Safety Evaluation Report

Related to the License Renewal 

of Prairie Island Nuclear 

Generating Plant Units 1 and 2

Docket Nos. 50-282 and 50-306

Northern States Power Company, a Minnesota 

Corporation (NSPM) 

Office of Nuclear Reactor Regulation

NUREG-1960

 
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Safety Evaluation Report

Related to the License Renewal 

of Prairie Island Nuclear 

Generating Plant Units 1 and 2

Docket Nos. 50-282 and 50-306

Northern States Power Company, a Minnesota 

Corporation (NSPM)

Manuscript Completed: May 2011

Date Published: August 2011

Office of Nuclear Reactor Regulation

NUREG-1960

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Prairie Island Nuclear 

Generating Plant (PINGP), Units 1 and 2, license renewal application (LRA) by the United 

States (US) Nuclear Regulatory Commission (NRC) staff (the staff). By letter dated April 11, 

2008, Nuclear Management Company, LLC, (NMC 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.” NMC requests renewal of the Units 1 

and 2 operating licenses (Facility Operating License Numbers DPR-42 and DPR-60, 

respectively) for a period of 20 years beyond the current expirations at midnight August 9, 2013, 

for Unit 1, and at midnight October 29, 2014, for Unit 2.

PINGP is located within the city limits of the City of Red Wing, Minnesota on the West bank of 

the Mississippi River in southeastern Minnesota. The NRC issued the construction permits for 

Units 1 and 2 on June 25, 1968. The NRC issued the operating licenses for Unit 1 on August 9, 

1973, and on October 29, 1974, for Unit 2. Units 1 and 2 employ a two-loop pressurized water 

reactor design with a dry ambient containment. Westinghouse Electric Corporation supplied the 

nuclear steam supply system and Pioneer Service & Engineering Company originally designed 

the balance of the plant, and Northern States Power constructed the plant. The licensed power 

output of each unit is 1650 megawatt thermal with a gross electrical output of approximately 

575 megawatt electric.

On June 4, 2009, the staff issued an SER with Open Items Related to the License Renewal of 

Prairie Island Nuclear Generating Plant, Units 1 and 2, in which the staff identified three open 

items necessitating further review. This SER presents the status of the staff’s review of 

information submitted through August 21, 2009, the cutoff date for consideration in this SER. 

The three open items that had been identified in the previous SER were resolved before the 

staff made a final determination on the LRA. SER Section 1.5 summarizes these items and their 

resolution. Section 6.0 provides the staff’s final conclusion on its review of the PINGP LRA.

v

TABLE OF CONTENTS

ABSTRACT.....................................................................................................................iii

ABBREVIATIONS.........................................................................................................xiv

INTRODUCTION AND GENERAL DISCUSSION ........................................................... 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 ......................................................................................1-6

1.5 Summary of Open Items...................................................................................1-7

1.6 Summary of Confirmatory Items .......................................................................1-9

1.7 Summary of Proposed License Conditions .......................................................1-9

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).......................................................2-13

