, ―Inspection of Internal Surfaces of Miscellaneous Piping and 

Ducting Components,‖ acceptable because: (1) the scope of this AMP includes internal surfaces 

of piping and ducting components not included in other AMPs, and (2) the WCP Program 

contains visual inspection techniques appropriate to the identification of loss of material for 

these components. In addition, a staff concern related to the selection and frequency of 

inspections is addressed in RAI B2.1.32-2, and the staff‘s evaluation of the RAI response is 

documented in SER Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.3.12 Cracking Due to Stress-Corrosion Cracking for Copper Alloy

In LRA Tables 3.4.2-5, 3.4.2-6, 3.4.2-8, 3.4.2-9, 3.4.2-12, and 3.4.2-14, the applicant stated that 

the copper alloy valves exposed to treated water and steam-secondary (internal) are being 

managed for cracking due to SCC. In LRA Table 3.4.2-7, the applicant stated that the copper 

alloy AFW pump oil coolers (tubes and tubesheet) and turbine driven AFW pump turbine 
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bearing coolers (coil) exposed to treated water and steam-secondary (internal) are being 

managed for cracking due to SCC. In LRA Table 3.4.2-10, the applicant stated that the copper 

alloy boric acid evaporator condenser return unit heat exchanger (shell), heating coils, and 

valves exposed to treated water and steam-secondary (internal) are being managed for 

cracking due to SCC. The applicant credited the Secondary Water Chemistry Program and the 

WCP Program to manage this aging effect for the components described above. The AMR 

items cite generic note H, which indicates that the aging effect is not in the GALL Report for this 

component, material, and environment combination.

The staff reviewed the applicant‘s Secondary Water Chemistry Program and WCP Program; 

these evaluations are documented in SER Sections 3.0.3.1.11 and 3.0.3.2.19, respectively. The 

staff determined that the Secondary Water Chemistry Program includes periodic monitoring and 

control of contaminants such as chloride, fluoride, dissolved oxygen, and sulfate concentrations 

below specified levels that may result in loss of material, and that the program also maintains 

water quality (pH and conductivity). The staff also determined that the applicant‘s program 

specifies sampling and analysis frequencies and corrective actions if specified limits are 

exceeded. The staff further determined that: (1) the applicant‘s WCP Program will manage the 

aging effects of loss of material through program inspections which provide verification of the 

effectiveness of Secondary Water Chemistry Program; (2) these inspections will be performed 

by using NDE techniques that are effective and capable of identifying these potential aging 

effects; and (3) the sample size and location will be based on an assessment of materials, 

environments, plausible aging effects, and OE. Based on its review, the staff finds the 

applicant‘s use of the programs identified above acceptable because the chemistry control will 

provide an environment that is not conducive for cracking to occur and the applicant will verify 

the effectiveness of the chemistry control with examinations performed by its WCP 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 functions 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 

functions 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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3.5 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 

structures and component supports components and component groups of the following:

● reactor containment vessel

● structures and structural components, which include the following:

▪ shield building

▪ administration building

▪ auxiliary building

▪ screenhouse access tunnel

▪ technical support center

▪ turbine building

▪ yard structures

▪ discharge structure

▪ discharge tunnel and pipe

▪ intake structure

▪ screen house

● component supports

● miscellaneous structural commodities

● NSSS supports 

3.5.1 Summary of Technical Information in the Application

LRA Section 3.5 provides AMR results for the structures and component supports components 

and component groups. LRA Table 3.5.1, ―Summary of Aging Management Programs for 

Structures and Component Supports Evaluated in Chapters II and III of NUREG-1801,‖ is a 

summary comparison of the applicant‘s AMRs with those evaluated in the GALL Report for the 

structures and component supports components and component groups.

The applicant‘s AMRs evaluated and incorporated applicable plant-specific and industry OE 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 OE included a review of the GALL Report and OE issues identified since the issuance 

of the GALL Report.

The applicant credited the following programs for managing the aging effects for the structures 

and component supports:

● ASME Section XI, Subsection IWE Program

● ASME Section XI, Subsection IWF Program

● Bolting Integrity Program

● Boric Acid Corrosion Program

● Buried Piping and Tanks Inspection Program

● External Surfaces Monitoring Program

● Fire Protection Program

● Primary Water Chemistry Program

● Reactor Containment Leakage Testing 10 CFR 50, Appendix J Program
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● Structures Monitoring Program

● Work Control Process Program

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 structures and component supports 

components, within the scope of license renewal and subject to an AMR, will be adequately 

managed so that the intended functions 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 a review of the AMR items that the applicant had identified as being 

consistent with the GALL Report to confirm 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 3.5.2.1.

The staff also conducted a review of 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 

evaluations are documented in SER Section 3.5.2.2.

The staff also conducted a technical review of the remaining AMRs 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 OE 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.
Aging Management Review Results

3-411

Table 3.5-1 Staff Evaluation for Structures and Component Supports Components in the 

GALL Report

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

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 Not applicable See SER 

Section 3.5.2.2.1.1

Concrete elements: 

all

(3.5.1-2)

Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Structures 

Monitoring 

Program. 

If a de-watering

system is relied 

upon for control of 

settlement, then the 

licensee is to 

ensure proper 

functioning of the 

de-watering system 

through the period 

of extended 

operation.

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.1.2)

Concrete elements: 

foundation, 

subfoundation

(3.5.1-3)

Reduction in 

foundation 

strength, 

cracking, and 

differential 

settlement due to 

erosion of porous 

concrete 

subfoundation

Structures 

Monitoring 

Program.

If a de-watering 

system is relied 

upon to control 

erosion of cement 

from porous 

concrete 

subfoundations, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period 

of extended 

operation.

Yes Not applicable See SER 

Section 3.5.2.2.1.2
Aging Management Review Results

3-412

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Concrete elements: 

dome, wall, basemat, 

ring girder, 

buttresses, 

containment, concrete 

fill-in annulus (as 

applicable)

(3.5.1-4)

Reduction of 

strength and 

modulus of 

concrete due to 

elevated 

temperature

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable See SER 

Section 3.5.2.2.1.3 

Steel elements: 

drywell; torus; drywell 

head; embedded shell 

and sand pocket 

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)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Steel elements: steel 

liner, liner anchors, 

integral attachments

(3.5.1-6)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

Yes ASME Section XI, 

Subsection IWE 

Program and 

10 CFR Part 50, 

Appendix J 

Program 

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.1.4)

Prestressed 

containment tendons

(3.5.1-7)

Loss of prestress 

due to relaxation, 

shrinkage, creep, 

and elevated 

temperature

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes Not applicable Not applicable

(See SER 

Section 3.5.2.2.1.5)

Steel and stainless 

steel elements: vent 

line, vent header, vent 

line bellows, and 

downcomers

(3.5.1-8)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Steel, stainless steel 

elements, dissimilar 

metal welds: 

penetration sleeves, 

penetration bellows; 

suppression pool 

shell, unbraced 

downcomers

(3.5.1-9)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA, evaluated in

accordance with 

10 CFR 54.21(c)

Yes TLAA See SER 

Section 3.5.2.2.1.6
Aging Management Review Results

3-413

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

penetration sleeves, 

penetration bellows, 

dissimilar metal welds

(3.5.1-10)

Cracking due to 

SCC

ISI (IWE) and 

10 CFR Part 50, 

Appendix J, and 

additional 

appropriate 

examinations/ 

evaluations for 

bellows assemblies 

and dissimilar metal 

welds.

Yes ASME Section XI, 

Subsection IWE 

Program and 

10 CFR Part 50, 

Appendix J 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.1.7)

Stainless steel vent 

line bellows

(3.5.1-11)

Cracking due to 

SCC

ISI (IWE) and 

10 CFR Part 50, 

Appendix J, and 

additional 

appropriate 

examination/ 

evaluation for 

bellows assemblies 

and dissimilar metal 

welds.

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Steel, stainless steel 

elements, dissimilar 

metal welds: 

penetration sleeves, 

penetration bellows, 

suppression pool 

shell, unbraced 

downcomers

(3.5.1-12)

Cracking due to 

cyclic loading

ISI (IWE) and 

10 CFR Part 50, 

Appendix J, and 

supplemented to 

detect fine cracks

Yes ASME Section XI, 

Subsection IWE 

Program and 

10 CFR Part 50, 

Appendix J 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.1.8)

Steel, stainless steel 

elements, dissimilar 

metal welds: torus, 

vent line, vent header, 

vent line bellows, 

downcomers

(3.5.1-13)

Cracking due to 

cyclic loading

ISI (IWE) and 

10 CFR Part 50, 

Appendix J, and 

supplemented to 

detect fine cracks

Yes Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Concrete elements: 

dome, wall, basemat 

ring girder,

buttresses, 

containment (as 

applicable)

(3.5.1-14)

Loss of material 

(scaling, 

cracking, and 

spalling) due to 

freeze-thaw

ISI (IWL). 

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering 

index > 100 

day-inch/yr) 

(NUREG-1557).

Yes Not applicable See SER 

Section 3.5.2.2.1.9 
Aging Management Review Results

3-414

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Concrete elements: 

walls, dome, 

basemat, ring girder, 

buttresses, 

containment, concrete 

fill-in annulus (as 

applicable)

(3.5.1-15)

Cracking due to 

expansion and 

reaction with 

aggregate; 

increase in 

porosity, 

permeability due 

to leaching of 

calcium 

hydroxide

ISI (IWL) for 

accessible areas. 

None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R.

Yes Not applicable See SER 

Section 3.5.2.2.1.10 

Seals, gaskets, and 

moisture barriers

(3.5.1-16)

Loss of sealing 

and leakage 

through 

containment due 

to deterioration of 

joint seals, 

gaskets, and 

moisture barriers 

(caulking, 

flashing, and 

other sealants)

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No ASME Section XI, 

Subsection IWE 

Program and 

10 CFR Part 50, 

Appendix J 

Program

Consistent with the 

GALL Report 

Personnel airlock, 

equipment hatch and 

CRD hatch locks, 

hinges, and closure 

mechanisms

(3.5.1-17)

Loss of leak 

tightness in 

closed position

due to 

mechanical wear 

of locks, hinges, 

and closure 

mechanisms

10 CFR Part 50, 

Appendix J and 

plant TSs

No 10 CFR Part 50, 

Appendix J 

Program and 

plant TSs 

Consistent with the 

GALL Report 

Steel penetration 

sleeves and dissimilar 

metal welds; 

personnel airlock, 

equipment hatch, and 

CRD hatch

(3.5.1-18)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No ASME Section XI, 

Subsection IWE 

Program and 

10 CFR Part 50, 

Appendix J 

Program

Consistent with the 

GALL Report

Steel elements: 

stainless steel 

suppression chamber 

shell (inner surface)

(3.5.1-19)

Cracking due to 

SCC 

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Steel elements: 

suppression chamber 

liner (interior surface)

(3.5.1-20)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Steel elements: 

drywell head and 

downcomer pipes

(3.5.1-21)

Fretting or 

lock-up due to 

mechanical wear

ISI (IWE) No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)
Aging Management Review Results

3-415

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Prestressed 

containment: tendons 

and anchorage 

components

(3.5.1-22)

Loss of material 

due to corrosion

ISI (IWL) No Not applicable Not applicable 

(KPS does not have a 

prestressed 

containment)

Safety-Related and Other Structures, and Component Supports

All Groups except 

Group 6: interior and 

above-grade exterior 

concrete

(3.5.1-23)

Cracking, loss of 

bond, and loss of 

material 

(spalling, scaling) 

due to corrosion 

of embedded 

steel

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program 

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.1)

All Groups except 

Group 6: interior and 

above-grade exterior 

concrete

(3.5.1-24)

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, scaling) 

due to 

aggressive 

chemical attack

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.1)

All Groups except 

Group 6: steel 

components: all 

structural steel

(3.5.1-25)

Loss of material 

due to corrosion

Structures 

Monitoring 

Program. 

If protective 

coatings are relied 

upon to manage 

the effects of aging, 

the Structures 

Monitoring Program 

is to include 

provisions to 

address protective 

coating, monitoring, 

and maintenance.

Yes Structures 

Monitoring 

Program, 

External Surfaces 

Monitoring

Program, and 

Fire Protection 

Program

Consistent with the 

GALL Report

(See SER

Section 3.5.2.2.2.1)

All Groups except 

Group 6: accessible 

and inaccessible 

concrete: foundation

(3.5.1-26)

Loss of material 

(spalling, scaling) 

and cracking due 

to freeze-thaw

Structures 

Monitoring 

Program. 

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

> 100 day-inch/yr) 

(NUREG-1557).

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Sections 3.5.2.2.2.1 

and 3.5.2.2.2.2.1)
Aging Management Review Results

3-416

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

All Groups except 

Group 6: accessible

and inaccessible 

interior and exterior 

concrete

(3.5.1-27)

Cracking due to 

expansion due to 

reaction with 

aggregates

Structures 

Monitoring 

Program. 

None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77.

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Sections 3.5.2.2.2.1 

and 3.5.2.2.2.2.2)

Groups 1-3, 5-9: all

(3.5.1-28)

Cracks and 

distortion due to 

increased stress 

levels from 

settlement

Structures 

Monitoring 

Program. 

If a de-watering 

system is relied 

upon for control of 

settlement, then the 

licensee is to 

ensure proper 

functioning of the 

de-watering system 

through the period 

of extended 

operation.

Yes Structures 

Monitoring 

Program 

Consistent with the 

GALL Report

(See SER 

Sections 3.5.2.2.2.1 

and 3.5.2.2.2.2.3)

Groups 1-3, 5-9: 

foundation

(3.5.1-29)

Reduction in 

foundation 

strength, 

cracking, and 

differential 

settlement due to 

erosion of porous 

concrete 

subfoundation

Structures 

Monitoring 

Program. 

If a de-watering 

system is relied 

upon for control of 

settlement, then the 

licensee is to 

ensure proper 

functioning of the 

de-watering system 

through the period 

of extended 

operation.

Yes Not applicable Not applicable

(See SER 

Sections 3.5.2.2.2.1 

and 3.5.2.2.2.2.3)

Group 4: radial beam 

seats in BWR drywell; 

RPV support shoes 

for PWR with nozzle 

supports; steam 

generator supports

(3.5.1-30)

Lock-up due to 

wear

ISI (IWF) or 

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program or 

ASME Section XI, 

Subsection IWF 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.1)
Aging Management Review Results

3-417

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Groups 1-3, 5, 7-9: 

below-grade concrete 

components, such as 

exterior walls below 

grade and foundation

(3.5.1-31)

Increase in 

porosity and 

permeability, 

cracking, loss of 

material 

(spalling, 

scaling), 

aggressive 

chemical attack; 

cracking, loss of 

bond, and loss of 

material 

(spalling, 

scaling), 

corrosion of 

embedded steel

Structures 

Monitoring 

Program. 

Examination of 

representative 

samples of 

below-grade 

concrete, and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive.

Yes Structures 

Monitoring 

Program and 

Commitments

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.2.4)

Groups 1-3, 5, 7-9: 

exterior above- and 

below-grade 

reinforced concrete 

foundations

(3.5.1-32)

Increase in 

porosity and 

permeability, and 

loss of strength 

due to leaching 

of calcium 

hydroxide

Structures

Monitoring Program 

for accessible 

areas. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77.

Yes Structures 

Monitoring 

Program 

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.2.5)

Groups 1-5: concrete

(3.5.1-33)

Reduction of 

strength and 

modulus due to 

elevated 

temperature

A plant-specific 

AMP is to be 

evaluated.

Yes Not applicable Not applicable

(See SER 

Section 3.5.2.2.2.3)
Aging Management Review Results

3-418

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Group 6: concrete; all

(3.5.1-34)

Increase in 

porosity and 

permeability, 

cracking, and 

loss of material 

due to 

aggressive 

chemical attack; 

cracking, loss of 

bond, and loss of 

material due to 

corrosion of 

embedded steel

Inspection of 

Water-Control 

Structures or 

Federal Energy 

Regulatory 

Commission 

(FERC)/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. For 

inaccessible 

concrete, an 

examination of 

representative 

samples of 

below-grade 

concrete and 

periodic monitoring 

of groundwater, if 

the environment is 

non-aggressive. A 

plant-specific 

program is to be 

evaluated if 

environment is 

aggressive.

Yes Structures 

Monitoring 

Program and 

Commitments

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.4.1)

Group 6: exterior 

above- and 

below-grade concrete 

foundation

(3.5.1-35)

Loss of material 

(spalling, scaling) 

and cracking due 

to freeze-thaw

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. 

Evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

> 100 day-inch/yr) 

(NUREG-1557).

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.4.2)
Aging Management Review Results

3-419

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Group 6: all 

accessible and 

inaccessible 

reinforced concrete

(3.5.1-36)

Cracking due to 

expansion/

reaction with 

aggregates

For accessible 

areas, inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77.

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.4.3)

Group 6: exterior 

above- and 

below-grade 

reinforced concrete 

foundation interior 

slab

(3.5.1-37)

Increase in 

porosity and 

permeability, loss 

of strength due to 

leaching of 

calcium 

hydroxide

For accessible 

areas, inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs. None for 

inaccessible areas 

if concrete was 

constructed in 

accordance with the 

recommendations 

in ACI 201.2R-77.

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.4.3)

Groups 7, 8: tank 

liners

(3.5.1-38)

Cracking due to 

SCC; loss of 

material due to 

pitting and 

crevice corrosion

A plant-specific 

AMP is to be 

evaluated

Yes Not applicable See SER 

Section 3.5.2.2.2.5

Support members, 

welds, bolted 

connections, and 

support anchorage to 

building structure

(3.5.1-39)

Loss of material 

due to general 

and pitting 

corrosion

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program, 

External Surfaces 

Monitoring 

Program, and 

Fire Protection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.6)

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for support 

base plates

(3.5.1-40)

Reduction in 

concrete anchor 

capacity due to 

local concrete 

degradation 

service-induced 

cracking, or other 

concrete aging 

mechanisms

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.6)
Aging Management Review Results

3-420

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Vibration isolation 

elements

(3.5.1-41)

Reduction or loss 

of isolation 

function radiation 

hardening, 

temperature, 

humidity, and 

sustained 

vibratory loading

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.2.2.6)

Groups B1.1, B1.2, 

and B1.3: support 

members: anchor 

bolts and welds

(3.5.1-42)

Cumulative 

fatigue damage 

(CLB fatigue 

analysis exists)

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA See SER 

Section 3.5.2.2.2.7

Groups 1-3, 5, 6: all 

masonry block walls

(3.5.1-43)

Cracking due to 

restraint 

shrinkage, creep, 

and aggressive 

environment

Masonry Wall 

Program

No Structures 

Monitoring 

Program and Fire

Protection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.1.3)

Group 6: elastomer 

seals, gaskets, and 

moisture barriers

(3.5.1-44)

Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Structures 

Monitoring Program

No Structures 

Monitoring 

Program, WCP 

Program, and 

Fire Protection 

Program

Consistent with the 

GALL Report

(See SER 

Section 3.5.2.1.6)

Group 6: exterior 

above- and 

below-grade concrete 

foundation; interior 

slab

(3.5.1-45)

Loss of material 

due to abrasion, 

cavitation

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Group 5: fuel pool 

liners

(3.5.1-46)

Cracking due to 

SCC; loss of 

material due to 

pitting and 

crevice corrosion

Water Chemistry 

and monitoring of 

SFP water level in 

accordance with 

TSs and leakage 

from the leak chase 

channels.

No Primary Water 

Chemistry 

Program

Consistent with the 

GALL Report
Aging Management Review Results

3-421

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Group 6: all metal 

structural members

(3.5.1-47)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice corrosion

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance. If 

protective coatings 

are relied upon to 

manage aging, 

protective coating 

monitoring and 

maintenance 

provisions should 

be included.

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Group 6: earthen 

water control 

structures-dams, 

embankments, 

reservoirs, channels, 

canals, and ponds

(3.5.1-48)

Loss of material, 

loss of form due 

to erosion, 

settlement, 

sedimentation, 

frost action, 

waves, currents, 

surface runoff, 

and seepage

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs

No Not applicable Not applicable 

(See SER 

Section 3.5.2.1.1)

Support members, 

welds, bolted 

connections, and 

support anchorage to 

building structure

(3.5.1-49)

Loss of material 

due to general, 

pitting, and 

crevice corrosion

Water Chemistry 

and ISI (IWF)

No Not applicable Not applicable to 

PWRs

(See SER 

Section 3.5.2.1.1)

Groups B2 and B4: 

galvanized steel, 

aluminum, stainless 

steel support 

members; welds; 

bolted connections; 

support anchorage to 

building structure

(3.5.1-50)

Loss of material 

due to pitting and 

crevice corrosion

Structures 

Monitoring Program

No Structures 

Monitoring 

Program and 

External Surfaces 

Monitoring 

Program

Consistent with the 

GALL Report

Group B1.1: 

high-strength 

low-alloy bolts

(3.5.1-51)

Cracking due to 

SCC; loss of 

material due to 

general corrosion

Bolting Integrity 

Program

No Bolting Integrity 

Program

Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Groups B2 and B4: 

sliding support 

bearings and sliding 

support surfaces

(3.5.1-52)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

and overload; 

fatigue due to 

vibratory and 

cyclic thermal 

loads

Structures 

Monitoring Program

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Groups B1.1, B1.2, 

and B1.3: support 

members: welds, 

bolted connections, 

and support 

anchorage to building 

structure

(3.5.1-53)

Loss of material 

due to general 

and pitting 

corrosion

ISI (IWF) No ASME Section XI, 

Subsection IWF 

Program

Consistent with the 

GALL Report

Groups B1.1, B1.2, 

and B1.3: constant 

and variable load 

spring hangers, 

guides, and stops

(3.5.1-54)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

and overload; 

fatigue due to 

vibratory and 

cyclic thermal 

loads

ISI (IWF) No ASME Section XI, 

Subsection IWF 

Program

Consistent with the 

GALL Report

Steel, galvanized 

steel, and aluminum 

support members; 

welds; bolted 

connections; support 

anchorage to building 

structure

(3.5.1-55)

Loss of material 

due to boric acid 

corrosion

Boric Acid 

Corrosion Program

No Boric Acid

Corrosion 

Program

Consistent with the 

GALL Report

Groups B1.1, B1.2, 

and B1.3: sliding 

surfaces

(3.5.1-56)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

and overload; 

fatigue due to 

vibratory and 

cyclic thermal 

loads

ISI (IWF) No ASME Section XI, 

Subsection IWF 

Program

Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Groups B1.1, B1.2, 

and B1.3: vibration 

isolation elements

(3.5.1-57)

Reduction or loss 

of isolation 

function radiation 

hardening, 

temperature, 

humidity, and 

sustained 

vibratory loading

ISI (IWF) No Not applicable Not applicable

(See SER 

Section 3.5.2.1.1)

Galvanized steel and 

aluminum support 

members, welds, 

bolted connections, 

and support 

anchorage to building 

structure exposed to 

air-indoor 

uncontrolled

(3.5.1-58)

None None Not applicable None Consistent with the 

GALL Report

Stainless steel 

support members, 

welds, bolted 

connections, and 

support anchorage to 

building structure

(3.5.1-59)

None None Not applicable None Consistent with the 

GALL Report

The staff‘s review of the structures and component supports 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 structures and component supports is documented in 

SER Section 3.0.3.

3.5.2.1 AMR Results That Are 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 structures and component supports components:

● ASME Section XI, Subsection IWE Program

● ASME Section XI, Subsection IWF Program

● Bolting Integrity Program

● Boric Acid Corrosion Program

● Buried Piping and Tanks Inspection Program

● External Surfaces Monitoring Program

● Fire Protection Program
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● Primary Water Chemistry Program

● Reactor Containment Leakage Testing 10 CFR 50, Appendix J Program

● Structures Monitoring Program

● Work Control Process Program

LRA Tables 3.5.2-1 through 3.5.2-15 summarize AMRs for the structures and component 

supports 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 and for which it does not recommend further evaluation, the staff performed an 

audit and review to determine 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 Report 

AMP. The staff reviewed these line items to verify consistency with the GALL Report and the 

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 Report AMP. The staff reviewed these line items to verify consistency with the GALL 

Report and verified that the identified exceptions to the GALL Report AMPs have been reviewed 

and accepted. The staff also determined whether the applicant‘s AMP was consistent with the 

GALL Report 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 the GALL 

Report component, is consistent with the GALL Report for material, environment, and aging 

effect. In addition, the AMP is consistent with the GALL Report 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 a different component in the GALL Report with the same 

material, environment, aging effect, and AMP as the component under review. The staff 

reviewed 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 the GALL 

Report component, is consistent with the GALL Report for material, environment, and aging 

effect. In addition, the AMP takes some exceptions to the GALL Report AMP. The staff reviewed 

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 whether 

the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The staff 

also determined whether the applicant‘s AMP was consistent with the GALL Report 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 reviewed these line items 

to verify consistency with the GALL Report. The staff also determined whether the credited AMP 
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would manage the aging effect consistently with the GALL Report AMP and whether the AMR 

was valid for the site-specific conditions.

The staff 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 

SCs support 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 3.5.1, 

the applicant‘s references to the GALL Report are acceptable and no further staff review is 

required, with the exception of the following AMRs that the applicant had identified were 

consistent with the AMRs of the GALL Report and for which the staff determined were in need 

of additional clarification and assessment. The staff‘s evaluations of these AMRs are provided in 

the subsections that follow. 

3.5.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.5.1, items 5, 8, 11, 13, 19, 20, 21, and 49, the applicant stated that the 

corresponding AMR items in the GALL Report are not applicable because these items are only 

applicable to particular components in BWR reactor designs, and KPS is a 

Westinghouse-designed PWR facility. The staff confirmed that the stated AMR items in the 

GALL Report are only applicable to BWR-designed facilities and are not applicable to the LRA.

LRA Table 3.5.1, items 48 and 57 are identified as ―Not Applicable‖ since the component, 

material, and environment combination does not exist within the scope of license renewal at 

KPS. 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 within the scope of license renewal. Since KPS does not have the 

component, material, and environment combination for these Table 1 items, the staff finds that 

these AMRs are not applicable.

3.5.2.1.2 Loss of Material for Carbon Steel Exposed to an Indoor Uncontrolled Air Environment

In LRA Tables 3.5.2-2, 3.5.2-13, and 14, the applicant proposed to manage loss of material for 

carbon steel exposed to an indoor uncontrolled air environment by using the Fire Protection or 

the External Surfaces Monitoring programs. The AMR line items cite generic note E, which 

indicates that a different AMP is credited in the GALL Report.

The staff reviewed the AMR line and determined that the component type, material, 

environment, and aging effect are consistent with the corresponding line of the GALL Report; 

however, where the GALL Report recommends GALL AMP XI.S6, ―Structures Monitoring 

Program,‖ the applicant has proposed using the Fire Protection or the External Surfaces 

Monitoring programs (SER Sections 3.0.3.2.8 and 3.0.3.2.7, respectively). The staff was not 

clear how the above programs satisfy the criteria of the Structures Monitoring Program. 

Therefore, the staff issued RAI 3.5.2.2.2.6-1 dated August 28, 2009, requesting that the 

applicant explain how the above mentioned AMPs meet or exceed the inspection 

recommendations of the Structures Monitoring Program. By letter dated September 28, 2009, 

the applicant explained that the External Surfaces Monitoring and Fire Protection programs 
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meet or exceed the inspection requirements of the GALL Report recommended Structures 

Monitoring Program. Additional information was also included in the response to RAI 3.5.2.3-5, 

dated September 28, 2009. A more detailed discussion and review of the applicant‘s response 

is contained in SER Section 3.5.2.2.2.6.

On the basis of its review of the AMR results and the RAI as described in the preceding 

paragraphs, and its comparison of the applicant‘s results to corresponding recommendations in 

the GALL Report, the staff finds the applicant has addressed the AERMs adequately, as 

recommended by the GALL Report. The staff finds that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.3 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 Structures Monitoring Program. During 

its review, the staff noted that in the AMP for the AMR results line that points to LRA 

Table 3.5.1, item 3.5.1-43, the applicant included a reference to note E for five groups, which 

states, ―The Fire Protection Program is utilized in addition to the Structures Monitoring Program 

to examine masonry walls for the specific masonry walls identified in the Fire Protection 

Program.‖

The staff reviewed the AMR line items referenced to note E and determined that the component 

type, material, environment, and aging effect are consistent with the corresponding line of the 

GALL Report; however, where the GALL Report recommends GALL AMP XI.S6, ―Structures 

Monitoring Program,‖ the applicant has proposed using the Fire Protection Program. The 

applicant stated that the AMR result line items that reference LRA Table 3.5.1, item 3.5.1-43 are 

also listed as fire barriers that are in the scope for 10 CFR 54.4(a)(2) criterion and, therefore, 

the Fire Protection Program was also credited. The Fire Protection Program and Structures 

Monitoring Program perform visual inspections to examine masonry walls 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, in conjunction with the Structures Monitoring Program, to be acceptable.

On the basis of its review of AMR result lines, as described in the preceding paragraphs, and its 

comparison of the applicant‘s results to corresponding recommendations in the GALL Report, 

the staff finds that the applicant addressed the AERMs adequately, as recommended by the 

GALL Report.

3.5.2.1.4 Increase in Porosity and Permeability, Cracking, and Loss of Material Due to 

Aggressive Chemical Attack

In LRA Table 3.5.2-1, the applicant proposed to manage increase in porosity and permeability, 

cracking, and loss of material (spalling, scaling) due to aggressive chemical attack in an 

inaccessible soil environment by using the Structures Monitoring Program. The AMR line item 

cites generic note E, which indicates that a different AMP is credited in the GALL Report.

The staff reviewed the AMR line and determined that the component type, material, 

environment, and aging effect are consistent with the corresponding line of the GALL Report; 

however, where the GALL Report recommends GALL AMP XI.S2, ―ASME Section XI, 
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Subsection IWL,‖ the applicant has proposed using the Structures Monitoring Program. The 

staff confirmed that the Structures Monitoring Program conducts appropriate opportunistic visual 

inspections for the above aging effects when the concrete is exposed for any reason. Therefore, 

the staff finds the applicant‘s AMR results to be acceptable. In addition, the concrete being 

inspected does not serve a containment pressure-retaining function; therefore, the staff agrees 

that the Structures Monitoring Program is the appropriate AMP.

On the basis of its review of the AMR results and its comparison of the applicant‘s results to 

corresponding recommendations in the GALL Report, the staff finds that the applicant 

addressed the AERMs appropriately, as recommended by the GALL Report. The staff finds that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.5.2.1.5 Loss of Material, Pitting, and Crevice Corrosion

LRA Table 3.5.2-14 credits the External Surfaces Monitoring Program for junction, terminal, and 

pull boxes of the material, environment, and aging effect (MEA) combination stainless steel or 

steel (M), air-indoor (E), and loss of material, pitting, and crevice corrosion (AERM). 

The applicant applied industry standard note E, which indicates that the above items are 

consistent with the GALL Report for component, material, environment, and aging effect, but a 

different AMP is credited or the GALL Report identifies a plant-specific AMP.

The GALL Report recommends the Structures Monitoring Program for the same MEA 

combination. The applicant‘s External Surfaces Monitoring Program does not monitor the inside 

of the components and does not include stainless steel. Also, the inspection frequency and 

sampling method for these components are not clear in the applicant‘s proposed program. By 

letter dated August 28, 2009, the staff issued RAI 3.5.2.3-5 requesting that the applicant justify 

the reason for using the External Surfaces Monitoring Program for managing the aging effect of 

loss of material, pitting, and crevice corrosion of junction, terminal, and pull boxes.

In its response dated September 28, 2009, the applicant stated that the External Surfaces 

Monitoring Program requires comprehensive visual inspections during both normal operation 

and refueling outages. The frequency of inspection is based on the availability and history, but 

they are performed at least once during each refueling cycle or during other major maintenance 

outages, which are more frequent than the 5-year interval of the Structures Monitoring Program. 

In response to RAI B2.1.10-1, by letter dated August 17, 2009, the applicant stated that it would 

add an exception to the recommendation of GALL AMP XI.M36 to manage aging of stainless 

steel, aluminum, copper, and elastomer. The applicant further stated that similar to the 

Structures Monitoring Program, the External Surfaces Monitoring Program manages the loss of 

material of steel or stainless steel by visual inspection; and the scope of the program element 

allows managing the loss of material from internal surfaces, for situations in which material and 

environment combinations are the same for internal and external surfaces such that external 

surface conditions are representative of internal surface conditions. In its RAI response, the 

applicant further stated that indications of degradation are addressed through the corrective 

action program and if needed, the corrective action program initiates further inspection, 

including inside the components.

The staff finds the applicant‘s response to the RAI acceptable because the External Surfaces 

Monitoring Program meets or exceeds the requirements of the Structures Monitoring Program in 
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relation to managing the aging effect of loss of material, pitting, and crevice corrosion of 

junction, terminal, and pull boxes. The staff‘s concern described in RAI 3.5.2.3-5 is resolved.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

structures will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.6 Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers

In LRA Table 3.5.2-14, for items that reference Table 3.5-1, item 3.5.1-44, and note E, the 

applicant credited the Fire Protection Program for managing loss of sealing due to deterioration 

of elastomer seals in an air-indoor uncontrolled environment.

The staff reviewed the AMR results discussed above and determined that the component type, 

material, environment, and aging effect are consistent with the corresponding line of the GALL 

Report; however, the GALL Report line items that address this AERM (III.A6-12) identify GALL 

AMP XI.S6, ―Structures Monitoring Program,‖ as the appropriate AMP. The staff‘s review of the 

Structures Monitoring Program and Fire Protection Program is documented in SER 

Section 3.0.3. The recommended GALL Report AMP proposes to manage aging through the 

use of visual inspections. The staff reviewed the applicant‘s use of the Fire Protection Program 

and finds it acceptable because it uses equivalent visual inspections on a shorter interval than 

the GALL Report recommended Structures Monitoring Program. Since the applicant has 

committed to an AMP which is equivalent to the GALL Report recommended AMP, the staff 

finds these AMR results to be acceptable.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.7 Loss of Material Due to Pitting and Crevice Corrosion

LRA Tables 3.5.2-1 and 3.5.2-11 credit the Structures Monitoring Program for managing aging 

of containment sumps and trash grill anchorages in the intake structure with the MEA 

combination of stainless steel, raw water, and loss of material due to pitting, crevice, and 

microbiologically-influenced corrosion (AERM). 

The applicant references GALL Report item 3.3.1-80 and industry standard note E, which 

indicate that the above items are consistent with the GALL Report for component, material, 

environment, and aging effect, but a different AMP is credited.

The GALL Report line item recommends GALL AMP XI.M20, ―Open-Cycle Cooling Water 

System,‖ for the same MEA combination. The GALL Report AMP recommends using visual 

inspections to manage this MEA combination. The staff confirmed that the Structures Monitoring 

Program conducts periodic visual inspections with an appropriate inspection frequency for the 

above MEA combination. The staff finds the applicant is crediting an AMP which includes the 

recommended inspections and, therefore, the staff finds the applicant‘s AMR results acceptable. 

The staff concludes that the applicant has demonstrated that the effects of aging for these 

structures will be adequately managed so that their intended functions will be maintained 
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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 That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended

In LRA Section 3.5.2.2, the applicant further evaluated aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports components, and 

provided information concerning how it will manage aging effects in the following three areas:

 (1) PWR containment:

● 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

 (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
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● aging of supports not covered by the Structures Monitoring Program

● cumulative fatigue damage due to cyclic loading

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

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 Pressurized Water Reactor Containment

The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1, which 

addresses several areas:

Item 1, Aging of Inaccessible Concrete Areas. LRA Section 3.5.2.2.1.1 states that the RCV is a 

steel structure supported on a foundation basemat. The foundation basemat, including concrete 

fill, is a below-grade inaccessible concrete area that is supported on soil. The LRA also states 

that the Structures Monitoring Program requires an examination of below-grade concrete 

whenever it is exposed by excavation. 

The staff reviewed LRA Section 3.5.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.1.1, 

which states that corrosion of embedded steel could occur in inaccessible areas of concrete and 

steel containments. The existing program relies on ASME Section XI, Subsection IWL to 

manage these aging effects. However, the GALL Report recommends further evaluation of 

plant-specific programs to manage aging effects for inaccessible areas if the environment is 

aggressive.

Since the KPS containment is a free standing steel vessel, no KPS concrete serves a 

containment pressure-retaining function. Therefore, the concrete does not need to be evaluated 

in this section. SER Section 3.5.2.2.2.2 documents the staff‘s review of the applicant‘s 

evaluation of aging of inaccessible concrete areas, including the containment basemat which 

provides structural support. 

Item 2, 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 applicant stated in 

LRA Section 3.5.2.2.1.2 that the building structures are founded on stiff to hard silty clays. The 

applicant also stated that building settlement readings have been measured and recorded 

periodically since plant construction. No significant variations in building settlement have been 

observed. The applicant also stated that a dewatering system was not used and there is no 

porous concrete below any foundation. The applicant further stated that the Structures 

Monitoring Program is used to inspect for visual cracks and distortion and that settlement 

readings are taken every 5 years.

The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2, 

which states that the cracks and distortion due to increased stress levels from settlement could 

occur in concrete and steel containments. Also, reduction of foundation strength, cracking, and 

differential settlement due to erosion of porous concrete subfoundations could occur in all types 

of containments. The existing program relies on the Structures Monitoring Program to manage 
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these aging effects. SRP-LR Section 3.5.2.2.1.2 also states that the GALL Report recommends 

no further evaluation if this activity is within the scope of the applicant‘s Structures Monitoring 

Program.

The Structures Monitoring Program, described in LRA Section B2.1.31, is an existing program 

that is consistent, with enhancements, with GALL AMP XI.S6, ―Structures Monitoring Program.‖ 

The staff‘s review of the applicant‘s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff noted that the applicant conservatively elected to use the 

Structures Monitoring Program to monitor the above-grade exposed containment concrete for 

the aging effect of cracking and distortion due to settlement. However, the staff was unable to 

verify the applicant‘s claim that no significant variations in building settlement have been 

observed and that the settlement readings are taken every 5 years. Therefore, on 

August 28, 2009, the staff issued RAI 3.5.2.2.1.2-1 requesting that the applicant provide this 

information for the staff to review. In its response dated September 28, 2009, the applicant 

stated that the building settlement readings are currently taken every 5 years at eight detection 

points. Variations in readings greater than plus or minus 0.050 inches per year are reported to 

the engineering group for review and evaluation. The applicant also provided a table that shows 

the latest gauge readings, recorded in August 2002 and November 2007. The average 

settlement per year is not significant when compared to the acceptance criteria 

(0.012 vs. 0.050 inches per year). 

On the basis of its review, the staff finds the applicant‘s response acceptable because the 

average settlement per year is not significant when compared to the acceptance criteria 

(0.012 vs. 0.050 inches per year). The staff also finds that the applicant‘s Structures Monitoring 

Program includes activities that are consistent with the recommendations in the GALL Report, 

and 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. Therefore, the staff finds that no further evaluation is 

required. 

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.5.2.2.1.2 criteria. For those 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 the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 3, Reduction of Strength and Modulus of Concrete Structures Due to Elevated 

Temperature. LRA Section 3.5.2.2.1.3 states that the RCV basemat and concrete fills are the 

only elements required to be addressed in this section. The applicant stated that neither of 

these elements is exposed to an environment that exceeds the elevated temperature limits 

(150 °F for general areas and 200 °F for local areas). 

The staff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3, 

which recommends further evaluation of plant-specific AMPs if any portion of the concrete 

containment components exceeds the specified temperature limits of 150 °F for general areas 

and 200 °F for local areas.

The staff finds the applicant‘s evaluation, that this aging effect is not applicable, acceptable 

because the concrete remains below the allowable temperature limits. 
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Item 4, Loss of Material Due to General, Pitting, and Crevice Corrosion. In LRA 

Section 3.5.2.2.1.4, the applicant stated that the RCV is a steel shell structure with a 

hemispherical dome and ellipsoidal bottom. The applicant also stated that the lower portion of 

the RCV is embedded by internal and external concrete. The applicant further stated that the 

RCV is housed within the shield building. The applicant stated that concrete is designed in 

accordance with ACI 318-63, ―Building Code Requirements for Reinforced Concrete,‖ and ACI 

201.2R-77, which provide a good quality, dense, well-cured, and low permeability concrete. The 

applicant further stated that loss of material due to general, pitting, and crevice corrosion is 

managed by the ASME Section XI, Subsection IWE and Reactor Containment Leakage Testing 

10 CFR 50, Appendix J programs. Therefore, the applicant concluded that loss of material due 

to corrosion is not expected. 

The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LR Section 3.5.2.2.1.4, 

which states that loss of material due to general, pitting, and crevice corrosion could occur in 

steel elements of accessible and inaccessible areas for all types of PWR and BWR 

containments. SRP-LR Section 3.5.2.2.1.4 further states that the existing program relies on the 

ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J programs to manage loss 

of material due to general, pitting, and crevice corrosion. However, the staff was unable to verify 

the applicant‘s statement that the KPS reactor containment building concrete in contact with the 

steel shell is designed in accordance with ACI 318-63 and ACI 201.2R-77 specifications. 

Therefore, on August 28, 2009, the staff issued RAI 3.5.2.2.1.4-1 requesting that the applicant 

provide this information for the staff to review. In its response dated September 28, 2009, the 

applicant stated that the concrete mixes were designed with water-cement ratios that ranged 

between 0.41 to 0.52 and air entrained between 3 percent and 7 percent. A more detailed 

discussion of the staff‘s review of the equivalence of KPS concrete to the ACI 201.2R-77 

recommendations is documented in SER Sections 3.5.2.2.2.2.1 and 3.5.2.2.2.2.2.

The staff finds the applicant‘s response acceptable because the concrete mixes were designed 

with water-cement ratios and air entrainment within the limit of ACI 318-63, ―Building Code 

Requirements for Reinforced Concrete,‖ recommendation. Therefore, the staff agrees that no 

additional plant-specific program is required for corrosion in inaccessible areas.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

the criteria of SRP-LR Section 3.5.2.2.1.4. For those items that apply to LRA 

Section 3.5.2.2.1.4, the staff determined that the LRA is consistent with the GALL Report and 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 5, Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.5 states that the RCV is not a prestressed concrete structure and, therefore, 

this item is not applicable. 

The staff finds the applicant‘s evaluation, that this aging effect is not applicable, acceptable on 

the basis that the KPS containment is a free standing steel vessel with no prestressed concrete.

Item 6, Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states that there are no fatigue 

analyses in the CLB applicable to penetrations (including penetration sleeves, dissimilar metal 

welds, and penetration bellows). Therefore, cumulative fatigue damage of penetrations is not a 

TLAA as defined in 10 CFR 54.3.
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SRP-LR Section 3.5.3.2.1.6 states that if included in the CLB, fatigue analyses of suppression 

pool steel shells and penetrations 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. TLAAs are 

required to be evaluated in accordance with 10 CFR 54.21(c).

The staff confirmed that cumulative fatigue damage of penetrations is not a TLAA for KPS. A 

further review of the applicant‘s TLAA for the containment vessel and penetrations is 

documented in SER Section 4.6.

Item 7, Cracking Due to Stress-Corrosion Cracking. LRA Section 3.5.2.2.1.7 states that SCC is 

applicable to carbon and low-alloy steel in air only if the fabrication material is high yield 

strength steel. SCC of stainless steel in air is only applicable to sensitized stainless steel that is 

exposed to intermittent wetting. The LRA further states that the RCV penetrations, including 

nozzles, bellows, and dissimilar metal welds, are not fabricated from high yield strength steel 

and the stainless steel materials are not subject to intermittent wetting. Therefore, cracking due 

to SCC does not require aging management since the conditions necessary for SCC do not 

exist.

The staff reviewed LRA Section 3.5.2.2.1.7 against the criteria in SRP-LR Section 3.5.2.2.1.7, 

which states that SCC of stainless steel penetration sleeves and dissimilar metal welds can 

occur in all types of PWR and BWR containments. The existing program relies on the ASME 

Section XI, Subsection IWE and Reactor Containment Leakage Testing 10 CFR Part 50, 

Appendix J programs to manage this aging effect. The GALL Report recommends further 

evaluation of additional appropriate examinations implemented to detect these aging effects.

The staff reviewed LRA Sections 2.4 and 3.5 and confirmed that the applicant‘s LRA does not 

have any AMR results for RCV penetrations that are fabricated from high yield strength steel or 

stainless steel subject to intermittent wetting. The staff also reviewed the USAR and did not find 

any evidence of high yield strength steel or stainless steel containment penetrations exposed to 

intermittent wetting. In addition, the staff reviewed the AMR results to verify that the containment 

penetrations will continue to be examined under the ASME Section XI, Subsection IWE and 

Reactor Containment Leakage Testing 10 CFR Part 50, Appendix J programs during the period 

of extended operation. Based on its review, the staff confirmed that the conditions conducive to 

SCC do not exist for the containment penetrations; therefore, additional examinations to detect 

this aging effect are not required.