2.1.4.3 Application of the Scoping Criteria in 

 10 CFR 54.4(a)(3).......................................................2-19

2.1.4.4 Plant-Level Scoping of Systems and Structures.......... 2-23

2.1.4.5 Mechanical Component Scoping.................................2-25

2.1.4.6 Structural Scoping.......................................................2-27

2.1.4.7 Electrical Component Scoping ....................................2-28

2.1.4.8 Scoping Methodology Conclusion ...............................2-29

2.1.5 Screening Methodology...................................................................2-30
vi

2.1.5.1 General Screening Methodology .................................2-30

2.1.5.2 Mechanical Component Screening..............................2-31

2.1.5.3 Structural Component Screening ................................2-32

2.1.5.4 Electrical Component Screening .................................2-33

2.1.5.5 Screening Methodology Conclusion ............................2-35

2.1.6 Summary of Evaluation Findings .....................................................2-35

2.2 Plant-Level Scoping Results ...........................................................................2-36

2.2.1 Introduction .....................................................................................2-36

2.2.2 Summary of Technical Information in the Application ......................2-36

2.2.3 Staff Evaluation ...............................................................................2-36

2.2.4 Conclusion ......................................................................................2-39

2.3 Scoping and Screening Results: Mechanical Systems....................................2-39

2.3.1 Reactor Vessel, Internals, and Reactor Coolant System ................. 2-40

2.3.1.1 Pressurizer System........................................................2-40

2.3.1.2 Reactor Coolant System ................................................2-41

2.3.1.3 Reactor Internals System...............................................2-41

2.3.1.4 Reactor Vessel System..................................................2-42

2.3.1.5 Steam Generator System...............................................2-42

2.3.2 Engineered Safety Features............................................................2-43

2.3.2.1 Containment Spray System.........................................2-43

2.3.2.2 Residual Heat Removal System..................................2-44

2.3.2.3 Safety Injection System...............................................2-45

2.3.3 Auxiliary Systems............................................................................2-45

2.3.3.1 Auxiliary and Radwaste Area Ventilation System ........ 2-47

2.3.3.2 Chemical and Volume Control System........................2-49

2.3.3.3 Component Cooling Water System .............................2-52

2.3.3.4 Containment Hydrogen Control System ......................2-53

2.3.3.5 Control Room and Miscellaneous Area 

 Ventilation System ......................................................2-54

2.3.3.6 Cooling Water System ................................................2-56

2.3.3.7 Diesel Generator and Screenhouse 

 Ventilation System ......................................................2-58

2.3.3.8 Diesel Generators and Support System ......................2-59

2.3.3.9 Fire Protection System................................................2-62

2.3.3.10 Fuel Oil System.........................................................2-70

2.3.3.11 Heating System.........................................................2-71

2.3.3.12 Miscellaneous Gas System .......................................2-73

2.3.3.13 Plant Sample System................................................2-74

2.3.3.14 Primary Containment Ventilation System .................. 2-75

2.3.3.15 Radiation Monitoring System.....................................2-77

2.3.3.16 Spent Fuel Pool Cooling System...............................2-77

2.3.3.17 Station and Instrument Air System ............................2-79

2.3.3.18 Steam Exclusion System...........................................2-81

2.3.3.19 Turbine and Administration Building 

 Ventilation System ....................................................2-82

2.3.3.20 Waste Disposal System ............................................2-82

2.3.3.21 Water Treatment System ..........................................2-85
vii

2.3.4 Steam and Power Conversion Systems ..........................................2-85

2.3.4.1 Auxiliary Feedwater System................................... 2-86

2.3.4.2 Bleed Steam System....................................................2-86

2.3.4.3 Circulating Water System.............................................2-87

2.3.4.4 Condensate System.....................................................2-88

2.3.4.5 Feedwater System .......................................................2-89

2.3.4.6 Main Steam System.....................................................2-89

2.3.4.7 Steam Generator Blowdown System............................2-90

2.3.4.8 Turbine Generator and Support System.......................2-90

2.4 Scoping and Screening Results: Containments, Structures, and Component 

 Supports .........................................................................................................2-91

2.4.1 Auxiliary Building and Turbine Building............................................2-92

2.4.1.1 Summary of Technical Information in the Application .. 2-92

2.4.1.2 Staff Evaluation...........................................................2-93

2.4.1.3 Conclusion ..................................................................2-94

2.4.2 Component Supports ......................................................................2-94

2.4.2.1 Summary of Technical Information in the Application .. 2-94

2.4.2.2 Conclusion ..................................................................2-94

2.4.3 Cranes, Heavy Loads, and Fuel Handling System Components...... 2-95

2.4.3.1 Summary of Technical Information in the Application .. 2-95

2.4.3.2 Staff Evaluation...........................................................2-95

2.4.3.3 Conclusion ..................................................................2-96

2.4.4 D5/D6 Diesel Generator Building and Underground 

 Storage Vault, Fuel Oil Transfer House, Old Service Building, and 

 New Service Building ......................................................................2-97

2.4.4.1 Summary of Technical Information in the Application .. 2-97

2.4.4.2 Conclusion ..................................................................2-98

2.4.5 Fire Protection Barriers....................................................................2-98

2.4.5.1 Summary of Technical Information in the Application .. 2-98

2.4.5.2 Conclusion ..................................................................2-98

2.4.6 Radwaste Building, Old Administration Building, and Administration 

 Building Addition..............................................................................2-99

2.4.6.1 Summary of Technical Information in the Application .. 2-99

2.4.6.2 Conclusion ..................................................................2-99

2.4.7 Reactor Containment Vessels, Unit 1 and Unit 2.............................2-99

2.4.7.1 Summary of Technical Information in the Application .. 2-99

2.4.7.2 Staff Evaluation.........................................................2-100

2.4.7.3 Conclusion ................................................................2-102

2.4.8 SBO Yard Structures.....................................................................2-102

2.4.8.1 Summary of Technical Information in the Application 2-102

2.4.8.2 Staff Evaluation.........................................................2-103

2.4.8.3 Conclusion ................................................................2-104

2.4.9 Shield Buildings, Unit 1 and Unit 2 ................................................ 2-104

2.4.9.1 Summary of Technical Information in the Application 2-104

2.4.9.2 Conclusion ................................................................2-105

2.4.10 Tank Foundations........................................................................2-105

2.4.10.1 Summary of Technical Information 

 in the Application.....................................................2-105
viii

2.4.10.2 Conclusion ..............................................................2-105

2.4.11 Water Control Structures-Approach Canal, Emergency 

 Cooling Water Intake, Intake Canal, and Screenhouse................ 2-106

2.4.11.1 Summary of Technical Information 

 in the Application.....................................................2-106

2.4.11.2 Staff Evaluation.......................................................2-107

2.4.11.3 Conclusion ..............................................................2-108

2.5 Scoping and Screening Results: Electrical and Instrumentation 

 and Control Systems ....................................................................................2-108

2.5.1 Electrical and Instrumentation and Controls Systems.................... 2-109

2.5.1.1 Summary of Technical Information 

 in the Application.......................................................2-109

2.5.1.2 Staff Evaluation.........................................................2-111

2.5.1.3 Conclusion ................................................................2-112

2.6 Conclusion for Scoping and Screening .........................................................2-112

AGING MANAGEMENT REVIEW RESULTS...............................................................3-1

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

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

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

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

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

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

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

3.0.2.3 UFSAR Supplement.......................................................3-6

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

3.0.3 Aging Management Programs...........................................................3-7

3.0.3.1 AMPs Consistent with the GALL Report.......................3-12

3.0.3.2 AMPs Consistent with the GALL Report with 

 Exceptions or Enhancements.......................................3-74

3.0.3.3 AMPs Not Consistent With or Not Addressed 

in the GALL Report.............................................3-161

3.0.4 Quality Assurance Program Attributes Integral to 

 Aging Management Programs........................................................3-183

3.0.4.1 Summary of Technical Information in Application........ 3-183

3.0.4.2 Staff Evaluation...........................................................3-183

3.0.4.3 Conclusion..................................................................3-184

3.1 Aging Management of Reactor Vessel, Internals and Reactor 

 Coolant System ..............................................................................................3-185

3.1.1 Summary of Technical Information in the Application ...................... 3-185

3.1.2 Staff Evaluation ...............................................................................3-185

3.1.2.1 AMR Results Consistent with the GALL Report.......... 3-206

3.1.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-216

3.1.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report ....................................................3-239
ix

3.1.3 Conclusion .....................................................................................3-243

3.2 Aging Management of Engineered Safety Features....................................... 3-243

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

3.2.2 Staff Evaluation ..............................................................................3-243

3.2.2.1 AMR Results Consistent with the GALL Report.......... 3-255

3.2.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-257

3.2.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report ....................................................3-271

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 Consistent with the GALL Report.......... 3-294

3.3.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-314

3.3.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report ....................................................3-347