Item 8, Cracking Due to Cyclic Loading. LRA Section 3.5.2.2.1.8 states that cracking due to 

cyclic loading is managed by the ASME Code Section XI, Subsection IWE and Reactor 

Containment Leakage Testing 10 CFR 50, Appendix J programs. The applicant also stated that 

Type A and B leakage testing per 10 CFR 50, Appendix J will be adequate to detect leakage.

The staff reviewed LRA Section 3.5.2.2.1.8 against the criteria in SRP-LR Section 3.5.2.2.1.8, 

which 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 for all types of PWR and BWR containments and 

BWR vent header, vent line bellows, and downcomers. The existing program relies on the 

ASME Section XI, Subsection IWE and Reactor Containment Leakage Testing 10 CFR Part 50, 

Appendix J programs to manage this aging effect. However, VT-3 inspection may not detect fine 

cracks. The GALL Report recommends further evaluation for detection of this aging effect.
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The staff reviewed the applicant‘s USAR and confirmed that KPS containment hot penetrations 

use a two-ply bellows system with a connection between bellows that allows for integrity testing. 

This design allows the Appendix J Type B tests to adequately detect leakage and fine cracks in 

the bellows. The applicant performs Type B tests on the bellows every third refueling outage, or 

approximately every 5 years. Since the design of the containment bellows allows adequate 

Type B testing on an appropriate frequency, the staff finds that the credited AMPs will be 

adequate to detect aging, and no further evaluation is necessary.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet 

SRP-LR Section 3.5.2.2.1.8 criteria. For those items that apply to LRA Section 3.5.2.2.1.8, the 

staff determines that the LRA is consistent with the GALL Report and the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

functions will be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Item 9, Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze-Thaw. LRA 

Section 3.5.2.2.1.9 states that the RCV is totally enclosed within the shield building and the 

foundation basemat. The applicant stated that loss of material due to freeze-thaw is not 

applicable. 

The staff reviewed LRA Section 3.5.2.2.1.9 against the criteria in SRP-LR Section 3.5.2.2.1.9, 

which recommends further evaluation of loss of material due to freeze-thaw for plants with 

concrete containments located in moderate to severe weathering conditions.

The staff finds that the applicant‘s evaluation, that this aging effect is not applicable, is 

acceptable because the containment is a free standing steel vessel. The steel vessel, as 

discussed in LRA Section 2.4.1, is supported directly on a grout base with concrete fill, which is 

enclosed within the shield building and will not experience freeze-thaw cycles. Therefore, loss of 

material due to freeze-thaw is not applicable to this support concrete. 

Item 10, Cracking Due to Expansion and Reaction with Aggregate, and Increase in Porosity and 

Permeability Due to Leaching of Calcium Hydroxide. LRA Section 3.5.2.2.1.10 states that the 

containment foundation basemat is a below-grade inaccessible concrete area supported on soil. 

The applicant stated that the installation of the concrete was in accordance with ACI and ASTM 

specifications and materials at the time of construction, which are in accordance with the 

recommendations in ACI 201.2R-77. The LRA further states that the aggregates complied with 

ASTM C-33, ―Specifications for Concrete Aggregates,‖ and were evaluated for potential alkali 

reactivity and tested to the requirements of ASTM C-227 and ASTM C-289 (for potential 

reactivity) and ASTM C-295, ―Petrographic Examination of Aggregates.‖ Therefore, the 

applicant concluded that aging management is not required.

The staff reviewed LRA Section 3.5.2.2.1.10 against the criteria in SRP-LR Section 3.5.2.2.1.10, 

which states that cracking due to expansion and reaction with aggregate, and increase in 

porosity and permeability due to leaching of calcium hydroxide could occur in concrete elements 

of concrete and steel containments. The GALL Report recommends further evaluation if 

concrete was not constructed in accordance with the recommendations in ACI 201.2R-77.

Since the KPS containment is a free standing steel vessel, no KPS concrete serves a 

containment pressure-retaining function. Therefore, the concrete does not need to be evaluated 

in this section. SER Section 3.5.2.2.2.2 documents the staff‘s review of the applicant‘s 

evaluation of cracking due to expansion and reaction with aggregate, and increase in porosity 
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and permeability due to leaching of calcium hydroxide for the remaining in-scope concrete 

structures. 

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

Item 1, Aging of Structures Not Covered by the Structures Monitoring Program. LRA 

Section 3.5.2.2.2.1 states that the Structures Monitoring, External Surfaces Monitoring, and Fire 

Protection programs are used to inspect the accessible areas for the aging effects and 

mechanisms discussed below. Additional discussion of specific aging effects follows.

The staff reviewed LRA Section 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1, 

which states that the GALL Report recommends further evaluation of certain structure and aging 

effect combinations if they are not covered by the Structures Monitoring Program, 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. 

In addition, SRP-LR Section 3.5.2.2.2.1 states that lock-up due to wear may occur for Lubrite® 

radial beam seats in BWR drywells, RPV support shoes for PWRs with nozzle supports, steam 

generator supports, and other sliding support bearings and sliding support surfaces. The 

existing program relies on the Structures Monitoring Program or the ASME Code Section XI, 

Subsection IWF Program to manage this aging effect. The GALL Report recommends further 

evaluation only for structure-aging effect combinations not within the ASME Code Section XI, 

Subsection IWF or Structures Monitoring programs.

 (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 – The staff reviewed LRA 

Section 3.5.2.2.2.1.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.1, which states 

that the GALL Report recommends further evaluation of certain structure and aging 

effect combinations if they are not covered by the Structures Monitoring Program. 

The applicant stated in the LRA that the Structures Monitoring Program is used to 

inspect the accessible areas for the aging mechanisms associated with cracking, loss of 

bond, and loss of material (spalling, scaling) due to corrosion of embedded steel for 

Groups 1-5, 7, and 9 structures.

Through a review of the LRA, the staff determined that the cracking, loss of bond, and 

loss of material (spalling, scaling) due to corrosion of embedded steel for Groups 1-5, 7, 

and 9 structures are included within the Structures Monitoring Program by the applicant. 

Therefore, the staff agrees that the criteria of SRP-LR Section 3.5.2.2.2.1.1 have been 

met, and no further evaluation is required. The staff‘s review of the Structures Monitoring 

Program is documented in SER Section 3.0.3.2.18.
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 (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 – The applicant 

stated in the LRA that increase in porosity and permeability, cracking, and loss of 

material (spalling, scaling) due to aggressive chemical attack for accessible concrete 

areas of Groups 1-5, 7, and 9 structures is managed by the Structures Monitoring 

Program. 

The staff confirmed that Groups 1-5, 7, and 9 structures subject to this AMR are all 

within the scope of the Structures Monitoring Program. Therefore, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation is 

required. The staff‘s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff‘s reviews for the increase in porosity and permeability, 

cracking, and loss of material (spalling, scaling) due to aggressive chemical attack for 

inaccessible concrete elements of containments and Groups 1-5, 7, and 9 structures are 

documented in SER Sections 3.5.2.2.1.1 and 3.5.2.2.2.2.4, respectively. 

 (3) Loss of Material Due to Corrosion for Groups 1-5, 7, and 8 Structures – The staff 

reviewed LRA Section 3.5.2.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.2.1.3, 

which states that the GALL Report recommends further evaluation of certain structure 

and aging effect combinations if they are not covered by the Structures Monitoring 

Program. 

The applicant stated in the LRA that the Structures Monitoring Program is used to 

inspect the accessible areas for the aging mechanisms associated with loss of material 

due to corrosion for Groups 1-5, 7, and 8 structures.

Through a review of the LRA, the staff determined that the loss of material due to 

corrosion for Groups 1-5, 7, and 8 structures are included within the Structures 

Monitoring Program by the applicant. Therefore, the staff agrees that the criteria of 

SRP-LR Section 3.5.2.2.2.1.3 have been met, and no further evaluation is required. The 

staff‘s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18.

 (4) Loss of Material (Spalling, Scaling) and Cracking Due to Freeze-Thaw for Groups 1-3, 5, 

and 7-9 Structures – The applicant stated in the LRA that loss of material (spalling, 

scaling) and cracking due to freeze-thaw for accessible concrete areas of Groups 1-5, 7, 

and 9 structures is managed by the Structures Monitoring Program. 

The staff confirmed that Groups 1-3, 5, and 7-9 structures subject to this AMR are all 

within the scope of the Structures Monitoring Program. Therefore, the staff finds that the 

criteria of SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation is 

required. The staff‘s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff‘s reviews for the loss of material (spalling, scaling) and 

cracking due to freeze-thaw for concrete elements of containments, and below-grade 

inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures, are documented in 

SER Sections 3.5.2.2.1.9, and 3.5.2.2.2.2.1, respectively. 

 (5) Cracking Due to Expansion and Reaction with Aggregates for Groups 1-5 and 7-9 

Structures – The applicant stated in the LRA that cracking due to expansion and reaction 

with aggregates for accessible concrete areas of Groups 1-5 and 7-9 structures is 

managed by the Structures Monitoring Program. 
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The staff finds that Groups 1-5 and 7-9 structures subject to this AMR are all within the 

scope of the Structures Monitoring Program. Therefore, the staff finds that the criteria of 

SRP-LR Section 3.5.2.2.2.1 have been met, and no further evaluation is required. The 

staff‘s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. The staff‘s reviews for the cracking due to expansion and reaction 

with aggregates for concrete elements of containments and inaccessible areas of 

Groups 1-5 and 7-9 structures are documented in SER Sections 3.5.2.2.1.10 and 

3.5.2.2.2.2.2, respectively. 

 (6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3 

and 5-9 Structures – The staff reviewed LRA Section 3.5.2.2.2.1.6 against the criteria in 

SRP-LR Section 3.5.2.2.2.1.6, which states that the GALL Report recommends further 

evaluation of certain structure and aging effect combinations if they are not covered by 

the Structures Monitoring Program. 

The applicant stated in the LRA that the Structures Monitoring Program is used to 

inspect accessible areas for the aging mechanisms associated with cracking and 

distortion due to increased stress levels from settlement for Groups 1-3 and 5-9 

structures.

Through a review of the LRA, the staff determined that the cracking and distortion due to 

increased stress levels from settlement for Groups 1-3 and 5-9 structures are included 

within the Structures Monitoring Program by the applicant. Therefore, the staff finds that 

the criteria of SRP-LR Section 3.5.2.2.2.1.1 have been met, and no further evaluation is 

required. The staff‘s review of the Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18. 

 (7) Reduction in Foundation Strength, Cracking, Differential Settlement Due to Erosion of 

Porous Concrete Subfoundation for Groups 1-3 and 5-9 Structures – The applicant 

stated in the LRA that reduction in foundation strength, cracking, and differential 

settlement due to erosion of porous concrete subfoundations for Groups 1-3 and 5-9 

structures is not applicable because no porous concrete subfoundation is used below 

any foundation and no dewatering system is installed for control of settlement. 

The staff finds that the applicant‘s evaluation of this aging effect as not applicable is 

acceptable because KPS has no porous concrete subfoundations. 

 (8) Lock-up Due to Wear for Lubrite® Radial Beam Seats in RPV Support Shoes for PWR 

with Nozzle Supports, Steam Generator Supports, and Other Sliding Support Bearings 

and Sliding Support Surfaces – The staff reviewed LRA Section 3.5.2.2.2.1.8 against the 

criteria in SRP-LR Section 3.5.2.2.2.1.8, which states that lock-up due to wear could 

occur for Lubrite®radial beam seats in BWR drywell, RPV support shoes for PWR with 

nozzle supports, steam generator supports, and other sliding support bearings and 

sliding support surfaces. The GALL Report recommends further evaluation only for 

structure and aging effect combinations that are not within the ASME Code Section XI, 

Subsection IWF Program or Structures Monitoring Program.

In LRA Section 3.5.2.2.2.1.8, the applicant stated that lock-up due to wear is not an 

AERM for this material because of the wear resistance inherent in the design of the 

material and the low number of times that movement occurs. However, the applicant 

further stated that Lubrite®plates are included within the Structures Monitoring Program 

and the ASME Section XI, Subsection IWF Program to confirm the absence of AERMs 

for this component. Since the components are included within the scope of the 
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appropriate programs, the staff finds that the criteria of SRP-LR Section 3.5.2.2.2.1.8 

have been met, and no further evaluation is required. The staff‘s review of the Structures 

Monitoring Program and the ASME Section XI, Subsection IWF Program are 

documented in SER Sections 3.0.3.2.18 and 3.0.3.2.2, respectively. 

Based on the programs and analyses discussed above, the staff concludes that the applicant‘s 

programs meet the criteria of SRP-LR Section 3.5.2.2.2.1. For those 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 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 2, 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) Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures.

LRA Section 3.5.2.2.2.2.1 states that KPS is located in a severe weathering area. The 

applicant stated that the concrete structures were designed in accordance with 

ACI 318-63, except for the TSC which was designed in accordance with ACI 318-77 

(a later addition to the building was designed in accordance with ACI 318-2002). The 

applicant also stated that plant documents indicate that concrete mixes were designed 

with water-cement ratios ranging from 0.41 to 0.52 with entrained air content between 

3 percent and 7 percent. The applicant further stated that a review of OE has not 

revealed any freeze-thaw related degradation; however, the Structures Monitoring 

Program will examine exposed portions of below-grade concrete whenever excavation 

occurs.

The staff reviewed LRA Section 3.5.2.2.2.2.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.1, which states that the GALL Report recommends further evaluation 

of this aging effect for inaccessible areas of these structures for plants located in 

moderate to severe weathering conditions.

The GALL Report recommends a water-to-cement ratio between 0.35 and 0.45, while 

the water-to-cement ratio at KPS ranges from 0.41 to 0.52. The staff is unsure how the 

applicant‘s Structures Monitoring Program is addressing the possibility of accelerated 

degradation in the inaccessible concrete due to freeze-thaw that may result from the 

higher water-to-cement ratio. By letter dated August 28, 2009, the staff issued 

RAI 3.5.2.2.2.2.1-1 requesting that the applicant explain what actions will be taken in the 

future to adequately address freeze-thaw degradation in inaccessible concrete areas 

during the period of extended operation.

By letter dated September 28, 2009, the applicant responded and explained that the 

Structures Monitoring Program has been used in the past to inspect and manage loss of 

material and cracking due to freeze-thaw, with no indications of degradation. The 

response also explained that the Structures Monitoring Program will perform 

opportunistic visual inspections on inaccessible concrete whenever exposed. The 

applicant further explained that although the concrete is outside the GALL Report 

water-to-cement ratio and air entrainment limits, the concrete was designed to applicable

ACI standards and meets the intent of ACI 201.2R-77. In addition, the applicant 
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explained that plant-specific OE shows that the ground tends to freeze and remain 

frozen throughout the winter, which reduces the number of freeze-thaw cycles 

experienced by the inaccessible concrete.

The staff reviewed the applicant‘s response and noted that the applicant did not identify 

any concrete degradation that was attributed to freeze-thaw. The staff‘s review also did 

not identify degradation that was attributed to freeze-thaw. The lack of identified 

freeze-thaw degradation in accessible regions provides assurance that freeze-thaw 

degradation has not occurred in inaccessible areas. In addition, the inaccessible areas 

will be inspected under the Structures Monitoring Program when exposed for any 

reason. Since the applicant is performing Structures Monitoring Program inspections for 

the period of extended operation, and concrete degradation has not been attributed to 

freeze-thaw, the staff concludes that the applicant‘s management approach is 

acceptable, even with the water-to-cement ratio above the GALL Report recommended 

limit. 

The GALL Report recommends an air content of 3 percent to 6 percent, while the value 

specified at KPS ranges from 3 percent to 7 percent. The staff noted that ACI 201.2R-77 

states that, ―too little entrained air will not protect cement paste against freezing and 

thawing. Too much air will penalize the strength.‖ This indicates that the upper limit of 

air-entrainment is tied to the strength, and if the necessary strength can be maintained, a 

higher air entrainment value is acceptable. The necessary KPS concrete strength was 

verified during construction with appropriate concrete batch testing; therefore, the 

increased air content provides increased protection against freeze-thaw without 

jeopardizing the concrete strength, and meets the intent of ACI 201.2R-77. In addition, 

as noted above in the RAI discussion, freeze-thaw degradation has not been reported at 

KPS and potential freeze-thaw effects on inaccessible concrete will be assessed under 

the Structures Monitoring Program whenever the concrete becomes accessible for 

inspection due to excavation. The Structures Monitoring Program will continue to inspect 

accessible concrete for indications of degradation due to freeze-thaw. The staff‘s review 

of the Structures Monitoring Program is documented in SER Section 3.0.3.2.18. 

On the basis of its review, including the response to RAI 3.5.2.2.2.2.1-1, the staff finds 

that there is assurance that the aging effect loss of material (spalling, scaling) and 

cracking due to freeze-thaw in below-grade inaccessible concrete areas of Groups 1-3, 

5, and 7-9 structures will be adequately managed during the period of extended 

operation. 

 (2) Cracking due to expansion and reaction with aggregates could occur in below-grade 

inaccessible concrete areas for Groups 1-5 and 7-9 structures. 

LRA Section 3.5.2.2.2.2.2 states that aging management is not required because KPS 

concrete was constructed in accordance with the recommendations contained in 

ACI 201.2R-77. The LRA further states that the aggregates complied with ASTM C-33 

and were tested per ASTM C-227, ASTM C-289, and ASTM C-295.

The staff reviewed LRA Section 3.5.2.2.2.2.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.2, which states that the GALL Report recommends further evaluation 

of inaccessible areas of these groups of structures if concrete was not constructed in 

accordance with the recommendations in ACI 201.2R-77.

GALL Report item III.A1-2 states that ASTM C-295 or ASTM C-227 can be used to 

demonstrate that aggregates are non-reactive. If non-reactive aggregates are used, 
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aging management is not necessary. KPS used both GALL Report recommended ASTM 

standards to demonstrate that non-reactive aggregates were used in KPS concrete. 

Since the aggregates in the KPS concrete are non-reactive, the staff finds that cracking 

due to expansion and reaction with aggregate in below-grade inaccessible concrete 

areas for Groups 1-5 and 7-9 structures is not an aging effect for inaccessible concrete.

On the basis of its review, the staff finds that the aging effect is not significant; therefore, 

no additional plant-specific program is required to manage the aging effect. 

 (3) 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 could occur in below-grade inaccessible concrete areas of 

Groups 1-3, 5, and 7-9 structures.

LRA Section 3.5.2.2.2.2.3 states that the building structures are founded on stiff to hard 

silty clays. Settlement readings have been measured since plant construction and no 

significant variations have been observed. The LRA further states that the Structures 

Monitoring Program requires that settlement readings be taken every 5 years. The 

program is also used to inspect for visual cracks and distortion due to increased stress 

levels from settlement in accessible areas. The LRA also states that no porous concrete 

subfoundations are used below foundations, and de-watering systems are not used at 

KPS.

The staff reviewed LRA Section 3.5.2.2.2.2.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.3, which states that the GALL Report recommends verification of the 

continued functionality of the de-watering system during the period of extended 

operation, if the plant‘s CLB credits a de-watering system. The GALL Report 

recommends no further evaluation if this activity and these aging effects are included in 

the scope of the applicant‘s Structures Monitoring Program.

On the basis of its review, the staff determines 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 in 

below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 structures are not 

plausible aging effects due to the absence of these aging mechanisms. KPS does not 

use a de-watering system, and there are no porous subfoundations on the site. In 

addition, the applicant elected to monitor accessible concrete for the aging effect of 

cracking due to settlement under the Structures Monitoring Program. The Structures 

Monitoring Program also requires settlement measurements to be taken every 5 years. 

On the basis of its review, the staff finds that the aging effects are not significant; 

therefore, no additional plant-specific program is required to manage the aging effects. 

 (4) Increase 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 could occur in below-grade inaccessible 

concrete areas of Groups 1-3, 5, and 7-9 structures.

LRA Section 3.5.2.2.2.2.4 states that the Structures Monitoring Program requires that 

below-grade concrete be examined whenever exposed, and that the program will be 

enhanced to include periodic monitoring of below-grade water chemistry. The LRA 

provides groundwater chemistry values for July 1968, June 1971, and 2006 which meet 

the GALL Report limits for non-aggressive groundwater chemistry. However, the LRA 
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also included chemistry test results for groundwater samples taken in June 2007 and 

March 2008 with chloride values as high as 1,240 ppm, which exceed the limit of 

500 ppm. The LRA attributes these high values to salt used for de-icing during the winter 

months. 

The staff reviewed LRA Section 3.5.2.2.2.2.4 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.4, which states that the GALL Report recommends further evaluation 

of plant-specific programs to manage these aging effects in inaccessible areas of these 

groups of structures if the environment is aggressive.

The GALL Report recommends periodic groundwater inspection for chlorides, sulfates, 

and pH to ensure non-aggressive groundwater chemistries, as well as examination of 

exposed portions of below-grade concrete whenever excavated. The staff noted that the 

applicant‘s Structures Monitoring Program requires examination of exposed portions of 

below-grade concrete, and the program will be enhanced to perform groundwater 

monitoring. Additionally, the Structures Monitoring Program inspects for this aging effect 

on accessible concrete areas. The staff‘s review of the applicant‘s Structures Monitoring 

Program is documented in SER Section 3.0.3.2.18. The staff is unsure how the 

applicant‘s Structures Monitoring Program is addressing the possibility of accelerated 

degradation in the inaccessible concrete due to the high chloride values in the 

groundwater. By letter dated July 13, 2009, the staff issued RAI B.2.1.31-3 requesting 

that the applicant describe past and present groundwater monitoring activities, including 

results, and to explain the technical basis and acceptance criteria of the monitoring 

program.

By letter dated August 17, 2009, the applicant restated the results included in the LRA, 

as well as the average value of samples taken since June 2007, from tritium assessment 

wells located near plant structures. The applicant explained that the elevated chloride 

levels were obtained from wells located near paved plant areas that are heavily salted in 

the winter months. The applicant further explained that the highest average chloride 

level was 640 ppm, which is only marginally above the GALL Report limit of 500 ppm. 

The applicant explained that the 500 ppm limit was conservative and that a value of 

640 ppm was acceptable. The applicant further explained that a waterproofing 

membrane had been installed on below-grade concrete during initial construction, which 

should minimize direct contact between concrete and groundwater.

The staff reviewed the response and required additional information in order to complete 

its review. By letter dated November 20, 2009, the staff issued follow-up 

RAI B.2.1.31-3a, requesting that the applicant demonstrate that the current chloride 

levels are not causing degradation. The applicant responded by letters dated December 

28, 2009, and February 15, 2010. In its responses, the applicant explained its plans to 

reduce the chloride levels in the groundwater, as well as commitments to take core 

samples of the inaccessible concrete. The concrete core samples would verify that the 

aggressive groundwater environment had not caused concrete degradation. The staff 

found the applicant‘s responses acceptable because they explained how the applicant 

would ensure that the aggressive environment had not caused degradation prior to and 

during the period of extended operation. This issue is discussed in more detail in the 

staff‘s review of the Structures Monitoring Program (SER Section 3.0.3.2.18).

On the basis of its review, the staff finds that there is assurance that the aging effect 

increase 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, 
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scaling) due to corrosion of embedded steel in below-grade inaccessible concrete areas 

of Groups 1-3, 5, and 7-9 structures will be adequately managed during the period of 

extended operation.

 (5) Increase in porosity and permeability, and loss of strength due to leaching of calcium 

hydroxide could occur in below-grade inaccessible concrete areas of Groups 1-3, 5, and 

7-9 structures.

LRA Section 3.5.2.2.2.2.5 states that KPS concrete was constructed in accordance with 

ACI and ASTM specifications and materials at the time of construction, which are in 

accordance with the recommendations in ACI 201.2R-77. 

The staff reviewed LRA Section 3.5.2.2.2.2.5 against the criteria in SRP-LR 

Section 3.5.2.2.2.2.5, which states that the GALL Report recommends further evaluation 

of this aging effect for inaccessible areas of Groups 1-3, 5, and 7-9 structures if concrete 

was not constructed in accordance with the recommendations in ACI 201.2R-77 for a 

quality concrete with low water-to-cement ratio (0.35-0.45), smaller aggregate, long 

curing period, adequate air entrainment (3 percent to 6 percent), and thorough 

consolidation. The staff finds that KPS concrete meets the intent of ACI 201.2R-77. A 

more detailed discussion of the staff‘s review of the equivalence of KPS concrete to the 

ACI 201.2R-77 recommendations is documented in SER Sections 3.5.2.2.2.2.1 and 

3.5.2.2.2.2.2. In addition, the Structures Monitoring Program will manage this aging 

effect in accessible areas, as well as inaccessible areas, when exposed for any reason. 

On the basis of its review, including the response to RAI 3.5.2.2.2.2.1-1, the staff finds 

that increase in porosity and permeability, and loss of strength due to leaching of 

calcium hydroxide in below-grade inaccessible concrete areas of Groups 1-3, 5, and 7-9 

structures is not a plausible AERM because the design and construction of concrete 

structures in accordance with ACI codes enhances resistance to leaching.

Based on the programs and analyses discussed above, including the RAI responses, the staff 

concludes that the applicant has met the criteria of SRP-LR Section 3.5.2.2.2.2. 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 the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Item 3, Reduction of Strength and Modulus of Concrete Structures Due to Elevated 

Temperature. LRA Section 3.5.2.2.2.3 states that none of the concrete elements of Groups 1-5 

exceeds the temperature limits of 150 °F for general areas or 200 °F for local areas. 

The staff reviewed LRA Section 3.5.2.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.2.3, 

which states that reduction of strength and modulus of concrete due to elevated temperatures 

may occur in PWR and BWR concrete structures of Groups 1-5. 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 °F, except for local areas allowed to have 

temperatures that do not exceed 200 °F.

The staff finds the applicant‘s evaluation acceptable since this aging effect is not applicable on 

the basis that KPS Groups 1-5 concrete does not experience temperatures above the limits.
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Item 4, 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) Increase 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 could occur in below-grade inaccessible 

concrete areas of Group 6 structures. 

LRA Section 3.5.2.2.2.4.1 states that the above aging effects for concrete in inaccessible 

areas are managed by the Structures Monitoring Program, which incorporates the 

attributes of GALL AMP XI.S7, ―RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants.‖ The LRA also states that the Structures 

Monitoring Program requires examination of below-grade concrete whenever exposed 

and the program will be enhanced to include periodic monitoring of below-grade water 

chemistry.

The staff reviewed LRA Section 3.5.2.2.2.4.1 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.1, which states that the GALL Report recommends further evaluation 

of plant-specific programs to manage these aging effects in inaccessible areas if the 

environment is aggressive. The staff‘s review for the increase in porosity and 

permeability, cracking, and loss of material (spalling, scaling) due to aggressive 

chemical attack and corrosion of embedded steel for inaccessible concrete elements is 

documented in SER Section 3.5.2.2.2.2.4. The staff‘s review of the applicant‘s 

Structures Monitoring Program is documented in SER Section 3.0.3.2.18.

On the basis of its review, as discussed in SER Section 3.5.2.2.2.2.4, the staff finds that 

there is assurance that the aging effect, increase 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 in 

below-grade inaccessible concrete areas of Group 6 structures will be adequately 

managed during the period of extended operation. 

 (2) Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in 

below-grade inaccessible concrete areas of Group 6 structures. 

LRA Section 3.5.2.2.2.4.2 states that KPS is located in a severe weathering area. The 

applicant stated that the concrete structures were designed in accordance with 

ACI 318-63, except for the TSC which was designed in accordance with ACI 318-77 

(a later addition to the building was designed in accordance with ACI 318-2002). Plant 

documents indicate that concrete mixes were designed with water-cement ratios ranging 

from 0.41 to 0.52, with entrained air content between 3 percent and 7 percent. The 

applicant further stated that a review of OE has not revealed any freeze-thaw related 

degradation; however, the Structures Monitoring Program will examine exposed portions 

of below-grade concrete whenever excavation occurs.

The staff reviewed LRA Section 3.5.2.2.2.4.2 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.2, which states that the GALL Report recommends further evaluation 

of this aging effect for inaccessible areas for plants located in moderate to severe 

weathering conditions (weathering index greater than 100 day-inch/year). The staff‘s 

review for the loss of material (spalling, scaling) and cracking due to freeze-thaw for 

inaccessible concrete elements, including the applicant‘s further evaluation, is 

documented in SER Section 3.5.2.2.2.2.1. The staff‘s review of the applicant‘s 

Structures Monitoring Program is documented in SER Section 3.0.3.2.18.
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On the basis of its review, including the response to RAI 3.5.2.2.2.2.1-1, the staff finds 

that there is assurance that the aging effect of loss of material (spalling, scaling) and 

cracking due to freeze-thaw in below-grade inaccessible concrete areas of Group 6 

structures will be adequately managed during the period of extended operation. 

 (3) Cracking due to expansion and reaction with aggregates and increase in porosity and 

permeability, and loss of strength due to leaching of calcium hydroxide could occur in 

below-grade inaccessible reinforced concrete areas of Group 6 structures. 

LRA Section 3.5.2.2.2.4.3 states that KPS concrete was constructed in accordance with 

the recommendations contained in ACI 201.2R-77. LRA Table 3.5.1, items 3.5.1-36 and 

3.5.1-37 state that no aging management is required for inaccessible areas if the 

concrete was constructed in accordance with ACI 201.2R-77. The LRA further states 

that the aggregates complied with ASTM C-33 and were tested per ASTM C-227, ASTM 

C-289, and ASTM C-295.

The staff reviewed LRA Section 3.5.2.2.2.4.3 against the criteria in SRP-LR 

Section 3.5.2.2.2.4.3, which states that the GALL Report recommends further evaluation 

of inaccessible areas if concrete was not constructed in accordance with the 

recommendations in ACI 201.2R-77. The staff‘s review for cracking due to expansion 

and reaction with aggregates for inaccessible concrete elements, including the review of 

the applicant‘s concrete, is documented in SER Section 3.5.2.2.2.2.2. The staff‘s review 

of the applicant‘s Structures Monitoring Program is documented in SER 

Section 3.0.3.2.18.

Since the applicant‘s concrete aggregate was tested in accordance with the GALL 

Report recommended ASTM standards, as discussed in SER Section 3.5.2.2.2.2.2, the 

staff finds that further evaluation is not necessary, and the criteria of SRP-LR 

Section 3.5.2.2.2.4.3 have been met for cracking due to expansion and reaction with 

aggregates.

The staff‘s review for an increase in porosity and permeability, and loss of strength due 

to leaching of calcium hydroxide for inaccessible concrete elements is documented in 

SER Section 3.5.2.2.2.2.5. The staff‘s review of the applicant‘s Structures Monitoring 

Program is documented in SER Section 3.0.3.2.18.

Since the concrete was constructed in accordance with ACI 201.2R-77, as discussed in 

SER Section 3.5.2.2.2.2.5, the staff finds that further evaluation is not necessary, and 

the criteria of SRP-LR Section 3.5.2.2.2.4.3 have been met for an increase in porosity 

and permeability, and loss of strength due to leaching of calcium hydroxide.

Based on the programs discussed above, including RAI responses, the staff concludes that the 

applicant has met the criteria of SRP-LR Section 3.5.2.2.2.4. 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 the applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended functions 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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Item 5, Cracking Due to Stress-Corrosion Cracking and Loss of Material Due to Pitting and 

Crevice Corrosion. In LRA Section 3.5.2.2.2.5, the applicant stated that tanks are evaluated for 

aging management in their respective mechanical systems. 

The staff reviewed LRA Section 3.5.2.2.2.5 against the criteria in SRP-LR Section 3.5.2.2.2.5, 

which states that cracking due to SCC and loss of material due to pitting and crevice corrosion 

could occur for 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.

During the review, the staff noticed that for GALL AMP XI.M29, ―Aboveground Steel Tanks,‖ the 

applicant stated that the AMRs did not identify the need for this AMP. The staff was unable to 

verify whether or not the applicant has any stainless steel tank liners exposed to standing water 

for Groups 7 and 8. Therefore, on August 28, 2009, the staff issued RAI 3.5.2.2.1.5-1 requesting 

that the applicant provide this information for the staff to review. In its response dated 

September 28, 2009, the applicant stated that there are no aboveground tanks with stainless 

steel liners exposed to standing water at KPS. 

On the basis of its review, the staff finds that cracking due to SCC and loss of material due to 

pitting and crevice corrosion that could occur for Groups 7 and 8 stainless steel tank liners 

exposed to standing water are not applicable to KPS. Therefore, the staff agrees that no 

additional plant-specific program is required.

Based on the programs identified above, the staff concludes that the applicant‘s programs meet

the criteria of SRP-LR Section 3.5.2.2.2.5. For those line items that apply to LRA 

Section 3.5.2.2.2.5, the staff determines that the LRA is consistent with the GALL Report and 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Item 6, Aging of Supports Not Covered by the Structures Monitoring Program. LRA 

Section 3.5.2.2.2.6 states that the Structures Monitoring Program is used to manage the aging 

effects for Groups B1 through B5 supports and miscellaneous structural commodities, such as 

cabinets and panels.

The staff reviewed LRA Section 3.5.2.2.2.6 against the criteria in SRP-LR Section 3.5.2.2.2.6, 

which recommends further evaluation of the following support and aging effect combinations if 

they are not covered by the Structures Monitoring Program.

 (1) Loss of Material Due to General and Pitting Corrosion for Groups B2 through B5 

Supports – LRA Section 3.5.2.2.2.6 states that the Structures Monitoring Program 

manages the aging effects for Groups B1 through B5 supports and miscellaneous 

structural commodities, such as cabinets and panels. For miscellaneous structural 

commodities, such as junction, terminal, and pull boxes and doors, the External 

Surfaces Monitoring and Fire Protection programs are used.

The staff is not clear how the above programs satisfy the criteria of the Structures 

Monitoring Program. Therefore, the staff issued RAI 3.5.2.2.2.6-1, dated August 28, 

2009, requesting that the applicant explain how the above mentioned AMPs meet or 

exceed the inspection recommendations of the Structures Monitoring Program.
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By response dated September 28, 2009, the applicant explained that both the External 

Surfaces Monitoring and Fire Protection programs require visual inspections to manage 

the loss of material for steel structural SC supports. The applicant stated that these 

visual inspections match the inspections required by the Structures Monitoring Program. 

The applicant further explained that the Structures Monitoring Program requires visual 

examinations be performed at 5-year inspection intervals, while the Fire Protection 

Program requires visual examinations every 18 months, and the External Surfaces 

Monitoring Program requires visual examinations at least once every refueling cycle, 

which is normally between 18 and 24 months. 

The staff reviewed the applicant‘s response and found it acceptable because the 

programs credited by the applicant require similar visual inspections more frequently 

than the GALL Report recommended program. Therefore, since the External Surfaces 

Monitoring and Fire Protection programs meet or exceed the recommendations of the 

GALL Report recommended Structures Monitoring Program, the staff finds that the 

criteria of the SRP-LR Section 3.5.2.2.2.6.1 have been met, and no further evaluation is 

required. The staff‘s review of the Fire Protection and External Surfaces Monitoring 

programs are documented in SER Sections 3.0.3.2.8 and 3.0.3.2.7, respectively.

 (2) Reduction in Concrete Anchor Capacity Due to Degradation of the Surrounding 

Concrete for Groups B1 through B5 Supports – LRA Table 3.5.1, item 3.5.1-40 states 

that reduction in concrete anchor capacity due to local concrete degradation of 

expansion and grouted anchors is managed by the Structures Monitoring Program. In 

LRA Section B2.1.31, the applicant also stated that the Structures Monitoring Program 

manages the aging effect of reduction in concrete anchor capacity due to local concrete 

degradation.

Since the aging effect is covered by the Structures Monitoring Program, the staff finds 

that the criteria of SRP-LR Section 3.5.2.2.2.6.2 have been met, and no further 

evaluation is required. The staff‘s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.18.

 (3) Reduction or Loss of Isolation Function Due to Degradation of Vibration Isolation 

Elements for Group B4 Supports – LRA Table 3.5.1, item 3.5.1-41 states that reduction 

or loss of isolation function due to radiation hardening, temperature, humidity, or 

sustained vibratory loading for vibration isolation elements is managed by the Structures 

Monitoring Program. In LRA Section B2.1.31, the applicant also stated that the 

Structures Monitoring Program manages the aging effect of reduction or loss of isolation 

function for elastomers.

Since the aging effect is covered by the Structures Monitoring Program, the staff finds 

that the criteria of SRP-LR Section 3.5.2.2.2.6.3 have been met, and no further 

evaluation is required. The staff‘s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.18.

Based on the programs and analysis identified above, the staff concludes that the applicant‘s 

programs meet the criteria of SRP-LR Section 3.5.2.2.2.6. For those 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 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended functions 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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Item 7, Cumulative Fatigue Damage Due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that 

there are no fatigue analyses in the CLB applicable to component supports. Therefore, the 

applicant concluded that cumulative fatigue damage of component supports is not a TLAA as 

defined in 10 CFR 54.3. 

The staff reviewed LRA Section 3.5.2.2.2.7 against the criteria in SRP-LR Section 3.5.2.2.2.7, 

which 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, only if 

a CLB fatigue analysis exists. The evaluation of this TLAA is addressed separately in SRP-LR 

Section 4.3.

The staff reviewed the USAR and the LRA and confirmed that there are no fatigue analyses in 

the CLB applicable to component supports. Therefore, the staff finds that cumulative fatigue 

damage of component supports is not a TLAA and the applicant has appropriately addressed 

the criteria of SRP-LR Section 3.5.2.2.2.7.

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 provides the staff‘s evaluation of the applicant‘s QA program.

3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

In LRA Tables 3.5.2-1 through 3.5.2-15, 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 3.5.2-15, 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 

functions 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 Concrete Reactor Containment Vessel Sumps Exposed to Raw Water, Aging Effect of

Cracking, Loss of Bond, and Increase in Porosity and Permeability

According to LRA AMR Table 3.5.2-1, the applicant credited the Structures Monitoring Program 

for aging of the RCV sumps in a raw water environment. The LRA also specifies the sumps as 

part of the pressure boundary. The GALL Report recommends ASME Section XI, Subsection 

IWL/IWE for containment components which are part of the pressure boundary.
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By letter dated October 13, 2009, the staff issued RAI 3.5.2.3-2 requesting that the applicant 

justify why aging effect for RCV sumps are not managed under the ASME Section XI, 

Subsection IWL/IWE Program. In its response dated November 13, 2009, the applicant clarified 

that the pressure boundary function indicated in LRA Tables 2.4.1-1 and 3.5.2-1 for the 

containment sump is considered a system function for water retention and not a structural 

function as pressure boundary. The applicant uses the ASME Section XI, Subsection IWE 

Program for the RCV and its components, such as penetrations, airlocks, and hatches. For all 

the internal structures of the RCV, including the sumps and common basemat, the applicant 

credited the Structures Monitoring Program.

The staff finds the applicant‘s response acceptable because in the RAI response, the applicant 

clarified that the sump is not considered part of the RCV pressure boundary from structural 

consideration and, therefore, the Structures Monitoring Program is suitable for monitoring the 

aging effects for the sump. The staff‘s concern described in RAI 3.5.2.3-2 is resolved.

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 concludes that the applicant has demonstrated that the effects of aging for 

these structures will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.2 Concrete Sumps Exposed to Raw Water, Aging Effect of Cracking, Loss of Bond, and 

Increase in Porosity and Permeability

In LRA Table 3.5.2-2, the applicant recognized the Structures Monitoring Program for shield 

building sumps and trenches of the MEA combination concrete (M); raw water (E); and cracking, 

loss of bond, and loss of material, and corrosion of embedded steel (AERM). Also, there is 

another MEA combination for concrete (M); raw water (E); and increase in porosity and 

permeability, cracking, loss of material (spalling, scaling), and aggressive chemical attack 

(AERM). Additionally, LRA Tables 3.5.2-4, 3.5.2-7, 3.5.2-9, 3.5.2-10, 3.5.2-11, and 3.5.2-12 

credit the Structures Monitoring Program for the same MEA combination.

For the similar combination, the GALL Report items III.A1-4 (T-05) and II.A1-4 (T-05) 

recommend further evaluation if the environment is aggressive; otherwise, the Structures 

Monitoring Program is adequate. 

By letter dated October 13, 2009, the staff issued RAI 3.5.2.3-1 requesting that the applicant: 

 (1) explain the past and present raw water monitoring activities and discuss the results

 (2) indicate which inspection and monitoring criteria of the Structures Monitoring Program

are or will be followed, and if raw water is not monitored, to ensure that the effects of 

aging will be adequately managed so that the intended functions will be maintained 

consistent with the CLB for the period of extended operation

In its response dated November 13, 2009, the applicant stated that it has not performed periodic 

monitoring of raw intake water from Lake Michigan presently or in the recent past. The applicant

further stated that Lake Michigan is a fresh water lake and analysis of lake water samples taken 

in 1971, 2004, and 2006 indicated average results of 8.18 pH, 8.94 ppm chloride, and 
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22.63 ppm sulfate. In addition, the applicant stated that in 2004, an analysis of water samples 

taken from the two deep potable water wells located on site indicated average readings of 

7.5 pH, 34 ppm chloride, and 640 ppm sulfate. Also, the applicant stated that it does not 

conduct periodic monitoring of aggressiveness of water in the drains and sumps. However, 

water collected in the floor drains and sumps is monitored for gamma, tritium, and suspended 

solids. If a high sump level is detected in the RCV, the applicant tests the sump water for boron, 

conductivity, and pH to help determine the leakage source. In normal situations, the water in the 

floor drains and sumps is either from Lake Michigan, potable wells, or treated water systems, 

and all three of these are considered non-aggressive to concrete and steel. Nevertheless, the 

applicant confirmed that identified leaks do not continue for the extensive period of time required 

for degradation of concrete, steel, and other material to occur. For inaccessible below-grade 

concrete, groundwater is periodically monitored under the Structures Monitoring Program. 

However, by letter dated August 17, 2009, in response to RAI B.2.1.31-3, the applicant stated 

that the groundwater samples taken in June 2007; March, July, August, and October 2008; and 

March and June 2009 indicate a chloride range from 34 ppm to 1,240 ppm, while the GALL 

Report limit for chlorides is 500 ppm.

The staff reviewed the responses and required additional information in order to complete its 

review. By letter dated November 20, 2009, the staff issued follow-up RAI B.2.1.31-3a asking 

the applicant to demonstrate that the current chloride levels are not causing degradation. The 

applicant responded by letters dated December 28, 2009, and February 15, 2010. In its 

responses, the applicant explained plans to reduce the chloride levels in the groundwater, as 

well as commitments to take core samples of the inaccessible concrete. The concrete core 

samples would verify that the aggressive groundwater environment had not caused concrete 

degradation. The staff found the applicant‘s responses acceptable because they explained how 

the applicant would ensure that the aggressive environment had not caused degradation prior to 

and during the period of extended operation. In addition, the staff confirmed that the Structures 

Monitoring Program will inspect the accessible concrete structures within the scope of license 

renewal that are exposed to raw water regardless of the water composition. The staff‘s concerns 

described in RAIs 3.5.2.3-1 and B.2.1.31-3 are resolved. This issue is discussed in more detail 

in the staff‘s review of the Structures Monitoring Program (SER Section 3.0.3.2.18).

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 concludes that the applicant has demonstrated that the effects of aging for 

these structures will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.3 Concrete Exposed to Air-Outdoor, Aging Effect of Cracking, Loss of Bond, and 

Increase in Porosity and Permeability

LRA Table 3.5.2-2 credits the Structures Monitoring Program for shield building equipment of 

the MEA combination concrete (M); air-outdoor (E); and increase in porosity and permeability, 

loss of strength, and leaching of calcium hydroxide (AERM). In LRA Tables 3.5.2-3, 3.5.2-4, 

3.5.2-6, 3.5.2-7, 3.5.2-8, 3.5.2-9, and 3.5.2-12, there are other items with the same combination.

The staff evaluated all of the above and found that the applicant‘s Structures Monitoring 

Program is adequate because the GALL Report recommends the Structures Monitoring 

Program for a similar combination in item III.A1-7 (T-02) where the environment is flowing water. 

The staff confirmed that if the Structures Monitoring Program can adequately manage this aging 
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effect of concrete in flowing water, it can also manage the aging effect of concrete in 

air-outdoor. However, by letter dated October 13, 2009, the staff issued RAI 3.5.2.3-3 

requesting that the applicant describe the structures where leaching of calcium hydroxide is 

occurring in the environment of air and explain the possible reason for such leaching.