3.3.3 Conclusion .....................................................................................3-382

3.4 Aging Management of Steam and Power Conversion System ....................... 3-382

3.4.1 Summary of Technical Information in the Application ..................... 3-382

3.4.2 Staff Evaluation ..............................................................................3-382

3.4.2.1 AMR Results Consistent with the GALL Report.......... 3-391

3.4.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-398

3.4.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report ....................................................3-415

3.4.3 Conclusion .....................................................................................3-426

3.5 Aging Management of Structures and Component Supports ......................... 3-426

3.5.1 Summary of Technical Information in the Application ..................... 3-426

3.5.2 Staff Evaluation ..............................................................................3-427

3.5.2.1 AMR Results Consistent with the GALL Report.......... 3-442

3.5.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-447

3.5.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report .................................................... 3-465

3.5.3 Conclusion .....................................................................................3-474

3.6 Aging Management of Electrical and Instrumentation and Controls System .. 3-474

3.6.1 Summary of Technical Information in the Application ..................... 3-474

3.6.2 Staff Evaluation ..............................................................................3-475

3.6.2.1 AMR Results Consistent with the GALL Report.......... 3-479

3.6.2.2 AMR Results Consistent with the GALL Report 

 for Which Further Evaluation is Recommended ......... 3-480

3.6.2.3 AMR Results Not Consistent with or Not Addressed 

 in the GALL Report ....................................................3-485
x

3.6.3 Conclusion .....................................................................................3-487

3.7 Conclusion for Aging Management Review Results....................................... 3-487

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

4.1.1.1 Amendment of LRA Section 4.7.5, Probability of 

 Damage to Safeguards Equipment from 

 Turbine Missiles ............................................................4-2

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

4.1.2.1 "Staff Evaluation of the Applicant's LRA Amendment to Delete 

LRA Section 4.7.5, Probability of Damage to Safeguards 

Equipment from Turbine Missiles, from the Scope of the LRA"

4.1.3 Conclusion ........................................................................................4-6

4.2 Reactor Vessel Neutron Embrittlement.............................................................4-6

4.2.1 Reactor Vessel Fluence ....................................................................4-7

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

4.2.1.2 Staff Evaluation.............................................................4-7

4.2.1.3 UFSAR Supplement......................................................4-8

4.2.1.4 Conclusion ....................................................................4-8

4.2.2 Charpy Upper-Shelf Energy ..............................................................4-9

4.2.2.1 Summary of Technical Information in Application..........4-9

4.2.2.2 Staff Evaluation.............................................................4-9

4.2.2.3 UFSAR Supplement....................................................4-10

4.2.2.4 Conclusion ..................................................................4-10

4.2.3 Pressurized Thermal Shock ............................................................4-11

4.2.3.1 Summary of Technical Information in Application........ 4-11

4.2.3.2 Staff Evaluation...........................................................4-11

4.2.3.3 UFSAR Supplement....................................................4-13

4.2.3.4 Conclusion ..................................................................4-13

4.2.4 Pressure-Temperature Limits and Low Temperature 

 Overpressure Protection Analyses ..................................................4-13