In its response dated November 13, 2009, the applicant stated that minor leaching of calcium 

hydroxide in an air-outdoor environment has occurred for the main auxiliary transformer walls, 

the concrete masonry wall that forms the back bay of the reserve auxiliary transformer (RAT) 

and turbine building exterior wall, the shield building exterior concrete wall, and the screenhouse 

forebay exterior concrete wall. Furthermore, the applicant stated that in an air-outdoor 

environment, water from rain or melting snow passes through cracks or inadequately prepared 

construction joints, causing leaching of calcium compound from concrete. Efflorescence, a 

surface phenomenon consisting of salt deposits that have been leached from concrete, is an 

aesthetic issue rather than a structural problem, and KPS has conservatively included 

efflorescence due to leaching of calcium hydroxide in an air-outdoor environment.

The staff finds the applicant‘s response acceptable because the applicant explained that only 

minor indications have occurred and the aging effect of loss of strength due to leaching of 

calcium hydroxide has been included in the Structures Monitoring Program. The staff‘s concern 

described in RAI 3.5.2.3-3 is resolved.

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 functions 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 Steel Exposed to Raw Water, Aging Effect of Cracking, Loss of Material, and Erosion

According to LRA Table 3.5.2-10, the applicant proposed the Structures Monitoring Program for 

discharge tunnel and pipe of the MEA combination steel (M), raw water (E), and loss of material 

and erosion (AERM).

The GALL Report, under item VII.C1-19 (A38) recommends using the program described in 

GALL AMP XI.M20, ―Open-Cycle Cooling Water System,‖ for managing loss of material and 

erosion in the open-cycle cooling water system or SCs. 

By letter dated August 28, 2009, the staff issued RAI 3.5.2.3-4 requesting that the applicant 

propose a program which is consistent with the recommendation in the GALL Report and also 

meets the commitments relating to GL 89-13, or otherwise, justify why the proposed program is 

sufficient.

In its response dated September 28, 2009, the applicant stated that the discharge tunnel and 

pipe consist of a concrete tunnel, a steel pipe encased in concrete, and a reinforced concrete 

pipe section. The applicant clarified that in order to manage the aging effects of the discharge 

tunnel and pipe, it uses the Structures Monitoring Program which requires divers to periodically 

inspect all three sections, including the steel pipe encased in concrete. The applicant further 

stated that the Open-Cycle Cooling Water System Program uses the same preventive 

maintenance procedure as the Structures Monitoring Program, requiring the divers to inspect 

the intake pipe from the intake structure to the screenhouse. The applicant also confirmed that 
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the loss of material, zebra mussels, and other organic macro-fouling, as discussed in GL 89-13, 

are part of their inspection.

The staff finds the applicant‘s response acceptable because the Structures Monitoring Program 

includes the necessary attributes of the program described in GALL AMP XI.M20, ―Open-Cycle 

Cooling Water System,‖ and GL 89-13. The staff‘s evaluation of the Structures Monitoring 

Program is documented in SER Section 3.0.3.2.18.

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 concludes that the applicant has demonstrated that the effects of aging for 

these structures will be adequately managed so that their intended functions will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.5 Concrete Exposed to Raw Water, Aging Effect of Loss of Material, and Cracking and 

Freeze-Thaw

According to LRA Tables 3.5.2-9 and 12, the applicant proposed the Structures Monitoring 

Program for managing the discharge structure and screenhouse of the MEA combination 

concrete (M); raw water (E); and loss of material (spalling, scaling), cracking, and freeze-thaw 

(AERM).

The GALL Report recommends GALL AMP XI.S7, ―RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants,‖ for a similar combination in item III.A6-5 

(T-15) where the environment is air-outdoor. The applicant is not committed to RG 1.127, 

Revision 1. Aging management of water-control structures has been included in the applicant‘s 

Structures Monitoring Program, which is permitted by the GALL Report. However, the GALL 

Report recommends that programs pertaining to water-control structures should incorporate the 

attributes described in GALL AMP XI.S7. To ensure the applicant‘s Structures Monitoring 

Program incorporates all the necessary attributes, the staff issued RAI B2.1.31-2 by letter dated 

July 13, 2009, and follow-up RAI B2.1.31-2a by letter dated November 20, 2009, requesting that 

the applicant include all the references for implementation in an element by element comparison 

of the applicant‘s Structures Monitoring Program and the GALL Report programs. In its 

responses to the RAIs, dated August 17, 2009, and December 28, 2009, respectively, the 

applicant included the necessary references in the program basis documents and provided the 

list of parameters that will be monitored for water-control structures. The staff also confirmed

that those parameters can be adequately monitored by the applicant‘s Structures Monitoring 

Program. These RAIs, including the staff‘s review, are discussed in more detail in the review of 

the Structures Monitoring Program (SER Section 3.0.3.2.18).

The staff evaluated the above and found that the applicant‘s use of the Structures Monitoring 

Program is adequate because the applicant‘s program incorporates the recommendations of the 

GALL Report-recommended AMP, and the program will be enhanced to require inspection of 

submerged structures in raw water on a frequency of 5 years. 

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 functions 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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3.5.2.3.6 Loss of Sealing Due to Deterioration of Seals, Gaskets, and Moisture Barriers from 

the External Surfaces of Seals Exposed to Outdoor or Uncontrolled Indoor Air 

In LRA Tables 3.5.2-1, 3.5.2-4, and 3.5.2-14, the applicant stated that external surfaces of seals 

exposed to outdoor or uncontrolled indoor air are being managed for loss of sealing due to 

deterioration of seals, gaskets, and moisture barriers by the WCP Program. The AMR line items 

cite generic note H, indicating that for the component, material, and environment combination 

listed, the aging effect being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material and 

component type is the external surfaces of seals exposed to outdoor or uncontrolled indoor air,

and noted that there are several AMPs recommended by the GALL Report that could monitor 

the aging effect of loss of sealing due to deterioration of seals, gaskets, and moisture barriers, 

such as GALL AMP XI.M26, ―Fire Protection,‖ and GALL AMP XI.S6, ―Structures Monitoring 

Program.‖ 

The staff reviewed the applicant‘s WCP Program and its evaluation is documented in SER 

Section 3.0.3.2.19. In its review of these items, the staff noted that the aging effect identified by 

the applicant is applicable for this combination of component, material, and environment. The 

staff also noted that the LRA AMP includes both visual inspections and physical manipulation of 

elastomers. The staff further noted that the combined use of visual inspections and physical 

manipulations are capable of detecting loss of sealing from elastomers. The staff finds the 

applicant‘s proposal acceptable because the applicant has: (1) identified an applicable aging 

effect, (2) selected an AMP with an appropriate scope for the component under consideration, 

and (3) chosen an AMP which contains appropriate inspection techniques to identify that aging 

effect. In addition, a staff concern related to selection and frequency of inspections is addressed 

in RAI B2.1.32-2 and the staff‘s evaluation of the RAI response is documented in SER 

Section 3.3.2.2.13.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.7 Changes in Material Properties and Cracking of the Exterior Surfaces of Elastomeric 

Materials Exposed to Uncontrolled Indoor Air

In LRA Table 3.5.2-2, the applicant stated that exterior surfaces of elastomeric materials 

exposed to uncontrolled indoor air are being managed for changes in material properties and 

cracking by the External Surfaces Monitoring Program. The AMR line items cite generic note H, 

indicating that for the component, material, and environment combination listed, the aging effect 

being considered is not evaluated in the GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material/component 

type is exterior surfaces of elastomeric materials exposed to uncontrolled indoor air and 

confirmed that there are no entries for this component/material and environment. 

The staff reviewed the applicant‘s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.7. In its review of these items, the staff noted that the 
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proposed AMP uses visual inspection to identify aging. The staff also noted that identification of 

cracking in elastomers may be difficult using only visual inspection techniques. The staff further 

noted that changes in material properties, such as hardness and elasticity, cannot be reliably 

identified using only visual inspection techniques. By letter dated October 13, 2009, the staff 

issued RAI 3.5.2.3.2-1 requesting that the applicant propose an AMP which includes visual 

inspection and manual manipulation of a sufficient number or area of elastomeric material at a 

sufficient inspection frequency to adequately detect cracking or changes in the material 

properties of those materials.

The applicant responded by letter dated November 13, 2009. In that response, the applicant 

cited its response to RAI B2.1.10-1 (this response is dated August 17, 2009), which stated that 

the External Surfaces Monitoring Program includes the ―scratch, sniff, and stretch‖ technique 

described in the EPRI Aging Assessment Field Guide, which entails detection of surface 

material degradation and hardening by scratching, odor changes possibly indicating degradation 

by sniffing, and elastomer hardening or cracking by stretching. The staff finds this acceptable 

because aging issues, such as changes in hardness and strength, may be discovered using this 

approach. The applicant also stated that these components were related to the fire protection 

system and their aging was managed under both the External Surfaces Monitoring and the Fire 

Protection programs. The applicant further stated that the frequency and sample size for the 

inspection of these components is based on the Fire Protection Program. During the on-site 

AMP audit, the applicant stated that it plans to examine 20 percent of the penetration seals that 

fulfill the 10 CFR Part 50 Appendix A function every 18 months and 100 percent of the 

penetration seals that fulfill the Appendix R requirements every 18 months. The staff reviewed 

the applicant‘s Fire Protection Program and its evaluation is documented in SER 

Section 3.0.3.2.8. The staff finds the applicant‘s approach acceptable because the AMP 

proposed will adequately detect the aging effects under consideration and the sampling size 

and frequency exceed the GALL Report Fire Protection Program recommendation of 10 percent 

every refueling outage interval. The staff‘s concern described in RAI 3.5.2.3.2-1 is resolved.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.8 Exterior Surfaces of Non-Metallic Materials Exposed to Uncontrolled Indoor Air and 

Interior Surfaces of Non-Metallic Materials Exposed to Raw Water

In LRA Tables 3.5.2-4, 3.5.2-12, and 3.5.2-14, the applicant stated that the exterior surfaces of 

non-metallic materials exposed to uncontrolled indoor air and the interior surfaces of 

non-metallic materials exposed to raw water have no aging effect and that no AMP is required. 

The AMR line items cite generic note H, indicating that for the component, material, and 

environment combination listed, the aging effect being considered is not evaluated in the GALL 

Report.

The staff reviewed all AMR result line items in the GALL Report where the material type is 

exterior surfaces of non-metallic materials exposed to uncontrolled indoor air and the interior 

surfaces of non-metallic materials exposed to raw water, and confirmed that there are no entries 

for this component/material and environment. The staff also noted that there is not a distinct 

definition for non-metallic material in the GALL Report Chapter IX. The staff further noted that 
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many polymeric materials are adversely affected by oxidizers (e.g., chlorine), UV light, and high 

temperatures. Based on the information provided, the staff cannot conclude that no aging 

effects will occur to the combination of materials and environments under consideration. By 

letter dated October 13, 2009, the staff issued RAI 3.5.2.3-6 requesting that the applicant 

identify the specific material under consideration and justify why this material is not subject to 

aging under the conditions being considered.

In its response dated November 13, 2009, the applicant stated that the non-metallic material in 

LRA Table 3.5.2-4, which has no aging effect, is wood. All surfaces of this material are exposed 

to uncontrolled indoor air. The applicant also stated that this material is located indoors and is 

not in contact with soil. The applicant conducted an OE search for this combination of material 

and environment and failed to find any instances of aging. The results of this search are 

consistent with the staff‘s knowledge of this material and environment. The staff finds the 

applicant‘s proposal that no aging effect exists for this combination of material and environment 

and that no aging management is required acceptable because the material environment 

combination under consideration is commonly employed and no evidence of aging has been 

detected.

The applicant stated that the non-metallic material in LRA Table 3.5.2-12, which has no aging 

effect, is fiberglass used in the travelling water screen covers. The external surfaces of this 

material are exposed to uncontrolled indoor air. The internal surfaces of this material are 

exposed to raw water. The applicant also stated that this material is not exposed to UV 

radiation, ozone, or high-voltage current, which could result in loss of strength. The applicant 

conducted an OE search for this combination of material and environments and failed to find 

any instances of aging. The results of this search are consistent with the staff‘s knowledge of 

this material and the external environment. The staff finds the applicant‘s proposal that no aging 

effect exists for fiberglass exposed to air acceptable because this material environment 

combination is commonly employed and no evidence of aging has been detected. The staff‘s 

assessment of the interaction between raw water and fiberglass differs from that proposed by 

the applicant. The staff is aware that fiberglass may undergo significant blistering as a result of 

exposure to water. Blistering can become sufficiently severe to result in structural degradation of 

the material. By letter dated December 16, 2009, the staff issued RAI 3.5.2.3-6a requesting that 

the applicant propose an AMP for fiberglass exposed to water or to justify why the fiberglass 

component under consideration should be considered to have no aging effect.

In its response dated January 21, 2010, the applicant stated that the inside fiberglass surface is 

not constantly immersed in water, but rather subject to splashing. The applicant also stated that 

the inside surface is not subjected to continuous hydraulic pressure whereby the water 

penetrates the gelcoat into the underlying laminate. The applicant further stated that as such, 

there is no potential for blistering of the travelling screen covers. The staff finds the applicant‘s 

response acceptable because the inside surface of the screens are not exposed to constant 

hydraulic pressure and, thus, there is no potential for blistering. The staff‘s concern described in 

RAI 3.5.2.3-6a is resolved.

The applicant stated that one non-metallic material in LRA Table 3.5.2-14, which has no aging 

effect, is fiberglass fire boots. All surfaces of this material are exposed to uncontrolled indoor air. 

The applicant also stated that this material is not exposed to UV radiation, ozone, or 

high-voltage current, which could result in loss of strength. The applicant conducted an OE 

search for this combination of material and environment and failed to find any instances of 

aging. The results of this search are consistent with the staff‘s knowledge of this material and 

environment. The staff finds the applicant‘s proposal that no aging effect exists for fiberglass 
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exposed to air acceptable because this material environment combination is commonly 

employed and no evidence of aging has been detected.

The applicant stated that the second non-metallic material in LRA Table 3.5.2-14, which has no 

aging effect, is calcium silicate, expanded silicate, and fiberglass insulation. These materials are 

exposed to uncontrolled indoor air. The applicant also stated that these materials are not 

exposed to UV radiation, ozone, or high-voltage current, which could result in loss of strength. 

The applicant conducted an OE search for this combination of materials and environment and 

failed to find any instances of aging. The results of this search are consistent with the staff‘s 

knowledge of these materials and environment. The staff finds the applicant‘s proposal that no 

aging effect exists for these materials exposed to air acceptable because these material 

environment combinations are commonly employed and no evidence of aging has been 

detected.

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 addressed in the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended functions will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.3.9 Structures and Component Supports – Discharge Structure – Aging Management 

Evaluation

In LRA Table 3.5.2-9, the applicant stated that steel sheet piling exposed to soil has no aging 

effect. The applicant also stated that no AMP is required. The AMR line items cite generic note 

H indicating that the component, material, and environment combination is not addressed in the 

GALL Report.

The staff reviewed all AMR result line items in the GALL Report where the material is steel and 

the environment is soil. The staff noted that the GALL Report recommends the consideration of 

the aging effect of loss of material due to corrosion. Based on the information provided, it is not 

clear to the staff why steel sheet pile exposed to soil as part of the plant‘s discharge structure 

would not experience loss of material due to corrosion. By letter dated December 16, 2009, the 

staff issued RAI 3.5.2.3-7 requesting that the applicant select an AMP appropriate for the 

management of aging in steel sheet piling exposed to soil.

In its response dated January 21, 2010, the applicant stated that the portions of the steel sheet 

piling that is exposed to air-outdoor and raw water environments, at the air-water and soil-water 

interfaces, respectively, are managed by the Structures Monitoring Program. The applicant also 

stated that the soil environment is applicable to the portion of the sheet steel pile that is driven 

into undisturbed soil where due to the oxygen-deficient environment, corrosion would be lower 

than at the air-water and soil-water environment interface points. The staff reviewed the 

applicant‘s Structures Monitoring Program and its evaluation is documented in SER 

Section 3.0.3.2.18. The staff finds the applicant‘s response acceptable because the inspections 

conducted by the Structures Monitoring Program at the air-water and soil-water interfaces will 

be conservatively representative of the conditions of the steel pilings driven into the 

oxygen-deficient environment.

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. The staff concludes that the 
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applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that their intended functions will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.10 Structures and Component Supports – Shield Building, Miscellaneous Structural 

Commodities – Aging Management Evaluation

LRA Tables 3.5.2-2 and 3.5.2-14 summarize the results of AMRs for the shield building and 

miscellaneous structural commodities. In LRA Table 3.5.2-2, the applicant stated that for 

elastomer penetration seals exposed to uncontrolled indoor air, the aging effects of change in 

material properties, cracking, and delamination are managed by the Fire Protection Program. In 

LRA Table 3.5.2-14, the applicant stated that for various fire barriers (e.g., fire doors, fire walls, 

radiant energy shields, fire coatings, penetration seals) constructed of elastomers and 

non-metallic materials, exposed to either indoor or outdoor uncontrolled air, the aging effects of 

change in material properties, cracking, delamination, and loss of material are managed by the 

Fire Protection Program. The applicant referenced generic note H for these items, indicating 

that the aging effect of this component, material, and environment combination is not evaluated 

in the GALL Report.

The staff evaluated the applicant‘s claim that the aging effect for this component, material, and 

environment combination is not evaluated in the GALL Report. The staff reviewed all AMR result 

lines in the GALL Report and found none where the material is elastomers or non-metallic, the 

environment is indoor or outdoor uncontrolled air, and the aging effect is change in material 

properties, cracking, delamination, or loss of material; and confirmed that the applicant‘s use of 

generic footnote H is acceptable.

The staff evaluated the use of elastomers and non-metallic materials in an indoor or outdoor 

uncontrolled air environment. The staff noted that these items are typically made of rubber-like 

polymers or other inorganic material (e.g., calcium sulfate dehydrate, silicate) and used as fire 

barriers to stop hot gases from traveling from fire areas to other areas or to protect steel 

members, pipes, and electrical raceways during a fire event. The staff also noted that these 

materials are designed for use in an outdoor or indoor air environment without significant 

degradation. 

The staff reviewed the applicant‘s Fire Protection Program and its evaluation is documented in 

SER Section 3.0.3.2.8. The staff noted that the applicant‘s Fire Protection Program includes 

periodic visual inspections of fire barriers, such as fire barrier penetration seals, fire coatings,

and fire wraps. The staff also noted that degradation, such as cracking, delamination, or loss of 

material from fire barriers, would be detectable during a visual inspection. The staff further noted 

that it is a common practice to examine the material condition of industrial fire barriers during 

periodic inspections, such that changes in material properties would be identified. The staff finds 

that the aging effects of change in material properties, cracking, delamination, or loss of material 

of fire barriers exposed to an indoor or outdoor uncontrolled air environment can, therefore, be 

adequately managed by periodic visual inspection in accordance with 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 concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions 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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3.5.2.3.11 Structures and Component Supports – Miscellaneous Structural Commodities –

Aging Management Evaluation 

LRA Table 3.5.2-14 summarizes the results of AMRs for miscellaneous structural commodities. 

In LRA Table 3.5.2-14, the applicant stated that for elastomer expansion joints and flood 

barriers and gaskets exposed to uncontrolled indoor air, the aging effects of change in material 

properties and cracking are managed by the Structures Monitoring Program. The applicant 

referenced generic note H for these items, indicating that the aging effect of this component, 

material, and environment combination is not evaluated in the GALL Report. 

The staff evaluated the applicant‘s claim that the aging effects for this component, material, and 

environment combination is not evaluated in the GALL Report. The staff reviewed all AMR result 

lines in the GALL Report and found none where the material is elastomers, the environment is 

indoor or outdoor uncontrolled air, and the aging effect is change in material properties, or 

cracking; and confirmed that the applicant‘s use of generic note H is acceptable. 

The staff evaluated the use of elastomers in an indoor or outdoor uncontrolled air environment. 

The staff noted that these items are typically made of rubber-like polymers and are designed for 

use in an outdoor or indoor air environment without significant degradation. The staff reviewed 

the applicant‘s Structures Monitoring Program and its evaluation is documented in SER 

Section 3.0.3.2.18. The staff noted that the applicant‘s Structures Monitoring Program includes 

periodic visual inspections of non-metallic structural commodities, including elastomers, 

sealants, and flood barriers for change in material properties, cracking, increased hardness, 

shrinkage and loss of strength, loss of sealing, and reduction or loss of isolation function. The 

staff also noted that degradation, such as cracking, delamination, or loss of material, would be 

detectable during a visual inspection. The staff further noted that it is a common industry 

practice to examine the material condition of elastomers during periodic inspections, such that 

changes in material properties would be identified. The staff finds that the aging effects of 

change in material properties, cracking, delamination, or loss of material of elastomer expansion 

joints and flood barriers and gaskets exposed to an indoor or outdoor uncontrolled air 

environment can, therefore, be adequately managed by periodic visual inspections in 

accordance with 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 concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended functions 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 structures and component supports within the scope of license 

renewal and subject to an AMR will be adequately managed such that the intended functions 

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 Commodity Group

The following information documents the staff‘s review of the applicant‘s AMR results for the 

electrical and instrumentation and control (I&C) components and component groups of:

● cables and connections

● fuse holders

● metal-enclosed bus

● switchyard bus and connections

● transmission conductors and connections

3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides the AMR results for the electrical and I&C components and 

component groups. LRA Table 3.6.1, ―Summary of Aging Management Programs for the 

Electrical Components Evaluated in Chapter VI of the NUREG-1801,‖ 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.

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 functions will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff reviewed the AMRs to confirm 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 has identified the appropriate GALL Report AMPs. The staff‘s evaluations of 

the AMPs are documented in SER Section 3.0.3. Details of the staff‘s evaluation are 

documented in SER Section 3.6.2.1.

The staff also reviewed the AMRs that were consistent with the GALL Report and those 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 

evaluations are documented in SER Section 3.6.2.2.

The staff also reviewed the remaining AMRs that were not consistent with, or not addressed in, 

the GALL Report. The technical review also evaluated whether all plausible aging effects have 

been identified and whether the aging effects listed were appropriate for the 

material-and-environment combinations specified. The staff‘s evaluations are documented in 

SER Section 3.6.2.3.

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

Report

Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Electrical equipment 

subject to 

10 CFR 50.49 

environmental 

qualification (EQ) 

requirements

(3.6.1-1)

Degradation due 

to various aging 

mechanisms

Environmental 

Qualification of 

Electric 

Components

Yes TLAA;

EQ of Electrical 

Components 

Program

Further evaluation 

(See SER

Section 3.6.2.2.1)

Electrical cables, 

connections and fuse 

holders (insulation) 

not subject to 

10 CFR 50.49 

EQ requirements

(3.6.1-2)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables 

and Connections 

Not Subject to 

10 CFR 50.49 

EQ Requirements

No Non-EQ Electrical 

Cables and 

Connections 

Program

Consistent with the 

GALL Report 

Conductor insulation 

for electrical cables 

and connections used 

in instrumentation 

circuits not subject to 

10 CFR 50.49 

EQ requirements that 

are sensitive to 

reduction in conductor 

insulation resistance

(3.6.1-3)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

Electrical Cables 

and Connections 

Used In 

Instrumentation 

Circuits Not Subject 

to 10 CFR 50.49 

EQ Requirements

No Non-EQ 

Instrumentation 

Circuits Subject to 

Sensitive, 

High-Voltage, 

Low-Level Signals 

Program

Consistent with the 

GALL Report 

Conductor insulation 

for inaccessible 

medium-voltage (2 kV 

to 35 kV) cables 

(e.g., installed in 

conduit or directly 

buried) not subject to 

10 CFR 50.49 

EQ requirements

(3.6.1-4)

Localized 

damage and 

breakdown of 

insulation leading 

to electrical 

failure due to 

moisture 

intrusion, water, 

and trees

Inaccessible 

Medium-Voltage 

Cables Not Subject 

to 10 CFR 50.49 

EQ Requirements

No Non-EQ 

Inaccessible 

Medium-Voltage 

Cables Program

Consistent with the 

GALL Report 

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage

(3.6.1-5 )

Corrosion of 

connector 

contact surfaces 

due to intrusion 

of borated water

Boric Acid 

Corrosion

No Boric Acid 

Corrosion Program

Consistent with the 

GALL Report
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Fuse holders (not part 

of a larger assembly): 

Fuse holders –

metallic clamp

(3.6.1-6)

Fatigue due to 

ohmic heating, 

thermal cycling, 

electrical 

transients, 

frequent 

manipulation, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Fuse Holders No No Not consistent with 

the GALL Report

(See SER 

Section 3.6.2.3) 

Metal-enclosed bus: 

bus, connections

(3.6.1-7)

Loosening of 

bolted 

connections due 

to thermal cycling 

and ohmic 

heating

Metal-Enclosed Bus No Metal-Enclosed 

Bus Program 

Consistent with the 

GALL Report 

Metal-enclosed bus: 

insulation, insulators

(3.6.1-8)

Reduced 

insulation 

resistance and 

electrical failure 

due to various 

physical, thermal, 

radiolytic, 

photolytic, and 

chemical 

mechanisms

Metal-Enclosed Bus No Metal-Enclosed 

Bus Program 

Consistent with the 

GALL Report 

Metal-enclosed bus: 

enclosure assemblies

(3.6.1-9)

Loss of material 

due to general

corrosion

Structures 

Monitoring Program

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

Metal-enclosed bus: 

enclosure assemblies

(3.6.1-10)

Hardening and 

loss of strength 

due to elastomer 

degradation

Structures 

Monitoring Program

No Structures 

Monitoring 

Program

Consistent with the 

GALL Report

High-voltage 

insulators

(3.6.1-11)

Degradation of 

insulation quality 

due to presence 

of any salt 

deposits and 

surface 

contamination; 

loss of material 

caused by 

mechanical wear 

due to wind 

blowing on 

transmission 

conductors

A plant-specific 

AMP is to be 

evaluated.

Yes None Further evaluation

(See SER 

Section 3.6.2.2.2)
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Component Group 

(GALL Report 

Item No.)

Aging Effect/ 

Mechanism

AMP in GALL 

Report

Further 

Evaluation in 

GALL Report

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Transmission 

conductors and 

connections; 

switchyard bus and 

connections

(3.6.1-12)

Loss of material 

due to wind 

induced abrasion 

and fatigue; loss 

of conductor 

strength due to 

corrosion; 

increased 

resistance of 

connection due 

to oxidation or 

loss of preload

A plant-specific 

AMP is to be 

evaluated.

Yes None Further evaluation 

(See SER 

Section 3.6.2.2.3)

Cable connections: 

metallic parts

(3.6.1-13)

Loosening of 

bolted 

connections due 

to thermal 

cycling, ohmic 

heating, electrical

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements

No Non-EQ Electrical 

Cable Connections 

Program

Consistent with the 

GALL Report 

Fuse holders (not part 

of a larger assembly): 

insulation material

(3.6.1-14)

None None No None Consistent with the 

GALL Report 

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 the 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 the 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 the 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 That Are 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 Program 

Metal-Enclosed Bus Program 
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Non-EQ Electrical Cable Connections Program 

Non-EQ Inaccessible Medium-Voltage Cable Program

Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals 

Program

Non-EQ Electrical Cables and Connections Program

In LRA Table 3.6.2-1, the applicant summarized the AMRs for the electrical and I&C 

components and claimed that these AMRs are 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 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 reviewed those AMRs with notes A through D, 

indicating how the AMR is consistent with the GALL Report.

The staff 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 AMPs.

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 review, the staff 

determines that, for those 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.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended functions 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 AMR Results That Are Consistent with the GALL Report, for Which Further 

Evaluation is Recommended

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

Electrical EQ is a TLAA. The staff‘s evaluation is documented in SER Section 4.4.

3.6.2.2.2 Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, and 

Loss of Material Due to Mechanical Wear

Summary of Technical Information in the Application. In LRA Section 3.6.2.2.2, the applicant 

stated that KPS is located in a rural environment with no major industry in close proximity; 
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therefore, contamination from industrial effluents is not significant. Lake Michigan is a fresh 

water lake used for cooling, and salt spray is not a concern for the insulators. The applicant also 

stated that seasonal rainwater or snow prevent any accumulation of surface contamination 

buildup. The applicant further stated that its review of OE has identified no concerns related to 

the occurrence of degradation of insulator quality due to the presence of salt deposits or surface 

contamination in the switchyard high-voltage insulators. Therefore, the applicant concluded that 

degradation of insulator quality due to the presence of salt deposits or surface contamination is 

not a credible aging mechanism requiring management.

The applicant also stated that the switchyard bus is rigid aluminum tube material or aluminum 

angle supported by post type insulators mounted on steel structures with concrete foundations. 

The bus runs are short lengths, rigidly supported and, therefore, the post insulators are not 

subject to vibration or wind abrasion and do not require management of loss of material due to 

mechanical wear. The applicant also stated that the overhead line from the switchyard to the 

RAT has suspension type insulators and the span lengths between towers are short which 

minimize wind effect. The applicant further stated that its experience has shown that the 

transmission conductors do not normally swing, and that when they do, due to a substantial 

wind, they do not continue to swing for very long once the wind has subsided. Wind loading that 

can cause a transmission line and insulators to vibrate or sway, is considered in the design and 

installation. No high-voltage insulator failures have been experienced. Therefore, the applicant 

concluded that these suspension insulators do not require aging management for loss of 

material due to mechanical wear. The applicant also stated that its review of OE has identified 

no concerns related to the occurrence of loss of material due to mechanical wear as a result of 

wind blowing on transmission conductors in the switchyard high-voltage insulators.

Staff Evaluation. The staff reviewed LRA Section 3.6.2.2.2 against SRP-LR Section 3.6.2.2.2, 

which 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 with 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 determined that since KPS is not located near facilities that discharge soot or near the 

sea coast, and since the applicant‘s plant-specific OE did not identify any issues associated with 

contamination buildup, degradation of insulators due to salt deposit or surface contamination is 

not an applicable AERM for high-voltage insulators at KPS. 

The staff noted that mechanical wear is an aging effect for both strain and suspension 

insulators, in that 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 

motion were severe enough, it could cause wear in the metal contact point of the insulator string 

and between an insulator and its support hardware. Although loss of material of insulators due 

to mechanical wear is possible, transmission conductors do not normally swing and when they 

do, due to a substantial wind, they do not continue to swing very long once the wind has 

subsided. Wind loading that can cause transmission lines and insulators to vibrate or sway is 

considered in the design and installation. In addition, the applicant has not experienced any 

insulator failures due to wear. Furthermore, transmission conductors, within the scope of license 

renewal, are short spans (i.e., connecting the switchyard to the RAT), and the surface areas
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exposed to wind loads are not significant. Based on its review, the staff finds that mechanical 

wear aging effect of high-voltage insulators is not an AERM at KPS.

Conclusion. Based on the programs identified above, the staff concludes that the applicant‘s 

programs meet the SRP-LR Section 3.6.2.2.2 criteria. For those 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 functions 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 Preload

Summary of Technical Information in the Application. In LRA Section 3.6.2.2.3, the applicant 

stated that the switchyard bus material consists of continuous runs of aluminum angle or tubular 

bus connected to rigid post insulator supports, and no aging effects for the ambient air 

environment have been identified that could cause a loss of intended function for the period of 

extended operation. The switchyard buses have terminations that are part of the active 

components (i.e., breakers, disconnect switches, etc.), or are evaluated as part of the cable and 

connections component types. Therefore, the applicant concluded that no aging management is 

required for the bus or connections. The applicant further stated that a review of OE has 

identified no concerns related to the occurrence of loss of material or loss of conductor strength 

due to wind-induced abrasion and fatigue, or corrosion of the switchyard bus and connections 

due to aging.

The applicant stated that transmission conductors within the scope of license renewal are 

138 kV, 795 thousands of circular mils (MCM) aluminum conductor steel reinforced (ACSR) 

conductors connecting the 138-kV switchyard to the RAT. The most prevalent mechanism 

contributing to loss of conductor strength of an ACSR transmission conductor is corrosion, 

which includes corrosion of the steel core and aluminum strand pitting. The applicant also stated 

that for ACSR conductors, degradation begins as a loss of Zn from the galvanized steel core 

wires. Corrosion rates depend largely on air quality, which includes suspended particles 

chemistry, sulfur dioxide concentrations in air, precipitation, fog chemistry, and meteorological 

conditions. The applicant further stated that the plant is located in a rural area and does not 

experience urban or industrial air pollutants. The corrosion of aluminum in air is very slow, 

particularly in the rural, non-industrial location of the plant. Additionally, the ACSR steel core is 

the primary strength component of the conductor. The applicant also stated that loss of

conductor strength through corrosion of the steel core is not considered a credible aging effect 

based on the Ontario Hydro testing of an 80-year old 4/0 ACSR conductor that retained a 37 

percent safety margin of the heavy load tensile strength when compared to the ultimate 

strength. The National Electric Safety Code (NESC) requires that the maximum tension a 

conductor be designed to withstand be not more than 60 percent of the ultimate conductor 

strength. Also, the NESC sets the maximum tension a conductor can be designed to withstand 

under heavy load requirements, which includes consideration of ice, wind, and temperature. In 

addition, the applicant stated that the installed (795 MCM-45/7 strands) conductor has an 

ultimate conductor strength of 22,100 pounds and was installed with 5,000 pound tension for 

NESC heavy loading. The installed margin of this conductor is 77.3 percent of the ultimate 

strength which is well above the 67 percent installed margin of the Ontario Hydro conductor that 

was tested. The applicant concluded that loss of conductor strength through corrosion is not a 

credible aging mechanism requiring management.
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The applicant also stated that NESC design of these conductors included the effects of wind 

loading and sways through span lengths (which are short), and the sag and tension criteria of 

the lines. Also, the applicant stated that experience has shown that when substantial wind 

causes a line to sway, the line does not continue to sway or vibrate once the wind subsides. 

Therefore, the applicant concluded that loss of material due to wind-induced abrasion and 

fatigue is not a credible aging mechanism requiring management.

The applicant stated that increased resistance of aluminum conductor connections due to 

oxidation or loss of preload is minimized through the use of compatible aluminum hardware, the 

use of lock washers in bolted connections, and no-oxide compounds at connection surfaces in 

all termination types. Therefore, the applicant concluded that increased resistance of aluminum 

conductor connections due to oxidation or loss of preload is not a credible aging mechanism 

requiring management. The applicant further stated that its review of OE has identified no 

concerns related to the occurrence of loss of material, loss of strength, or increased resistance 

of connections in the high-voltage transmission conductors due to aging.

Staff Evaluation. The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR 

Section 3.6.2.2.3 which 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 preload could 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 this aging effect is adequately managed.

The staff noted that the sections of transmission conductor in the scope of license renewal are 

short spans connecting the switchyard to the RAT, and the surface areas exposed to wind loads 

are not significant. Furthermore, the applicant confirmed that plant-specific OE did not identify 

any aging effects of mechanical wear of transmission. Based on this information, the staff 

determined that loss of material of transmission conductors due to vibration is not an AERM.

The staff reviewed the aging effect due to corrosion of specific conductors installed at KPS 

against NESC requirements. The installed (795 MCM-45/7 strands) conductors have the 

conductor strength of 22,100 pounds and were installed with 5,000 pound tension for NESC 

heavy loading. The Ontario study showed about 30 percent of conductor strength loss due to 

corrosion. For plant-specific conductors at KPS, the tension on installed conductors is about 

32 percent of the ultimate conductor strength after 80 years in service (5,000 lb/22,100 lb x 0.7). 

The NESC requires that tension installed on conductors be a maximum of 60 percent of ultimate 

conductor strength. The ratio of maximum heavy load and the ultimate conductor strength of 

installed conductors is below the 60 percent NESC requirements. Furthermore, the staff noted 

that the length of transmission conductors in scope of license renewal is generally in short span. 

These transmission conductors connect the switchyard to the RAT, providing restoration of 

offsite power after an SBO event. The loading of these transmission conductors is much less 

than the calculated heavy loading of a long span transmission line. The staff determined that 

with a 30 percent loss of conductor strength, there is still ample margin between the NESC 

requirements and the actual conductor strength. Based on this information, the staff determined 

that loss of conductor strength due to corrosion of transmission conductor is not a significant 

AERM for the period of extended operation.

In LRA Section 3.6.2.2.3, the applicant stated that switchyard buses have terminations that are 

evaluated as part of the cable and connections component types. The staff noted that the scope

of the Non-EQ Electrical Cables and Connections Program does not include high-voltage 

connections. The scope of this program only includes medium- and low-voltage levels. In a 
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letter dated November 20, 2009, the staff issued RAI 3.6.2.2.3-1 requesting that the applicant 

explain how switchyard bus terminations are evaluated as part of the cable and connection 

component types. In response to the staff‘s request, in a letter dated December 28, 2009, the 

applicant stated that switchyard bus terminations were evaluated as part of the AMR for cables 

and connections component types and the results of the evaluation are provided in LRA 

Table 3.6.2-1 for the commodity group and component type ―Transmission Conductors and 

Connections.‖ The applicant also stated that the AMR concluded that there are no AERMs for 

the switchyard bus terminations and no AMP is required. The applicant further stated that the 

basis for this conclusion, as described in LRA Section 3.6.2.2.3, is that: (1) oxidation and loss of 

preload for these connections are minimized through the use of compatible aluminum bolting 

hardware, (2) lock washers are used in bolted connections, and (3) no-oxide compounds are 

used at connection surfaces in all termination types, such that increased resistance of aluminum 

conductor connections due to oxidation or loss of preload is not a credible aging mechanism. 

The staff finds the applicant‘s response acceptable because the applicant clarified that 

switchyard bus terminations are evaluated as part of cable and connection component types 

and not in the Non-EQ Electrical Cables and Connections Program, which is only applicable to 

medium- and low-voltage connections (below 35 kV) and not the high-voltage connections 

(above 35 kV). The staff noted that increased temperature of electrical bolted joints is due to 

high circuit rating or an increase in current duration. The different coefficient thermal expansion 

of different material of electrical bolted joints will rise, and stress will increase with increasing 

current duration. If this temperature increase is not taken into consideration, loose joints or joint 

failures will occur. The design of the transmission conductor bolted connections at KPS 

precludes torque relaxation due to different coefficient thermal expansion and the plant-specific 

OE has not identified any failures of switchyard connections due to aging. The staff also noted 

that the use of compatible aluminum hardware and lock washers in bolted connections in all 

termination types will preclude torque relaxation. This method of assembly is consistent with the 

good bolting practices recommended by industry guidelines (EPRI TR-104213, ―Bolted Joint 

Maintenance & Application Guide‖). The bolted connections and washers are coated with an 

anti-oxidant compound (i.e., a grease-type sealant) prior to tightening the connection to prevent 

the formation of oxides on the metal surface and to prevent moisture from entering the 

connection, thus reducing the chances of corrosion. This method of installation has been shown 

to provide a corrosion-resistant, low-electrical-resistance connection. Based on this information, 

the staff determined that increased resistance of switchyard bus and transmission conductor 

connections due to torque relaxation or corrosion is not a significant AERM at KPS. The staff‘s 

concern described in RAI 3.6.2.2.3-1 is resolved.

However, the staff noted that failures of locked washers (i.e., Belleville washers causing loose 

connections) were noted from industry OE, whereby hydrogen entrapment with plated steel 

washers causing embrittlement and stress cracking of the plated washer can lead to loose 

connections. In addition, EPRI document TR-104213 also identifies this problem with galvanized 

and electroplated Belleville washers. In a letter dated November 20, 2009, the staff issued 

RAI 3.6.2.2.3-2 requesting that the applicant explain if electroplated and galvanized Belleville 

washers are currently used at KPS. If they are, the staff requested that the applicant explain 

why hydrogen embrittlement is not a problem at KPS. The staff also requested that the applicant 

describe the switchyard maintenance activity used to confirm the effectiveness of bolted 

connections in the switchyard. In a letter dated December 28, 2009, the applicant responded 

that stainless steel Belleville washers are installed in switchyard bus aluminum conductor 

connections. Therefore, embrittlement and stress cracking due to the use of plated washers is 

not applicable. The applicant also stated that thermography of switchyard bolted connections is 

performed at least annually to identify any increased resistance condition in switchyard bus 

connections. The applicant further stated that after any switchyard maintenance that could 
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create a high-resistance condition, all re-worked connections have micro-ohm resistance 

measurements taken to ensure that no high-resistance conditions have been created during the 

maintenance activities. The staff finds the applicant‘s response acceptable because Belleville 

washers used at KPS are stainless steel; thus the concern with hydrogen entrapment with 

plated steel washers is not applicable to KPS. The staff also finds the applicant‘s use of 

thermography to check for switchyard connections acceptable to confirm the effectiveness of 

bolted connections in the switchyard. The staff‘s concern described in RAI 3.6.2.2.3-2 is 

resolved.

Conclusion. Based on the programs identified above, the staff concludes that the applicant‘s 

programs meet the SRP-LR Section 3.6.2.2.3 criteria. For those 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 functions will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL Report

GALL Report, Volume 2, Revision 1, item VI.A-8, ―Fuse Holders (Not Part of a Larger Assembly; 

Metallic Clamp),‖ identifies the aging/effect mechanism as fatigue due to ohmic heating, thermal 

cycling, electrical transients, frequent manipulation, vibration, chemical contamination, 

corrosion, and oxidation. The associated GALL AMP XI.E5, ―Fuse Holders,‖ states that fuse 

holders within the scope of license renewal should be tested to provide an indication of the 

condition of the metallic clamps of fuse holders. In LRA Section 3.6.2.1.2, ―Fuse Holders,‖ the 

applicant stated that there are no AMPs required for fuse holders based on a review of the 

environment of the fuse holders. LRA Table 3.6.1, item 3.6.1-06 concludes that only fuse 

holders located in two enclosed cabinets in the relay room required evaluation, and concludes 

that these fuse holders are in a controlled environment, and are not subject to the aging 

effect/mechanisms identified in the GALL Report, Volume 2, Revision 1, item VI.A-8. Although 

the applicant concluded in LRA Section 3.6.2.1.2 that the aging effects/mechanisms identified 

by the GALL Report are not applicable to the fuse holders at KPS, the applicant did not provide 

an evaluation to substantiate the conclusion. LRA Table 3.6.1, item 3.6.1-06 provides the same 

conclusion.

In a letter dated November 20, 2009, the staff issued RAI 3.6.2.1.2-1 requesting that the 

applicant provide an evaluation that addresses the aging effect/mechanisms (environmental and 

mechanical) identified in the GALL Report, Volume 2, Revision 1, item VI.A-8 that supports the 

conclusions made in LRA Section 3.6.2.1.2 and Table 3.6.1, item 3.6.1-06. In a letter dated 

December 28, 2009, the applicant responded that the fuse holders subject to an AMR are those 

located in enclosed cabinets in the relay room. The relay room is a temperature and humidity 

controlled environment. The applicant provided the following as a basis for the conclusion that 

the fuse holders are not subject to the aging effects/mechanisms:

Fatigue. The applicant stated that NUREG-1760, ―Aging Assessment of Safety-Related Fuses 

Used in Low- and Medium-Voltage Application in Nuclear Power Plants,‖ states that fatigue of 

fuse holders can typically occur due to elevated temperature, mechanical stress, and repeated 

insertion and removal of fuses. NUREG-1760 further states that fuse failures resulting from 

thermal cycling are associated with the fuse element, and not the fuse holder. The applicant 

also stated that the fuse holders subject to an AMR are located indoors and in a controlled air 

environment. There is no significant source of heat in close proximity to the fuse holders such 

that elevated temperatures are not expected. Therefore, the applicant concluded that fatigue 
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due to elevated temperature is not an applicable aging effect. The applicant stated that fatigue 

related to mechanical stress and/or repeated insertion and removal is evaluated under 

Mechanical Stress below.

Mechanical Stress. The applicant stated that the fuse holders subject to an AMR are located in 

enclosed cabinets and the fuses are not routinely removed and reinserted into the metallic 

clamps. The fuses are only removed during fuse replacement with circuit isolation performed by 

other devices in the circuit (circuit breaker). Therefore, the applicant concluded that the fuse 

holder metallic clamps are not subject to repeated manipulation, which could lead to mechanical 

fatigue. The applicant also stated that mechanical stress resulting from electrical faults and 

transients is not considered a credible aging mechanism since they are infrequent and random 

in nature. In addition, the applicant stated that stresses resulting from electrical faults are 

mitigated by fast acting circuit protective devices.

Vibration. The applicant stated that two fuse panels are wall mounted, not mounted on rotating 

equipment, and are not in close proximity to rotating equipment such that they could be affected 

by vibration. Therefore, the applicant concluded that vibration is not an applicable aging 

mechanism for the fuse holders in these panels.

Chemical Contamination and Corrosion. The applicant stated that these fuse holders are 

located in enclosed cabinets that are located indoors, in a controlled air environment, and are 

not subject to exposure to fluid system leakage. The fuse holders are not subject to moisture or 

chemicals inside the panel enclosures and do not experience a corrosive environment. 

Therefore, the applicant concluded that chemical contamination and corrosion do not require 

management for the fuse holders.

Ohmic heating and Thermal Cycling. The applicant stated that these fuses are used in a 

low-voltage and low current application such that there is no significant ohmic heating. The 

applicant also stated that the power is continuous such that thermal cycling does not occur. 

Therefore, the applicant concluded that ohmic heating and thermal cycling is not an applicable 

aging mechanism for these fuse holders.

Oxidation. The applicant stated that the relay room is a controlled air environment. The room is 

served by the control room air conditioning system. The environment is maintained at 

approximately 80 °F and 35 percent relative humidity. The applicant also stated that oxidation in 

this environment is not considered an applicable mechanism. In addition, the applicant stated 

that a review of industry and plant-specific OE has indicated there are no aging concerns for 

copper alloy fuse holders in this environment.

The staff finds the applicant‘s response acceptable. The staff determined that the applicant has 

provided an adequate evaluation to support the conclusion that aging effect/mechanism as 

identified in the GALL Report, Volume 2, Revision 1, item VI.A-8 are not applicable to the fuse 

holders at KPS. Fatigue due to elevated temperatures and mechanical stress is not applicable 

to KPS because the fuse holders subject to an AMR are located in a controlled air environment. 

There is no significant source of heat in close proximity to the fuse holders such that elevated 

temperature is not a concern for these fuse holders. Mechanical stress resulting from electrical 

faults and transient is not considered a credible aging mechanism since they are infrequent and 

random in nature. Furthermore, stresses resulting from electrical faults are mitigated by fast 

acting circuit protective devices (e.g., circuit breakers, fuses). The fuses are not routinely 

removed and reinserted to the metallic clamps. The fuses are only removed during fuse 

replacement with circuit isolation performed by circuit breakers in the circuit; therefore, fatigue is 
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not an applicable aging effect. The fuse panels are mounted on the wall and not on rotating 

equipment or in close proximity to rotating equipment; therefore, vibration is not an applicable 

aging effect. The fuse holders are located in a controlled air environment and are not exposed 

to fluid system leakage; therefore, chemical contamination and corrosion is not an aging effect. 

These fuses are used in low-voltage/low-current applications such that there is no significant 

ohmic heating. Ohmic heating and thermal cycling is not an applicable aging effect. The relay 

room is a controlled air environment and oxidation is not expected in this environment. In 

addition, there is no oxidation concern for copper alloy in a controlled air environment. 

Furthermore, the applicant did review industry and plant-specific OE and indicated that there is 

no aging concern for copper alloy fuse holders in a controlled air environment. Therefore, the 

staff determined that aging affects and mechanisms identified in the GALL Report are not 

applicable to KPS. The staff‘s concern described in RAI 3.6.2.1.2-1 is resolved.

In LRA Table 3.6.2-1, ―Electrical Components-Cables and Connections-Aging Management 

Evaluation,‖ the applicant indicated that fuse holder insulations are not in an adverse localized 

environment and denoted note H. Note H means that the aging effect is not in the GALL Report 

for this component, material, and environment combination. The staff noted that the GALL 

Report, Volume 2, Revision 1, item VI.A-6 identifies embrittlement, cracking, melting, or loss of 

dielectric strength leading to reduced insulation resistance for insulation materials of fuse 

holders in an adverse localized environment due to heat, radiation, or moisture in the presence 

of oxygen or greater than 60-year service limiting temperature. In a letter dated November 20, 

2009, the staff issued RAI 3.6.2.3-1, requesting that the applicant explain why the aging effect 

identified in the GALL Report or in an adverse localized environment is not applicable to the 

insulation materials of fuse holders. In a letter dated December 28, 2009, the applicant stated 

that as indicated in LRA Table 3.6.2-1, for Commodity Group and Component Type ―Fuse 

Holders insulation,‖ note 1 states that the fuse holders are not located in an adverse localized 

environment (e.g., high heat, high radiation). The fuse holders subject to an AMR are located in 

enclosed cabinets in the relay room, which has a temperature and humidity controlled 

environment. The applicant stated that since the fuse holders are not located in an adverse 

localized environment, the aging effects identified in the GALL Report, item VI.A-6 for fuse 

holder insulation materials are not applicable. The staff finds the applicant‘s response 

acceptable because fuse holder insulation materials are not in an adverse localized 

environment. The fuse holders are located in two cabinets inside a relay room which have 

temperature and humidity controlled environments. These fuse holders are not in an adverse 

localized environment. The staff determined that there is no aging effect for fuse holder 

insulation material in a controlled environment. The staff‘s concern described in RAI 3.6.2.3-1 is 

resolved.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environments, 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 functions 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 functions will be 
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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 

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 

adequately managed so that the intended functions 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 USAR 

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 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 54.21(a)(3), are in accordance with the Atomic 

Energy Act of 1954 and NRC regulations.
4-1

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 Sections 4.2 through 4.8 of the license renewal application (LRA), 

Dominion Energy Kewaunee, Inc. (Dominion, DEK, or the applicant) addressed the TLAAs for 

Kewaunee Power Station (KPS). SER Sections 4.2 through 4.8 document the review of the 

TLAAs conducted by the staff of the U.S. Nuclear Regulatory Commission (NRC or 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, 

―Definitions.‖

In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list existing plant-specific 

exemptions granted under 10 CFR 50.12, ―Specific Exemptions,‖ 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

LRA Section 4.1.1, ―Identification Process of Time-Limited Aging Analyses,‖ states that the 

applicant used a process consistent with Nuclear Energy Institute (NEI) 95-10, ―Industry 

Guidelines for Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule.‖ 

LRA Section 4.1.1 also states that the applicant identified TLAAs by evaluating calculations for 

KPS against the six criteria specified in 10 CFR 54.3. The applicant indicated that it identified 

the calculations that met the six criteria by searching the current licensing basis (CLB), which 

included the updated safety analysis report (USAR), engineering calculations, technical reports, 

licensing correspondence, and applicable vendor reports. In LRA Table 4.1-1, ―Time Limited 

Aging Analysis Applicable to KPS,‖ the applicant listed the following applicable TLAA 

categories:

● reactor vessel neutron embrittlement 

● metal fatigue 

● environmental qualification (EQ) of electrical equipment

● containment liner plate, metal containments, and penetrations

● other unit-specific TLAAs:

▪ crane load cycle limits

▪ reactor coolant pump flywheel

▪ leak-before-break (LBB) 

▪ reactor vessel underclad cracking

▪ reactor coolant loop piping flaw tolerance evaluation
Time-Limited Aging Analyses

4-2

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it had identified one exemption 

granted under 10 CFR 50.12 that is in effect, and based upon a TLAA as defined in 

10 CFR 54.3. This concerns an exemption from the requirements of 10 CFR 50.61 and 

10 CFR Part 50, Appendices G and H. This exemption request, granted in a letter dated 

May 2001 (Agencywide Document Access and Management System (ADAMS) Accession 

No. ML011210180), provided the following for KPS:

● established the use of a new methodology to meet the requirements of Appendix G to 

10 CFR Part 50

● established the use of a new methodology to meet the requirements of 10 CFR 50.61

● modified the basis for the KPS reactor pressure vessel (RPV) surveillance program 

(required by Appendix H of 10 CFR Part 50) to incorporate the acquisition of fracture 

toughness data

The applicant stated:

The new methodology for assessing the [reactor pressure vessel] RPV 

circumferential beltline weld is based on the use of the 1997 Edition of [American 

Society for Testing and Materials] ASTM Standard Test Method E-1921 and 

[American Society of Mechanical Engineers] ASME Code Case N-629. The 

exemption was necessary for the reactor vessel beltline weld to meet the 

pressurized thermal shock criterion of 10 CFR 50.61.

The applicant evaluated pressurized thermal shock (PTS) as a TLAA as part of LRA 

Section 4.2.

4.1.2 Staff Evaluation

LRA Table 4.1-1 lists the TLAAs the applicant identified as being applicable to KPS. The staff 

reviewed the information to determine whether the applicant had provided sufficient information 

pursuant to 10 CFR 54.21(c)(1) and (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, 

pursuant to 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, pursuant to 

10 CFR 54.4(b)

 (6) are contained or incorporated by reference in the CLB
Time-Limited Aging Analyses

4-3

The applicant reviewed the list of potential TLAAs from NUREG-1800, ―Standard Review Plan 

for Review of License Renewal Applications for Nuclear Power Plants,‖ (SRP-LR) dated 

September 2005. The applicant listed those potential TLAAs applicable to KPS in LRA 

Table 4.1-2, ―Review of Generic Analyses Listed on Tables 4.1-2 and 4.1-3 of NUREG-1800,‖ 

and indicated whether the TLAA was applicable to KPS or not.

The staff confirmed that the applicant‘s LRA includes the TLAAs that are normally applicable to 

pressurized water reactor (PWR) applications, including TLAAs on the following:

● reactor vessel neutron embrittlement for neutron fluence, upper-shelf energy, 

pressurized thermal shock limits, and pressure-temperature limits

● metal fatigue of ASME Class 1 components and of non-Class 1 components

● environmental qualification of electrical equipment

● fatigue of the reactor containment vessel, liner plate, and containment penetrations

The staff noted that a concrete containment tendon prestress TLAA does not apply to KPS 

since the containment vessel is not a concrete, prestressed, tensioned containment. The staff 

finds the applicant‘s identification of these TLAAs acceptable because they are consistent with 

the TLAAs identified in SRP-LR Sections 4.2, 4.3, 4.4, and 4.6 as being applicable to PWR 

LRAs.

The staff also verified that the LRA included the following plant-specific TLAA evaluations:

● crane load cycle limits

● reactor coolant pump motor flywheel fatigue crack growth analysis

● leak-before-break

● reactor vessel underclad cracking

● reactor coolant loop piping flaw tolerance evaluation

The staff confirmed that the applicant‘s identification of these additional TLAAs satisfies the 

recommendation in SRP-LR Section 4.7 that the applicant identify any additional analyses for 

the facilities that meet the definition of a TLAA in 10 CFR 54.3.

During the review of the applicant‘s TLAA identification process, the staff concluded that it was 

consistent with that identified in NEI 95-10, Revision 6. The staff did not identify any omissions 

of TLAAs that should have been addressed for this LRA.

Based on its review, the staff concludes that the applicant has satisfied the requirement of 

10 CFR 54.21(c)(1) to identify the TLAAs that are applicable to the LRA because the applicant 

has satisfied the TLAA identification guidance and recommendations in SRP-LR Sections 4.2, 

4.3, 4.4, 4.6, and 4.7.

As required by 10 CFR 54.21(c)(2), the applicant must list all exemptions granted in accordance 

with 10 CFR 50.12, based on TLAAs, and evaluate and justify them for continuation through the 

period of extended operation. The LRA states that each active exemption was reviewed to 

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 and 
Time-Limited Aging Analyses

4-4

results of the applicant‘s search of the CLB to identify these exemptions, the staff has 

determined, in accordance with 10 CFR 54.21(c)(2), that there is one TLAA-based exemption 

granted under 10 CFR 50.12 which the applicant has identified for continuation through the 

period of extended operation. This exemption applies to the applicant‘s methodology for 

assessing an RPV circumferential beltline weld to meet the PTS criterion of 10 CFR 50.61. The 

staff‘s review of the reactor vessel neutron embrittlement TLAA is described in SER Section 4.2.

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 also confirmed, as required by 

10 CFR 54.21(c)(2), that the applicant has provided an evaluation, as discussed in LRA 

Sections 4.1.2 and 4.2, that justifies the continuation of one exemption pursuant to 

10 CFR 50.12 for the period of extended operation.

4.2 Reactor Vessel Neutron Embrittlement

―Neutron embrittlement‖ is the term for changes in mechanical properties of RPV materials 

caused by exposure to fast neutron flux (E > 1.0 million electron volts (MeV)) within the vicinity 

of the reactor core, called the beltline region. The most pronounced material change is a 

reduction in fracture toughness. As fracture toughness decreases with cumulative fast neutron 

exposure, the material‘s resistance to cleavage and ductile fracture decreases. Fracture 

toughness also depends on temperature. The reference nil ductility transition temperature 

(RTNDT), above which the material behaves in a ductile manner and below which the material 

behaves in a brittle manner, increases as fluence increases and requires higher temperatures 

for continued ductility. As required by 10 CFR 50.60, all light-water reactors must meet the 

fracture toughness, pressure-temperature (P-T) limits, and material surveillance program 

requirements for the reactor coolant pressure boundary (RCPB) in Appendices G and H to 

10 CFR Part 50. Section 50.61 of 10 CFR provides the fracture toughness requirements 

protecting the RPV of a PWR against the consequences due to a PTS event: a severe 

overcooling concurrent with or followed by significant pressure in the RPV. Neutron fluence, 

upper-shelf energy (USE), PTS, and P-T limits are time-dependent items that must be 

investigated to evaluate RPV embrittlement or reduction of fracture toughness. The CLB 

analyses evaluating reduction of fracture toughness of the RPV for 40 years are TLAAs. The 

following sections address neutron fluence, USE, PTS, and P-T limits for RPV beltline materials 

for the period of extended operation.

4.2.1 Neutron Fluence

4.2.1.1 Summary of Technical Information in the Application

The WCAP-16641 report, ―Analysis of Capsule T from Dominion Energy Kewaunee Power 

Station Reactor Vessel Radiation Surveillance Program,‖ provides the calculation of the KPS

RPV neutron fluence projections to the end of the period of extended operation based on 

52.1 effective full-power years (EFPYs), or a 60-year plant lifetime. Neutron exposure up to 

Cycle 27 was based upon actual plant operating history, including power uprate from 

1,650 megawatt-thermal (MWt) to 1,772 MWt that occurred during Cycle 26. Neutron exposure 
Time-Limited Aging Analyses

4-5

projections beyond the end of Cycle 27 were based upon a series of 18-month operating cycles 

at full power having operating characteristics similar to Cycle 27 of 1,772 MWt followed by a 

25-day refueling outage. Based on this scenario, the calculated capacity factor for the KPS RPV 

is 95.6 percent with 33.0 EFPYs at the end of license and 52.1 EFPYs at the end of the period 

of extended operation. The neutron exposure projections were based on continued use of low 

neutron leakage fuel management.

All of the calculations and dosimetry evaluations for the specimens documented in the 

WCAP-16641 report were based on the latest available nuclear cross section data derived from 

Evaluated Nuclear Data File (ENDF/B-VI) and made use of the latest available calculational 

tools. Furthermore, the neutron transport and dosimetry evaluation methodologies follow the 

guidance of Regulatory Guide (RG) 1.190, ―Calculational and Dosimetry Methods for 

Determining Pressure Vessel Neutron Fluence,‖ version 2001. The power distributions used in 

the plant-specific transport analysis were based on the individual core designs for each of the 

first 27 fuel cycles at KPS.

The transport calculations supporting the analysis were carried out using the DORT discrete 

ordinates code Version 3.1 and the BUGLE-96 cross-section library. The fluence calculations 

concluded that capsule T surveillance specimens received a fluence of 5.62E+19 neutrons per 

square centimeter (n/cm2) (E > 1.0 MeV) after irradiation to 24.6 EFPYs and the peak RPV 

clad/base metal interface fluence after 24.6 EFPYs of plant operation was 2.60E+19 n/cm2

(E > 1.0 MeV). LRA Table 4.2-1 provides fast neutron fluence (E > 1.0 MeV) projections for 

60 calendar years of operation (52.1 EFPYs) at the clad/base metal interface for all materials 

comprising the beltline and the extended beltline region of the KPS RPV.

4.2.1.2 Staff Evaluation

RG 1.190 recommends a neutron fluence evaluation to satisfy the following: 

● a fluence calculation performed using an acceptable methodology 

● analytic uncertainty analysis identifying possible sources of uncertainty 

● benchmark comparison to approved results of a test facility 

● plant-specific qualification by comparison to measured fluence values 

The fast neutron exposure parameters were determined for DEK by Westinghouse, using the 

methodologies discussed in WCAP-14040-NP-A, ―Methodology Used to Develop Cold 

Overpressure Mitigating Systems Setpoints and RCS Heatup and Cooldown Limit Curves,‖ and 

WCAP-16083-NP-A, ―Benchmark Testing of the FERRET Code for Least Squares Evaluation of 

Light Water Reactor Dosimetry, May 2006.‖ As noted by safety evaluations dated February 27, 

2004, and January 10, 2006, these reports describe a methodology that the staff found 

acceptable.

The WCAP-16641 report, which was provided to the staff as Attachment 1 to a letter dated 

November 14, 2006, regarding the KPS RPV Capsule T test results, indicated that DEK is using 

the two-dimensional discrete ordinates code, DORT, with the BUGLE-96 cross-section library 

derived from the ENDF/B-VI. Approximations include a P5 Legendre expansion for anisotropic 

scattering and an S16 order of angular quadrature. These approximations are of a higher order 

than the P3 expansion and S8 quadrature suggested in RG 1.190. Space and energy 

dependent core power (neutron source) distributions and associated core parameters are 

treated on a fuel cycle specific basis. Three dimensional flux solutions are constructed using a 
Time-Limited Aging Analyses

4-6

synthesis of azimuthal, axial, and radial flux. Source distributions include cycle-dependent fuel 

assembly initial enrichments, burnups, and axial power distributions, which are used to develop 

spatial and energy dependent core source distributions that are averaged over each fuel cycle. 

This method accounts for source energy spectral effects by using an appropriate fission split for 

uranium and plutonium isotopes based on the initial enrichment and burnup history of each fuel 

assembly. The neutron transport calculations, as described above, are performed consistent 

with RG 1.190.

As described in the WCAP-16641 report, DEK performed an analytic uncertainty analysis by 

combining the uncertainties associated with the individual components of the transport 

calculations in quadrature. The calculations were compared with the benchmark measurements 

from the Poolside Critical Assembly simulator at the Oak Ridge National Laboratory, and with 

surveillance capsule and reactor cavity measurements from the H.B. Robinson power reactor 

benchmark experiment. These constitute acceptable test facilities.

Finally, the WCAP-16641 report provided a direct comparison against the measured sensor 

reaction rates from Capsule T. For all reactions, the measured-to-calculated (M/C) ratios were 

very close to unity; the average ratio was 0.99 with 5.2-percent standard deviation. The 

distribution of M/C ratios ranged from 0.93 to 1.07. Therefore, all reaction rates were calculated 

within 20 percent of measured values, as suggested in RG 1.190.

In addition, LRA Section 4.2.1 stated that WCAP-16641 provides the calculation of KPS RPV 

neutron fluence projections to the end of the period of extended operation (60 years of plant 

lifetime or 52.1 EFPYs of exposure). The fluence estimate to the end of Cycle 27 included 

actual plant operating history, considering power uprate. Neutron exposure projections beyond 

Cycle 27 assumed an 18-month fuel cycle followed by a 25-day refueling outage. This 

assumption resulted in a 95.6-percent capacity factor. Based on the operating history at KPS, 

the average capacity factor for the period of time from 2001 through 2006 was 80.25 percent, as 

noted in NUREG-1350, ―2007-2008 Information Digest.‖ This makes the assumption of a 

95.6-percent capacity factor reasonably conservative. Based on these considerations, the staff 

concludes that the fluence calculations are in accordance with RG 1.190 and the 52.1 EFPY 

fluence values, which adequately account for the period of extended operation, and are

acceptable.

4.2.1.3 USAR Supplement

The applicant did not provide a USAR supplement summary description of its evaluation of 

neutron fluence in LRA Appendix A, ―USAR Supplement.‖ Therefore, the staff issued request for 

additional information (RAI) 4.2.1-1.

RAI 4.2.1-1:

The Evaluation of neutron fluence is provided in LRA Section 4.2.1, ―Neutron 

Fluence.‖ The LRA does not provide a USAR Supplement summary description 

of LRA Section 4.2.1 in LRA Appendix A, ―Updated Safety Analysis Report 

Supplement.‖ Please provide a USAR supplement summary description of the 

evaluation of neutron fluence for 52.1 effective full power years.

In its response dated November 13, 2009, the applicant provided a USAR supplement summary 

description of its evaluation of neutron fluence, which will be added to LRA Section A.3.1. 

Hence, RAI 4.2.1-1 is resolved. On the basis of its review of the USAR supplement, the staff 
Time-Limited Aging Analyses

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concludes that the summary description of the applicant‘s actions to address neutron fluence is 

adequate.

4.2.1.4 Conclusion

In summary, the applicant has provided fluence calculations performed using an acceptable 

methodology, supported by analytic uncertainty analysis and comparison to approved test 

facilities, along with a plant-specific comparison of measured fluence values from Surveillance 

Capsule T. Based on these considerations, the staff concludes that the applicant has followed 

the guidance in RG 1.190, and the neutron exposures reported in the applicant‘s submittal are, 

therefore, acceptable. The staff also concludes that, because the applicant has assumed actual 

past operating history in its fluence calculations, accounted for a power uprate, and assumed a 

reasonably conservative capacity factor, the fluence projections adequately account for the 

period of extended operation.

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that its reactor vessel neutron fluence 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).

4.2.2 Upper-Shelf Energy Evaluation

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2 summarizes the evaluation of USE values for the period of extended 

operation.

Appendix G to 10 CFR Part 50 contains screening criteria that establish limits on how far the 

USE values for an RPV material may be allowed to decrease due to neutron irradiation 

exposure. The regulation requires the initial USE value be greater than 75 foot-pounds (ft-lb) in 

the unirradiated condition and that the value be greater than 50 ft-lb in the fully irradiated 

condition throughout the licensed life of the plant. USE values of less than 50 ft-lb may be 

acceptable to the staff if it can be demonstrated that these lower values will provide margins of 

safety against brittle fracture equivalent to those required by ASME Code Section XI, 

Appendix G. RG 1.99, Revision 2 provides guidance for the USE evaluation of the RPV 

materials. In this application, Charpy USE for the beltline forgings and weld were determined 

using surveillance data (Position 2.2 of RG 1.99, Revision 2), and the Charpy USE for the 

extended beltline materials was determined without the use of surveillance data (Position 1.2 of 

RG 1.99, Revision 2). LRA Table 4.2-2 summarized the predicted Charpy USE values at the 

end of the period of extended operation (52.1 EFPYs) using the fluence projection at one 

quarter of the RPV wall thickness (1/4 T), the copper (Cu) content of the beltline and the 

extended beltline materials, and the results of the capsule specimens tested to date using 

Figure 2 in RG 1.99, Revision 2. The USE values for the beltline and extended beltline materials 

remain above the 50 ft-lb requirement for the period of extended operation.
Time-Limited Aging Analyses

4-8

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.

According to RG 1.99, Revision 2, the predicted decrease in USE values due to neutron 

embrittlement during plant operation is dependent upon the amount of Cu in the material and 

the predicted neutron fluence for the material. As indicated in SER Section 4.2.2.1 above, the 

applicant used Position 2.2 to determine the Charpy USE values at the end of the period of 

extended operation for the RPV beltline forgings and weld because five sets of surveillance data

are available for each of these materials. For the extended beltline materials, however, the 

applicant used Position 1.2, in accordance with the RG, to determine its Charpy USE values 

because the values for extended beltline materials are not represented by capsule specimens.

The staff performed an independent evaluation considering the KPS RPV information in the 

NRC‘s Reactor Vessel Integrity Database (RVID) and the recent capsule T surveillance data in 

the WCAP-16641 report. The staff found that Cu contents and unirradiated USEs for all beltline 

materials in LRA Table 4.2-2 are identical to those in the RVID. Based on this information and 

the complete surveillance data information in the RVID and the WCAP-16641 report, the staff 

plotted a line in Figure 2 of RG 1.99, Revision 2, bounding all surveillance data for each RPV 

beltline material. These bounding lines indicate that the applicant‘s projected USE values at the 

end of the period of extended operation are valid for all KPS RPV beltline materials. The 

projected USE value at 52.1 EFPYs for the limiting material (the intermediate shell-to-lower shell 

circumferential weld) is 60 ft-lb.

Because of the relatively high fluence for 52.1 EFPYs for the beltline material, the applicant 

prudently performed a USE evaluation for ―extended beltline materials,‖ using Position 1.2 of 

RG 1.99, Revision 2 (i.e., without surveillance data). However, because RVID does not contain 

information for the extended beltline materials, the staff issued RAI 4.2.2-1.

RAI 4.2.2-1:

The U.S. Nuclear Regulatory Commission‘s (NRC) Reactor Vessel Integrity 

Database (RVID) does not contain information for the extended beltline materials 

reported in the LRA. Please discuss the procedures used to determine the 

chemistry data, initial reference temperature (RTNDT), and margins for the 

extended beltline materials to demonstrate that there are consistent approaches 

for both beltline and extended beltline materials.

The applicant‘s response dated November 13, 2009, provided additional information regarding 

the chemistry data, initial RTNDT, and margins for the extended beltline materials. This response 

stated that: (1) between the Certified Material Test Reports and the guidance from RG 1.99, 

Revision 2, best-estimate Cu and nickel (Ni) weight percentages were determined for the 

extended beltline materials; (2) the initial RTNDT values of the RPV materials were determined in 

accordance with Subsection NB-2331 of Section III of the ASME Code and Branch Technical 

Position MTEB 5-2, ―Fracture Toughness Requirements,‖ of the NRC Standard Review Plan 

(NUREG-0800); and (3) the margins are determined in accordance with RG 1.99, Revision 2. 

Therefore, the staff agrees with the applicant‘s conclusion that, ―the procedures that were 

applied to determine the properties for the extended beltline materials are consistent with those 

applied for determination of properties for the traditional beltline forgings,‖ and RAI 4.2.2-1 is 

resolved. This information also supplements LRA Section 4.2.3 on PTS.
Time-Limited Aging Analyses

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The staff used Position 1.2 of RG 1.99, Revision 2 and verified that the upper shell forging is the 

limiting extended beltline material with a projected 52.1 EFPY USE of 71 ft-lb. Thus, pursuant to 

10 CFR 54.21(c)(1)(ii), the KPS RPV beltline and extended beltline materials, which have 

52.1 EFPY USE values at 1/4 T greater than 50 ft-lb, meet the 10 CFR Part 50, Appendix G 

USE requirement to the end of the period of extended operation.

4.2.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of the 

USE values for RPV materials in LRA Section A.3.1.1. On the basis of its review of the USAR 

supplement, the staff concludes that the summary description of the applicant‘s actions to 

address USE is adequate.

4.2.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that for USE, the analyses have been 

projected to the end of the period of extended operation and meet 10 CFR Part 50, Appendix G 

requirements. 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) and is, therefore,

acceptable.

4.2.3 Pressurized Thermal Shock Limits for Reactor Vessel Materials Due to Neutron 

Embrittlement

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3 summarizes the PTS evaluation of the KPS RPV beltline and extended 

beltline materials for the period of extended operation against the screening criteria established 

in accordance with 10 CFR 50.61. The screening criteria are 270 °F for plates, forgings, and 

axial weld materials, and 300 °F for circumferential weld materials.

The KPS RPV beltline region is composed of three different materials: two ring forgings and a 

circumferential weld, which were included in the Reactor Vessel Surveillance Program. The 

WCAP-16642 report, ―Evaluation of Pressurized Thermal Shock for Kewaunee Power Station,‖ 

defined reference temperatures for PTS (RTPTS) for the forgings in accordance with 

10 CFR 50.61 for materials that have surveillance data. Since the data scatter requirements are 

exceeded, the surveillance data for the forgings are considered to be not credible and higher 

chemistry factors based on the measured Cu and Ni contents are used with a 2σ margin. RTPTS

values for RPV extended beltline materials have also been evaluated in accordance with 

10 CFR 50.61 and determined to be not controlling.

For the circumferential weld (heat 1P3571), an exemption to 10 CFR 50.61 was granted for KPS 

in an NRC safety evaluation dated May 1, 2001, regarding use of the Master Curve method as 

defined in ASME Code Case N-629, ―Use of Fracture Toughness Test Data to Establish 

Reference Temperature for Pressure Retaining Materials,‖ coupled with measured fracture 

toughness data from pre-cracked Charpy specimens. The WCAP-16609 report, ―Master Curve 

Assessment of Kewaunee Power Station Reactor Vessel Weld Metal,‖ re-evaluated RTPTS for 

this weld using the same methodology defined in the May 1, 2001, NRC safety evaluation based 
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on fracture toughness data determined from Capsule T specimens to obtain a Master 

Curve-based irradiated reference temperature (RTTo) for use in place of the adjusted RTPTS

value for this weld. The PTS evaluation results from the WCAP-16642 report for the reactor 

vessel beltline and extended beltline materials in LRA Table 4.2-3 meet the screening criteria of 

10 CFR 50.61(b)(2). Therefore, acceptable RTPTS values have been calculated in accordance 

with 10 CFR 50.61 and the approved exemption to 10 CFR 50.61 requirements, to the end of 

the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

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.

Section 50.61 of 10 CFR provides the fracture toughness requirements protecting the RPVs of 

PWRs against the consequences of PTS. Licensees are required to perform an assessment of 

the RPV materials‘ projected RTPTS values through the end of their operating license. Here, 

RTPTS values defined in 10 CFR 50.61 are identical to RTNDT values defined in RG 1.99, 

Revision 2. The rule requires each licensee to calculate the end-of-license RTPTS value for each 

RPV beltline material. The RTPTS value for each beltline material is the sum of the unirradiated 

RTNDT, a shift in the RTNDT value caused by neutron irradiation of the material (ΔRTNDT), and a 

margin value to account for uncertainties (M). Section 50.61 of 10 CFR also provides screening 

criteria against which the calculated values are to be evaluated.

As stated in LRA Section 4.2.3.1, the screening criteria are 270 °F for plates, forging, and axial 

weld materials, and 300 °F for circumferential weld materials. RG 1.99, Revision 2 provides a 

discussion regarding the calculations of ΔRTNDT and the M value. In this RG, ΔRTNDT is the 

product of a chemistry factor and a fluence factor, where the fluence factor is dependent upon 

the neutron fluence at the clad-to-base metal interface and the chemistry factor is dependent 

upon information from either the surveillance material or from the tables in the RG. If the RPV 

beltline material is not represented by surveillance material, its chemistry factor may be 

determined using the tables and the methodology documented in Position 1.1 in this RG.

The chemistry factor determined from the tables in the RG depends upon the amount of Cu and 

Ni in the material. If the RPV beltline material is represented by surveillance material, its 

chemistry factor may be determined from the surveillance data using the methodology 

documented in Position 2.1 of the RG.

The applicant summarized its PTS evaluation results for the KPS RPV beltline and extended 

beltline materials in LRA Table 4.2-3. For beltline intermediate forging and lower shell forging, 

LRA Table 4.2-3 presents 52.1 EFPY RTPTS values based on Position 1.1 and Position 2.1 of 

RG 1.99, Revision 2. The staff verified that the Cu and Ni contents and the initial RTPTS values 

for these two beltline forgings are identical to those in the RVID. Using this material information 

and the 52.1 EFPY fluence, the staff calculated the RTPTS values for these forgings based on 

Position 1.1 and found them almost identical to the applicant‘s values. For the PTS evaluation of 

the two forgings based on surveillance data or Position 2.1, the staff validated the chemistry 

factors reported in LRA Tables 4.2-3, which are also consistent with those in the WCAP-16641 

report. Using the 52.1 EFPY fluence and the calculated chemistry factors, the staff verified the 

applicant‘s 52.1 EFPY RTPTS values based on surveillance data. Since the applicant‘s limiting 

52.1 EFPY RTPTS value is significantly below the PTS screening criteria, the staff determined 

that the KPS RPV beltline forgings meet the PTS requirements at the end of the period of 

extended operation.
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For the circumferential weld, the applicant performed its PTS evaluation using the Master Curve 

methodology defined in the May 1, 2001, NRC safety evaluation, which supported granting an 

exemption from the requirements of 10 CFR Part 50, Appendices G and H, and 10 CFR 50.61. 

The details for this recent PTS evaluation based on the Master Curve methodology are 

contained in the WCAP-16609 report, which was submitted as Attachment 2 to the applicant‘s 

November 14, 2006, letter. The staff confirmed that the fundamental material information 

regarding two of the three surveillance weld data used in the WCAP-16609 report is identical to 

those in Appendix A of the May 1, 2001, NRC safety evaluation, except for a minor modification 

to the neutron fluence for Capsule S. This modification is appropriate because neutron fluence 

values for capsules are updated based on the latest information whenever a new capsule is 

withdrawn and tested. The WCAP-16609 report evaluated the KPS weld RTPTS value in 

accordance with the procedures designated as ―Calculation #1‖ and ―Calculation #2‖ in 

Appendix A of the May 1, 2001, NRC safety evaluation for the two surveillance weld data. 

Similar calculations were performed via the Calculation #2 procedure for the new Capsule T 

weld data. This is acceptable because the Calculation #2 procedure is for plant-specific 

surveillance weld data (i.e., data from KPS capsules). The staff‘s calculations verified the RTPTS

values reported in Table 8-1 of the WCAP-16609 report. The staff first adjusted these RTPTS

values considering the difference in the neutron fluence between LRA Table 4.2-3 

(5.37E+19 n/cm2) and Table 8-1 of the WCAP-16609 report (4.7E+19 n/cm2), and then used the 

three surveillance weld data, including the most recent Capsule T data, to determine the 

best-estimate value for the KPS RPV circumferential weld. This exercise verified the applicant‘s 

RTPTS value of 297.5 °F for the circumferential weld at the end of the period of extended 

operation. This RTPTS value is below the PTS screening criteria and, thus, is acceptable to the 

staff.

LRA Table 4.2-3 shows that, for extended beltline materials, the upper shell forging and upper 

shell-to-intermediate shell circumferential weld have about the same magnitude of 52.1 EFPY 

RTPTS values as the beltline intermediate shell forging; others have values significantly below 

the PTS screen criteria. Thus, the staff concludes that the applicant is prudent by including the 

extended beltline materials in its PTS evaluation, and that the extended beltline materials meet 

the PTS screening criteria.

Based on the above discussion, the staff concludes that all KPS RPV beltline and extended 

beltline materials satisfy the PTS requirements of 10 CFR 50.61 through the period of extended 

operation. Thus, the applicant‘s TLAA for calculating the RTPTS values of the KPS RPV beltline 

materials at the end of the period of extended operation is acceptable because it meets the 

requirements of 10 CFR 54.21(c)(1)(ii) and will ensure that the RPV materials will have 

adequate RTPTS values and fracture toughness through the period of extended operation for 

KPS.

4.2.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of PTS 

in LRA Section A.3.1.2. 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.

4.2.3.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

satisfactorily demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that for PTS, the analyses, 
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including the Master Curve methodology for the circumferential weld in the approved 

Exemption, have been projected to the end of the period of extended operation. However, an 

Exemption request for the period of extended operation must be submitted at the same time 

when the applicant requests an amendment to use the P-T limits 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).

4.2.4 Pressure-Temperature Limits

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the evaluation of P-T limits for the period of extended operation. 

Appendix G to 10 CFR Part 50 requires that heatup and cooldown of the RPV be accomplished 

within established P-T limits, which considers reduced fracture toughness of the RPV materials 

due to neutron irradiation embrittlement. Heatup and cooldown limit curves have been 

calculated using the adjusted RTNDT value corresponding to the limiting beltline material of the 

RPV for the current period of licensed operation. In accordance with 10 CFR 50, Appendix G, 

updated P-T limits for the period of extended operation have been developed in WCAP-16643, 

―Kewaunee Power Station Heatup and Cooldown Limit Curves for Normal Operation,‖ and will 

be implemented prior to the period of extended operation. The low-temperature overpressure 

protection (LTOP) enables temperature requirements to be updated concurrently with the P-T 

limits in order to ensure that these limits are not exceeded for postulated plant transients during 

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)(iii), that the 

effects of aging on the intended function will be adequately managed by the KPS Reactor 

Vessel Surveillance Program for the period of extended operation. The Reactor Vessel 

Surveillance Program is responsible for development of P-T limits and LTOP set points for the 

RPV protection.

The current P-T limits were approved by the NRC on April 1, 1999. These P-T limits were 

developed by the applicant for 33 EFPYs, but were limited to 28 EFPYs due to the staff‘s 

concern with the initial RTNDT value and the standard deviation for the initial RTNDT value for the 

circumferential weld. This is an area that the staff will pay attention to when the updated P-T 

limits are submitted for the NRC review in a license amendment request. LRA Section 4.2.4 

states that updated P-T limits for the period of extended operation have been developed in 

accordance with 10 CFR Part 50, Appendix G and documented in WCAP-16643, which will be 

implemented prior to the period of extended operation. The applicant did not include the 

updated P-T limits in the LRA for the staff‘s review.

The staff does not require the updated P-T limit curves for the period of extended operation to 

be submitted as part of the applicant‘s LRA for this TLAA. However, the applicant is required to 

submit revised P-T limits (not necessarily the 52.1 EFPY P-T limits) in accordance with 

10 CFR Part 50, Appendix G prior to the expiration of the facility‘s current P-T limit curves, 

considering adequate time for staff review and approval. Hence, the staff finds that the 

applicant‘s plan to manage the P-T limits in accordance with 10 CFR 54.21(c)(1)(iii) is 

acceptable because changes to the P-T limit curves will be implemented by the license 
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amendment process (i.e., through revision of the plant technical specifications (TSs)) and meet 

the requirements of 10 CFR 50.60 and 10 CFR Part 50, Appendix G.

4.2.4.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation of P-T 

limits in LRA Section A.3.1.3. 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.

4.2.4.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that for P-T limits, 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 Metal Fatigue

Summary of Technical Information in the Application. LRA Section 4.3 states that its design 

basis addresses the effects of metal fatigue. The section also states that ASME Class 1 vessels 

and the pressurizer surge line piping have been explicitly analyzed in accordance with ASME

Boiler and Pressure Vessel (B&PV) Code requirements using assumptions for thermal and 

mechanical loading cycles over the component life. The applicant further stated that other plant 

piping systems were designed and constructed to United States of America Standards 

(USAS) B31.1.0 Power Piping Code requirements, and have been evaluated for the effects of 

thermal fatigue using stress range reduction factor methodology based on expected full thermal 

cycles. Furthermore, if the cyclic behavior of the plant systems and components were evaluated 

for a 40-year plant life, the associated analyses are considered TLAAs according to 

10 CFR 54.3(a)(3), and the fatigue-related analysis must be evaluated for the period of 

extended operation. The applicant stated if a component has a fatigue TLAA that remains valid 

to the end of the period of extended operation (demonstration in accordance with 

10 CFR 54.21(c)(1)(i)), or is projected to the end of the period of extended operation 

(demonstration in accordance with 10 CFR 54.21(c)(1)(ii)), then cracking due to metal fatigue is 

not an aging effect requiring management for that component. If the fatigue TLAA cannot be 

demonstrated to remain valid by either of these methods, then an aging management program 

(AMP) is needed to manage the effects of fatigue on the intended function of the affected 

component(s) (demonstration in accordance with 10 CFR 54.21(c)(1)(iii)).

The applicant stated the following sections provide the results of the evaluation of metal 

fatigue-related TLAAs:

● Section 4.3.1, ―Fatigue of ASME Class 1 Components‖

● Section 4.3.2, ―Fatigue of Non-ASME Class 1 Components‖

Staff Evaluation. The staff noted that in LRA Section 4.3, the applicant stated that if a 

component whose fatigue TLAA remains valid to the end of the period of extended operation or 
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is projected to the end of the period of extended operation, then cracking due to metal fatigue is 

not an aging effect requiring management for that component. The staff noted that cracking is a 

major safety issue for any operating structural component and must be addressed immediately, 

and that the applicant‘s statement implies that cracking could be ignored as long as the fatigue 

TLAA remains valid or can be projected to the end of the period of extended operation. By letter 

dated July 13, 2009, the staff issued RAI 4.3-1 requesting that the applicant provide the basis to 

justify this statement in LRA Section 4.3 and discuss how it would address cracks for 

components dispositioned in accordance with 10 CFR 54.21(c)(1)(i) or 10 CFR 54.21(c)(1)(ii).

In its response dated August 17, 2009, the applicant stated that this statement was not intended 

to imply that identified cracking in pressure boundary components could be ignored if the fatigue 

TLAAs are shown to remain valid for the period of extended operation. The applicant asserted 

that all required inspections will continue to be performed for components within the scope of 

metal fatigue TLAAs, and any identified nonconforming conditions, including cracking, will be 

evaluated in accordance with the corrective action program, as appropriate.

Based on its review, the staff finds the applicant‘s response to RAI 4.3-1 acceptable because 

the applicant clarified that all required inspections will continue to be performed and that any 

cracking that is identified will be evaluated in accordance with the corrective action program. 

The staff‘s concern described in RAI 4.3-1 is resolved.

4.3.1 Fatigue of ASME Class 1 Components

LRA Section 4.3.1 stated its design incorporates the requirements of the ASME B&PV Code, 

Section III, for Class 1 pressure vessels, which requires a discrete analysis of the thermal, 

mechanical, and dynamic stress cycles for portions of components that make up the RCPB. The 

applicant stated that although original design specifications commonly state that the transient 

conditions are for a 40-year design life, the fatigue analyses are based on the specified number 

of occurrences of each transient rather than on this lifetime. Furthermore, the number of 

occurrences of each design transient was selected based on operating experience and on 

assumptions for future plant operation during the 40-year design life.

The applicant stated that in addition to the original design transients, fatigue loading transients 

related to insurges or outsurges from the pressurizer and associated thermal stratification 

transients that are not part of the original fatigue analyses were subsequently identified. As a 

result, the applicant stated it performed an ASME Code fatigue analysis for the pressurizer 

surge line, in response to NRC Bulletin 88-11, ―Pressurizer Surge Line Thermal Stratification,‖ 

that was incorporated into its design basis. The applicant also stated the ASME Code Class 1 

reactor coolant loop piping was designed and constructed to the requirements of 

USAS B31.1.0-1967 and, with the exception of the pressurizer surge line piping, there are no 

design-basis fatigue analyses. The reactor coolant loop piping and branch connections are 

subject to the stress range reduction factor thermal cycle limits of the design code (i.e., 7,000 

cycles without stress range reduction).

The applicant further stated the additional consideration of the reactor coolant environmental 

effects on the fatigue usage factor, in accordance with the resolution of Generic Safety Issue 

(GSI) 190, must be considered for the period of extended operation, and these effects have 

been evaluated for the required ASME Code Class 1 locations.
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The results of the applicant‘s TLAA evaluations for ASME Code Class 1 components are 

presented in the following sections:

● Section 4.3.1.1, ―Component Design Transient Cycles‖

● Section 4.3.1.2, ―ASME Code Class 1 Vessels and Surge Line Piping‖

● Section 4.3.1.3, ―Reactor Coolant Loop Piping‖

● Section 4.3.1.4, ―Pressurizer Lower Head and Surge Line‖

● Section 4.3.1.5, ―Effects of Reactor Coolant Environment on Fatigue Life of ASME Code 

Class 1 Piping and Components‖

4.3.1.1 Component Design Transient Cycles

4.3.1.1.1 Summary of Technical Information in the Application

The applicant stated that operating experience at its site and other Westinghouse nuclear steam 

supply system (NSSS) units has demonstrated that the analyzed numbers of design-basis 

transients are generally conservative for a 40-year life. LRA Table 4.3-1, ―Reactor Coolant 

System Operating Transients,‖ provides a listing of these transients and indicates those that are 

monitored by the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The applicant 

stated the program monitors transients and components to assure that actual plant operation 

remains bounded by the assumptions used in the design analyses and this program tracks 

cycles of design-basis transient events and evaluates the number of occurrences against the 

design basis. Furthermore, for transients that are not monitored, LRA Table 4.3-1 provides the 

basis for not being monitored.

The applicant stated a projection of the number of occurrences of transient cycles monitored by 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program to the end of the period of 

extended operation has been provided in LRA Table 4.3-1. The applicant stated the projection is 

based on doubling the number of transient occurrences as of July 2006 (representing more than 

32 years of operation) and provides a conservative estimate of transient occurrences for a 

60-year plant lifetime. The applicant stated that these transients will continue to be tracked in 

accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary Program for the 

remaining plant life.

4.3.1.1.2 Staff Evaluation

The applicant stated that the 60-year cycle projection was based on the cycles accrued over the 

plant life (from plant startup through July 10, 2006) multiplied by a factor of 2. The staff finds that 

this projection is conservative and acceptable because: (1) the applicant‘s baseline period 

through July 10, 2006, is 32 years, which is 2 years beyond the mid-term of a 60-year plant life;

(2) the transient occurrence rate for the first few years of operation are higher than that for the 

later years of operation when plant operational experience was better; and (3) these transients 

will continue to be tracked in accordance with the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program for the remaining plant life.
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The staff noted that the applicant relies on transient cycle monitoring and tracking to manage 

the aging due to fatigue effects. The staff noted that for a valid cycle-based fatigue (CBF) 

management program, it is essential that all thermal and pressure activities (transients) are 

bounded by the design specifications (including P-T excursion ranges and temperature rates). 