4.2.4.1 Summary of Technical Information in Application........ 4-13

4.2.4.2 Staff Evaluation...........................................................4-14

4.2.4.3 UFSAR Supplement....................................................4-15

4.2.4.4 Conclusion ..................................................................4-15

4.3 Metal Fatigue..................................................................................................4-16

4.3.1 Class 1 Fatigue ...............................................................................4-16

4.3.1.1 Transient Cycles .........................................................4-17

4.3.1.2 Reactor Pressure Vessel and CRDM Housings .......... 4-22

4.3.1.3 Reactor Vessel Internals .............................................4-26

4.3.1.4 Pressurizers................................................................4-28

4.3.1.5 Steam Generators...............................................4-32

4.3.1.6 Reactor Coolant Pumps........................................4-36

4.3.1.7 Class 1 Piping ................................................4-38
xi

4.3.2 Non-Class 1 Fatigue........................................................................4-41

4.3.2.1 Summary of Technical Information 

 in the Application.........................................................4-41

4.3.2.2 Staff Evaluation...........................................................4-42

4.3.2.3 UFSAR Supplement....................................................4-43

4.3.2.4 Conclusion ..................................................................4-43

4.3.3 Environmentally-Assisted Fatigue (GSI-190)...................................4-43

4.3.3.1 Summary of Technical Information 

 in the Application.........................................................4-43

4.3.3.2 Staff Evaluation...........................................................4-45

4.3.3.3 UFSAR Supplement....................................................4-48

4.3.3.4 Conclusion ..................................................................4-49

4.4 Environmental Qualification of Electric Equipment..........................................4-49

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

4.4.2 Staff Evaluation ...............................................................................4-50

4.4.3 UFSAR Supplement ........................................................................4-50

4.4.4 Conclusion ......................................................................................4-51

4.5 Concrete Containment Tendon Prestress Analyses........................................4-51

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

4.5.2 Staff Evaluation ...............................................................................4-51

4.5.3 UFSAR Supplement ........................................................................4-51

4.5.4 Conclusion ......................................................................................4-51

4.6 Containment and Penetration Fatigue Analyses .............................................4-51

4.6.1 Reactor Containment Vessel Fatigue ..............................................4-51

4.6.1.1 Summary of Technical Information 

 in the Application.........................................................4-51

4.6.1.2 Staff Evaluation...........................................................4-52

4.6.1.3 UFSAR Supplement....................................................4-52

4.6.1.4 Conclusion ..................................................................4-52

4.6.2 Containment Penetration Fatigue....................................................4-53

4.6.2.1 Summary of Technical Information 

 in the Application.........................................................4-53

4.6.2.2 Staff Evaluation...........................................................4-53

4.6.2.3 UFSAR Supplement....................................................4-53

4.6.2.4 Conclusion ..................................................................4-53

4.7 Other Plant-Specific TLAA..............................................................................4-53

4.7.1 RCS Piping Leak-Before-Break Analyses........................................4-54

4.7.1.1 Summary of Technical Information 

 in the Application.........................................................4-54

4.7.1.2 Staff Evaluation...........................................................4-55

4.7.1.3 UFSAR Supplement....................................................4-60

4.7.1.4 Conclusion ..................................................................4-61

4.7.2 Reactor Pressure Vessel Underclad Cracking.................................4-61

4.7.2.1 Summary of Technical Information 

 in Application...............................................................4-61
xii

4.7.2.2 Staff Evaluation.................................................. 4-60

4.7.2.3 UFSAR Supplement....................................................4-63

4.7.2.4 Conclusion ..................................................................4-63

4.7.3 Reactor Coolant Pump Flywheel .....................................................4-63

4.7.3.1 Summary of Technical Information 

 in Application...............................................................4-63

4.7.3.2 Staff Evaluation...........................................................4-63

4.7.3.3 UFSAR Supplement....................................................4-64

4.7.3.4 Conclusion ..................................................................4-64

4.7.4 Fatigue Analysis of Cranes..............................................................4-64

4.7.4.1 Summary of Technical Information 

 in the Application.........................................................4-64

4.7.4.2 Staff Evaluation...........................................................4-65

4.7.4.3 UFSAR Supplement....................................................4-65

4.7.4.4 Conclusion ..................................................................4-66

4.7.5 Probability of Damage to Safeguards Equipment from 

 Turbine Missiles ..............................................................................4-66

4.8 Conclusion for TLAAs .....................................................................................4-66

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS..............5-1

CONCLUSION.............................................................................................................6-1

APPENDIX A: PINGP UNIT 1 AND UNIT 2 LICENSE RENEWAL COMMITMENTS....A-1

APPENDIX B:CHRONOLOGY.....................................................................................B-1

APPENDIX C: PRINCIPAL CONTRIBUTORS ............................................................ C-1

APPENDIX D: REFERENCES.................................................................................... D-1

Tables

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

Table 3.0.3-1 PINGP 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 ............................... 3-186

Table 3.2-1 Staff Evaluation for Engineered Safety Features System

Components in the GALL Report .............................................................................3-244

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 Systems

Components in the GALL Report .............................................................................3-383
xiii

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

Component Supports in the GALL Report................................................................3-428