By letter dated July 13, 2009, the staff issued RAI B3.2-1 requesting that the applicant: 

(a) describe the procedures that it uses for tracking thermal transients, (b) confirm that all 

monitored transient events were bounded by the design specifications, (c) confirm that transient 

events were continuously monitored since the plant startup, and (d) provide a histogram of 

cycles accrued for plant heatup and plant cooldown transients.

The applicant responded to RAI B3.2-1 by letter dated August 17, 2009. For parts (a) and (b),

the applicant stated that the thermal and pressure transients listed in LRA Table 4.3-1 and 

USAR Table 4.1-8 are tracked by its program and that the requirements of the program are 

implemented by a plant surveillance procedure, which includes a summary description of critical 

parameters associated with the transient definition and requires tracking the occurrence of 

transients listed in LRA Table 4.3-1. The applicant also stated that transient conditions were 

defined for fatigue evaluation based on a conservative estimate of the magnitude and frequency 

of the temperature and pressure cycles resulting from normal operation, normal and abnormal 

load transients, and accident conditions. The applicant further stated that if a thermal or 

pressure transient occurs that is not bounded by the transient parameters described in the 

procedure, the event will be documented in the corrective action program and an engineering 

evaluation will be performed to determine the impact on applicable components and analyses. 

In its response to part (c), the applicant stated that thermal and pressure transients listed in LRA 

Table 4.3-1 have been monitored and tracked since initial plant operation in 1973. In its 

response to part (d), the applicant provided histograms of cycles accrued for plant heatup and 

plant cooldown transients.

The staff reviewed these histograms (see applicant‘s response, Attachment 1, pages 113 and 

114) and found that the transient occurrence rates (both heatup and cooldown) are quite 

constant since 1980. This means that for the past 26 years (through 2006), the plant operation 

has been quite steady. The applicant made its cycle projections by doubling the actual number 

of cycles accrued as of July 10, 2006. The staff noted that cycle projection can be graphically 

represented (e.g., as shown in the histograms), by drawing a straight line from the intersection 

of the x and y axes to the 2004 data point, boosted to the July 10, 2006, cycle value. It is 

evident from the two histograms that the slope used by the applicant for making cycle 

projections is significantly greater than that of the average of the past 26 years. This means that 

the basis of projections that the applicant used is conservative and, therefore, the staff finds it 

acceptable. As expected, the slopes of event occurrence (i.e., the rates) during the first few 

years (5 to 7 years) are significantly higher than the averages for both heatups and cooldowns.

Based on its review, the staff finds the applicant‘s response to RAI B3.2-1 acceptable because: 

(1) for parts (a) and (b), the applicant has demonstrated effectiveness of its program on 

transient cycle capturing and counting, as well as keeping all transients being bounded within 

the design specifications; (2) for part (c), the applicant confirmed that transient events have 

been continuously monitored since the plant startup; and (3) for part (d), the applicant provided 

the transient cycle histograms for the plant heatup and cooldown transients, covering the plant 

operating history thus far. Based on the applicant‘s response, the staff confirmed that: (a) all 

transients are bounded within the design specifications, and (b) all transient cycles that had 

occurred were captured and counted since the startup of the plant. The staff noted that these 

two criteria are the essence and technical bases of the CBF management methodology. The 

staff‘s concern described in RAI B3.2-1 is resolved.
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4.3.1.1.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of component 

design transient cycles in LRA Section A.3.2.1.1. Based on its review of the USAR supplement, 

the staff concludes that the applicant has provided an adequate summary description of its 

actions to address component design transient cycles.

4.3.1.1.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated that the component design transient cycles will be adequately managed during 

the period of extended operation pursuant to 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), and, therefore, is acceptable.

4.3.1.2 ASME Class 1 Vessels and Surge Line Piping

4.3.1.2.1 Summary of Technical Information in the Application

LRA Section 4.3.1.2 states the reactor vessel (including the control rod drive mechanism 

pressure housings), steam generators, pressurizer, reactor coolant pumps, and the pressurizer 

surge line have been analyzed for fatigue usage in accordance with ASME Code Section III 

requirements for Class 1 components. Furthermore, the applicant stated that as an input to the 

fatigue analysis, design-basis operational transients were defined. To provide assurance of the 

necessary high degree of integrity for the components in the reactor coolant system (RCS), 

transient conditions were selected for fatigue evaluation based on a conservative estimate of 

the magnitude and frequency of the temperature and pressure transients resulting from normal 

operation, normal and abnormal load transients, and accident conditions. The applicant also 

stated that those transients were chosen which are representative of transients to be expected

during plant operation and which are sufficiently severe or frequent to be of possible 

significance to component cyclic behavior. Furthermore, an assumed number of occurrences of 

each of the design transients during the plant lifetime were used as input to the design-basis 

fatigue calculations.

The applicant stated that based on the transient cycle projections, which will be confirmed by

continued monitoring through the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program, the design fatigue analyses remain valid for 60 years, and the ASME Code Class 1 

vessels and surge line piping fatigue TLAA has been demonstrated to be acceptable for the 

period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i) and (iii).

4.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.2 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

TLAA remains valid during the period of extended operation, and pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation.

The staff noted that the applicant has dispositioned its ASME Code Class 1 vessels and surge 

line piping fatigue in accordance with 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii). The 

staff noted that the 60-year cycle projection was based on the cycles accrued over the plant life 

(from plant startup through July 10, 2006) multiplied by a factor of 2. The staff finds that this 
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projection is conservative and acceptable because: (1) the applicant‘s baseline period through 

July 10, 2006, is 32 years, which is 2 years beyond the mid-term of a 60-year plant life; (2) the 

transient occurrence rate for the first few years of operation is higher than that for the later years 

of operation when plant operational experience was better; and (3) these transients will continue 

to be tracked in accordance with the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program for the remaining plant life. The staff noted that the applicant dispositioned its TLAA in 

accordance with 10 CFR 54.21(c)(1)(i) because its conservative projections for 60 years did not 

exceed the design cycles for 40 years of operation. However, the staff also noted that the 

applicant‘s Metal Fatigue of Reactor Coolant Pressure Boundary Program will continue to track 

and confirm, by continued monitoring, to ensure that these transients will not exceed the design 

cycles for the remaining plant life, in accordance with 10 CFR 54.21(c)(1)(iii), and that the 

effects of aging on the intended functions will be adequately managed for the period of 

extended operation. The staff noted that the applicant‘s Metal Fatigue of Reactor Coolant 

Pressure Boundary Program includes corrective actions, such as repair or replacement of the 

component or a more rigorous analysis of the component to demonstrate that the design code 

limit will not be exceeded during the period of extended operation, consistent with the 

recommendations of NUREG-1801, ―Generic Aging Lessons Learned (GALL) Report,‖

AMP X.M1, ―Metal Fatigue of Reactor Coolant Pressure Boundary.‖ The staff reviewed the 

applicant‘s Metal Fatigue of Reactor Coolant Pressure Boundary Program and its evaluation is 

documented in SER Section 3.0.3.2.20.

The staff finds the applicant ̳s disposition of the ASME Class 1 vessels and surge line piping

TLAA pursuant to 10 CFR 54.21(c)(1)(i) and 10 CFR 54.21(c)(1)(iii) acceptable because the 

applicant‘s cycle projection of design basis transients is conservative as described above and 

the applicant‘s Metal Fatigue of Reactor Coolant Pressure Boundary Program will continue to 

monitor the number of transient occurrences to ensure the limits used in the analyses are not 

exceeded, such that analyses remains valid.

Further discussion of the staff‘s review of the pressurizer surge line is documented in SER 

Sections 4.3.1.4.2 and 4.3.1.5.2.

4.3.1.2.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of the ASME 

Code Class 1 vessels and surge line piping in LRA Section A.3.2.1.2. The staff noted that the 

applicant‘s USAR supplement is consistent with the recommendations in SRP-LR 

Section 4.3.3.3. Based on its review of the USAR supplement, the staff concludes that the 

applicant provided an adequate summary description of its actions to address the fatigue 

evaluation of the ASME Code Class 1 vessels and surge line piping.

4.3.1.2.4 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 the ASME Code Class 1 vessels and surge line piping remains valid 

during the period of extended operation, and pursuant to 10 CFR 54.21(c)(1)(iii), that the effects 

of aging on the intended functions of the ASME Code Class 1 vessels and surge line piping 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), and, therefore, is acceptable.
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4.3.1.3 Reactor Coolant Loop Piping

4.3.1.3.1 Summary of Technical Information in the Application

LRA Section 4.3.1.3 states the reactor coolant loop piping was designed in accordance with the 

requirements of USAS B31.1.0-1967 and there is no general requirement in this code for an 

explicit fatigue analysis; however, piping systems are required to be evaluated for thermal 

expansion cycles, and a thermal expansion stress range reduction factor is to be applied if 

cycling is excessive. The applicant stated the code allows 7,000 full temperature thermal 

expansion cycles without penalty.

The applicant stated the design transients defined for RCS ASME Code Class 1 vessels are 

also applicable to the reactor coolant loop piping. An evaluation of these transients, and the 

60-year cycle projections discussed in LRA Section 4.3.1.1, concluded that thermal cycling of 

the reactor coolant loop piping will remain well below the 7,000 thermal expansion cycles 

allowed by USAS B31.1.0, and as a result, the design-basis stress analysis for the reactor 

coolant loop piping remains valid for 60 years of plant operation.

The applicant stated the expected number of thermal transients affecting the reactor coolant 

loop piping is significantly below the design-basis limit of 7,000 cycles and, therefore, the piping 

stress analysis remains acceptable, and the TLAA remains valid for the period of extended 

operation, in accordance with 10 CFR 54.21(c)(1)(i).

4.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.3 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

TLAA remains valid during the period of extended operation.

The staff noted that since the piping systems are connected to the vessel, they are generally 

cycled in parallel with reactor operations. The staff noted that the 60-year transient cycles for 

the reactor vessel components in LRA Table 4.3-1 can be used to estimate the cycles for the 

piping systems. The staff reviewed the 60-year transient cycles for the reactor vessel 

components in LRA Table 4.3-1 and finds that the total number of projected transients for 

60 years is significantly lower than the 7,000 cycles permitted by the requirements of 

USAS B31.1.0-1967.

The staff finds the applicant‘s disposition of the reactor coolant loop piping fatigue TLAA 

pursuant to 10 CFR 54.21 (c)(1)(i) acceptable because as shown in LRA Table 4.3-1, the 

60-year projected cycles are well below the cycles used in the original design analysis by a 

significant margin.

4.3.1.3.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of reactor 

coolant loop piping in LRA Section A.3.2.1.3. The staff noted that the applicant‘s USAR 

supplement is consistent with the recommendations in SRP-LR Section 4.3.3.3. Based on its 

review of the USAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the fatigue evaluation of the reactor coolant loop 

piping.
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4.3.1.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses of reactor coolant loop piping will remain valid during 

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),

and, therefore, is acceptable.

4.3.1.4 Pressurizer Lower Head and Surge Line

4.3.1.4.1 Summary of Technical Information in the Application

LRA Section 4.3.1.4 states that insurge and outsurge fatigue effects on the pressurizer lower 

head and the surge line must be evaluated for license renewal. The applicant stated that these 

effects were evaluated using stress-based fatigue (SBF) monitoring software (Electric Power 

Research Institute (EPRI) FatigueProTM) as part of the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program. The applicant further stated that for license renewal, SBF 

monitoring software modules have been developed for critical locations in the pressurizer lower 

head and in the surge line, including the pressurizer and hot leg nozzles. The applicant stated 

the fatigue monitoring software calculates the cumulative usage factor (CUF) for these locations 

based on actual plant conditions such as temperature, pressure, and other parameters affecting 

component material stresses and fatigue usage and accounts for loading due to pressurizer 

insurges and outsurges, and any thermal stratification conditions present. The applicant stated 

the software also provides a fatigue CUF projection based on analysis of several years of 

collected plant data. Furthermore, the applicant has always operated with a ―Modified Steam 

Bubble‖ method of startup and shutdown, such that recent operating data is representative of 

past operations, and in order to further reduce thermal fatigue in the pressurizer lower head and 

surge line, operating procedures were changed at the end of Cycle 28 (March 2008) to 

incorporate the ―Water Solid‖ method of startup and shutdown. The applicant also stated the 

fatigue CUF projection currently does not take into account these improved startup and 

shutdown operating methods as a conservative measure, and the highest projected 60-year 

CUF for these locations is 0.318 at a pressurizer heater penetration, which is less than the 

design limit of 1.0.

Therefore, the applicant stated the design limits are not challenged due to pressurizer insurge 

and outsurge fatigue effects for a 60-year plant life, and the pressurizer lower head and surge 

line fatigue will be managed using SBF monitoring under the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program. As such, the TLAA has been demonstrated to be acceptable for 

the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.4 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended functions will be adequately managed for the period of 

extended operation.

Based on its review, the staff noted that the applicant‘s fatigue evaluation for the pressurizer 

lower head and surge line used FatigueProTM, which is relied upon for making SBF usage 

calculations for this location and several other locations. The staff noted that NRC Regulatory 

Issue Summary (RIS) 2008-30, ―Fatigue Analysis of Nuclear Power Plant Components,‖ dated 

December 16, 2008, identifies issues with the use of a simplified methodology associated with 
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FatigueProTM. By letter dated July 13, 2009, the staff issued RAI B3.2-2 requesting that the 

applicant: (1) identify the items whose CUF values were calculated using FatigueProTM or 

simplified methodology, including the results shown in LRA Table 4.3-2 and the results 

embedded in the text (not tabulated), and the items that are identified must be re-evaluated in 

accordance with the guidelines described in the ASME Code Section III NB-3200, taking all six 

components of stress into consideration; and (2) make appropriate adjustments and corrections 

regarding the use of the ―stress-based monitoring‖ and ―SBF‖ terminologies, and reliance on the 

SBF methodology for fatigue usage calculations. This action applies to the entire body of the 

LRA, including Commitment No. 28.

In its response dated August 19, 2009, the applicant stated that the reanalysis of locations 

subject to evaluation of the environmental effects on fatigue usage in accordance with

NUREG/CR-6260, ―Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components,‖ that were initially evaluated using SBF monitoring methods, is 

currently in progress. The applicant further stated that the response to RAI B3.2-2 will be 

provided following completion of the reanalysis.

In its response dated February 2, 2010, the applicant stated that the reanalysis of the surge line 

hot leg nozzle and charging line nozzle in accordance with the guidance in ASME B&PV Code 

Section III, Subsection NB-3200 is still in progress and is not yet complete. The staff noted that 

these two locations were the only NUREG/CR-6260 locations that the applicant evaluated with 

SBF monitoring methods. The applicant committed (Commitment No. 41) to perform a fatigue 

analysis of the surge line hot leg nozzle and the charging line nozzle in accordance with ASME 

B&PV Code Section III, Subsection NB-3200 guidance and determine the CUF, considering the 

effects of the reactor coolant environment and confirm that the CUF is less than 1.0 at the end 

of 60 years of plant operation. The staff noted that a summary of results for the reanalysis of the 

surge line hot leg nozzle and charging line nozzle in accordance with the guidance in ASME 

B&PV Code Section III, Subsection NB-3200 will be provided to the staff. The staff identified this 

as Open Item 3.0.3.2.20-1.

The staff‘s evaluation and resolution of Open Item 3.0.3.2.20-1 is documented in SER 

Section 3.0.3.2.20. Open Item OI 3.0.3.2.20-1 is closed.

The staff noted that LRA Section 4.3.1.4 states that the SBF monitoring software module of 

FatigueProTM has been used for critical locations in the pressurizer lower head and in the surge 

line, including the pressurizer and hot leg nozzles. The LRA section states that the highest 

projected 60-year CUF for these locations is 0.318 at a pressurizer heater penetration.

On September 30, 2010, the staff conducted a telephone conference call with the applicant to 

discuss its concerns. The staff was concerned with whether the analysis submitted for the surge 

line hot leg nozzle, which is part of the applicant‘s submittal to satisfy its Commitment No. 41, 

with its environmentally-adjusted CUF of 0.0166 was bounding for all of the locations for which 

an SBF analysis was calculated using FatigueProTM, including the two components discussed in 

LRA Section 4.3.1.4 (i.e., the pressurizer lower head and surge line).

By letter dated October 20, 2010, the applicant supplemented its response to RAI B3.2-2a and 

committed (Commitment No. 51) to the following:

DEK will perform a fatigue evaluation of the pressurizer lower head and surge 

line that is consistent with the requirements of ASME B&PV Code, Section III, 
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4-22

NB-3200 and will determine the cumulative fatigue usage through the period of 

extended operation.

The applicant also stated that this additional evaluation will be performed through its Metal 

Fatigue of Reactor Coolant Pressure Boundary Program to manage metal fatigue associated 

with pressurizer lower head and surge line fatigue in accordance with 10 CFR 54.21 (c)(1)(iii). 

The applicant also stated that the EPRI FatigueProTM SBF monitoring module described in LRA 

Section 4.3.1.4 will not be used to monitor fatigue usage for the pressurizer lower head and 

surge line.

Based on its review, the staff finds the applicant‘s Commitment No. 51 and the disposition of the 

evaluation for the pressurizer lower head and surge line, pursuant to 10 CFR 54.21(c)(1)(iii), 

acceptable because: (1) the applicant committed to calculate the CUF for the pressurizer lower 

head and surge line, consistent with the requirements of the ASME Code Section III, NB-3200;

(2) the applicant will manage the effects of aging for the pressurizer lower head and surge line, 

without the use of SBF; and (3) the applicant will use its Metal Fatigue of Reactor Coolant 

Pressure Boundary Program to monitor the number of transient occurrences to ensure the limits 

used in the analysis are not exceeded and the analysis remains valid.

4.3.1.4.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of pressurizer 

lower head and surge line in LRA Section A.3.2.1.4. The staff noted that the applicant‘s USAR 

supplement is consistent with the recommendations in SRP-LR Section 4.3.3.3. Based on its 

review of the USAR supplement, the staff concludes that the applicant provided an adequate 

summary description of its actions to address the fatigue evaluation of the pressurizer lower 

head and surge line.

4.3.1.4.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the 

intended functions of the pressurizer lower head and surge line will be adequately managed 

during 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).

4.3.1.5 Effects of Reactor Coolant Environment on Fatigue Life of ASME Code Class 1 

Piping and Components

4.3.1.5.1 Summary of Technical Information in the Application

LRA Section 4.3.1.5 summarizes the closure of GSI-190 in 1999, along with stating the staff 

conclusion that licensees should address the effects of the reactor coolant environment on the 

fatigue life of selected components in support of applicants‘ license renewal submittals. The 

section also states that the applicant‘s plant design did not include requirements for fatigue 

analysis for piping locations and that, therefore, the four piping locations‘ evaluations were 

based upon guidance from the ASME B&PV Code Section III, 1989 Edition with 1989 Addenda.
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4-23

In LRA Section 4.3.1.5, the applicant stated that it performed environmentally-assisted fatigue

(EAF) analyses for the plant-specific locations identified in NUREG/CR-6260 for older vintage 

Westinghouse plants as listed below:

● reactor vessel shell and lower head

● reactor vessel outlet nozzle

● reactor vessel inlet nozzle

● surge line hot leg nozzle

● safety injection (SI) cold leg nozzle

● charging line nozzle

● residual heat removal (RHR) system tee at SI accumulator line

The applicant stated that it calculated the environmental fatigue life correction factor, Fen, in 

accordance with NUREG/CR-5704 for stainless steel components and in accordance with 

NUREG/CR-6583 for carbon and low-alloy steel components.

The applicant also stated that since there are no design-basis fatigue analyses for the SI cold 

leg nozzle and the RHR system tee at SI accumulator line, fatigue usage for these two locations 

were now calculated for the LRA as a response to GSI-190 to evaluate the effects of reactor 

water environment on fatigue life of components. The applicant presented the results of the EAF

usage in LRA Table 4.3-2. The applicant used a separate subsection to discuss the results and 

disposition for each NUREG/CR-6260 location listed above.

The applicant dispositioned the following locations pursuant to 10 CFR 54.21(c)(1)(ii):

● reactor vessel shell and lower head 

● reactor vessel inlet nozzle and outlet nozzle

● SI cold leg nozzle

● RHR system tee at SI accumulator line

The applicant stated that the fatigue usages for the reactor vessel shell and lower head, and 

reactor vessel inlet nozzle and outlet nozzle were calculated based on the design transients and 

cycles shown in LRA Table 4.3-1, whereas the fatigue usages for the SI nozzle and RHR 

system tee at SI accumulator line were analyzed using the ASME B&PV Code Section III, 

Subsection NB-3600 rules using the limiting numbers and severity of transients typically defined 

for these locations. The applicant concluded that since the environmentally-assisted CUF for the 

locations listed above are less than the limit of 1.0, the evaluations for these locations are

acceptable, in accordance with 10 CFR 54.21(c)(1)(ii).

The applicant dispositioned the following locations pursuant to 10 CFR 54.21(c)(1)(iii):

● surge line hot leg nozzle

● charging line nozzle

The applicant stated that the fatigue usages for the surge line hot leg nozzle and charging 

nozzle were calculated using the SBF monitoring methodology based on the actual plant 

operating data collected over several years. The applicant concluded that since the surge line 

hot leg nozzle and charging nozzle are monitored as part of the Metal Fatigue of Reactor 
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4-24

Coolant Pressure Boundary Program, the fatigue usage at these two locations will be managed 

for the period of extended operation by the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program, in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.5.2 Staff Evaluation

The staff noted that the applicant conservatively addressed the effects of the reactor coolant 

environment on component fatigue life consistent with the guidance in the SRP-LR and the 

staff‘s recommendations for resolving GSI-190, dated December 26, 1999. The staff also noted 

that, consistent with Commission Order No. CLI-10-17, dated July 8, 2010, the evaluations 

associated with the effects of the reactor coolant environment on component fatigue life do not 

fall within the definition of a TLAA in 10 CFR 54.3(a) because these evaluations are not in the 

applicant‘s CLB. Based on Commission Order No. CLI-10-17, the staff finds the applicant‘s 

evaluation of the effects of the reactor coolant environment on component fatigue life is 

conservative and an acceptable practice consistent with the staff‘s recommendations in the 

SRP-LR and the closure of GSI-190.

The staff reviewed LRA Section 4.3.1.5 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

applicant‘s evaluation is projected to the end of the period of extended operation for the reactor 

vessel shell and lower head, reactor vessel outlet nozzle, reactor vessel inlet nozzle, SI cold leg 

nozzle, and RHR system tee at SI accumulator line. The staff also verified, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation for the surge line hot leg nozzle and the charging 

line nozzle.

Based on its review, the staff noted that the applicant‘s fatigue evaluations for the pressurizer 

surge line hot leg nozzle and the charging line nozzle use FatigueProTM, which is relied upon for 

making SBF usage calculations for these locations. The staff noted that NRC RIS 2008-30, 

―Fatigue Analysis of Nuclear Power Plant Components,‖ dated December 16, 2008, identifies 

issues with the use of a simplified methodology associated with FatigueProTM. By letter dated 

July 13, 2009, the staff issued RAI B3.2-2 requesting that the applicant: (1) identify the items 

whose CUF values were calculated using FatigueProTM or simplified methodology, including the 

results shown in LRA Table 4.3-2 and the results embedded in the text (i.e., not tabulated), and 

the items that are identified must be re-evaluated in accordance with the guidelines described in 

ASME B&PV Code Section III, Subsection NB-3200, taking all six components of stress into 

consideration; and (2) make appropriate adjustments and corrections regarding the use of the 

―stress based monitoring‖ and ―SBF‖ terminologies, and reliance on the SBF methodology for 

fatigue usage calculations. This action applies to the entire body of the LRA, including 

Commitment No. 28.

In its response dated August 19, 2009, the applicant stated that the reanalysis of locations 

subject to evaluation of the environmental effects on fatigue usage in accordance with 

NUREG/CR-6260, ―Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear 

Power Plant Components,‖ that were initially evaluated using SBF monitoring methods, is 

currently in progress. The applicant further stated that the response to RAI B3.2-2 will be 

provided following completion of the reanalysis.

The staff noted that the results of the applicant‘s re-evaluation will be provided upon its 

completion. The staff further noted that the surge line hot leg nozzle and the charging line 

nozzle are the two locations in which FatigueProTM was used for determining the CUFs.
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4-25

In its response dated February 2, 2010, the applicant stated that the reanalysis of the surge line 

hot leg nozzle and charging line nozzle in accordance with the guidance in ASME B&PV Code 

Section III, Subsection NB-3200 is still in progress and is not yet complete. The staff noted that 

these two locations were the NUREG/CR-6260 locations that the applicant evaluated with SBF 

monitoring methods. The applicant committed (Commitment No. 41) to perform a fatigue 

analysis of the surge line hot leg nozzle and the charging line nozzle in accordance with ASME 

B&PV Code Section III, Subsection NB-3200 guidance and determine the CUF, considering the 

effects of the reactor coolant environment and confirm that the CUF is less than 1.0 at the end 

of 60 years of plant operation. The staff noted that a summary of results for the reanalysis of the 

surge line hot leg nozzle and charging line nozzle in accordance with the guidance in ASME 

B&PV Code Section III, Subsection NB-3200 will be provided to the staff. The staff identified this 

as Open Item 3.0.3.2.20-1.

The staff‘s evaluation and resolution of Open Item 3.0.3.2.20-1 is documented in SER 

Section 3.0.3.2.20. Open Item OI 3.0.3.2.20-1 is closed.

In its review of the fatigue analysis results shown in LRA Table 4.3-2, the staff noted that three 

Fen values are used for the components considered as part of NUREG/CR-6260. Specifically, a 

Fen value of 2.455 is used for low-alloy steel locations and a Fen value of 15.35 is used for 

stainless steel locations, except for the RHR tee at SI accumulator line location, in which a Fen 

value of 2.55 is used. The staff noted that the Fen factor is dependent upon the type of material, 

strain rates, temperature of the component considered, and the dissolved oxygen (DO) 

concentration of the reactor water. The staff noted that for the stainless steel locations, except

for the RHR tee at SI accumulator line location, the applicant used the maximum and bounding 

Fen factor of 15.35, as described in NUREG/CR-5704. The staff finds the applicant‘s use of a Fen

factor of 15.35 acceptable because it is conservative and is the bounding and maximum value 

for stainless steel components. The staff noted that for the RHR tee at SI accumulator line 

location, a design-basis fatigue analysis did not exist; therefore, the applicant performed its 

evaluation for the 60-year CUF using the ASME B&PV Code Section III, Subsection NB-3600. 

The staff noted that the applicant used a Fen factor of 2.55 because this location is subjected to 

temperatures less than 200 °C (392 °F), as described in NUREG/CR-5704. The staff further 

noted and confirmed in USAR Table 9.3-2 that the RHR system operates to remove residual 

heat from the RCS from 350 °F to 140 °F, therefore, the applicant‘s use of a ―low-temperature‖ 

(less than 200 °C) is reasonable. The staff noted that the RHR system tee at SI accumulator line 

is downstream of the RHR heat exchanger and the staff confirmed in USAR Table 9.3-2 that the 

temperature of the outlet side of the RHR heat exchanger is less than 200 °C. The staff finds 

that the applicant appropriately analyzed the 60-year CUF for the RHR tee at SI accumulator 

line location and the applicant used the appropriate Fen factor of 2.55 because: (1) the applicant 

used the requirements of the ASME B&PV Code Section III, Subsection NB-3600 to calculate 

the 60-year CUF; and (2) the applicant appropriately calculated the Fen factor, based on 

NUREG/CR-5704, for the operating temperatures for the RHR system.

However, the staff noted that for the low-alloy steel locations, the applicant used a Fen value of 

2.455, based on the equations from NUREG/CR-6583, which assumes that the DO is not 

greater than 0.05 parts per million (ppm). The staff noted that the applicant may have operated 

at DO levels greater than 0.05 ppm during the early years of operation, such that this Fen value 

of 2.455 may not be bounding. By letter dated July 13, 2009, the staff issued RAI 4.3-2 

requesting that the applicant: (1) summarize its experience in controlling the DO level in the 

reactor water since initial plant startup, including describing all water chemistry programs it has 

used, as well as procedures and requirements used for managing DO concentration including 

the inception date of each water chemistry program; (2) provide a historic summary of the DO 
Time-Limited Aging Analyses

4-26

level since the plant startup, including estimating the fraction of time of its operating history, thus 

far, that the DO level exceeded 0.05 ppm; and (3) describe how reactor water samples were 

taken, including the sampling locations. If samples were taken from a single location, justify that 

the DO data discussed in part (2) above are applicable to all NUREG/CR-6260 components for 

the Fen calculations.

In its response dated August 17, 2009, to part (1), the applicant stated that its TSs provide a 

limit of 100 parts per billion (ppb) for DO with the reactor coolant temperature greater than 

250 °F. The applicant stated that reactor coolant DO has been controlled since initial plant 

operation and is currently controlled in accordance with the latest industry guidelines provided in 

EPRI 1002884, ―Pressurized Water Reactor Primary Water Chemistry Guidelines.‖ The 

applicant also stated that reactor coolant chemistry control requires monitoring of water 

chemistry parameters including DO concentration, and these are achieved through routine 

sampling and analysis of the samples for contaminants, as well as through maintaining an 

elevated hydrogen concentration (hydrogen overpressure) in the volume control tank of the 

chemical and volume control system.

In its response dated August 17, 2009, to part (2), the applicant stated that the reactor coolant 

elevated hydrogen concentration is effective in mitigating oxidizing conditions due to radiolysis 

or oxygen ingress. The applicant stated that historically, DO concentrations are significantly less 

than the limit provided in the TS or in the EPRI guidelines. The applicant also stated that based 

on a review of reactor coolant chemistry data from 1984 to 2009, the typical reactor coolant DO 

level during normal operation has been less than 5 ppb (0.005 ppm). The applicant also stated 

that based on the review of chemistry data, there have been no significant periods where the 

RCS operated at a temperature greater than 250 °F and DO level was greater than 50 ppb (0.05 

ppm). The applicant further stated that based on the DO level control method used, the 

sampling frequency and DO level limits specified in the chemistry control program, and the 

historical DO level, it is reasonable to assume that reactor coolant DO level will continue to be 

maintained below 50 ppb (0.05 ppm) at temperatures above 250 °F.

In its response dated August 17, 2009, to part (3), the applicant stated that reactor coolant 

samples are taken on a routine basis either directly from the sample point at the reactor coolant 

―B‖ hot leg connection during normal operation or indirectly via the RHR system sample point 

during startup and shutdown. The applicant also stated that based on flow rates through the 

RCS that promote mixing within the system, the samples obtained are representative of the bulk 

reactor coolant water chemistry. The applicant further stated that the low-alloy steel locations 

that are required to be evaluated for the effects of the reactor coolant environment on fatigue 

usage are the reactor vessel nozzles and reactor vessel shell to lower head transition. At these 

locations, the applicant stated there are no stagnant fluid conditions (i.e., potentially caused by 

dead-leg or creviced geometries). As such, the applicant concluded that the local water 

chemistry at these locations is expected to be consistent with the bulk reactor coolant water 

chemistry conditions and so the DO data discussed are representative of the DO level at these 

locations.

The staff noted that the applicant did not provide the historical DO data for the first 10 years of 

plant operating history. By letter dated December 3, 2009, the staff issued follow-up RAI 4.3-2a 

requesting that the applicant provide justification for the first 10 years of operation that the DO

level in the RCS was maintained at or below 0.05 ppm.

In its response dated January 21, 2010, the applicant stated it maintains an elevated hydrogen 

concentration in the reactor coolant during normal operation to ensure a low concentration of 
Time-Limited Aging Analyses

4-27

DO. The applicant further stated that reactor coolant chemistry data recorded since 1984 was 

reviewed and showed that DO is typically less than 0.005 ppm. The staff noted that the 

applicant has operated its plant since initial startup in 1973 with an elevated hydrogen

concentration.

The staff finds it reasonable that the applicant stated that the operating period of 1973 to 1984 is 

expected to be consistent with the DO data recorded since 1984 because the applicant has 

operated and maintained elevated hydrogen concentration since initial plant start up and the 

applicant‘s review showed the DO level one order of magnitude lower than the threshold in 

NUREG/CR-6583.

Based on its review, the staff finds the applicant‘s responses to RAI 4.3-2 and RAI 4.3-2a 

acceptable because the applicant: (1) provided its operating experience with DO and the limits it 

controls the DO level in the reactor; (2) confirmed in its reactor coolant chemistry data that since 

initial plant startup (i.e., 1973–2009), it is reasonable to state that the DO level was maintained 

one order of magnitude below the threshold the applicant used to calculate the Fen factors for 

low-alloy steel; and (3) confirmed that for the reactor vessel shell and lower head and reactor 

vessel inlet and outlet nozzles, there are no stagnant fluid conditions such that the local water 

chemistry at these locations is consistent with the bulk reactor coolant water chemistry 

conditions and the DO level is representative of the DO concentration at these locations.

Based on its review, the staff found disposition of the applicant‘s evaluation for the reactor 

vessel shell and lower head, reactor vessel outlet nozzle, reactor vessel inlet nozzle, SI cold leg 

nozzle, and RHR system tee at SI accumulator line, pursuant to 10 CFR 54.21(c)(1)(ii), 

acceptable because: (1) the 60-year environmentally-assisted CUF results are within the limit of 

1.0, as shown in LRA Table 4.3-2; and (2) the Fen factors for the reactor vessel shell and lower 

head, reactor vessel outlet nozzle, reactor vessel inlet nozzle, SI cold leg nozzle, and RHR 

system tee at SI accumulator line calculated by the applicant are either bounding or appropriate 

as discussed above.

Based on its review, the staff found disposition of the applicant‘s evaluation for the surge line 

hot leg nozzle and charging line nozzle, pursuant to 10 CFR 54.21(c)(1)(iii), acceptable 

because: (1) the fatigue usage factor analysis was performed in accordance with ASME Code 

Section III, Subsection NB-3200, which utilized six components of a transient stress tensor that 

addressed the staff‘s concern expressed in RIS-2008-30; (2) the CUFs and the EAF usage 

factors for both the surge line hot leg nozzle and the charging line nozzle are below the ASME 

B&PV Code Section III allowable limit of 1.0; (3) the applicant will manage the effects of aging 

for the surge line hot-leg nozzle and the charging line nozzle, without the use of FatiguePro‘sTM 

SBF; and (4) the applicant will use its Metal Fatigue of Reactor Coolant Pressure Boundary 

Program to monitor the number of transient occurrences to ensure the limits used in the 

analysis are not exceeded and the analysis remains valid.

On September 30, 2010, the staff conducted a telephone conference call with the applicant to 

discuss some concerns. The staff was concerned whether the applicant had considered 

environmental effects on fatigue for those locations with a CUF higher than those for the 

NUREG/CR-6260 locations, consistent with SRP-LR Sections 4.3.2.2 and 4.3.3.2 and GALL 

AMP X.M1 to consider environmental effects for the NUREG/CR-6260 locations ―at a minimum.‖
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By letter dated October 20, 2010, the applicant supplemented its response to RAI B3.2-2a and 

committed (Commitment No. 52) to the following:

DEK will perform a review of design basis ASME Class 1 component fatigue 

evaluations to determine whether the NUREG/CR-6260-based components that 

have been evaluated for the effects of the reactor coolant environment on fatigue 

usage are the limiting components for the Kewaunee plant configuration. If more 

limiting components are identified, the most limiting component will be evaluated 

for the effects of the reactor coolant environment on fatigue usage.

The applicant also stated that this additional evaluation will be performed through its Metal 

Fatigue of Reactor Coolant Pressure Boundary Program to manage metal fatigue associated

with the environmental effects on fatigue usage in accordance with 10 CFR 54.21(c)(1)(iii).

Based on its review, the staff finds the applicant‘s Commitment No. 52 acceptable because:

(1) the applicant commited to determine whether the NUREG/CR-6260-based locations, 

evaluated for environmental fatigue, are the limiting locations; (2) if more limiting locations are 

identified, they will be evaluated and managed in accordance with 10 CFR 54.21(c)(1)(iii), with 

its Metal Fatigue of Reactor Coolant Pressure Boundary Program; and (3) Commitment No. 52 

is consistent with SRP-LR Sections 4.3.2.2 and 4.3.3.2 and with GALL AMP X.M1 to consider 

environmental effects for the NUREG/CR-6260 locations at a minimum.

4.3.1.5.3 USAR Supplement

The applicant provided the USAR supplement summarizing its evaluation of the 

NUREG/CR-6260 components in LRA Section A.3.2.1.5. The staff noted that the applicant‘s 

USAR supplement is consistent with the recommendations in SRP-LR Section 4.3.3.3 and 

SRP-LR Table 4.3-2. Based on its review of the USAR supplement, the staff concludes that the 

applicant provided an adequate summary description of its actions to address the fatigue 

evaluation of the NUREG/CR-6260 components.

4.3.1.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the applicant‘s evaluations of the reactor vessel shell and lower 

head, reactor vessel outlet nozzle, reactor vessel inlet nozzle, SI cold leg nozzle, and RHR 

system tee at SI accumulator line are projected to the end of the period of extended operation. 

The staff also concludes that the applicant has acceptably accounted for the effects of the 

reactor coolant environment on fatigue life of ASME Code Class 1 piping and components and 

has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on 

the intended functions of the surge line hot leg nozzle and charging nozzle will be adequately

managed during the period of extended operation. The staff also concludes that the USAR 

supplement contains an appropriate summary description of the applicant‘s evaluation, as 

required by 10 CFR 54.21(d).

The staff concludes that the applicant‘s evaluations on the effects of the reactor coolant 

environment on component fatigue life is not a TLAA as defined by 10 CFR 54.3(a) and is 

consistent with Commission Order No. CLI-10-17 (Entergy Nuclear Vermont Yankee, LLC 

(Vermont Nuclear Power Station) CLI-10-17), dated July 8, 2010 (ADAMS Accession 

No. ML101890775). The staff also concludes that the applicant‘s evaluation on the effects of the 
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reactor coolant environment on component fatigue life is conservative and consistent with the 

recommendations of the SRP-LR and the closure of GSI-190.

4.3.2 Fatigue of Non-ASME Code Class 1 Components

The applicant stated that its results of TLAA evaluations for non-ASME Code Class 1 

components are presented in the following sections:

● Section 4.3.2.1, ―Non-Class 1 Piping‖

● Section 4.3.2.2, ―Auxiliary Heat Exchangers‖

4.3.2.1 Non-Class 1 Piping

4.3.2.1.1 Summary of Technical Information in the Application

LRA Section 4.3.2.1 states that non-ASME Code Class 1 piping systems were designed and 

constructed to the requirements of USAS B31.1.0-1967 and there are no general requirements 

in this code for an explicit fatigue analysis. The applicant further stated that these piping 

systems are required to be evaluated for thermal expansion cycles, and a thermal expansion 

stress range reduction factor is to be applied if cycling is excessive. Furthermore, the applicant 

stated that the code allows 7,000 full temperature thermal expansion cycles without penalty.

The applicant also stated that since a limit is placed on thermal cycles and these cycles can be 

related to time in service for the piping systems, its design in accordance with USAS B31.1 rules 

is, therefore, considered a TLAA.

The applicant stated that a review of non-ASME Code Class 1 piping systems was performed to 

determine whether any systems or components would exceed the number of thermal expansion 

stress cycles assumed in the design. Its review concluded that, with the exception of the reactor 

coolant hot leg sample line, all non-Class 1 piping systems remained within the design cycle 

limit for 60 years of operation. The applicant further stated the reactor coolant hot leg sample 

line was reanalyzed and was found to be acceptable for 60 years with the application of the 

appropriate stress range reduction factor to account for the increased number of thermal 

expansion cycles.

Therefore, the applicant stated its non-ASME Code Class 1 (except for the reactor coolant hot 

leg sample line) piping systems TLAA is acceptable for the period of extended operation, in 

accordance with 10 CFR 54.21(c)(1)(i), and the reactor coolant hot leg sample line TLAA is 

acceptable for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii).

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)(i), that the 

TLAA remains valid during the period of extended operation, and also to verify, pursuant to 

10 CFR 54.21(c)(1)(ii), that the TLAA is projected to the end of the period of extended 

operation.

The staff noted that USAS B31.1.0-1967 Code imposes reduction factors to the allowable 

thermal stress-range according to rules defined in the Code when the total number of thermal 
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cycles is larger than 7,000 cycles. The required stress-range reduction factor for a given number 

of full temperature cycles is listed in SRP-LR Table 4.3-1.

The staff finds the applicant‘s disposition of the non-ASME Code Class 1 piping, except for the 

reactor coolant hot leg sample line, fatigue TLAA pursuant to 10 CFR 54.21 (c)(1)(i) acceptable 

because as shown in LRA Table 4.3-1, the 60-year projected cycles are well below the cycles 

used in the original design analysis by a significant margin.

However, for the reactor coolant hot leg sample line, LRA Section 4.3.2.1 states the 

re-evaluation was performed to account for the increased number of thermal expansion cycles. 

The staff noted that the applicant did not provide information regarding the details of the 

re-evaluation to disposition this TLAA in accordance with 10 CFR 54.21(c)(1)(ii). By letter dated 

July 13, 2009, the staff issued RAI 4.3-3 requesting that the applicant: (1) describe the sampling 

practice, including number of times sampling activity takes place each day or each week and 

estimate the total number of thermal cycles projected for 60 years, including those due to the 

sampling operations and those due to other means; (2) provide the maximum stress intensity 

range induced by those thermal cycles; and (3) specify the allowable stress range, and the 

stress-range reduction factor used in the re-evaluation described in LRA Section 4.3.2.1.

In its response by letter dated August, 17, 2009, the applicant stated that reactor coolant hot leg 

samples are taken seven times per week (i.e., one sample per day during normal operation). 

The applicant stated that this equates to 21,840 samples in a 60-year period but the analysis of 

the reactor coolant hot leg sample line conservatively assumed 43,680 full temperature cycles 

to account for non-routine sampling. The applicant further stated that the maximum stress range 

was 20,104 pounds per square inch (psi), which was determined based on the USAS B31.1 

Code (1967 Edition). The applicant further stated that the allowable stress range is 26,683 psi, 

which reflected a stress range reduction factor, f = 0.7, corresponding to 22,000 to 45,000 full 

temperature cycles.

Based on its review, the staff finds the applicant‘s response to RAI 4.3-3 acceptable because: 

(1) the applicant provided the details of its re-evaluation, (2) the applicant‘s analysis assumed a 

conservative number of full temperature cycles (double the once-a-day sample practice for 

60 years of operation) in its evaluation, (3) the applicant applied the appropriate stress-range 

reduction factor that corresponds to 22,000 to 45,000 full temperature cycles, and (4) the 

maximum stress range induced by the thermal cycles is less than the allowable stress range. 

The staff‘s concern described in RAI 4.3-3 is resolved.

4.3.2.1.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of non-Class 1 

piping in LRA Section A.3.2.2.1. The staff noted that the applicant‘s USAR supplement is 

consistent with the recommendations in SRP-LR Section 4.3.3.3. Based on its review of the 

USAR supplement, the staff concludes that the applicant provided an adequate summary 

description of its actions to address the fatigue evaluation of the non-Class 1 piping.

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)(i), that the analyses of non-Class 1 piping, except for the reactor coolant hot 

leg sample line, will remain valid during the period of extended operation. The staff also 

concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 
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analyses of the reactor coolant hot leg sample line is 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).

4.3.2.2 Auxiliary Heat Exchangers

4.3.2.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2.2 states that heat exchangers in auxiliary systems were designed in 

accordance with ASME Code Section III Class C and/or Section VIII rules, which do not require 

an explicit fatigue analysis. However, the applicant stated that the equipment specification for 

the RHR, letdown, regenerative, excess letdown, and primary sample heat exchangers included 

thermal and pressure transient conditions as an input to the component design, therefore, the 

specified transient occurrences are considered a TLAA and have been evaluated for the period 

of extended operation.

The applicant stated the transient occurrences specified for the design of these auxiliary heat 

exchangers are either conservatively large when compared to actual operating conditions, or 

are bounded by the transient occurrences monitored by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program, with the exception of the primary sample heat exchanger in the 

reactor coolant hot leg sample stream. The applicant further stated that based on current 

sampling practice, it is anticipated that the number of specified transient occurrences for the 

reactor coolant hot leg primary sample heat exchanger will be exceeded prior to the end of the 

period of extended operation.

The applicant stated that, therefore, the auxiliary heat exchangers TLAA, with the exception of 

the primary sample heat exchanger, will remain valid during the period of extended operation in 

accordance with 10 CFR 54.21(c)(1)(i). The applicant further stated the primary sample heat 

exchanger transient cycles will be tracked in accordance with the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program and corrective actions (including reanalysis, replacement, 

or repair) will be initiated prior to exceeding the specified number of transient occurrences; 

therefore, the effects of transient cycles on the function of the sample heat exchanger will be 

managed in accordance with 10 CFR 54.21(c)(1)(iii).

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 

TLAA remains valid during the period of extended operation and to verify, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequately 

managed for the period of extended operation.

Based on its review, the staff finds that the applicant‘s disposition of the auxiliary heat 

exchangers, except for the primary sample heat exchanger, pursuant to 10 CFR 54.21(c)(1)(i), 

is acceptable because: (1) as shown in LRA Table 4.3-1, the 60-year projected cycles are well 

below the cycles used in the original design analysis by a significant margin and the applicant‘s 

Metal Fatigue of Reactor Coolant Pressure Boundary Program will continue to track and confirm 

by continued monitoring to ensure that these transients will not exceed the design cycles for the 

remaining plant life; and (2) corrective actions will be taken consistent with its Metal Fatigue of 

Reactor Coolant Pressure Boundary Program.
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For the primary sample heat exchanger, since the thermal cycles may not be bounded by the 

design cycles, the applicant stated that it will manage this component in accordance with 

10 CFR 54.21(c)(1)(iii). Based on its review, the staff finds that the applicant‘s disposition of the 

primary sample heat exchanger, pursuant to 10 CFR 54.21(c)(1)(iii), is acceptable because the 

applicant‘s Metal Fatigue of Reactor Coolant Pressure Boundary Program will continue to track 

and confirm by continued monitoring to ensure that these transients will not exceed the design 

cycles for the remaining plant life, and corrective actions (including reanalysis, replacement, or 

repair) will be initiated prior to exceeding the specified number of transient occurrences.

4.3.2.2.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of auxiliary heat 

exchangers in LRA Section A.3.2.2.2. Based on its review of the USAR supplement, the staff 

concludes that the applicant provided an adequate summary description of its actions to 

address the fatigue evaluation of the auxiliary heat exchangers.

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 the analyses of auxiliary heat exchangers, except for the primary 

sample heat exchanger, will remain valid during the period of extended operation. The staff also 

concludes that for the primary sample heat exchanger, the applicant has demonstrated, 

pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue on the intended 

functions will be adequately managed during 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 EQ requirements established by 10 CFR Part 50, Appendix A, Criterion 4 and 

10 CFR 50.49 specifically require each applicant to establish a program to qualify electrical 

equipment so that such equipment, in its end of life, will meet its performance specifications 

during and following design-basis accidents. The 10 CFR 50.49 EQ Program is a TLAA for 

purposes of license renewal. Electrical equipment with a qualified life equal to or greater than 

the duration of the current operating term is covered by TLAAs. The TLAA of the EQ of electrical 

components includes all long-lived, passive, and active electrical and instrumentation and 

control (I&C) components that are important to safety and are located in a harsh environment. 

The harsh environment includes those areas subject to environmental effects caused by loss of 

coolant accidents (LOCAs), high-energy line breaks (HELBs), and post-LOCA radiation.

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of TLAAs. In addition, 

10 CFR 54.21(c)(1) requires that the applicant demonstrate one of the following for each TLAA: 

(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 functions will be adequately managed for the period of extended operation.
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4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 summarizes the applicant‘s evaluation of EQ of electric equipment for the 

period of extended operation and states that the KPS Environmental Qualification (EQ) of 

Electric Components Program is an existing program established to meet KPS commitments for 

10 CFR 50.49. The applicant stated that the KPS EQ Program manages component thermal, 

radiation, and cyclic aging, as applicable, through the use of aging evaluations based on 

10 CFR 50.49(f) qualification methods. The applicant also stated that, as required by 

10 CFR 50.49, EQ components not qualified for the current license term are to be refurbished, 

replaced, or have their qualification extended prior to reaching the age limits established in the 

evaluation. The applicant further stated that equipment qualification evaluation for EQ 

components that specify qualification of at least 40 years, but less than 60 years, are 

considered a TLAA for license renewal. The applicant, therefore, concluded that in accordance 

with 10 CFR 54.21(c)(1)(iii), implementation of the EQ Program provides reasonable assurance 

that the effects of aging on components associated with the EQ TLAA will be adequately 

managed such that the intended functions can be maintained for the period of extended 

operation.

4.4.2 Staff Evaluation

The staff reviewed LRA Section 4.4 and program basis documents to determine if the 

applicant‘s EQ Program meets the requirements of 10 CFR 54.21(c)(1). The staff reviewed the 

applicant‘s EQ Program to determine whether it is implemented in accordance with the 

requirements of 10 CFR 54.21(c)(1)(iii), and whether it shows that components evaluated under 

the applicant‘s TLAA evaluation are adequately managed during the period of extended 

operation. The staff reviewed the applicant‘s EQ Program conformance to the requirements of 

10 CFR 50.49, including the management of aging effects, to confirm that electric equipment 

requiring EQ will continue to operate consistent with the CLB during the period of extended 

operation.

The staff also conducted a review of the information provided in LRA Section B3.1 and the 

program basis documents provided to the staff during the audit. The staff‘s evaluation of this 

AMP is contained in SER Section 3.0.3.1.13. Based on its review of LRA Section B3.1, including 

audit results, the staff concludes that the applicant‘s Environmental Qualification (EQ) of Electric 

Components Program elements are consistent with GALL AMP X.E1, ―Environmental 

Qualification (EQ) of Electric Components.‖ Therefore, the staff finds that the EQ Program is 

capable of managing the qualified life of components within the scope of the program for license 

renewal and that the continued implementation of the EQ Program provides assurance that the 

aging effects will be managed and that electric equipment will continue to perform its intended 

functions for the period of extended operation.

4.4.3 USAR Supplement

In LRA Appendix A, Section A4.1, the applicant provided the USAR supplement for the EQ of 

electric components TLAA. GALL AMP X.E1 states that reanalysis of an aging evaluation is 

normally performed to extend the qualification by reducing excess conservatism incorporated in 

the prior evaluation. Important attributes of a reanalysis include analytical methods, data 

collection and reduction methods, underlying assumptions, acceptance criteria, and corrective 

actions (if acceptance criteria are not met). The applicant‘s USAR supplement includes aging 
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evaluation reanalysis as a routine part of the EQ Program that addresses attributes of analytical 

methods, data collection and reduction methods, underlying assumptions, acceptance criteria, 

and corrective actions consistent with GALL AMP X.E1 and SRP-LR Table 4.4-2.

The staff determines that the information in the USAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

4.4.4 Conclusion

On the basis of its review of the applicant‘s Environmental Qualification (EQ) of Electric 

Components Program, the staff concludes that the applicant has demonstrated that the effects 

of aging will be adequately managed so that the intended functions will be maintained pursuant 

to 10 CFR 54.21(c)(1)(iii) for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed LRA Section A4.1, the USAR supplement 

referenced for LRA Section 4.4, and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d), and, therefore, is acceptable.

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 LRA states that the KPS reactor containment vessel (RCV) is 

a metal containment designed without the use of prestressed concrete containment tendons. 

4.5.2 Staff Evaluation

The KPS containment has no prestressed tendons; therefore, the staff finds that this TLAA is 

not required.

4.5.3 USAR Supplement

The staff concludes that no USAR supplement is required because KPS does not have any 

prestressed tendons in its containment building.

4.5.4 Conclusion

On the basis of its review, as discussed above, the staff concludes this TLAA is not required.
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4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analysis

4.6.1 Reactor Containment Vessel Fatigue

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6 summarizes the evaluation of the primary containment for the KPS reactor, 

which consists of a cylindrical steel pressure vessel and is referred to as the RCV. The function 

of the RCV is to confine radioactive materials that could be released by accidental loss of 

integrity of the RCPB. The LRA further states that the RCV is completely enclosed within the 

concrete shield building. A 5-foot annular space is provided between the RCV and the shield 

building.

LRA Section 4.6 states that the RCV design included an analysis which determined that a 

cyclical fatigue analysis was not required, per ASME Code Section III, Subsection B, 

Paragraph N-415.1. The original design assumed 40 cycles of vessel pressurization from 

atmospheric to design pressure. The LRA further states that this condition will only occur during 

integrated leak rate tests, which are performed on a 10-year basis, or during an accident. 

Therefore, the applicant concluded that the 40-cycle limit is conservative and will remain valid 

during the period of extended operation. The original design also specified the number of 

temperature variations from 50 °F to 120 °F as 200 cycles. LRA Table 4.3-1 projects 110 heatup 

and 108 cooldown occurrences for a 60-year span; therefore, the applicant stated the 

assumption will remain valid during the period of extended operation. The applicant further 

stated that these results demonstrate that the exemption from fatigue analysis will remain valid 

for the period of extended operation. Therefore, the applicant dispositioned the RCV fatigue 

TLAA in accordance with 10 CFR 54.21(c)(1)(i).

4.6.1.2 Staff Evaluation

The staff reviewed LRA Section 4.6.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses will remain valid for the period of extended operation. The staff reviewed USAR 

Table 4.1-8 and verified that the original plant design was for 200 heatup/cooldown cycles. The 

staff found that the projected thermal cycles of 110 will remain below the original design value. 

The staff also found that the projected number of pressurizations is less than the design value of 

40 cycles. Since the number of projected cycles remains below the original design assumptions, 

the staff finds the existing exemption from fatigue analysis for the RCV will remain valid for the 

period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

4.6.1.3 USAR Supplement

The applicant also provided a USAR supplement summary description of its TLAA evaluation of 

the RCV fatigue 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 the RCV 

fatigue is adequate because the applicant has provided information equivalent to that in 

Table 4.6-1 of SRP-LR Section 4.6.
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4.6.1.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for the RCV fatigue TLAA, the analysis of 

the unit‘s RCVs remains valid through 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).

4.6.2 Containment Penetration Fatigue

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6 summarizes the evaluation of containment penetration fatigue analysis for the 

period of extended operation. The LRA states that hot piping penetration assemblies were 

designed in accordance with USAS B31.1.0, which begins to decrease code allowable stresses 

when thermal cycles become greater than 7,000. This section also states that, for penetration 

assemblies, no fatigue analyses or specified cyclic loading limits were identified. The LRA states 

the evaluation of loading for the associated piping (in LRA Section 4.3.2.1) indicates that 7,000 

thermal cycles will not be exceeded during the period of extended operation for any of the 

penetrations. Therefore, the applicant concluded that this TLAA will remain valid through the 

period of extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

4.6.2.2 Staff Evaluation

The staff reviewed LRA Section 4.6, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses will remain valid for the period of extended operation. During its review, the staff 

verified that the hot piping penetration thermal cycles correlate to the RCS thermal cycles, 

including reactor trips. Per USAR Table 4.1-8, the original design thermal cycles for the RCS 

are 200, and the original design number of reactor trips is 400. The 60-year projected cycles by 

the applicant in LRA Table 4.3-1 are 110 for heatup, 108 for cooldown, and 114 for reactor trips. 

These values bound the number of thermal cycles for the containment penetrations and are not 

at all expected to exceed the 7,000 limit during the period of extended operation. Since the 

number of applicable design transients and the number of predicted transients remain below the 

code allowable limit of 7,000, the staff finds that the TLAA will remain valid for the period of 

extended operation, in accordance with 10 CFR 54.21(c)(1)(i).

4.6.2.3 USAR Supplement

The applicant provided a USAR supplement summary description of the TLAA evaluation of the 

containment penetration fatigue 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 the containment penetration fatigue is adequate because the applicant has provided 

information equivalent to that in Table 4.6-1 of SRP-LR Section 4.6.

4.6.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for the containment penetration fatigue 

TLAA, the analyses remain valid through the period of extended operation. The staff also 
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concludes that the USAR supplement contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d), and, therefore, is acceptable.

4.7 Other Plant-Specific Time-Limited Aging Analyses

4.7.1 Crane Load Cycle Limit

4.7.1.1 Summary of Technical Information in the Application 

In LRA Section 4.7.1, the applicant stated that overhead cranes were originally designed to 

Specification 61 of the Electric Overhead Crane Institute (EOCI). EOCI-61 did not require a 

specific fatigue or load-cycle analysis. However, the applicant stated that the cranes subject to 

the requirements of NUREG-0612 were subsequently evaluated according to the guidelines of 

Specification 70 of the Crane Manufacturers Association of America (CMAA-70), which includes 

an evaluation of load cycles. The applicant also stated that the containment building polar 

crane, turbine building crane, and auxiliary building crane are considered to be within the scope 

of NUREG-0612 and were evaluated for load cycles in accordance with CMAA-70. These three 

cranes are considered Class A service cranes for CMAA-70 and are designed for 20,000 to 

100,000 cycles. The applicant further stated that the 125-ton auxiliary building crane was 

upgraded, and incorporated CMAA-70 and ASME NOG-1, ―Rules for Construction of Overhead 

and Gantry Cranes (Top Running Bridge, Multiple Girder),‖ in the new design and noted that the 

ASME Code does not require any reduction in allowable stresses due to fatigue for less than 

20,000 cycles over the life of the crane.

The applicant stated that it has determined a conservative estimate of the crane usage to be 

less than 800 significant lifts (i.e., lifts greater than 25 percent of the capacity) for the 

containment building polar crane, turbine building crane, and auxiliary building crane over the 

40-year period of operations. This is considerably less than 20,000 full load cycles. Therefore, 

the applicant concluded that the crane load cycle TLAA remains acceptable, in accordance with 

the requirements of 10 CFR 54.21(c)(1)(i).

4.7.1.2 Staff Evaluation

The staff reviewed LRA Section 4.7.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses remain valid for the period of the extended operation. According to LRA Section 4.7.1, 

the 230-ton polar crane, 125-ton turbine building crane, and 125-ton auxiliary building crane are 

all within the scope of NUREG-0612, ―Control of Heavy Loads at Nuclear Power Plants: 

Resolution of Generic Technical Activity A-36,‖ and have been evaluated according to CMAA. 

The applicant further stated in LRA Section 4.7.1 that these cranes will be used to lift significant 

heavy loads (greater than 25 percent of the rated capacity) less than 800 times during the 

current licensing period of 40 years, and the expected number of lifts at the end of the period of 

extended operation (60 years) is not likely to exceed 1,200. The staff noted that this is 

considerably less than the lower bound of the crane design life of 20,000 cycles. Therefore, the 

crane load cycle TLAA remains acceptable, in accordance with the requirements of 

10 CFR 54.21(c)(1)(i).
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4.7.1.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA evaluation for the 

crane load cycle limit in LRA Section A.3.5.1. On the basis of its review of the USAR 

supplement, the staff concludes that the summary description of the applicant‘s actions to 

address the crane load cycles is adequate because the number of significant lifts over the 

60-year period of operation will not exceed the original design limit of 20,000 cycles.

4.7.1.4 Conclusion

Based on its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the crane load cycle analyses remain 

valid for the 60-year period of 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 Reactor Coolant Pump Flywheel

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 states the potential for crack propagation in the reactor coolant pump motor 

flywheel was evaluated due to the potential for flywheel failure that could inhibit pump coast 

down or result in missile generation. The applicant stated that WCAP-14535 updated the 

original flywheel crack growth analysis to credit the LBB analysis that results in a limited 

postulated break size and lower reactor coolant pump overspeed conditions, and to account for 

a 60-year operating life of the motor flywheel. The applicant further stated the evaluation 

established a basis for the elimination of the 40-month inservice inspection (ISI) requirements 

for the flywheel.

The applicant stated that WCAP-14535 was reviewed and approved by the staff and reissued 

as WCAP-14535-A, which includes the NRC SER and response to NRC RAIs. The applicant 

further stated that in the safety evaluation, the staff continued to require a flywheel inspection to 

be performed on a reduced frequency of 10 years. Subsequently, WCAP-15666 was developed 

to provide a technical basis and risk assessment for extending the flywheel inspection interval to 

20 years in order to coincide with the typical 10- to 15-year reactor coolant pump motor 

refurbishment schedule and this evaluation was reviewed and approved by the NRC and 

reissued as WCAP-15666-1A.

The applicant stated the reactor coolant pump motor flywheels are inspected on a 20-year 

frequency through its ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program. The applicant further stated the potential aging effect of cracking will be managed with 

the application of an AMP for the period of extended operation such that the reactor coolant 

pump motor flywheel crack growth TLAA is resolved, in accordance with 10 CFR 54.21(c)(1)(iii).

4.7.2.2 Staff Evaluation

The staff reviewed LRA Section 4.7.2 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of aging on the intended functions of the reactor coolant pump flywheel will be 

adequately managed for the period of extended operation.
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The staff noted that Topical Report WCAP-15666-1A provides analyses of the fatigue crack 

initiation and growth in the flywheel bore keyway from stresses due to starting the motor. The 

staff further noted that based on the results of the analyses, the fatigue crack growth in the 

flywheel after 6,000 starts of the reactor coolant pump (60-year plant life) was determined using 

the approved methodology of the ASME Code Section XI is negligible (0.08 inch) even when 

assuming a conservative initial crack length of 10 percent through the flywheel.

In its safety evaluation, dated May 5, 2003, ―Safety Evaluation of Topical Report WCAP-15666, 

 ̳Extension of Reactor Coolant Pump Motor Flywheel Examination‘ (TAC NO. MB2819),‖ the 

staff determined the reactor coolant pump flywheel conditional failure probability analysis in the 

report to be conservative in its assumptions of input parameters (e.g., pump motor revolutions 

per minute, number of cycles per year, initial crack length) required to predict critical crack sizes 

through the period of extended operation, and that this probabilistic approach supported the 

negligible fatigue crack growth analysis previously mentioned. The staff finds the fatigue crack 

growth TLAA for the applicant‘s reactor coolant pump flywheels to be in accordance with 

10 CFR 54.21(c)(1)(iii), and that the effects of aging on the intended functions of the reactor 

coolant pump flywheel will be adequately managed for the period of extended operation by the 

ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, and finds it to 

be acceptable on the basis of the staff‘s acceptance of the WCAP-15666 analyses. 

4.7.2.3 USAR Supplement

The applicant provided the USAR supplement summarizing its TLAA evaluation of reactor 

coolant pump motor flywheel fatigue crack growth analysis in LRA Section A.3.5.2. Based on its 

review of the USAR supplement, the staff concludes that the applicant has provided an 

adequate summary description of its actions to address the fatigue evaluation of the reactor 

coolant pump motor flywheel fatigue crack growth analysis.

4.7.2.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the reactor coolant pump motor flywheel 

fatigue crack growth analysis will be adequately managed during 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).

4.7.3 Leak-Before-Break

4.7.3.1 Summary of Technical Information in the Application

In LRA Section 4.7.3, the applicant stated that Criterion 4 of 10 CFR Part 50, Appendix A allows 

for the use of the LBB methodology for excluding the dynamic effects of postulated ruptures in 

RCS piping. The applicant stated that it referred to LBB guidance methodology contained in 

NUREG-1061, ―Report of the U.S. Nuclear Regulatory Commission Piping Review Committee,‖ 

Volume 3, and NUREG-0800, ―Standard Review Plan,‖ (SRP) Section 3.6.3. The applicant also 

stated that, based upon the fundamental premise of LBB methodology that the materials used in 

nuclear power plant piping are sufficiently tough enough to withstand a large through-wall crack,

remaining stable without progressing to a double-ended pipe rupture, it limited application of the 

LBB methodology ―to those high-energy fluid systems not considered to be susceptible to failure 
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from such mechanisms as corrosion, water hammer, fatigue, thermal aging; or indirectly from 

such causes as missile damage or the failure of nearby components.‖

The applicant stated that it applied LBB methodology to the following piping systems: reactor 

coolant loop piping, pressurizer surge line piping, and reactor coolant loop branch piping, 

including portions of the SI and RHR systems.

Finally, the applicant stated that since there are time-based inputs to its LBB analyses 

(consisting of both thermal aging effects of cast austenitic stainless steel (CASS) materials and 

thermal and mechanical cycling assumptions of fatigue crack growth predictions) and the factors 

typically reflect a 40-year lifetime, it concluded it would treat its LBB analyses as TLAAs and 

evaluate them for the period of extended operation.

4.7.3.2 Staff Evaluation

Pursuant to 10 CFR 54.21(c)(1)(i), the staff reviewed LRA Section 4.7.3 to verify that the 

applicant‘s TLAA of LBB analyses for the reactor coolant loop piping, pressurizer surge line 

piping, and reactor coolant loop branch piping remain valid for the period of extended operation. 

Pursuant to 10 CFR 54.21(c)(1)(iii), the staff verified that the effects of aging on the intended 

function of the subject piping will be adequately managed for the period of extended operation. 

The TLAA of the LBB piping and associated analyses are fatigue crack growth analyses of the 

subject piping and thermal aging of the CASS material of the RCS components because these 

two issues are time-dependent. In addition, the staff also reviewed the impact of primary water 

stress-corrosion cracking (PWSCC) and power uprate on the subject piping. As part of its 

review, the staff asked the applicant to address the current status of the LBB piping structural 

integrity, the inspection history and results of the LBB piping, and future inspection schedules 

for each of the LBB pipes. By letter dated August 6, 2009, the applicant responded that the 

piping in the scope of the LBB analyses at KPS has been inspected in accordance with the 

requirements of the approved ASME Code Section Xl ISI program since initial plant operation. 

This piping is subject to the inspection requirements of the Inservice Inspection Program 

through the period of extended operation. There are currently no identified unresolved 

reportable indications or flaws existing in this LBB piping. The staff finds that the LBB piping has 

maintained structural integrity because there are no reportable indications in the subject LBB 

piping. The applicant will follow the ASME Code Section XI ISI program to perform necessary 

inspection during the period of extended operation. Therefore, the staff finds that the structural 

integrity of LBB piping has been, and will be, maintained satisfactorily.

LRA Section 4.7.3.1, ―LBB-Reactor Coolant Loop Piping,‖ states that the LBB evaluations have 

been updated to support the power uprate program and steam generator replacement. In a 

letter dated July 7, 2009, the staff issued RAI 4.7.3.1-1 requesting that the applicant address the 

impact of the power uprate and steam generator replacement on all the LBB piping (including 

branch lines and surge line) and fatigue flaw growth analysis at the end of 60 years.

The applicant responded to the RAI by letter dated August 6, 2009, stating that the KPS power 

uprate and steam generator replacement projects were completed in 2004 and 2001, 

respectively. The applicant further stated that the impact of power uprate and steam generator 

replacement on the plant, including the LBB analyses, were evaluated and incorporated into the 

CLB at the time these projects were completed. The applicant submitted proprietary and 

non-proprietary versions of a Westinghouse report, WCAP-16738-P and WCAP-16738-NP, 

respectively, ―Technical Bases for Eliminating Large Primary Loop Pipe Rupture as the 

Structural Design Basis for the Kewaunee Power Station for the License Renewal Program‖
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(ADAMS Accession No. ML092230619). The report evaluated the impact that an additional 20 

years of plant operation would have on the reactor coolant loop and pressurizer surge line LBB 

analyses, with consideration of power uprate and steam generator replacement.

The staff finds that the WCAP-16738 report includes the operating conditions of power uprate in 

analyzing reactor coolant loop piping, including the branch piping, during the period of extended 

operation. The report showed that the subject LBB piping maintains the safety margin of 

SRP Section 3.6.3 and is, therefore, acceptable.

LRA Section 4.7.3.1 states that Westinghouse has updated the LBB analysis to support the 

steam generator replacement project in WCAP-15311 and the power uprate program in 

WCAP-16040-P. LRA Section 4.7.3.1 states that a review of the above documents identified 

that the fracture toughness values for the CASS loop piping were based on a 40-year plant 

service life. LRA Section 4.7.3.1 further states that the fracture toughness for the fully-aged 

condition was used and that mechanical properties were determined at operating temperatures. 

By letter dated July 7, 2009, the staff issued RAI 4.7.3.1-2 requesting that the applicant discuss 

whether the fracture toughness values used in the LBB evaluations were the values at the end 

of the 60-year plant life. The staff also questioned why the mechanical properties were 

determined at operating temperatures and not at the temperature at faulted conditions.

By letter dated August 6, 2009, the applicant responded to RAI 4.7.3.1-2 and stated that, as 

indicated in LRA Section 4.7.3.1, fully-aged fracture toughness values were used in the updated 

LBB analysis. ―Fully-aged‖ refers to the cast stainless steel fracture toughness properties 

corresponding to the maximum thermal aging condition, whcih is determined based on the 

methodology presented in NUREG/CR-4513, Revision 1, ―Estimation of Fracture Toughness of 

Cast Stainless Steels During Thermal Aging in LWR Systems.‖ Accordingly, the fully-aged 

material fracture toughness values used in the LBB evaluation are conservative and envelop the 

material condition at the end of the 60-year plant life. The applicant stated that there is no CASS 

material in the pressurizer surge line piping or the reactor coolant loop branch line piping.

The fracture toughness of cast stainless steel is adversely affected by long-term exposure to a 

high temperature environment, resulting in thermal embrittlement. Since faulted conditions are 

short-lived, the long-term high temperature environment that the reactor coolant loop piping is 

exposed to is the normal reactor coolant operating temperature. For this reason, the short-lived 

faulted conditions are not expected to contribute significantly to thermal embrittlement of the 

piping. Therefore, the mechanical properties were determined using the normal operating 

temperatures.

The staff finds that the applicant used, in the LBB analyses, the fully-aged fracture toughness 

values of the CASS corresponding to the worst thermal aging condition, which bounds the 

thermal aging from 60-year operation. This is conservative and is acceptable. The staff also 

finds that the mechanical properties taken at normal operating temperature are reasonable 

values to use in the LBB evaluation because it is the normal operating conditions that contribute 

significantly to thermal embrittlement of the CASS.

LRA Section 4.7.3.1 states that the LBB analysis for the period of extended operation is 

discussed in Westinghouse report WCAP-16738. The applicant stated that the report 

documents the plant-specific geometry, operating parameters, loading, and material properties 

used in the fracture mechanics evaluation. However, it was not clear to the staff as to the impact 

of 60-year operation on the above parameters in the original LBB analysis. Also, the staff 

questioned whether WCAP-16738 considered the effects of power uprate and steam generator 
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replacement. By letter dated July 7, 2009, the staff issued RAI 4.7.3.1-3 to request this 

information.

By letter dated August 6, 2009, the applicant clarified that the impact of 60-year operation is 

potentially significant to CASS piping material properties (i.e., fracture toughness) due to the 

prolonged exposure to a high temperature environment resulting in thermal aging of the 

material. The reactor coolant loop piping includes CASS material and has been evaluated for 

the effects of thermal aging. As indicated in LRA Section 4.7.3.1, thermal aging resulting from 

60-year operation was considered in the LBB analysis for the reactor coolant loop piping and 

the results of the analysis were found to remain acceptable.

During the period of extended operation, there are no anticipated changes to operating 

parameters or loading on the reactor coolant loop piping, surge line piping, or reactor coolant 

loop branch line piping for which there are LBB analyses. Therefore, there is no impact due to 

60-year operation on operating parameters and loadings for this piping.

The staff finds that the applicant has clarified that there are no anticipated changes to operating 

parameters or loading on the subject LBB piping until the end of the period of extended 

operation. Therefore, this issue is closed.

LRA Section 4.7.3.2, ―LBB–Pressurizer Surge Line Piping,‖ discusses the applicant‘s evaluation 

of the pressurizer surge line. Operating experience in PWRs has shown that thermal 

stratification in the surge line has occurred, which can affect the structural integrity of the surge 

line piping. By letter dated July 7, 2009, the staff issued RAI 4.7.3.2-1 requesting that the 

applicant discuss operating procedures implemented to prevent or mitigate thermal stratification 

events. By letter dated August 6, 2009, the applicant responded that as discussed in LRA 

Section 4.7.3.2, the pressurizer surge line crack growth predictions were based on the 

design-basis operational transients for the NSSS, including the effects of thermal stratification. 

KPS operating procedures have historically limited the temperature difference between the 

reactor coolant loop and the pressurizer during plant startup and shutdown to minimize the 

effects of pressurizer insurge and outsurge and thermal stratification in the surge line. LRA 

Section 4.3.1.4, ―Pressurizer Lower Head and Surge Line,‖ states that operating procedures 

were changed at the end of Cycle 28 (March 2008). These changes were implemented to 

further limit differential temperature between the reactor coolant loop and the pressurizer, and 

reduce the occurrence of pressurizer insurge and outsurge and surge line thermal stratification.

The staff finds that the applicant has implemented the necessary procedures to minimize 

thermal stratification in the surge line and has analyzed the surge line including thermal 

stratification loadings. Therefore, the issue regarding the impact of thermal stratification is 

closed.

LRA Section 4.7.3.3, ―LBB–Reactor Coolant Loop Branch Piping,‖ states that the fatigue growth 

evaluation for the 8-inch RHR lines and the 12-inch SI accumulator lines show that only a 

limited number of RHR initiation transients could be tolerated. The applicant stated further that 

growth of a postulated crack would remain well within critical crack size limits for a period of 

10 years. By letter dated July 13, 2009, the staff issued RAI 4.7.3.3-1 requesting that the 

applicant clarify why the 8-inch and 12-inch branch piping can tolerate only a limited number of 

RHR initiation transients, but the analysis still concludes that growth of a postulated crack would 

remain well within the critical crack size.
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By letter dated August 6, 2009, the applicant responded that the growth of postulated surface 

cracks by fatigue was evaluated in the reactor coolant branch lines LBB analysis, entitled, 

―Leak-Before-Break Evaluation 6-inch to 12-inch Safety Injection and Residual Heat Removal 

Piping Attached to the RCS (Kewaunee Nuclear Power Plant),‖ SIR-00-045, which is consistent 

with the guidance provided in NUREG-1061, ―Report of the U.S. Nuclear Regulatory 

Commission Piping Review Committee,‖ Volume 3, Section 5.6, ―Crack Growth Analysis.‖

The applicant stated that since the branch line piping was designed to the requirements of

American National Standards Institute (ANSI) B31.1, 1967 Code (code of record), no specific 

fatigue evaluation or transient definitions exist in the design basis for the branch piping. 

Transient information specific to the LBB analysis was developed to perform the crack growth 

evaluation. The transients used in the crack growth evaluation consist of those specified for the 

ASME Code Class 1 vessel analyses as described in LRA Section 4.3.1.1, ―Component Design 

Transient Cycles,‖ and three additional thermal cycles specific to the operational conditions for 

this piping: RHR operation, refueling flood-up, and high head SI initiation. The RHR operation 

thermal cycle was assumed to occur coincident with each heatup or cooldown cycle.

For the 12-inch SI accumulator line, when initial flaw sizes meeting the ASME Code Section Xl 

acceptance standards are postulated (i.e., 11 percent through-wall), the crack growth evaluation 

concluded that the ASME Code allowable flaw size limit could be reached after 38 heatup and 

cooldown cycles at the worst-case location. For the 8-inch RHR line, the crack growth 

evaluation concluded that the ASME Code allowable flaw size limit could be reached after 

123 heatup or cooldown cycles at the worst-case location. These total allowable cycle 

occurrences are less than the design number of heatup and cooldown cycles specified for the 

40-year life of the plant. Therefore, the LBB analysis for the reactor coolant loop branch lines 

concluded that a postulated 11 percent through-wall flaw could potentially grow to greater than 

the ASME Code allowable flaw size within a 40-year period. However, these heatup and 

cooldown cycle occurrences are greater than the number expected for a 10-year period (13 for 

the 10 years preceding the development of the LBB analysis). Therefore, the analysis 

concluded that the postulated flaw would not exceed the ASME Code allowable flaw size limit 

within a 10-year period and that the 10-year inspection intervals of the ASME Code Section Xl 

ISI program would effectively manage the potential for flaw growth.

The SI and RHR piping remain within their design bases since all of the design requirements 

continue to be met in accordance with the code of record. The LBB analysis limitation with 

regard to heatup or cooldown cycles results from the conservative fatigue crack growth 

evaluation which postulates a pre-existing large flaw. There have been no reportable indications 

identified during the inspections performed to date.

The applicant stated that based on the assessment included in the LBB analysis for this piping, 

the time required for a postulated large flaw to reach the Code-allowable flaw size would be 

approximately 30 years (i.e., 38 allowable heatups and cooldowns per 13 cycles per 10 years). 

Revision 1 of the applicant‘s Calculation SIR-00-045 (reviewed by the NRC and approved in a 

letter dated September 5, 2002) included the fatigue crack growth evaluation of the 8-inch RHR 

and 12-inch SI piping. Revision 2 of SIR-00-045 documents that the KPS power uprate was 

evaluated and that the conclusions of the LBB analysis are not affected.

The staff finds that the crack growth analysis for the 8-inch and 12-inch piping shows that it 

would take about 30 years for the postulated flaw to reach the allowable flaw size. During that

time, the piping will be inspected every 10 years in accordance with the ASME Code Section XI 
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ISI program. The staff finds that the inspections will be able to monitor the structural integrity of 

the piping and, therefore, this issue is closed.

LRA Section 4.7.3.3 states that, ―Since the time-based input for the crack growth analysis for 

these lines is less than 40 years, the crack growth analysis associated with these branch lines 

does not constitute a TLAA according to 10 CFR 54.3(a)(3).‖ The staff had reservations with the 

applicant‘s position that the crack growth analysis for the branch piping is not a TLAA. In 

general, a crack growth analysis assumes an initial flaw size. The flaw is assumed to grow to 

the end of the plant life based on a certain growth rate to determine whether the final flaw size 

at the end of plant life will still be within the allowable flaw size. In LRA Section 4.7.3.3, the 

crack growth is based on the fatigue mechanism. For the fatigue mechanism, transient cycles 

for 40 years (60 years for the LRA) should be used in combination with the fatigue crack growth 

rate to derive the final flaw size. The staff questioned why a crack growth analysis was 

performed for the time-based input that is less than 40 years, but not 60 years.

In 10 CFR 54.3(a)(3), it states that a TLAA is applicable if it ―Involve[s] time-limited assumptions 

defined by the current operating term, for example 40 years.‖ The applicant contends that the 

crack growth analysis of the subject 8-inch and 12-inch piping did not use a time-based input for 

40 years; therefore, the crack growth analysis would not be considered a TLAA. The staff 

believes that time-limited assumptions, not time-based inputs (that are less than 40 years), 

should be the criterion to satisfy the criterion in 10 CFR 54.3(a)(3) that the crack growth analysis 

is not a TLAA. It appears that the original crack growth analysis used transient cycles less than 

40 years so that the final flaw size could satisfy the allowable flaw size. The ―less than 40-year 

transient cycles‖ is not an assumption but an input to the analysis. Therefore, the staff did not 

agree with the applicant that the crack growth analysis of the subject LBB piping is not a TLAA. 

By letter dated July 13, 2009, the staff issued RAI 4.7.3.3-2 to ask the applicant for clarification.

By letter dated August 6, 2009, the applicant responded that the purpose of the review of TLAAs

in the LRA is to ensure that the results of plant-specific analyses that are based on an explicitly 

assumed 40-year plant life remain valid for the additional 20 years of plant operation to be 

authorized by the renewed license. The fatigue crack growth evaluation for the 12-inch SI and 

8-inch RHR lines was performed as part of the reactor coolant branch lines LBB analysis. Based 

on the ASME Code Section XI ISIs performed during the 10-year interval, only a 10-year time 

period was ultimately considered for the fatigue crack growth evaluation of these lines. Since 

the fatigue crack growth evaluation considered a time period less than the current operating 

term (i.e., 40 years), it was initially concluded that the evaluation did not meet the criteria in 

10 CFR 54.3(a)(3) and, therefore, was not a TLAA.

However, based on staff concerns, the applicant amended the LRA to include the fatigue crack 

growth evaluation for the 12-inch SI and 8-inch RHR lines as a TLAA. As described in LRA 

Section 4.7.3.3, the 12-inch SI and 8-inch RHR lines are inspected in accordance with the 

ASME Code Section XI ISI program, as described in LRA Appendix B, Section B2.1.2, ―ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.‖

Therefore, fatigue crack growth is managed by the ASME Section Xl Inservice Inspection, 

Subsections IWB, IWC, and IWD Program and the LBB analysis crack growth evaluation TLAA 

for the 12-inch SI and 8-inch RHR lines and is acceptable for the period of extended operation 

in accordance with 10 CFR 54.21(c)(1)(iii).

The staff finds that the applicant has amended the LRA by including the fatigue crack growth 

evaluation for the 8-inch RHR lines and 12-inch SI lines as a TLAA. In addition, the applicant will 
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follow the inspection requirements of ASME Code Section XI to monitor the condition of the 

subject piping. Therefore, this issue is closed.

LRA Section 4.7.3.3 states that, ―The fatigue crack growth conclusions are not affected by the 

extended plant service life since the original design-basis transient has been shown to be 

bounding for the period of extended operation in Section 4.3.1.1, Component Design Transient 

Cycles.‖ By letter dated July 13, 2009, the staff issued RAI 4.7.3.3-3 requesting that the 

applicant discuss how the actual transient cycles are monitored to verify that the design 

transient cycles used in the LBB evaluations bound the actual operating transients at the end of 

60 years.

By letter dated August 6, 2009, the applicant responded that as indicated in LRA 

Sections 4.7.3.1, 4.7.3.2, and 4.7.3.3, the fatigue crack growth evaluations of the LBB analyses 

were based on the design-basis operational transients for the NSSS. The branch line LBB 

analysis also included additional transients defined specifically for these lines. The design-basis 

operational transients have been shown to be bounding for the period of extended operation as 

shown in LRA Section 4.3.1.1, ―Component Design Transient Cycles.‖

LRA Section 4.3.1.1 provides the approach to monitoring design-basis operational transients 

using the Metal Fatigue of Reactor Coolant Pressure Boundary Program. As described in LRA 

Appendix B3.2, the program monitors actual transients and components. Specifically, the 

design-basis operational transients are tracked and the number of occurrences is evaluated 

against the design basis to assure that actual plant operation remains bounded by the 

assumptions used in the design analyses.

The staff finds that the applicant has implemented specific AMPs to monitor the actual 

transients to ensure that the design-basis transients are bounding in the LBB evaluations. This 

issue is closed.

LRA Section 4.7.3.3 states that the inspection of the 8-inch RHR lines and the 12-inch SI 

accumulator lines every 10 years, in accordance with the ASME Code Section XI, would 

effectively manage cracking in this piping such that a crack greater in size than that postulated 

in the fatigue growth analysis would not be present at the start of the 10-year interval. It appears 

that the 10-year ISI is a part of the applicant‘s technical basis for not considering the crack 

growth analysis as a TLAA. By letter dated July 13, 2009, the staff issued RAI 4.7.3.3-4

requesting that the applicant clarify how these two piping systems will be inspected during the 

period of extended operation to ensure their structural integrity to the end of 60 years.

By letter dated August 6, 2009, the applicant stated that there are two 12-inch SI lines and two 

8-inch RHR lines that were evaluated for fatigue crack growth in the LBB analyses and that are 

subject to inspection in accordance with the ASME Code Section Xl ISI program. There are a 

total of 6 welds in the two 12-inch SI lines and a total of 17 welds in the two 8-inch RHR lines. 

Weld selection for inspection is performed in accordance with the ASME Code Section XI 

requirements for sample size and selection and does not depend upon calculated stress levels 

or fatigue crack growth evaluation results. The examination method is currently ultrasonic 

testing.

The applicant stated that inspections of the subject piping in accordance with the ASME Code 

Section XI is a CLB commitment that will continue to apply through the period of extended 

operation, thus, there is no new commitment established specifically for license renewal. Each 

of the welds in these lines was ultrasonically examined in accordance with the ASME Code 
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Section XI preservice inspection requirements. Additionally, each of these weld locations, with 

the exception of one inaccessible weld (i.e., RHR W-7) in an 8-inch RHR line have either been 

inspected in the first three intervals or are scheduled for inspection in the fourth inspection 

interval. Each accessible weld location will have been inspected twice, ensuring that 

degradation, if present, would have been detected. The examination inaccessibility of weld 

RHR W-7 was caused by an integrally welded rigid pipe restraint. The examination of weld 

RHR W-7 was managed under the risk-informed ISI program. There were no reportable 

indications identified during the inspections that have been performed.

Since the fifth and sixth 10-year ISI program plans are to be developed and approved in the 

future, it is not currently known which RHR or SI accumulator pipe welds will be inspected 

during the period of extended operation. However, the ISI program is in place and will continue 

to remain in place during the period of extended operation.

The staff finds that the applicant will inspect the subject 8-inch and 12-inch piping in accordance 

with the requirements of the ASME Code Section XI, to maintain the structural integrity of the 

subject LBB piping. Therefore, the staff finds that the applicant‘s inspection of the subject piping 

is acceptable.

PWR plants have experienced PWSCC in Alloy 82/182 dissimilar metal welds in ASME Code 

Class 1 piping. PWSCC has an aggressive crack growth rate and is an active degradation 

mechanism in Alloy 82/182 dissimilar metal welds. NUREG-1061, Volume 3 and 

SRP Section 3.6.3 prohibit the LBB application on piping having active degradation 

mechanisms. By letter dated July 13, 2009, the staff issued RAI 4.7.3-2 requesting that the 

applicant address potential PWSCC in Alloy 82/182 dissimilar metal welds in the LBB piping.

By letter dated August 6, 2009, the applicant responded that the only Alloy 82/182 dissimilar 

metal welds in the LBB piping at KPS are the steam generator primary nozzle-to-reactor coolant 

loop piping welds. These welds are clad in the inside diameter surface of the pipe with 

Alloy 52/152 weld material such that the Alloy 82/182 material is not exposed to the reactor 

coolant environment. Therefore, the Alloy 82/182 weld material should not experience PWSCC 

in this application and no mitigative actions are required to ensure that PWSCC will not affect 

the structural integrity of the LBB piping. The staff notes that Alloy 52/152 weld material 

provides improved resistance to PWSCC than that of Alloy 82/182 weld material. At present, the 

industry uses Alloy 52/152 as the repair weld material to mitigate PWSCC in piping. As such, 

the Alloy 52/152 weld material will isolate Alloy 82/182 from primary water to mitigate the 

potential for PWSCC. The staff finds that the applicant has minimized the potential for PWSCC 

in Alloy 82/182 dissimilar metal welds in the steam generator primary nozzle-to-reactor coolant 

loop piping by Alloy 52/152 cladding. This issue is closed.

The staff identified two discrepancies in LRA Section 4.7.3. By letter dated August 6, 2009, the 

applicant responded that the citation of NUREG-1031, Volume 3 in LRA Section 4.7.3 is the 

result of a typographical error. The correct reference is NUREG-1061, Volume 3. In addition, the 

applicant responded that the citation of WCAP-14111 (LRA Reference 4.8-15) is the result of a 

typographical error. The correct document number is WCAP-11411.

The staff concludes that the TLAA of the LBB analyses is acceptable and that the LBB analyses 

are valid for the period of extended operation because: (1) the applicant used worst case 

fracture toughness values to analyze CASS reactor coolant loop piping in the LBB analysis, 

(2) the applicant will monitor the transient cycles to ensure that they are within the design 

transient cycles used in the LBB analyses, and (3) the subject LBB piping continues to satisfy 
Time-Limited Aging Analyses

4-47

the SRP Section 3.6.3 margins using power uprate and post-steam generator replacement 

conditions. The applicant also has addressed the potential for PWSCC in Alloy 82/182 dissimilar 

metal welds satisfactorily.

4.7.3.3 USAR Supplement

The applicant provided a USAR supplement summary description of its TLAA of the LBB 

analyses for the reactor coolant loop piping, pressurizer surge line piping, and reactor coolant 

loop branch piping, including portions of the SI and RHR systems in LRA Section A.3.5.3. On 

the basis of its review of the USAR supplement in LRA Section A.3.5.3, the staff concludes that 

the summary description of the applicant‘s actions to address the TLAA for LBB analyses of the 

subject LBB piping is adequate.

4.7.3.4 Conclusion

On the basis of its review, the staff concludes that, pursuant to 10 CFR 54.21(c)(1)(i), the 

applicant has demonstrated that the LBB analyses for the reactor coolant loop piping, 

pressurizer surge line piping, and reactor coolant loop branch piping, including portions of the SI 

and RHR systems, remain valid for the period of extended operation. Pursuant to 

10 CFR 54.21(c)(1)(iii), the applicant has demonstrated that the effects of aging on the intended 

function of the subject LBB piping will be adequately managed for the period of extended 

operation. The USAR supplement contains an appropriate summary description of the TLAA 

evaluation of the subject LBB piping, as required by 10 CFR 54.21(d).