Table 3.6-1 Staff Evaluation for Electrical and instrumentation

And controls in the GALL Report..............................................................................3-475
xiv

ABBREVIATIONS

ABS acrylonitrile-butadiene stryene

ACI American Concrete Institute

ACSR Aluminum Cable-Steel Reinforced

AERM Aging Effect Requiring Management

AF Auxiliary Feedwater

AFW Auxiliary Feedwater

AFWP Auxiliary Feedwater Pump

AMP Aging Management Program

AMR Aging Management Review

AMSAC ATWS Mitigating System Actuation Circuitry

AMSAC/DSS ATWS Mitigating System Actuation Circuitry/Diverse Scram System

ANSI American National Standards Institute

APC Approach Canal

ART Adjusted Reference Temperature

ASA American Standards Association

ASME American Society of Mechanical Engineers

ASTM American Society for Testing of Materials

ATWS Anticipated Transients Without Scram

BL Bleed Steam

BMI Bottom Mounted Instrumentation

BTP Branch Technical Position

BWR Boiling Water Reactor

CAP Corrective Action Program

CASS Cast Austenitic Stainless Steel

CC Component Cooling
xv

CCW Component Cooling Water

CD Condensate

CEA Control Element Assembly

CF Chemistry Factor

CFR Code of Federal Regulations

CG Miscellaneous Gas

CHRMS Chemistry History and Records Management Software

CL Cooling Water

CLB Current Licensing Basis

CMAA Crane Manufactures Association of America

CRD Control Rod Drive

CRDM Control Rod Drive Mechanism

CRGT Control Rod Guide Tube

CS Containment Spray

CUF Cumulative Usage Factor

CVUSE Charpy Upper-Shelf Energy

CW Circulating Water

DBA Design Basis Accident

DBD Design Basis Document

DBE Design Basis Event

DE Water Treatment

DG Diesel Generators and Support

DGB Diesel Generator Building

EAF Environmentally Assisted Fatigue

ECI Emergency Cooling Water Intake

ECCS Emergency Core Cooling System

ECT Eddy Current Testing
xvi

EDG Emergency Diesel Generator

EFPY Effective Full Power Years

EIC Electrical and Instrumentation and Control

ENDF Evaluated Nuclear Data File

EOCI Electric Overhead Crane Institute

EOL End of Life

EPDM Ethylene Propylene Diene Monomer

EPRI Electric Power Research Institute

ESF Engineered Safety Features

EQ Environmental Qualification or Environmentally Qualified

EQML Environmental Qualification Master List

FAC Flow-Accelerated Corrosion

f’c Minimum Strength of Concrete

FCU Fan Coil Unit 

Fen Environmentally Assisted Fatigue Correction Factor

FERC Federal Energy Regulatory Commission

FMP Fatigue Monitoring Program

FO Fuel Oil

FOH Fuel Oil Transfer House

FP Fire Protection

FRN Federal Register Notice

FSAR Final Safety Analysis Report

FSWOL Full Structural Weld Overlay

FW Feedwater

GALL Generic Aging Lessons Learned

GEIS Generic Environmental Impact Statement

GH Guardhouse Ventilation
xvii

GSI Generic Safety Issue

HAZ Heat-Affected Zone

HC Containment Hydrogen Control

HELB High Energy Line Break

HEPA High Efficiency Particulate

HGR Component Supports

HPSI High Pressure Safety Injection

HS Heating System

HVAC Heating, Ventilation and Air Conditioning

I&C Instrumentation & Controls

IASCC Irradiation-Assisted Stress Corrosion Cracking

ICPA Insulated Cable Power Association

IEEE Institute of Electrical and Electronics Engineers, Inc.