4.7.4 Reactor Vessel Underclad Cracking

4.7.4.1 Summary of Technical Information in the Application

In LRA Section 4.7.4, the applicant stated that the transient list which was used in 

WCAP-15338-A, ―A Review of Cracking Associated with Weld Deposited Cladding in Operating 

PWR Plants,‖ has been compared to the operational transients list in KPS USAR Table 4.1-8,

―Reactor Coolant System Operating Transients,‖ and it was determined that the WCAP transient 

set is bounding for the KPS RPV. The transients listed in USAR Table 4.1-8 have been shown 

to be bounding for the period of extended operation in LRA Section 4.3.1.1, ―Component Design 

Transient Cycles.‖ Thus the WCAP-15338 conclusions related to underclad cracking are 

determined to be applicable to the KPS RPV. Therefore, the reactor vessel underclad cracking 

TLAA remains valid for the period of extended operation, in accordance with 

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

4.7.4.2 Staff Evaluation

Underclad cracks were first discovered in October 1970 during examination of the Atucha 

reactor vessel. They have been reported to exist only in SA-508, Class 2 RPV forgings 

manufactured with a coarse grain microstructure and clad by high heat input submerged arc 

welding processes. The underclad cracking issue was first addressed by Westinghouse Topical 

Report WCAP-7733, ―Reactor Vessels Weld Cladding - Base Metal Interaction,‖ which justified 

the continued operation of Westinghouse plants for 32 EFPYs. Subsequently, Westinghouse 

submitted WCAP-15338-A, which extended the analysis to justify operation of Westinghouse 

plants for 60 years of plant operation. The staff review of WCAP-15338-A is contained in a 
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September 25, 2002, letter to R.A. Newton (Westinghouse Owners Group) and concluded that 

LRAs should include the following two action items:

 (1) The license renewal applicant is to verify that its plant is bounded by the WCAP-15338-A 

report. Specifically, the renewal applicant is to indicate whether the number of design 

cycles and transients assumed in the WCAP-15338-A analysis bounds the number of 

cycles for 60 years of operation of its RPV.

 (2) As required by 10 CFR 54.21(d), a USAR supplement for the facility must contain a 

summary description of the programs and activities for managing the effects of aging 

and the evaluation of the TLAA for the period of extended operation. Those applicants 

for license renewal referencing the WCAP-15338-A report for the RPV components shall 

ensure that the evaluation of the TLAA is summarily described in the USAR supplement.

The NRC safety evaluation for WCAP-15338-A requires the applicant to verify that its plant is 

bounded by the WCAP report. LRA Section 4.7.4 states that the applicant compared the 

WCAP-15338-A transients with the KPS operational transients and determined that the 

WCAP-15338-A transients bound the KPS transients for 60 years. The applicant did not, 

however, provide information regarding how the comparison was performed to arrive at this 

conclusion. Therefore, the staff issued RAI 4.7.4-1 by letter dated August 28, 2009.

RAI 4.7.4-1:

LRA Section 4.7.4, ―Reactor Vessel Underclad Cracking,‖ states that the 

applicant compared the transients utilized in the WCAP-15338-A report, with the 

Kewaunee operational transients and determined that the WCAP-15338-A 

transients bound the Kewaunee transients. Please elaborate on this comparison 

using a couple of examples (transients) to substantiate the conclusion.

In its response dated September 28, 2009, the applicant stated that the assumed number of 

occurrences of the transients used as input to the WCAP-15338-A report was compared to the 

NSSS operational transients included in USAR Table 4.1-8 to determine whether the 

WCAP-15338-A inputs were bounding for KPS. Two examples were provided: (1) the number of 

heatup and cooldown transients of 300 each for 60 years used in the WCAP-15388-A report 

bounds the number of heatup and cooldown transients listed in USAR Table 4.1-8 (i.e., 200 

each), and (2) the number of loss of power transient occurrences of 60 for 60 years used in the 

WCAP-15388-A report bounds the 40 operating transient value listed in USAR Table 4.1-8. 

Additionally, the transients listed in USAR Table 4.1-8 have been shown to be bounding for a 

60-year plant lifetime as described in LRA Section 4.3.1.1. Based on this information, the staff 

considers that RAI 4.7.4-1 has been resolved and agrees with the applicant that the 

WCAP-15338-A conclusions related to underclad cracking are applicable to the KPS RPV and

that this TLAA is in accordance with 10 CFR 54.21(c)(1)(i).

4.7.4.3 USAR Supplement

On the basis of the staff‘s evaluation described above, the summary description for the RCS 

TLAA for RPV unclad cracking described in the USAR supplement (LRA Appendix A) provides 

an adequate description of this TLAA, as required by 10 CFR 54.21(d).
Time-Limited Aging Analyses

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4.7.4.4 Conclusion

On the basis of its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for RPV underclad cracking, the 

WCAP-15338-A analysis applies to KPS and 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).

4.7.5 Reactor Coolant Loop Piping Flaw Tolerance Evaluation

4.7.5.1 Summary of Technical Information in the Application

LRA Section 4.7.5 describes the reactor coolant loop piping flaw tolerance evaluation to account 

for susceptibility of the CASS piping materials to thermal aging embrittlement. The applicant 

stated that an evaluation of the susceptibility of the loop piping to thermal aging and the 

potential for flaw growth in the piping due to reduced fracture toughness has been performed 

consistent with the recommendations of GALL AMP XI.M12, ―Thermal Embrittlement of Cast 

Austenitic Stainless Steel (CASS).‖ The applicant indicated that the evaluation approach 

consisted of: (1) screening the CASS material properties for susceptibility to thermal aging 

embrittlement, and (2) for susceptible materials, performing a plant-specific flaw tolerance 

evaluation, consistent with the GALL Report and the letter dated May 19, 2000, from 

Christopher Grimes, NRC, to Douglas Walters, NEI (LRA Reference 4.8-27). 

The applicant further stated that evaluation was performed for the susceptible CASS piping 

locations using plant-specific bounding material properties, geometry, and stresses in each leg 

(i.e., hot leg, cold leg, and cross-over leg) of the reactor coolant loop piping. Based on the 

evaluation, the applicant concluded that even in the fully-aged condition, the CASS reactor 

coolant loop piping has adequate fracture toughness for a minimum service life of 30 years, 

which envelops the period of extended operation. Therefore, it is not necessary to manage the 

effects of thermal aging embrittlement of CASS reactor coolant loop piping for the period of 

extended operation. 

However, in LRA Table 4.1-1 the applicant indicated that the reactor coolant loop piping flaw 

tolerance evaluation does not meet the definition of a TLAA per 10 CFR 54.3.

4.7.5.2 Staff Evaluation

The staff reviewed LRA Section 4.7.5 to evaluate the applicant‘s claim of consistency with the 

recommendations of GALL AMP XI.M12. The applicant stated that the loop piping, constructed 

of ASME SA-351 Grade CF8M with 2–3 percent molybdenum content, consists of 

centrifugally-cast piping segments and statically-cast elbows, and that the material delta-ferrite 

did not exceed 25 percent. The applicant further stated that screening results indicated that 

based on the delta-ferrite content, four statically-cast elbows and one centrifugally-cast pipe 

were identified to be potentially susceptible to thermal aging embrittlement (i.e., contained more 

than 14 percent and more than 20 percent ferrite, respectively). The staff noted that the 

applicant had not mentioned whether the method used to determine the ferrite content of the 

CASS materials was consistent with the GALL Report, which states that for susceptibility 

screening, ferrite content is calculated by using the Hull‘s equivalent factors (described in 

NUREG/CR-4513, Revision 1), or a method producing an equivalent level of accuracy (plus or 

minus 6 percent deviation between measured and calculated values). By letter dated October 
Time-Limited Aging Analyses

4-50

13, 2009, the staff issued RAI 3.1.2.1.2-1 requesting that the applicant confirm whether the 

Hull‘s equivalent factors were used to determine the delta-ferrite content of the CASS materials, 

and if they were not, verify that the method produced an equivalent level of accuracy.

In its response dated November 13, 2009, the applicant stated that the susceptibility screening 

for the CASS reactor coolant loop piping was performed consistent with the letter from 

Christopher Grimes, NRC, to Douglas Walters, NEI, License Renewal Issue No. 98-0030, 

―Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Components,‖ dated May 19, 

2000, with the exception that delta-ferrite content was determined using the method outlined in 

ASTM A800, ―Standard Practice for Steel Casting, Austenitic Alloy, Ferrite Content Thereof,‖ 

rather than the Hull‘s equivalent factors method identified in the letter. In addition, the applicant 

provided the following information: 

In accordance with ASTM A800, estimation of ferrite content in the base metal of 

the reactor coolant loop piping was performed by analysis of the chemical 

composition of the castings. The ferrite content of the casting was estimated from 

the equation of the central line of the Schoefer diagram at the composition ratio 

of ―chromium equivalent‖ (Cre) to ―nickel equivalent‖ (Nie) determined from the 

formula in ASTM A800. The ASTM A800 Schoefer diagram method details, 

provided in Appendix XI to the standard, include a description of potential error 

associated with the estimation of ferrite content based on chemical composition. 

The probable error determined in the Standard is approximately +3.5%/-2.5% 

ferrite at ferrite contents of 5%; +4.5%/-3.5% at 10%; +6%/-4.5% at 15%; and 

+8%/-5.5% at 20% ferrite content. As stated in the NRC License Renewal Issue 

No. 98-0030 letter dated May 19, 2000, the Hull‘s equivalent factors method 

produces results with +/-6% ferrite potential error. The difference in potential 

error at higher levels of ferrite content between the Hull‘s equivalent factors 

method and the Schoefer diagram method provided in ASTM A800 is small, and 

the Schoefer diagram method used for estimating the ferrite content of the steel 

was considered to provide an acceptable level of accuracy.

Based on its review, the staff finds the applicant‘s response to RAI 3.1.2.1.2-1 acceptable 

because: (1) the applicant provided the information regarding the method used to determine the 

ferrite content of the CASS reactor coolant loop piping, and (2) the applicant‘s method to 

determine ferrite content is in accordance with ASTM A800, which provides an acceptable level 

of accuracy. The staff‘s concern described in RAI 3.1.2.1.3-1 is resolved.

In LRA Section 4.7.5, the applicant also stated that for the susceptible CASS piping locations, a 

flaw tolerance evaluation was performed by using plant-specific bounding material properties, 

geometry, and stresses in the hot leg, cold leg, and cross-over leg of the reactor coolant loop 

piping. The applicant further stated that because the delta-ferrite content of the CASS materials 

does not exceed 25 percent, a flaw evaluation was performed in accordance with the principles 

associated with IWB-3640 procedures for submerged arc welds (SAW), discarding the Code 

restriction of 20 percent delta-ferrite content in IWB-3641(b)(1). The staff finds this to be an 

acceptable approach as stated in the NRC letter from Christopher Grimes to Douglas Walters 

regarding License Renewal Issue No. 98-0030, dated May 19, 2000 (LRA Reference 4.8-27), 

because of the similarity between the lower bound fracture toughness data for CF8M steels with 

15–25 percent ferrite and the IWB-3640 SAW data. The applicant indicated that the effects of 

unstable ductile tearing due to the reduced toughness of thermally-aged CASS material are 

addressed through the use of penalty factors, called ―Z factors,‖ in accordance with the 
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4-51

IWB-3640 flaw evaluation procedure and acceptance criteria. The staff finds this consistent with 

the GALL Report.

The applicant further stated that the results indicated that the limiting initial flaw depth for an 

aspect ratio of 6 was in the crossover leg (i.e., 28.2 percent through-wall) and that a flaw of this 

initial size would not grow to critical size (i.e., a size that could result in piping failure at 

design-basis loading conditions) during an additional 30 years of service. Based on these 

results, the applicant concluded that even with thermal aging embrittlement of CASS loop piping 

materials to the fully-aged condition, the susceptible piping locations are tolerant of large flaws. 

Therefore, the applicant concluded that there is no requirement to manage the effects of thermal 

aging embrittlement of CASS reactor coolant loop piping for the period of extended operation. 

The staff finds this methodology to be consistent with GALL AMP XI.M12 and, therefore, 

acceptable. GALL AMP XI.M12 states, ―... for potentially susceptible components, aging 

management is accomplished through either enhanced volumetric examination or plant-or 

component-specific flaw tolerance evaluation.‖

However, in its review, the staff finds that the applicant did not provide sufficient details 

regarding the stresses in specific pipe sections, cyclic crack growth rates, or bounding fracture 

toughness of thermally-aged CASS, to verify the applicant‘s statement that the initial flaw will 

not grow to critical size, or to check the critical flaw size. For example, the applicant stated that 

the number of occurrences of design transients considered in the generation of flaw tolerance 

analysis were based on the revisions for KPS 7.4 percent uprating and steam generator 

replacement. However, it is not clear to the staff whether the 7.4 percent uprating was also 

considered in determining the design stresses for the flaw tolerance evaluation. Also, although 

the applicant stated that the loop piping was constructed of CF-8M steel with less than 

25 percent ferrite, the applicant did not confirm whether or not it contained niobium. The staff 

noted that typically, niobium is not specified in CF-8M steel. The staff further noted that the 

recommendations of GALL AMP XI.M12 are not applicable to niobium-bearing steels. In 

addition, the applicant stated that an environmental factor of 2 was applied to the crack growth 

reference curves for austenitic stainless steel in air to account for the effect of PWR 

environment on growth rates. However, the applicant did not provide the basis for choosing an 

environmental factor of 2. The staff noted that several recent studies have reported data 

showing that the fatigue crack growth rates can be enhanced appreciably in a PWR primary 

coolant environment at low loading frequencies. 

By letter dated October 13, 2009, the staff issued RAI 4.7.5-1 requesting that the applicant: 

(1) confirm that the loop piping material is not niobium bearing, (2) confirm that the 7.4 percent 

uprating was considered in determining the design stresses for the flaw tolerance evaluation, 

and (3) provide details regarding flaw growth analyses, in particular, the technical basis for the 

choice of the environmental factor of 2 for fatigue crack growth rates in a PWR environment.

In its response dated November 13, 2009, the applicant stated that the reactor coolant loop 

piping was supplied in accordance with material specification of ASTM A351, Grade CF-8M, 

which does not require the addition of niobium or columbium. The applicant further stated that 

the chemical compositions for the loop piping heats were reviewed and there was no indication 

of niobium content. The applicant also confirmed that the KPS 7.4 percent uprating was 

considered in determining the design stresses for the flaw tolerance evaluation.

In its response to the request for details regarding the flaw growth analyses associated with the 

reactor coolant loop piping flaw tolerance evaluation, the applicant stated that the analyses were 

based on the methods described in the ASME B&PV Code Section XI, Subsection IWB-3640. 
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4-52

The applicant further stated the use of an environmental factor of 2 applied to the crack growth 

rate determined for austenitic stainless steels in air, to account for the effect of a PWR 

environment, is based on the factor recommended for the PWR environment in ―Evaluation of 

Flaws in Austenitic Steel Piping—Section XI Task Group for Piping Flaw Evaluation,‖ 

Transactions of ASME, Journal of Pressure Vessel Technology, Volume 108, August 1986.

Based on its review, the staff finds the applicant‘s response to RAI 4.7.5-1 acceptable because: 

(1) the applicant confirmed that its reactor coolant loop piping does not have indications of 

niobium, (2) the applicant confirmed that the 7.4 percent uprating was considered in determining 

the design stresses for the flaw tolerance evaluation, and (3) the applicant‘s analyses were 

based on the methods described in the ASME Code Section XI, Subsection IWB-3640. The 

staff‘s concern described in RAI 4.7.5-1 is resolved. The applicant has demonstrated how a 

drop in the fracture toughness property will be adequately addressed for components made 

from these CASS materials.

The staff notes that the applicant has applied fully thermally-aged conditions to the flaw 

tolerance analysis for these CASS materials, and that the applicant‘s flaw tolerance analysis 

assumes, therefore, the most limiting reduced fracture toughness property value (i.e., Kic value) 

for its analysis. Since the applicant applies the most limiting fracture toughness property value 

(i.e., the lowest Kic value possible) to the assessment, the staff finds that this aspect of the 

analysis does not include a time dependency. Based on this review, the staff concludes that the 

drop in the fracture toughness property value does not need to be treated as a TLAA because, 

contrary to TLAA identification criterion in 10 CFR 54.3(a)(3),

1

the value used for the analysis 

does not include a time dependency.

The staff also noted that the applicant has applied the flaw growth analysis aspect of its flaw 

tolerance for a presumed additional 30 years of licensed operation, which is beyond the 

remainder of the 40-year current licensed operating period plus the additional 20 years of the 

period of extended operation. Therefore, the staff concludes that the flaw growth analysis 

aspect of the flaw tolerance evaluation does not need to be treated as a TLAA because, 

contrary to the TLAA identification criterion in 10 CFR 54.3(a)(3), the period of applicability for 

this aspect of the analysis extends beyond what would constitute a 60-year licensed plant life.

Based on this assessment, the staff concurs with the TLAA identification basis in LRA 

Table 4.1-1, that the flaw tolerance evaluation for the CASS materials does not conform to 

10 CFR 54.3(a)(3) (i.e., does not conform to one of the six criteria in 10 CFR 54.3(a) that must 

be met to define an analysis in the CLB as a TLAA) and that, therefore, this analysis does not 

need to be identified as a TLAA for this LRA.

4.7.5.3 USAR Supplement

The applicant provided a USAR supplement summary of its evaluation of the susceptibility of 

CASS reactor coolant loop piping to thermal aging and the potential for flaw growth in the piping 

due to reduced fracture toughness in LRA Section A3.5.5. Based on its review of the USAR 

 

1

As one of the six criteria in 10 CFR 54.3(a) for identifying analyses as TLAAs, Criterion 3 states that, to 

be identified as a TLAA, the analysis must involve time-limited assumptions defined by the current 

operating term (for example 40 years). Section III.g.(i) in the Statement of Consideration on 

10 CFR Part 54 clarifies what is within the scope and context of the TLAA identification criterion (refer to 

Federal Register Notification Volume 60, Number 88, pages 22461–22495 [May 8, 1995]). 
Time-Limited Aging Analyses

4-53

supplement, the staff concludes that the applicant provided an adequate summary description 

and that the applicant‘s actions to address reduced fracture toughness of CASS reactor coolant 

loop piping is adequate, even though this analysis does not need to be identified as a TLAA for 

this LRA.

4.7.5.4 Conclusion

Based on its review , the staff concludes that the reactor coolant loop piping flaw tolerance 

evaluation does not need to be identified as a TLAA for the KPS LRA because the analysis 

does not conform to the TLAA identification criterion in 10 CFR 54.3(a)(3). However, the staff 

concludes that the analysis description in LRA Section 4.7.5 provides an adequate discussion 

on why the flaw tolerance analysis for the CASS materials is considered to be capable of 

addressing thermal aging in the CASS ASME Code Class 1 piping components. Based on this 

review, and given the application of this analysis to the CASS ASME Code Class 1 piping 

components, the staff finds that the applicant has provided an acceptable basis for addressing 

loss of fracture toughness due to thermal aging in these CASS piping components, such that no

augmented inspection of the components is necessary beyond what is currently required for 

these components under the ASME Code Section XI, Table IWB-2500-1. This basis is 

consistent with the staff‘s assessment in SER Section 3.1.3.1.2.

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 an adequate list of 

TLAAs, as defined in 10 CFR 54.3. Furthermore, the staff concludes that the applicant 

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) that the effects of aging on the 

intended functions 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 

found that the USAR supplement contains descriptions of the TLAAs sufficient to satisfy the 

requirements of 10 CFR 54.21(d). In addition, the staff concludes that one plant-specific 

exemption is in effect that is based on TLAAs and that the applicant has provided an adequate 

evaluation that justifies the continuation of this exemption for the period of extended operation, 

as required by 10 CFR 54.21(c)(2).

With regard to these matters, the staff concludes 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 54.21(c), are in accordance with the Atomic Energy 

Act of 1954 and NRC regulations.

5-1

SECTION 5 

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The U.S. Nuclear Regulatory Commission (NRC or the staff) issued its safety evaluation report 

(SER) with open items related to the renewal of the operating license for Kewaunee Power 

Station (KPS) on July 16, 2010. On August 18, 2010, the applicant presented its license renewal 

application (LRA), and the staff presented its review findings to the Advisory Committee on 

Reactor Safeguards (ACRS) Plant License Renewal Subcommittee. The staff reviewed the 

applicant‘s comments on the SER and completed its review of the LRA. The staff‘s evaluation is 

documented in an SER that was issued by letter dated November 4, 2010. Subsequently, the 

staff received additional information from the applicant dated November 9, 2010, and November 

23, 2010, that provided clarifications regarding its Aging Management Programs for Selective 

Leaching, ASME Section XI Inservice Inspection, and Masonry Wall and Structures Monitoring. 

The staff‘s review of this information is documented in sections 3.0.3.1.12, 3.0.3.2.1, and 

3.0.3.2.18, respectively, of this SER.

During the 578th meeting of the ACRS held December 2–4, 2010, the ACRS completed its 

review of the KPS LRA and the staff‘s SER. The ACRS documented its findings in a letter to the 

Commission dated January 7, 2011. A copy of this letter is provided on the following pages of 

this SER section.
5-2

UNITED STATES

NUCLEAR REGULATORY COMMISSION

ADVISORY COMMITTEE ON REACTOR SAFEGUARDS

WASHINGTON, DC 20555 - 0001

January 7, 2011

The Honorable Gregory B. Jaczko

Chairman

U.S. Nuclear Regulatory Commission

Washington, DC 20555-0001

SUBJECT: REPORT ON THE SAFETY ASPECTS OF THE LICENSE RENEWAL 

APPLICATION FOR THE KEWAUNEE POWER STATION

During the 578th meeting of the Advisory Committee on Reactor Safeguards, December 2-4, 

2010, we completed our review of the license renewal application for the Kewaunee Power 

Station (KPS) and the Safety Evaluation Report (SER) prepared by the NRC staff. Our Plant 

License Renewal Subcommittee also reviewed this matter during its meeting on August 18, 

2010. During these reviews, we had the benefit of discussions with representatives of the NRC 

staff and the applicant, Dominion Energy Kewaunee, Inc. (DEK). We also had the benefit of the 

documents referenced. This report fulfills the requirements of 10 CFR 54.25 that the ACRS

review and report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage age-related 

degradation provide reasonable assurance that KPS can be operated in accordance with 

its licensing basis for the period of extended operation without undue risk to the health 

and safety of the public.

2. The application for the renewal of the operating license of KPS should be approved.

BACKGROUND AND DISCUSSION

KPS is a 2-loop pressurized water reactor of Westinghouse design with a dry, ambient 

containment. KPS operates at a licensed power output of 1,772 megawatt-thermal. DEK 

requested renewal of the KPS license for 20 years beyond the current license term, which 

expires on December 21, 2013. In the SER, the staff documented their review of the license 

renewal application and other information submitted by the applicant or obtained during three 

staff audits and a two-week inspection conducted at the plant site. The staff reviewed the 

completeness of the applicant‘s identification of 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 the 

identification and assessment of time-limited aging analyses (TLAAs) requiring review.
5-3

The applicant identified the SSCs that fall within the scope of license renewal and performed an 

aging management review for these SSCs. The applicant will implement 34 AMPs for license 

renewal. Thirteen AMPs are consistent with the guidance in the Generic Aging Lessons 

Learned (GALL) Report, seven are consistent with exceptions, eight are consistent with 

enhancements, five are consistent with both enhancements and exceptions, and one is plantspecific. We reviewed the plant-specific program and the AMP exceptions to the GALL Report, 

and we agree with the staff that they are acceptable.

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 

acceptable list of TLAAs, as defined in 10 CFR 54.3. Furthermore, the staff 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 the TLAAs have been 

projected to the end of the period of extended operation, or the aging effects will be adequately 

managed for the period of extended operation. We concur with the staff conclusion that the 

TLAAs have been properly identified and that the required criteria will be met for the period of 

extended operation.

The staff conducted three license renewal audits and one inspection at KPS. The audits verified 

the appropriateness of the aging management review, scoping and screening methodology, and 

associated AMPs. The inspection examined the scoping and screening of non-safety related 

SSCs and verified the adequacy of the guidance, documentation, and implementation of 

selected AMPs. The audit and inspection teams also performed independent examinations of 

KPS condition reports to confirm that plant-specific operating experience has been adequately 

addressed during the AMP development and implementation processes. Based on the audits 

and inspections, the staff concluded in the SER that the proposed activities will adequately 

manage the 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.

KPS steam generators have divider plates fabricated from Alloy 600. DEK credits its Primary 

Water Chemistry Program (PWCP) to manage cracking due to primary water stress corrosion 

cracking (PWSCC) for Alloy 600 steam generator divider plates exposed to reactor coolant. 

Significant cracking due to PWSCC has been identified in some European steam generator 

divider plates, even with proper primary water chemistry. 

The staff noted that the PWCP alone may not be effective in managing the aging effect of 

cracking due to PWSCC divider plates. In order to address the staff concerns, the applicant has 

committed to participate in ongoing industry efforts related to the divider plate cracking issue. 

Recognizing that the industry resolution is still under development, the applicant will assess the 

condition of the divider plate assembly in each steam generator by inspection during the period 

of extended operation, in a time period consistent with the detection of potential PWSCC cracks, 

and with appropriate examination techniques. We agree with the staff that the applicant has 

demonstrated that the effects of aging for these components will be adequately managed. 
5-4

The staff is concerned that for Alloy 600 tubesheet cladding, autogenous welds may not have 

sufficient PWSCC resistance, even when tubes are made of Alloy 690. The applicant has 

committed to developing a plan prior to the period of extended operation, to exercise one of two 

options: 1) Perform an analytical evaluation of the tube-tubesheet region to establish the 

technical basis for this boundary being maintained even if cracked, and to demonstrate that the 

weld is not needed for reactor coolant pressure boundary integrity; or 2) Perform a one-time 

inspection of a representative number of welds in each steam generator. If cracking is 

identified, cracks will be evaluated or repaired and aging management inspections will be 

performed for the remaining life of the steam generators. We agree with the staff that this plan 

should be effective in managing this aging issue.

The applicant has chosen to address environmentally assisted fatigue by demonstrating that the 

cumulative usage factor (CUF) at the most sensitive locations will remain below 1.0 throughout 

the period of extended operation, considering both mechanical and environmental effects. 

Analyses were performed by the applicant. These analyses showed that the CUF at all 

analyzed locations will remain below 1.0 throughout the period of extended operation. 

However, the staff challenged the methodology used by the applicant because this methodology 

does not consider the full stress state on the component. At the request of the staff, the 

applicant performed additional analyses. These analyses confirmed that the CUF will not 

exceed 1.0 during the period of extended operation. The applicant also restricted consideration 

of environmental effects to those locations identified in NUREG/CR-6260. The staff requested 

that the applicant review its design to confirm that these are the most limiting locations in its 

plant. The applicant agreed with this request. We concur with this process.

Following issuance of the SER, the applicant submitted commitments that expand the scope 

and means to detect aging effects in several license renewal programs. The most significant 

are those summarized below.

The staff has identified industry operating experience which indicates that power cables 

energized to 480V and higher can experience failures where extended exposure to moisture is a 

contributing factor. The Inaccessible Medium Voltage Cable Program in Revision 1 to the GALL 

Report does not recommend testing for inaccessible cables energized to less than 2kV and 

does not require testing of inaccessible cables that are not normally energized. Although KPS 

has not experienced any 480V to 35kV power cable failures due to aging, DEK has addressed 

the staff‘s concerns by expanding the scope of the Medium Voltage Power Cable Program to 

include all inaccessible 480V to 2kV power cables, energized and not. This expanded scope of 

cable monitoring is consistent with the draft Final Revision 2 of the GALL Report we recently 

reviewed.

The staff has concluded that external visual inspections do not provide adequate assurance that 

cracking is not present at the internal radius of socket welds in Class 1 small bore piping 

systems. There are currently no approved industry standard methods or qualified techniques to 
5-5

perform volumetric examinations of these welds. The KPS operating experience indicates that 

cracking has not occurred in any small bore socket welds. Nevertheless, in addition to visual 

inspections, DEK will perform volumetric examinations of ten Class 1 socket welds for the 

period of extended operation. If no industry demonstrated technique is available at the time of 

inspection, the applicant will perform destructive examinations of at least five socket welds in 

lieu of volumetric examinations. These commitments provide reasonable assurance that this 

issue will be adequately addressed.

The staff has noted a number of recent industry events involving leakage from buried and 

underground piping and tanks within the scope of license renewal. KPS has never experienced 

a piping failure of in-scope piping; but the circulating water, fire protection, and diesel fuel oil 

systems have a significant amount of buried piping. Buried steel piping is coated, and recent 

inspections of excavated fire protection and diesel generator fuel oil piping demonstrate that 

coatings are in very good condition, with appropriate backfill. The applicant has committed to 

continue to periodically inspect components in a vault below grade. KPS will maintain 

availability of cathodic protection of the buried portions of the circulating water system and 400 

feet of buried fuel oil piping at least 90 percent of the time. National Association of Corrosion 

Engineers (NACE) surveys of cathodic protection will be conducted during the period of 

extended operation. Visual inspections will be performed on portions of all buried piping and 

one of the three fuel oil storage tanks within each 10 year period starting 10 years prior to the 

period of extended operation. The staff has concluded that, with these enhancements, the 

proposed program will adequately monitor and manage the aging of buried piping and tanks. 

We agree with this conclusion.

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 KPS. The programs 

established and committed to by DEK provide reasonable assurance that KPS 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 DEK application for renewal of the operating 

license for KPS should be approved.

Sincerely,

 /RA/

Said Abdel-Khalik

Chairman
5-6

References:

1. U.S. Nuclear Regulatory Commission, "Safety Evaluation Report Related to the License 

Renewal of Kewaunee Power Station," November 2010 (ML103090024) 

2. Letter from David A. Christian, dated August 12, 2008, "Dominion Energy Kewaunee, 

Inc. (DEK) Kewaunee Power Station Application for Renewed Operating License" 

(ML082341020)

3. Letter from Ann Marie Stone dated November 12, 2009, "Kewaunee Power Station -

NRC License Renewal Scoping, Screening, and Aging Management Inspection Report 

05000305/2009007" (ML093160727)

4. Letter from Samuel Hernandez dated August 12, 2009, "AMP Audit Report Regarding 

the Kewaunee Power Station License Renewal Application" (ML091900449)

5. Letter from Samuel Hernandez dated December 14, 2009, "Work Control Process Aging 

Management Program Audit Report Regarding the Kewaunee Power Station License 

Renewal Application" (ML093260003)

6. Letter from Samuel Hernandez dated July 13, 2009, "Scoping and Screening Audit 

Report Regarding the Kewaunee Power Station License Renewal Application" 

(ML091900081)

7. Letter from J. Alan Price dated October 20, 2010, "Dominion Energy Kewaunee, Inc. 

Kewaunee Power Station Supplemental Information for the Review of the Kewaunee 

Power Station License Renewal Application" (ML102930573)

8. Letter from J. Alan Price dated November 9, 2010, "Dominion Energy Kewaunee, Inc. 

Kewaunee Power Station Supplemental Information for the Review of the Kewaunee 

Power Station License Renewal Application" (ML103130472)

9. Letter from J. Alan Price dated November 23, 2010, "Dominion Energy Kewaunee, Inc. 

Kewaunee Power Station Supplemental Information for the Review of the Kewaunee 

Power Station License Renewal Application" (ML103270580)

10. Memorandum from B. Pham dated December 17, 2010, ―Advisory Committee Reactor 

Safeguards Review of the Kewaunee Power Station License Renewal Application –

Safety Evaluation Report (ML103500555)
6-1

SECTION 6 

CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (the staff), reviewed the license renewal 

application (LRA) for Kewaunee Power Station (KPS), in accordance with NRC regulations and 

NUREG-1800, ―Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants,‖ Revision 1, dated September 2005. Title 10, Section 54.29, of the Code of 

Federal Regulations (10 CFR 54.29) provides 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 notes that any requirements of Subpart A of 10 CFR Part 51 are documented in 

Supplement 40 to NUREG-1437, ―Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants: Regarding Kewaunee Power Station,‖ dated August 19, 2010.

A-1

APPENDIX A 

COMMITMENTS FOR LICENSE RENEWAL OF KEWAUNEE POWER 

STATION

During the review of the Kewaunee Power Station (KPS) license renewal application (LRA) by 

the staff of the U.S. Nuclear Regulatory Commission (the staff), Dominion Energy Kewaunee, 

Inc. (Dominion, DEK, or the applicant), made commitments related to aging management 

programs (AMPs) to manage aging effects of structures and components (SCs) prior to the 

period of extended operation. The following table lists these commitments, along with the 

implementation schedules and the sources of the commitment.
Appendix A

A-2

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

1 The ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program 

will be enhanced to: (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, submit an 

inspection plan for reactor internals to the staff for review and approval to augment the current 

inspections.

At least 2 years prior to 

entering the period of 

extended operation.

ASME Code Section XI 

Inservice Inspection, 

Subsections IWB, IWC, 

and IWD

2 The ASME Code Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program 

will be enhanced to include identification of the limiting susceptible cast austenitic stainless 

(CASS) steel reactor vessel internal components from the standpoint of thermal aging 

susceptibility, neutron fluence, and cracking. For each identified component, a plan will be 

developed that accomplishes aging management through either a supplemental examination or 

a component-specific evaluation. The plan will be submitted for staff review and approval, not 

less than 24 months before entering the period of extended operation.

At least 2 years prior to 

entering the period of 

extended operation.

ASME Code Section XI 

Inservice Inspection, 

Subsections IWB, IWC, 

and IWD

3 The Bolting Integrity Program will be enhanced to further incorporate applicable Electric Power 

Research Institute (EPRI) and industry bolting guidance. Topic enhancements will include 

proper joint assembly, torque values, gasket types, use of lubricants, and other bolting 

fundamentals.

Prior to the Period of 

Extended Operation 

Bolting Integrity

4 The Buried Piping and Tanks Inspection program will be enhanced to perform visual

inspections of a representative sample of material/protective measure combinations for 

in-scope buried piping and tanks.

The following materials are utilized in buried applications with the associated protective 

measures:

• Steel (including cast iron)/coated,

• Steel/coated and wrapped,

• Steel/uncoated, and

• Stainless steel/coated and wrapped

Visual inspections of the external surfaces of the components will be performed to identify 

damaged wrapping (if present), degraded or damaged coating (if present), and evidence of 

loss of material. Each piping inspection will include a minimum of 10 linear feet of piping.

The following inspections will be performed:

The circulating water system 30 inch diameter recirculation line, which is coated and wrapped 

carbon steel, will receive one inspection prior to the period of extended operation, and

additional inspections within the first 10 years and second 10 years of the period of extended 

operation. (Continued next page)

Prior to the Period of 

Extended Operation 

And

During the first 10 years 

of the period of extended

operation

And

During the second 

10 years of the period of

extended operation

Letter 10-548, Response 

to RAI B2.1.7-3a.
Appendix A

A-3

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

The circulating water system recirculation line vent piping, which is coated and wrapped 

stainless steel, will receive one inspection prior to the period of extended operation and

additional inspections within the first 10 years and second 10 years of the period of extended 

operation.

The diesel generator system fuel oil piping, which includes coated and wrapped carbon steel 

fuel oil supply and return piping, storage tank vent piping, and day tank vent piping, will receive 

one inspection prior to the period of extended operation and additional inspections within the 

first 10 years and second 10 years of the period of extended operation. The inspections will be 

performed in the non-cathodically protected portion of the piping.

The diesel generator system fuel oil storage tanks, which are coated carbon steel, will receive 

one inspection of one tank prior to the period of extended operation. An additional tank 

inspection will be performed within each of the first and second 10 years of the period of 

extended operation.

The diesel generator system fuel oil storage tanks hold down straps, which are uncoated 

carbon steel, will be inspected in conjunction with the associated fuel oil storage tank 

inspection. One set will be inspected prior to the period of extended operation, and one set will 

be inspected within each of the first and second 10 years of the period of extended operation.

The fire protection system piping, which is coated ductile iron, will receive three inspections 

prior to the period of extended operation, and three additional inspections within each of the 

first and second 10 years of the period of extended operation.

5 The Compressed Air Monitoring Program will be enhanced to incorporate the compressed air 

system testing and maintenance recommendations from the ASME OM-S/G-1998, Part 17 and 

the EPRI TR-108147 and to identify these documents as part of the program basis.

Prior to the Period of 

Extended Operation 

Compressed Air 

Monitoring

6 The External Surfaces Monitoring Program will be enhanced to inspect the accessible external 

surfaces of in-scope components, piping, supports, structural members, and structural 

commodities, in the infrequently accessed areas, consistent with the criteria used in other plant 

areas.

Prior to the Period of 

Extended Operation 

External Surfaces 

Monitoring

7 The External Surfaces Monitoring Program will be enhanced to provide training for operations, 

engineering, and health physics personnel performing the program inspections and walkdowns. 

The training will address: (1) the requirements of the External Surfaces Monitoring Program for 

license renewal, (2) the need to document the identified conditions with sufficient detail to 

support monitoring and trending the aging effects, and (3) the aging effects monitored by the 

program and how to identify them.

Prior to the Period of 

Extended Operation 

External Surfaces 

Monitoring

8 The Fire Protection Program will be enhanced to test a representative sample of sprinkler 

heads or to replace all affected sprinkler heads in accordance with the requirements of National 

Fire Protection Association (NFPA) 25.

Prior to the sprinkler 

heads achieving 

50 years of service life. 

Fire Protection
Appendix A

A-4

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

9 The Fire Protection Program fire barrier penetration seal inspections will be revised to include 

the elastomer shield building fire boots.

Prior to the Period of 

Extended Operation 

Fire Protection

10. The Fire Protection Program inspections of the reactor coolant pump oil collection system will 

be revised to include additional inspection criteria for the visual inspection of the system and to 

perform a one-time inspection of the internal surfaces of the reactor coolant pump oil collection 

tank.

Prior to the Period of 

Extended Operation 

Fire Protection

11. The Fuel Oil Tank Inspections Program will be enhanced to provide guidance for the periodic 

draining, cleaning, and inspection activities.

Prior to the Period of 

Extended Operation 

Fuel Oil Tanks Inspection

12. The Inspection of Overhead Heavy Load and Refueling Handling Systems Program will be 

enhanced to clarify the requirements of visual inspection of structural members, including 

structural bolting, of the in-scope heavy load and refueling handling cranes and associated 

equipment.

Prior to the Period of 

Extended Operation 

Inspection of Overhead 

Heavy Load and 

Refueling Handling 

Systems

13. The Metal-Enclosed Bus (MEB) Program will be enhanced to include augmented periodical 

visual inspections of the MEB internal surfaces, bus supports, bus insulation, taped joints, and 

boots for signs of degradation or aging.

Prior to the Period of 

Extended Operation. 

Thereafter, the 

inspection of all MEB will 

not exceed a 10-year 

interval and the 

inspection of the sample 

of bolted connections will 

not exceed a 5-year 

interval.

Letter 09-469, Response 

to RAI B2.1.18-1

14. The Non-EQ Electrical Cables and Connections Program will be established. The program will 

periodically visually inspect for accessible electrical cables and connections installed in an 

adverse localized equipment environment. Should an adverse localized environment be 

observed, a representative sample of electrical cables and connections installed within that 

environment will be visually inspected for jacket surface anomalies.

Prior to the Period of 

Extended Operation. 

Thereafter, the 

inspections will not 

exceed a 10-year 

interval. 

Non-EQ Electrical Cables 

and Connections

15. The Non-EQ Electrical Cable Connections Program will be established. The program will 

perform a one-time inspection, on a sampling basis, to confirm the absence of loosening of 

bolted connections.

Prior to the Period of 

Extended Operation 

Non-EQ Electrical Cables 

and Connections
Appendix A

A-5

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

16. The Non-EQ Inaccessible Medium-Voltage Cables Program will be established. The program 

will periodically inspect the in-scope manholes and pulling pit for water collection and will 

remove water, if required. The program will periodically perform a test on the in-scope cables to 

provide an indication of the condition of the conductor insulation.

Prior to the Period of 

Extended Operation. 

Thereafter, the manholes 

and pulling pit 

inspections will be 

performed at least every 

2 years. 

And

Thereafter, the cable 

testing will be performed 

at least every 10 years. 

Non-EQ Inaccessible 

Medium-Voltage Cables, 

and Letter 10-548, RAI 

response to 

RAI B2.1.21-1a.

17. The Non-EQ Instrumentation Circuits Subject to Sensitive, High-Voltage, Low-Level Signals 

Program will be established. The program will periodically perform a proven cable system test 

for detecting deterioration of the insulation system for those electrical cables and connections 

disconnected during calibration, or will periodically review the results and findings of 

calibrations for those electrical cables that remain connected during the calibration process.

Prior to the Period of 

Extended Operation. 

Thereafter, the cable 

testing and calibration 

reviews will not exceed a 

10-year interval. 

Non-EQ Instrumentation 

Circuits Subject to 

Sensitive, High-Voltage, 

Low-Level Signals

18. The Open-Cycle Cooling Water System Program will be enhanced to add the applicable aging 

effects as inspection criteria for the circulating water system underwater visual inspections.

Prior to the Period of 

Extended Operation 

Open-Cycle Cooling 

Water System

19. The Reactor Vessel Surveillance Program will be enhanced to include the applicable limitations 

on operating conditions to which the surveillance capsules were exposed (e.g., neutron flux, 

spectrum, irradiation temperature, etc.).

Prior to the Period of 

Extended Operation 

Reactor Vessel 

Surveillance

20. The Reactor Vessel Surveillance Program will be enhanced to include requirements for storing, 

and possible recovery, of tested and untested capsules (removed from the reactor vessel after 

August 31, 2000).

Prior to the Period of 

Extended Operation 

Reactor Vessel 

Surveillance

21. The Selective Leaching of Materials Program will be established. The program will perform a 

one-time visual inspection and hardness measurement or qualitative examination of selected 

components, within the scope of license renewal for selective leaching.

Prior to the Period of 

Extended Operation 

Selective Leaching of 

Materials

22. The Structures Monitoring Program will be enhanced to clearly define structures, structural 

elements, and miscellaneous structural commodities that are in-scope. Defined scope to 

include the MEB enclosure assemblies, structural supports, and enclosure seals.

Prior to the Period of 

Extended Operation

Letter 09-469, Response 

to RAI B2.1.18-2

23. The Structures Monitoring Program will be enhanced to monitor groundwater quality and verify 

that it remains non-aggressive to below-grade concrete.

Prior to the Period of 

Extended Operation 

Structures Monitoring 

Program

24. The Structures Monitoring Program will be enhanced to improve criteria for the detection of

aging effects for the underwater visual inspections of the in-scope structures.

Prior to the Period of 

Extended Operation 

Structures Monitoring 

Program
Appendix A

A-6

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

25. The Work Control Process Program will be established. The program will perform one-time 

inspections as a verification of the effectiveness of chemistry control programs. The program 

will also perform visual inspections of component internal surfaces and external surfaces of 

selected components to manage the effects of aging when the surfaces are made available for 

examination through surveillance and maintenance activities.

Prior to the Period of 

Extended Operation

Letter 09-597, Changes to 

the WCP Program

26. Deleted N/A Letter 09-597

27. Deleted N/A Letter 09-597

28. The Metal Fatigue of Reactor Coolant Pressure Boundary Program will be enhanced to include 

a routine assessment of the transient cycle count totals and fatigue usage status for monitored 

locations, including an action limit for the initiation of corrective action.

Prior to the Period of 

Extended Operation 

Metal Fatigue of Reactor 

Coolant Pressure 

Boundary

29. The following will be further evaluated as part of the applicant‘s ongoing performance 

improvement programs:

 ● SAMA 160: Install Emergency Diesel Generator (EDG) exhaust duct insulation.

 ● Concurrent implementation of SAMAs 81,160,166, and 167.

 ● Implementation of temporary screenhouse ventilation.

Prior to the Period of 

Extended Operation

Environmental Report –

SAMA Analysis, Letters 

09-028 and 09-291

30. Quarterly laboratory testing of fuel oil samples for water, sediment, and particulates will be 

performed on the EDG day tanks and on the technical support center diesel generator (TSC 

DG) day tank. The testing acceptance criteria will be consistent with the requirements specified 

in American Society for Testing and Materials (ASTM) D975-06b for water and sediment and 

ASTM D6217 for particulates.

Prior to the Period of 

Extended Operation

Letter 09-680, 

RAI response to 

B2.1.14-3

31. The Work Control Process Program will be enhanced to provide for a one-time-inspection of 

the EDG day tanks and the TSC DG day tank. An exterior surfaces ultrasonic test (UT) 

inspection will be performed to verify wall thickness of the bottom of each day tank. Based 

upon the UT inspections, the most limiting EDG day tank will also be drained, cleaned, and 

visually inspected as a leading indicator for the remaining tanks.

Prior to the Period of 

Extended Operation

Letter 09-469, Response 

to RAI B2.1.15-1

32. The 14 potentially cost beneficial SAMAs identified in LRA Appendix E, Attachment F, will be 

further evaluated as part of the applicant‘s ongoing performance improvement programs.

Prior to the Period of 

Extended Operation

Environmental Report –

SAMA Analysis

33. Develop a plan for identification and remediation of reactor refueling cavity liner leakage to be 

implemented during the period of extended operation.

Prior to the Period of 

Extended Operation

Letter 09-760, Response 

to RAI B2.1.31-4a

34. At least one core bore sample will be taken from the waste drumming room reinforced concrete 

ceiling below the spent fuel pool. The core sample location and depth will be sufficient to 

validate the strength of the concrete and the extent of any degradation. The core sample will be 

tested for compressive strength and will be subject to petrographic examination. Reinforcing 

steel in the core sample area will be exposed and inspected for material condition.

Prior to the end of 2011 Letter 10-093, Response 

to RAI B2.1.31-5a
Appendix A

A-7

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

35. Develop an action plan for identification and remediation of spent fuel pool (SFP) liner leakage 

to be implemented during the period of extended operation.

Prior to the Period of 

Extended Operation

Letter 09-760, Response 

to RAI B2.1.31-5a

36. If SFP liner leakage persists during the period of extended operation, an additional concrete 

core sample will be taken from the waste drumming room reinforced concrete ceiling below the 

spent fuel pool. The core sample location and depth will be sufficient to validate the strength of 

the concrete and the extent of any degradation. The core sample will be tested for compressive 

strength and will be subject to petrographic examination. Reinforcing steel in the core sample 

area will be exposed and inspected for material condition.

Prior to the end of the 

first 10 years of the 

Period of Extended 

Operation

Letter 09-760, Response 

to RAI B2.1.31-5a

37. Perform a VT-1 visual examination of the stainless steel cladding of a safety injection pump for 

indications of cracking or corrosion due to cladding breach. 

Prior to the Period of 

Extended Operation

Letter 09-777, Response 

to RAI 3.2.2.2.2 

38. The Boron Carbide Surveillance Program, which includes neutron attenuation testing, will 

continue to be performed during the period of extended operation every 3 years.

During the Period of 

Extended Operation

Letter 09-777, 

Supplemental Response 

to RAI 3.3.2.2.6-1 

39. A surveillance program will be implemented to perform verification that the Boral spent fuel 

storage rack neutron absorber B-10 areal density is maintained within the bounds of the spent 

fuel pool criticality analysis. Alternatively, the criticality analysis for the spent fuel pool will be 

revised to eliminate credit for the Boral neutron absorber material.

Prior to 2017. 

Surveillance program will 

be performed every 10 

years thereafter

Letter 09-777, 

Supplemental Response 

to RAI 3.3.2.2.6-2 

40. Implement nitrate monitoring for the component cooling system on a frequency consistent with 

the existing monitoring for ammonia. 

Prior to the Period of 

Extended Operation

Letter 10-008, Response 

to RAI B2.1.8-3a 

41. Perform a fatigue analysis of the surge line hot leg nozzle and the charging line nozzle in 

accordance with ASME Boiler and Pressure Vessel (B&PV) Code Section III, Subsection 

NB-3200 guidance and determine the cumulative usage factor (CUF), considering the effects of 

the reactor coolant environment. Confirm that CUF is less than 1.0 at the end of 60 years of 

plant operation.

Completed Letter 10-033, Final 

Response to RAI B3.2-2, 

Letter 10-324, Completion 

of Kewaunee Power 

Station License Renewal 

Commitment 41.

42. For Examination Category B-J, item No. B9.21, eight ASME Class 1 small-bore circumferential 

welds will receive volumetric and surface examinations during each 10-year lSI inspection 

interval during the period of extended operation.

During each 10-year lSI 

inspection interval during

the period of extended 

operation

Letter 10-033, 

Supplemental Response 

to RAI B2.1.2-1 
Appendix A

A-8

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

43. Ten volumetric examinations of ASME Class 1 small-bore socket welds will be performed using 

a demonstrated, nuclear-industry endorsed, inspection methodology that can detect cracking 

within the specified examination volume, if a methodology becomes available. In the event that 

a demonstrated, nuclear-industry endorsed, inspection methodology is not available, 

destructive examinations of socket welds will be substituted for volumetric nondestructive 

examinations. Each destructive weld examination will be considered equivalent to performing 

two volumetric weld examinations, such that a maximum of five destructive examinations will 

be performed.

Four volumetric 

examinations or two 

destructive examinations 

(or an equivalent 

combination of

examinations) prior to 

the period of extended

operation.

Remaining examinations

within three years of

entering the period of

extended operation.

Letter 10-665, 

Supplemental Response 

to RAI B2.1.2-2

44. Core samples will be obtained from the inside surface of a concrete wall (below the 

groundwater table elevation) or from the foundation basemat in the vicinity of the groundwater 

wells for which average sampling results have exceeded the chloride concentration limit of 500 

ppm. The concrete core samples will be tested to determine if the chloride content within the 

concrete could cause degradation due to corrosion of reinforcing steel.

Prior to the Period of 

Extended Operation

Letter 10-093, Response 

to RAI B2.1.31-3a

45. In the event that the chloride content in the groundwater does not decrease to below 500 ppm 

within the first ten years of the period of extended operation, core samples will be obtained 

from the inside surface of a concrete wall (below the groundwater table elevation) or from the 

foundation basemat in the vicinity of a groundwater well for which average sampling results 

have exceeded the chloride concentration limit of 500 ppm. The concrete core samples will be 

tested to determine if the chloride content within the concrete could cause degradation due to 

corrosion of reinforcing steel.

Prior to the end of the 

first 10 years of 

extended operation.

Letter 10-093, Response 

to RAI B2.1.31-3a

46. If the results of the core sample testing of the waste drumming room reinforced concrete ceiling 

leakage site (related to potential SFP liner leakage - Commitment 34) indicate degradation of 

the structural integrity of the concrete, at least one core bore sample will be taken near at least 

one of the refueling cavity liner leakage indication sites. The core sample location and depth 

will be sufficient to validate the strength of the concrete and the extent of any degradation. The 

core sample will be tested for compressive strength and will be subject to petrographic 

examination. Reinforcing steel in the core sample area will be exposed and inspected for 

material condition.

Prior to the Period of 

Extended Operation

Letter 10-093, Response 

to RAI B2.1.31-4a

47. Submit three examples of operating experience associated with the Work Control Process –

Internal Surfaces Monitoring Program for NRC staff review in determining the effectiveness of 

the program to detect and correct the effects of aging prior to the loss of function.

Within 2 years following 

implementation of the 

WCP aging management 

program

Letter 10-286; Response 

to RAI B2.1.32-5
Appendix A

A-9

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

48. The cathodic protection system associated with the diesel generator fuel oil storage tanks and 

protected portions of the fuel oil lines, and the circulating water system recirculation piping, will 

each be maintained available a minimum of 90% of the time during the period of extended 

operation. In addition, NACE cathodic protection system surveys will be performed at least 

annually during the period of extended operation.

During the Period of 

Extended Operation

Letter 10-548 Response 

to RAI-B2.1.7-3a

49 Recognizing that the EPRI Steam Generator Maintenance Program (SGMP) resolution is still 

under development, Kewaunee will perform an inspection of each steam generator to assess 

the condition of the divider plate assembly. The examination technique(s) will be capable of 

detecting PWSCC in the divider plate assembly and associated welds. The steam generator 

divider plate inspections will be completed prior to exceeding 10 years into the period of 

extended operation. In addition, Dominion Energy Kewaunee, Inc., (Dominion, DEK, or the 

applicant) will continue to actively participate in the EPRI SGMP studies.

Prior to 2023 Letter 10-548 Response 

to RAI-3.1.2.2.13-1a

50 Perform an audit of the Internal Surfaces Monitoring portion of the Work Control Process 

Program inspections to confirm that the components representing the leading indicators of 

aging for each of the material/environment combinations have been inspected at least once 

during the audit period.

If any scheduled surveillance and maintenance activities which were intended to encompass 

components as leading indicators of aging in each of the material/environment combinations 

have not been performed, then perform deliberate focused inspections of these components.

Prior to the Period of 

Extended Operation and 

every 10 years 

thereafter.

Deliberate focused 

inspections will be 

performed within 5 years 

of completion of the 

audits.

Letter 10-595 

(Supplemental Response 

to RAI B2.1.32-5a)

51 DEK will perform a fatigue evaluation of the pressurizer lower head and surge line that is 

consistent with the requirements of ASME B&PV Code, Section III, NB-3200 and will determine 

the cumulative fatigue usage through the period of extended operation.

Prior to the Period of 

Extended Operation

Letter 10-595 

Supplemental Response 

to RAI B3.2-2a

52 DEK will perform a review of design basis ASME Code Class 1 component fatigue evaluations 

to determine whether the NUREG/CR-6260-based components that have been evaluated for 

the effects of the reactor coolant environment on fatigue usage are the limiting components for 

the Kewaunee plant configuration. If more limiting components are identified, the most limiting 

component will be evaluated for the effects of the reactor coolant environment on fatigue 

usage.

Prior to the Period of 

Extended Operation

Letter 10-595 

Supplemental Response 

to RAI B3.2-2a
Appendix A

A-10

APPENDIX A: LONG TERM COMMITMENTS FOR LICENSE RENEWAL OF KPS

No. Commitment Implementation 

Schedule

Source

53 DEK will develop a plan to address the potential for failure of the primary-to-secondary

pressure boundary due to PWSCC cracking of tube-to-tubesheet welds.

The plan will consist of two resolution options:

1. Perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order 

to: 

a) Establish a technical basis which concludes that the structural integrity of the steam 

generator tube-to-tubesheet interface is adequately maintained with the presence of 

tube-to-tubesheet weld cracking, and

b) Establish a technical basis which concludes that the steam generator 

tube-to-tubesheet welds are not required to perform a reactor coolant pressure

boundary function.

-or2. Perform a one-time inspection of a representative number of tube-to-tubesheet welds in 

each steam generator to determine if PWSCC cracking is present. If weld cracking is 

identified: 

a) The condition will be resolved through repair or engineering evaluation to justify

continued service, as appropriate, and

b) An ongoing monitoring program will be established to perform routine 

tube-to-tubesheet inspections for the remaining life of the steam generators.

Develop a plan prior to 

the Period of Extended 

Operation

Implement the 

requirements of the plan 

prior to 2023

Letter 10-595

54 The Structures Monitoring Program will be revised to include the evaluation criteria of 

ACI 349.3R-96, Chapter 5, as the criteria to be used when evaluating conditions or findings 

identified during concrete structure inspections. This will be done prior to the performance of 

the next scheduled inspection, which will occur prior to the period of extended operation.

Prior to the Period of 

Extended Operation

Letter 10-707, Response 

to RAI B2.1.31-9.
B-1

APPENDIX B 

CHRONOLOGY

This appendix contains a chronological listing of the routine correspondence between the staff 

of the U.S. Nuclear Regulatory Commission (NRC or the staff) and the Dominion Energy 

Kewaunee, Inc.(Dominion, DEK, or the applicant), and other correspondence regarding the 

staff‘s reviews of the Kewaunee Power Station (KPS), Docket Number 50-305, license renewal 

application (LRA).

Document Date Title

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 4: 

Reactor Coolant System. (Accession No. ML071150387)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 5: 

Containment System. (Accession No. ML071150388)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 6: 

Engineered Safety Features. (Accession No. ML071150389)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 7: 

Instrumentation and Control. (Accession No. ML071150391)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 8: 

Electrical System. (Accession No. ML071150393)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. Chapter 9: 

Auxiliary and Emergency Systems. (Accession No. ML071150394)

April 19, 2007 Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. 

Chapter 10: Steam and Power Conversion System. (Accession No. ML071150399)

April 19, 2007

Kewaunee Power Station, Updated Safety Analysis Report, Revision 20. 

Chapter 11: Waste Disposal and Radiation Protection System. 

(Accession No. ML071150402)

July 14, 2008 Kewaunee License Renewal Drawing LRM-532, Revision 0, ―Personnel and 

Emergency Airlock Test Piping.‖ (Accession No. ML082470141)

July 22, 2008 Kewaunee License Renewal Drawing LRM-211, Revision 0, ―Turbine and Auxiliary 

Bldg. Traps and Drains.‖ (Accession No. ML082470110)

August 12, 2008 Kewaunee Power Station, Applicant‘s Environmental Report, Operating License 

Renewal Stage. (Accession No. ML082341039)

August 14, 2008

Kewaunee License Renewal Drawing LRM-213-9, Revision 0, ―Diesel Generator 

Startup Air Compressor A & B and Fish Screen Air Compressor System.‖ 

(Accession No. ML082470117)

August 25, 2008 Kewaunee Power Station, Receipt and Availability License Renewal Application. 

(Accession No. ML082120504)

August 25, 2008 Kewaunee Power Station, Notice of Receipt and Availability License Renewal 

Application. (Accession No. ML082120515)

September 2, 2008 Press Release-08-161: License Renewal Application for Kewaunee Nuclear Plant 

Available for Public Inspection. (Accession No. ML082460767)
Appendix B

B-2

Document Date Title

September 25, 2008 Federal Register Notice Regarding Renewal of Facility Operating License No. 

DPR-42 for an Additional 20-Year Period. (Accession No. ML082610294)

September 25, 2008

Determination of Acceptability and Sufficiency for Docketing, Proposed Review 

Schedule, and Opportunity for a Hearing Regarding the Application from Dominion 

Energy Kewaunee, Inc., for Renewal of the Operating License for the Kewaunee 

Power Station. (Accession No. ML082610303)

September 30, 2008

Request for List of State Protected Species Within the Area Under Evaluation for 

the Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML082610748)

October 2, 2008

Notice of Intent to Prepare an Environmental Impact Statement and Conduct 

Scoping Process for License Renewal for Kewaunee Power Station 

(TAC No. MD9409). (Accession No. ML082520774)

October 8, 2008 Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML082610168)

October 8, 2008 10/22/2008 -– Notice of Meeting to Discuss License Renewal Process and 

Environmental Scoping Kewaunee Power Station. (Accession No. ML082750112)

October 10, 2008 Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML082661119)

October 10, 2008 Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML082670685)

October 10, 2008 Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML082680027)

October 16, 2008 Request for Scoping Comments Concerning the Kewaunee Power Station License 

Renewal Application Review. (Accession No. ML082800098)

October 16, 2008

Press Release-08-190: NRC Seeks Public Input on Environmental Impact 

Statement for Kewaunee Nuclear Plant License Renewal Application. 

(Accession No. ML082900265)

October 22, 2008 Kewaunee Power Station License Renewal Public Meeting Presentation Slides. 

(Accession No. ML083050589)

October 22, 2008 Written Comment Submitted by State Representative Jim Soletski Supporting the 

Kewaunee Power Station License Renewal. (Accession No. ML083100092)

October 22, 2008

Written Comment Submitted by Nancy Crowley, Manitowoc Emergency Services 

Coordinator, regarding the Kewaunee Power Station License Renewal. 

(Accession No. ML083100093)

October 22, 2008 Written Comment from Bob Ziegelbauer, Manitowoc County Executive, regarding 

Kewaunee Power Station License Renewal. (Accession No. ML083100094)

October 22, 2008

Comment (1) of Bob Ziegelbauer on Behalf of the State of WI, Supporting Dominion 

Energy Kewaunee‘s Application for License Renewal. 

(Accession No. ML083100586)

October 22, 2008 Transcript of the Kewaunee License Renewal Afternoon Scoping Meeting Afternoon 

Session, October 22, 2008. (Accession No. ML083190734)

October 22, 2008 Transcript of the Kewaunee License Renewal Evening Scoping Meeting Evening 

Session, October 22, 2008. (Accession No. ML083190744)

October 27, 2008

Request for Additional Information Regarding the Review of the License Renewal 

Application for Kewaunee Power Station (TAC No. MD9409). 

(Accession No. ML082560558)
Appendix B

B-3

Document Date Title

October 28, 2008

U.S. Department of Interior, Fish and Wildlife Service, Response to Request for a 

List of Federally-Listed, Proposed, and Candidate Species and Critical Habitat in 

the Vicinity of Kewaunee Power Station. (Accession No. ML083390643)

November 5, 2008 Comments of Greg Veith in Support of Kewaunee Power Station License Renewal. 

(Accession No. ML083380455)

November 17, 2008

10/22/08 – Summary of Public License Renewal Overview and Environmental 

Scoping Meeting Related to the Review of the Kewaunee Power Station License 

Renewal Application. (Accession No. ML083090452)

November 25, 2008

Kewaunee Power Station, Response to Request for Additional Information 

Regarding the Review of the License Renewal Application. 

(Accession No. ML083520612)

December 3, 2008

Project Manager Change for the License Renewal Review for Kewaunee Power 

Station (TAC No. MD9408). (Accession No. ML083370231)

December 9, 2008 Revision of Schedule for the Conduct of Review of the Kewaunee Power Station 

License Renewal Application (TAC No. MD9408). (Accession No. ML083370245)

March 9, 2009

Kewaunee Power Station, Response to Request for Additional Information 

Regarding Severe Accident Mitigation Alternatives for the Kewaunee Power Station 

License Renewal Application. (Accession No. ML090690458)

March 23, 2009

Request to Supplement the Kewaunee Power Station License Renewal Application 

in Regards to the Use of the Work Control Process as an Aging Management 

Program (TAC No. MD9408). (Accession No. ML090530003)

April 3, 2009

Kewaunee Power Station License Renewal Application Review, Request for 

Additional Information – Balance of Plant Scoping and Screening. 

(Accession No. ML090760786)

April 8, 2009

Issuance of Environmental Scoping Summary Report Associated with the Staff‘s 

Review of the Application by Dominion Energy Kewaunee, Inc., for Renewal of the 

Operating License for Kewaunee Power Station (TAC No. MD9409). 

(Accession No. ML090770880)

April 8, 2009

04/28/2008 – Public Meeting Notice with Dominion Energy Kewaunee, Inc., to 

Discuss the NRC‘s End-of-Cycle Assessment of Kewaunee‘s Performance for the 

2008 Calendar Year. (Accession No. ML090980435)

April 11, 2009 Environmental Site Audit Regarding the Kewaunee Power Station License Renewal 

Application (TAC No. MD9409). (Accession No. ML090750720)

April 15, 2009 Revision of Schedule for the Conduct of Review of the Kewaunee Power Station 

License Renewal Application. (Accession No. ML090860946)

April 20, 2009

Reissuing of the Environmental Scoping Summary Report Associated with the 

Staff‘s Review of the Application by Dominion Energy Kewaunee, Inc., for Renewal 

of the Operating License for Kewaunee Power Station (TAC No. MD9409). 

(Accession No. ML091100093)

April 27, 2009

Kewaunee Power Station, Response to Request for Additional Information 

Regarding the Review of the License Renewal Application – Balance of Plant 

Scoping and Screening. (Accession No. ML091180470)

April 30, 2009

Kewaunee Power Station, Request for Additional Information, Review of the 

License Renewal Application – Scoping & Screening Methodology. 

(Accession No. ML091120199)

May 28, 2009

Plan for the Aging Management Program Regulatory Audit Regarding the 

Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML091470382)

May 28, 2009

Kewaunee Power Station, Response to Request for Additional Information 

Regarding the Review of the License Renewal Application – Scoping and Screening 

Methodology. (Accession No. ML091520540)
Appendix B

B-4

Document Date Title

June 4, 2009 Kewaunee License Renewal Inspection, Request for Information. 

(Accession No. ML091560579)

July 6, 2009

7/28/2008 – Forthcoming Meeting to Discuss the Status of the License Renewal 

Review for the Kewaunee Power Station License Renewal Application. 

(Accession No. ML090670003)

July 6, 2009

Kewaunee Power Station, Response to Request to Docket Information Related to 

the Environmental Site Audit, Enclosure F, Archeological and Cultural Resources. 

(Accession No. ML091970516)

July 7, 2009

Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application – Leak-Before-Break. 

(Accession No. ML090760786)

July 8, 2009 Environmental Project Manager Change for the License Renewal of Kewaunee 

Power Station. (Accession No. ML091880344)

July 10, 2009

Request for Additional Information Regarding the Environmental Review of the 

License Renewal Application for Kewaunee Power Station. 

(Accession No. ML091890017)

July 13, 2009

Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application – Aging Management Programs. 

(Accession No. ML091810958)

July 13, 2009 Scoping and Screening Audit Report Regarding the Kewaunee Power Station, 

License Renewal Application. (Accession No. ML091900081)

July 16, 2009

Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application – Structures Scoping/Fire Protection. 

(Accession No. ML091880555)

July 27, 2009

Kewaunee Power Station, Response to Request for Additional Information 

Regarding the Environmental Review of the Kewaunee Power Station License 

Renewal Application. (Accession No. ML092090277)

July 27, 2009 Kewaunee Power Station, License Renewal Application First Annual Update 

Required by 10 CFR 54.21(b). (Accession No. ML092090314)

July 28, 2009 Kewaunee License Renewal Application, Slides Public Meeting July 28, 2009. 

(Accession No. ML092100603)

August 6, 2009

Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the License Renewal Application – Structures Scoping/Fire Protection. 

(Accession No. ML092190757)

August 6, 2009

Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the License Renewal Application – Leak-Before-Break/Boral. 

(Accession No. ML092230618)

August 10, 2009 Summary of Public Meeting Related to the Review of the Kewaunee Power Station 

License Renewal Application (TAC No. MD9408). (Accession No. ML092100612)

August 12, 2009 Aging Management Program Audit Report Regarding the Kewaunee Power Station, 

License Renewal Application. (Accession No. ML091900449)

August 12, 2009 Summary of Site Audit Related to the Review of the License Renewal Application 

for Kewaunee Power Station (TAC No. MD9409). (Accession No. ML092050144)

August 12, 2009 Summary Site Audit Related to the Review of the License Renewal Application for 

Kewaunee Power Station. (Accession No. ML092180137)

August 17, 2009

Kewaunee Power Station, Response to Request for Additional Information for 

Review of License Renewal Application – Aging Management Programs. 

(Accession No. ML092320093)
Appendix B

B-5

Document Date Title

August 28, 2009

Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application – Aging Management Review Results. 

(Accession No. ML092120546)

September 10, 2009 Kewaunee Letter Re: Notice of Public Exit Meeting for NRC License Renewal 

Inspection. (Accession No. ML092530732)

September 10, 2009

9/30/2009 – Notice of Meeting with Dominion Energy Kewaunee, Inc. Re: Exit 

Meeting for IR 05000305/2009007, License Renewal Inspection. 

(Accession No. ML092540381)

September 24, 2009 Press Release-III-09-028: NRC to Discuss Results of License Renewal Inspection 

for Kewaunee Nuclear Power Plant. (Accession No. ML092670399)

September 25, 2009

Kewaunee Power Station, Supplemental Information for the Review of the License 

Renewal Application – Changes to the Work Control Process Aging Management 

Program. (Accession No. ML092710045)

September 28, 2009

Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the Kewaunee Power Station License Renewal Application – Ventilation 

Systems. (Accession No. ML092720184)

October 13, 2009

Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application – Aging Management Review Results. 

(Accession No. ML092390063)

October 13, 2009 Revision of Schedule for the Conduct of Review of the Kewaunee Power Station 

License Renewal Application. (Accession No. ML092790585)

October 14, 2009

Plan for the Aging Management Program Regulatory Audit Regarding the 

Kewaunee Power Station License Renewal Application Review. 

(Accession No. ML092790582)

November 12, 2009 IR 05000305-09-007, on 08/17/2009–09/30/2009, Kewaunee Power Station, 

License Renewal Inspection. (Accession No. ML093160727)

November 13, 2009

Kewaunee Power Station, Response to Request for Additional Information for 

Review of the Kewaunee Power Station License Renewal Application – Aging 

Management Review Results. (Accession No. ML093170751)

November 20, 2009 Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application. (Accession No. ML091890836)

December 3, 2009

Request for Additional Information for the Review of the Kewaunee License 

Renewal Application – Aging Management Review/Aging Management Program. 

(Accession No. ML093240095)

December 14, 2009 Work Control Process Program Audit Report Regarding the Kewaunee Power 

Station License Renewal Application. (Accession No. ML093260003)

December 16, 2009

Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application – Aging Management Reviews. 

(Accession No. ML093310443)

December 17, 2009 Safety Project Manager Change for the License Renewal Review for the Kewaunee 

Power Station. (Accession No. ML093310360)

December 28, 2009 Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the License Renewal Application. (Accession No. ML100110061)

January 4, 2010

Request for Additional Information Regarding the Review of the Kewaunee Power 

Station License Renewal Application – Aging Management Reviews. 

(Accession No. ML093500306)

January 21, 2010

Kewaunee Power Station, Response to Request for Additional Information for the

Review of the License Renewal Application – Aging Management Review/Aging 

Management Program. (Accession No. ML100220066)
Appendix B

B-6

Document Date Title

January 21, 2010

Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the License Renewal Application – Aging Management Review/Aging 

Management Program. (Accession No. ML100220082)

January 29, 2010

Notice of Availability of the Draft Plant-Specific Supplement 40 to the Generic 

Environmental Impact Statement for License Renewal of Nuclear Plants Regarding 

Kewaunee Power Station. (Accession No. ML093240009)

January 29, 2010

Notice of Availability of the Draft Plant-Specific Supplement 40 to the Generic 

Environmental Impact Statement for License Renewal of Nuclear Power Plants 

Regarding Kewaunee Power Station. (Accession No. ML093240014)

January 29, 2010

Notice of Availability of the Draft Plant-Specific Supplement 40 to the Generic 

Environmental Impact Statement for License Renewal of Nuclear Plants Regarding 

Kewaunee Power Station. (Accession No. ML093280799)

February 1, 2010

Press Release 10-022: NRC Seeks Public Input on Draft Environmental Impact 

Statement for Kewaunee Nuclear Plant License Renewal; Meetings Scheduled. 

(Accession No. ML100322044)

February 2, 2010

Kewaunee Power Station – Response to Request for Additional Information for the 

Review of the Kewaunee Power Station License Renewal Application – Aging 

Management Review/Aging Management Program. (Accession No. ML100331879)

February 2, 2010

Kewaunee Power Station, Response to Request for Additional Information for the 

Review of the Kewaunee Power Station License Renewal Application – Aging 

Management Review/Aging Management Program. (Accession No. ML100360085)

February 2, 2010 Price J A, Dominion Energy Kewaunee, Inc., ―Kewaunee Power Station - Response 

to Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application Aging Management Review/Aging Management 

Program.‖ (Accession No. ML100331879)

February 2, 2010 Price J A, Dominion Energy Kewaunee, Inc., ―Kewaunee Power Station, Response 

to Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application-Aging Management Review/Aging Management 

Program.‖ (Accession No. ML100360085)

February 15, 2010 Price J A, Dominion Energy Kewaunee, Inc., ―Kewaunee, Supplemental Information 

for Review of License Renewal Application-Aging Management Review/Aging 

Management Program.‖ (Accession No. ML100470795)

February 16, 2010 Daily J W, ―Summary of Telephone Conference Call Between Dominion Energy 

Kewaunee, Inc. and USNRC to Discuss Certain Request for Additional Information 

on Structural Items‖ (TAC No. MD9408). (Accession No. ML100321077)

March 11, 2010 Request for Additional Information for the Review of the Kewaunee Power Station, 

License Renewal Application. (Accession No. ML100690399)

March 26, 2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee, Response to Request for 

Additional Information Associated with Review of License Renewal Application.‖ 

(Accession No. ML100890229)

March 31, 2010 Meeting Summary, Daily J W, ―Summary of Telephone Conference Call Between 

Dominion Energy Kewaunee, Inc. and the NRC to Discuss Certain RAI Responses 

on Two Mechanical Systems.‖ (Accession No. ML100710741)

April 14, 2010 Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application. (TAC No. MD9408). (Accession No. ML100950379)

May 5, 2010 Gilman T D, Structural Integrity Associates, Inc, Report No. 0900090.401, 

Revision 0, ―60-Year EAF Analyses Summary Report, Kewaunee Power Station 

Charging Nozzle & RCS Hot Leg Surge Nozzle.‖ (Accession No. ML101610286)

May 13, 2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee, Response to Request for 

Additional Information Related to the Review of the License Renewal Application.‖

(Accession No. ML101340182)

May 27, 2010 Daily J, NRC/NRR/DLR/RPOB, to Heacock D A, Dominion Energy Kewaunee, Inc, 

―Request for Additional Information for the Review of the Kewaunee Power Station 

License Renewal Application.‖ (Accession No. ML101410322)
Appendix B

B-7

Document Date Title

June 1, 2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee, Completion of License 

Renewal Commitment 41 re Fatigue Analysis of Surge Line Hot leg Nozzle. Report 

No. 0900090.401 Enclosed.‖ (Accession No. ML101610233)

June 16, 2010 Daily J W, NRC/NRR/DLR/RPOB, to Heacock D A, Dominion Energy Kewaunee, 

Inc, Letter re: ―Change in Schedule for Review of the Kewaunee Power Station 

License Renewal Application Safety Evaluation (TAC No. MD9408).‖ (Accession 

No. ML101600324)

July 15, 2010 Robinson J E, NRC/NRR/DLR/RPOB, to Hackett E H, NRC/ACRS, ―Memorandum 

to ACRS Subcommittee re Kewaunee SER.‖ (Accession No. ML101190116)

July 15, 2010 Holian B E, NRC/NRR/DLR, to Heacock D A, Dominion Energy Kewaunee, Inc, 

―Transmittal of Kewaunee Safety Evaluation Report with Open Items Related to 

License Renewal of Kewaunee Power Station.‖ (Accession No. ML101190345)

July 22, 2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee Power Station - Response 

to Request for Additional Information for the Review of License Renewal 

Application.‖ (Accession No. ML102240062)

August 9, 2010 Hartz L N, Dominion, Dominion Energy Kewaunee, Inc, ―Kewaunee - License 

Renewal Application Second Annual Update Required by 10 CFR 54.21(b).‖

(Accession No. ML102290141)

August 30,2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee, License Renewal -

Comments on SER with Open Items.‖ (Accession No. ML102430118)

September 9, 2010 Daily, J, NRC/NRR/DLR/RPOB, Record of conversation-email re: Operator 

Response to High dP in IA Dryers - related to Kewaunee SER with open itemsSeptember 9, 2010. (Accession No. ML102700431)

September 9, 2010 Daily, J, NRC/NRR/DLR/RPOB, Summary of Discussion on September 9, 2010, 

Between Dominion Energy Kewaunee, Inc. and the U.S. Nuclear Regulatory 

Commission to Discuss Draft Follow-Up RAI on Steam Generator Divider Plates.

(Accession No. ML102700438)

September 20, 2010 Daily, J, NRC/NRR/DLR/RPOB, Summary of Discussion on September 20, 2010, 

Between Dominion Energy Kewaunee, Inc. and the U.S. Nuclear Regulatory 

Commission to Discuss Applicant‘s Commitment #43 Small Bore Piping. (Accession 

No. ML102700447)

September 22, 2010 Satorius M A, NRC/RGN-III/ORA, to Leeds E J, NRC/NRR, ―Memo 09/22/10 

Kewaunee Power Station License Renewal Application.‖ (Accession 

No. ML102660247)

September 23, 2010 Hartz L N, Dominion Energy Kewaunee, Inc, ―Kewaunee Power Station - Response 

to Request for Additional Information for the Review of the License Renewal 

Application.‖ (Accession No. ML102700162)

September 30, 2010 Daily, J, NRC/NRR/DLR/RPOB, Summary of Discussion on September 30, 2010, 

Between Dominion Energy Kewaunee, Inc. and the U.S. Nuclear Regulatory 

Commission to Discuss Draft Follow-Up RAI on Metal Fatigue and FatigueProTM.

(Accession No. ML102910050)

October 13, 2010 Daily, J, NRC/NRR/DLR/RPB1, Summary of Discussion on October 13, 2010, 

Between Dominion Energy Kewaunee, Inc. and the U.S. Nuclear Regulatory 

Commission to Discuss Issues Related to LRA Item 3.1.1-35 and to Dominion‘s 

Responses on Work Control Process Program. (Accession No. ML102910058)

October 20, 2010 Price, J A, Dominion Energy Kewaunee, Inc., ―Kewaunee Power Station 

Supplemental Information for the Review of the Kewaunee Power Station License 

Renewal Application.‖ (Accession No. ML102930573) 

November 9, 2010 Daily, J, NRC/NRR/DLR/RPB1, Summary of Discussion on November 4, 2010, 

Between Dominion Energy Kewaunee, Inc. and the U.S. Nuclear Regulatory 

Commission to discuss latest issue related to ASME Class 1 small-bore socket 

welds. (Accession No. ML103130124)
Appendix B

B-8

Document Date Title

November 9, 2010 Price, J A, Dominion Energy Kewaunee, Inc., ―Kewaunee Power Station 

Supplemental Information for the Review of the Kewaunee Power Station License 

Renewal Application.‖ (Accession No. ML103130472)

November 23, 2010 Price, J A, Dominion Energy Kewaunee, Inc., ―Kewaunee Power Station 

Supplemental Information for the Review of the Kewaunee Power Station License 

Renewal Application.‖ (Accession No. ML103270580)

December 8, 2010 Daily, J, NRC/NRR/DLR/RPB1, Record of Discussion with Dominion Energy 

Kewaunee on four issues related to DEK‘s Structures Monitoring and Selective 

Leaching Programs. (Accession No. ML103210140)

December 17, 2010 Pham, B, NRC/NRR/DLR/RPB1, ―Advisory Committee Reactor Safeguards Review 

of the Kewaunee Power Station License Renewal Application – Safety Evaluation 

Report (Accession No. ML103500555)

January 7, 2011 Abdel-Khalik, S. to Gregory B. Jaczko, Chairman, U.S. Nuclear Regulatory 

Commission, ―Report on the Safety Aspects of the License Renewal Application for 

the Kewaunee Power Station‖ (Accession No. ML103410361)
C-1

APPENDIX C 

PRINCIPAL CONTRIBUTORS

Name Responsibility

E. Leeds Management Oversight

B. Boger Management Oversight

B. Holian Management Oversight

S. Lee Management Oversight

M. Galloway Management Oversight

J. Dozier Management Oversight

R. Auluck Management Oversight

B. Pham Management Oversight

J. Robinson Management Oversight

D. Pelton Management Oversight

G. Shukla Management Oversight

G. Cranston Management Oversight

G. Wilson Management Oversight

T. Chan Management Oversight

R. Taylor Management Oversight

T. Lupold Management Oversight

M. Mitchell Management Oversight

R. Denning Management Oversight

M. Khanna Management Oversight

G. Casto Management Oversight

A. Klein Management Oversight

A. Hiser Management Oversight

J. Daily Project Management

S. Lopas Project Management
Appendix C

C-2

Name Responsibility

D. Doyle Project Management

S. Hernandez-Quinones Project Management

S. Cuadrado De Jesús Project Management

B. Rogers Reviewer—Mechanical

A. Prinaris Reviewer—Materials

A. Sheik Reviewer—Structural

A. Wong Reviewer—Mechanical

B. Fu Reviewer—Materials

B. Lehman Reviewer—Structural

B. Parks Reviewer—Mechanical

B. Rogers Scoping and Screening Methodology Audit

C. Doutt Reviewer—Electrical

C. Yang Reviewer—Mechanical

D. Alley Reviewer—Materials

D. Brittner Reviewer—Mechanical

D. Diercks Reviewer—Mechanical

D. Hoang Reviewer—Structural

D. Naus Reviewer—Structural

D. Nguyen Reviewer—Electrical

E. Smith Reviewer—Mechanical

E. Wong Mechanical Engineering

J. Collins Reviewer—DCI

J. Davis Reviewer—Materials

J. Gavula Reviewer—Mechanical

J. Medoff Reviewer—Mechanical

J. Shea Reviewer—Mechanical

J. Tsao Reviewer—Mechanical
Appendix C

C-3

Name Responsibility

J. Uribe Reviewer—Structural

K. Desai Reviewer—Mechanical

M. Kichline Reviewer—Mechanical

M. Sircar Reviewer—Structural

N. Iqbal Reviewer—Fire Protection

O. Chopra Reviewer—Materials

O. Yee Reviewer—Mechanical

R. Sun Reviewer—Mechanical

R. Vaucher Reviewer—Mechanical

S. Min Reviewer—Materials

W. Holston Reviewer—Mechanical

W. Smith Reviewer—Materials

Contractor Technical Area

Thomas Associates, Inc. SER Support

Advanced Technologies and Laboratories, Inc. Plant Systems/GALL Audit

D-1

APPENDIX D 

REFERENCES

This appendix contains a listing of the references used in the preparation of the safety 

evaluation report (SER) prepared during the review of the license renewal application (LRA) for 

Kewaunee Power Station (KPS), Docket Number 50-305.

APPENDIX D: REFERENCES

10 CFR Part 140, Appendix B, ―Form of Indemnity Agreement With Licensees Furnishing Insurance Policies As 

Proof of Financial Protection.‖

10 CFR Part 50, ―Domestic Licensing of Production and Utilization Facilities.‖

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

Functions.‖

10 CFR Part 54, ―Requirements for Renewal of Operating Licenses for Nuclear Power Plants.‖

AMSE OM-S/G-1998, Part 17, Section 5.3, ―Inservice Performance Tests.‖

ANSI/ISA-7.0.01-1996.

ASME Boiler & Pressure Vessel Code.

ASME Code Case N-629, ―Use of Fracture Toughness Test Data to Establish Reference Temperature for 

Pressure Retaining Materials.‖

ASME OM-S/G-1998, Part 17.

ASTM D130, ―Standard Test Method for Corrosiveness to Copper from Petroleum Products by Copper Strip Test.‖

ASTM D6217, ―Standard Test Method for Particulate Contamination in Middle Distillate Fuels by Laboratory 

Filtration.‖

EPRI, ―Aging Assessment Field Guide.‖

EPRI 1002884, ―Pressurized Water Reactor Primary Water Chemistry Guidelines.‖

EPRI 1010639, ―Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,‖ Revision 4, January 

2006.

EPRI MRP-126 ―Generic Guidance for Alloy 600 Management.‖

EPRI NP-7079, ―Instrument air systems: A guide for power plant maintenance personnel.‖

EPRI Report 1010639, ―Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,‖ Revision 4, 

dated January 2006.

EPRI TR-1007820, ―Closed Cooling Water Chemistry Guideline,‖ Revision 1, 2004.

EPRI TR-1008224, ―PWR Secondary Water Chemistry Guidelines,‖ Revision 6, December 2004.

EPRI TR-1014986, ―Pressurized Water Reactor Primary Water Chemistry Guidelines,‖ Volume1, Revision 6.

EPRI TR-104213, ―Bolted Joint Maintenance & Applications Guide,‖ December 1, 1995.

EPRI TR-107514, ―Age-Related Degradation Inspection Method and Demonstration in Behalf of Calvert Cliffs 

Nuclear Power Plant License Renewal Application.‖

EPRI TR-108147, ―Compressor and Instrument Air System Maintenance Guide,‖ March 1998.

Generic Letter 98-04, ―Potential for Degradation of the Emergency Core Cooling System and the Containment 

Spray System After a Loss-Of-Coolant Accident Because of Construction and Protective Coating Deficiencies and 

Foreign Material In Containment.‖
Appendix D

D-2

APPENDIX D: REFERENCES

GSI-191, ―Assessment of Debris Accumulation on PWR Sump Performance.‖

Kewaunee Power Station, Updated Safety Analysis Report (USAR).

Letter from Christopher I. Grimes, NRC to Douglas J. Walters, Nuclear Energy Institute, Subject: License Renewal 

Issue No. 98-0030, ―Thermal Aging Embrittlement Of Cast Austenitic Stainless Steel Components,‖ dated May 19, 

2000.

License Renewal Application (LRA), Kewaunee Power Station, dated August 12, 2008.

NEI 03-08, ―Guideline for the Management of Materials Issues.‖

NEI 95-10, Revision 6, ―Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License 

Renewal Rule,‖ June 2005.

NRC Bulletin 2003-01, ―Potential Impact of Debris Blockage on Emergency Sump Recirculation at PWRs.‖

NRC Bulletin 88-09, ―Thimble Tube Thinning in Westinghouse Reactors.‖

NRC Commission Order, Entergy Nuclear Vermont Yankee, LLC (Vermont Nuclear Power Station) CLI-10-17, 

dated July 8, 2010. (Accession No. ML101890775)

NRC Generic Letter (GL) 2004-02, ―Potential Impact of Debris Blockage on Emergency Recirculation During 

Design Basis Accidents at Pressurized-Water Reactors.‖

NRC GL 88-14, ―Instrument Air Supply System Problems Affecting Safety-Related Equipment.‖

NRC GL 92-01, ―Reactor Vessel Structural Integrity,‖ issued February 28, 1992.

NRC GL 88-05, ―Boric Acid Corrosion of Carbon Steel Reactor Components in PWR Plants.‖

NRC Information Notice 94-63, ―Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks.‖

NUREG/CR-4513, Revision 1, ―Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging 

in LWR Systems.‖

NUREG/CR-5704, ―Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels,‖ April 1999.

NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant 

Components.‖

NUREG/CR-6583, ―Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy 

Steels,‖ February 1998.

NUREG-0313, ―Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure 

Boundary Piping.‖

NUREG-0612, ―Control of Heavy Loads at Nuclear Power Plants,‖ July 1980.

NUREG-1061, ―Report of the U.S. Nuclear Regulatory Commission Piping Review Committee.‖

NUREG-1275, Volume 2, ―Operating Experience Feedback Report – Air Systems Problems.‖

NUREG-1350, ―2007-2008 Information Digest.‖

NUREG-1431, ―Standard Technical Specifications Westinghouse Plants.‖

NUREG-1557, ―Summary of technical information and agreements from Nuclear Management and Resources 

Council industry reports addressing license renewal.‖

NUREG-1760, ―Aging Assessment of Safety-Related Fuses Used in Low-and Medium-Voltage Application in 

Nuclear Power Plants.‖ 

NUREG-1800, Revision 1, ―Standard Review Plan for Review of License Renewal Applications for Nuclear Power 

Plants,‖ September 2005.

NUREG-1801, Revision 1, ―Generic Aging Lessons Learned (GALL) Report,‖ September 2005.

NUREG-1833, ―Technical Bases for Revision to the License Renewal Guidance Documents,‖ October 2005.
Appendix D

D-3

APPENDIX D: REFERENCES

Regulatory Guide (RG) 1.89, Revision 1, ―Environmental Qualification of Certain Electric Equipment Important to 

Safety for Nuclear Power Plants.‖

RG 1.188, Revision 1, ―Standard Format and Content for Applications To Renew Nuclear Power Plant Operating 

Licenses,‖ September 2005.

RG 1.190, ―Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,‖ March 2001.

RG 1.54, ―Quality Assurance Requirements for Protective Coatings Applied to Water Cooled Nuclear Power 

Plants.‖

RG 1.99, Revision 2, ―Radiation Embrittlement of Reactor Vessel Materials,‖ May 1988.

WCAP-12866, ―Bottom Mounted Instrumentation Flux Thimble Tube Wear,‖ 1991.

WCAP-16609, ―Master Curve Assessment of Kewaunee Power Station Reactor Vessel Weld Metal.‖ 

WCAP-16642, ―Evaluation of Pressurized Thermal Shock for Kewaunee Power Station.‖

WCAP-12841, ―Structural Evaluation of the Kewaunee Pressurizer Surge Line, Considering the Effects of Thermal 

Stratification.‖

WCAP-12842, ―Structural Evaluation of the Kewaunee Pressurizer Surge Line, Considering the Effects of Thermal 

Stratification‖ (non-proprietary).

WCAP-16641, ―Analysis of Capsule T from Dominion Energy Kewaunee Power Station Reactor Vessel Radiation 

Surveillance Program.‖

WCAP-14040-NP-A, ―Methodology Used to Develop Cold Overpressure Mitigating Systems Setpoints and RCS 

Heatup and Cooldown Limit Curves.‖ 

WCAP-16083-NP-A, ―Benchmark Testing of the FERRET Code for Least Squares Evaluation of Light Water 

Reactor Dosimetry, May 2006.‖

WCAP-16643, ―Kewaunee Power Station Heatup and Cooldown Limit Curves for Normal Operation.‖

WCAP-14535, ―Topical Report of Reactor Coolant Pump Flywheel Inspection Elimination.‖

WCAP-14535-A, ―Topical Report of Reactor Coolant Pump Flywheel Inspection Elimination‖ (staff-approved 

version).

WCAP-15666-1A, ―Extension of RCP Motor Flywheel Examination.‖

WCAP-15666, ―Extension of Reactor Coolant Pump Motor Flywheel Examination.‖ (TAC No. MB2819) 

(Accession No. ML031250595)

WCAP-16738-NP, ―Technical Bases for Eliminating Large Primary Loop Pipe Rupture as the Structural Design 

Basis for the Kewaunee Power Station for the License Renewal Program.‖ (Accession No. ML092230622)

WCAP-15338-A, ―A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants.‖

WCAP-7733, ―Reactor Vessels Weld Cladding – Base Metal Interaction.‖

WCAP-8330, ―Westinghouse Anticipated Transients without Trip Analysis.‖ (Accession No. ML0617902740)