IGA Intergranular Attack

IGSCC Intergranular Stress Corrosion Cracking

INC Intake Canal

INPO Institute of Nuclear Power Operations

IPA Integrated Plant Assessment

IPCEA Insulated Power Cable Engineered Association

ISA The Instrumentation, Systems, and Automation Society

ISG Interim Staff Guidance

ISI Inservice Inspection

IWA General Requirements

IWB Requirements for Class 1 Components of Light-Water Cooled Power 

Plants

IWC Requirements for Class 2 Components of Light-Water Cooled Power 

Plants

IWD Requirements for Class 3 Components of Light-Water Cooled Power 

Plants
xviii

IWE Requirements for Class MC and Metallic Liners of Class CC Components 

of Light-Water Cooler Power Plants

IWF Requirements for Class 1, 2, 3, and MC Component Supports of LightWater Cooled Power Plants

IWL Requirements for Class CC Concrete Components of Light-Water Cooled 

Power Plants

LBB Leak-Before-Break

LBLOCA Large Break Loss of Coolant Accident

LER Licensee Event Report

LOCA Loss-of-Coolant Accident

LTOP Low-Temperature Overpressure Protection

LRA License Renewal Application

LWR Light Water Reactor

MCM One-thousand Circular Mils

MEB Metal Enclosed Bus

MIC Microbiologically-Influenced Corrosion

MRP Materials Reliability Program

MS Main Steam

MUR-PU Measurement Uncertainty Recapture - Power Uprate

MWt Megawatt Thermal

NaOH Sodium Hydroxide

NDE Nondestructive Examination

NEC National Electric Code

NEI Nuclear Energy Institute

NESC Institute of Electrical & Electronic Engineers National Electrical Safety 

Code

NFPA National Fire Protection Association

NMC Nuclear Management Company
xix

NPS Nominal Pipe Size

NRC Nuclear Regulatory Commission

NSAC Nuclear Safety Analysis Center

NSAS Non-Safety Affecting Safety

NSB New Service Building

NSP/NSPM Northern States Power Company

NSSS Nuclear Steam Supply System

NUMARC Nuclear Utility Management and Resource Council

NUREG Nuclear Regulation Document

OCCW Open Cycle Cooling Water

OE Operating Experience

OPPS Overpressure Protection System

OSG Original Steam Generator

PEO Period of Extended Operation

P-T Pressure Temperature

PINGP Prairie Island Nuclear Generating Plant

PS Pressurizer

PTLR Pressure and Temperature Limit Report

PTS Pressurized Thermal Shock

PVC Polyvinyl Chloride

PVDF Polyvinylidene Fluoride

PWR Pressurized Water Reactor

PWSCC Primary Water Stress Corrosion Cracking

QA Quality Assurance

QAP Quality Assurance Program
xx

RAI Request for Additional Information

RC Reactor Coolant

RCCA Rod Control Cluster Assembly

RCGVS Reactor Coolant Gas Vent System

RCP Reactor Coolant Pump

RCPB Reactor Coolant Pressure Boundary

RCS Reactor Coolant System

RCV Reactor Containment Vessel

RD Radiation Monitoring

RG Regulatory Guide

RH Residual Heat Removal

RHR Residual Heat Removal

RPV Reactor Pressure Vessel

RSG Replacement Steam Generator

RTNDT Reference Temperature for Nil Ductility Transition

RTPTS Reference Temperature for Pressurized Thermal Shock

RVCH Reactor Vessel Closure Head

RVI Reactor Vessel Internals

RVID Reactor Vessel Integrity Database

RVLIS Reactor Vessel Level Instrument System

RVSP Reactor Vessel Surveillance Program

RWST Refueling Water Storage Tank

SA Station and Instrument Air

SB Steam Generator Blowdown

SBO Station Blackout

SC Structure and Component

SCC Stress Corrosion Cracking

SCH Screenhouse
xxi

SE Steam Exclusion

SER Safety Evaluation Report

SF Spent Fuel Pool Cooling

SFA Steam/Feedwater Application

SFP Spent Fuel Pool

SG Steam Generator

SHB Shield Building

SI Safety Injection

SIR Structural Integrity Report

SM Plant Sample

SOC Statement of Consideration

SQUG Seismic Qualification Utility Group

SRP Standard Review Plan

SSC System, Structure, and Component

SSEL Safe Shutdown Equipment List

TB Turbine Generator and Support

TLAA Time-Limited Aging Analysis

TRM Technical Requirements Manual

TS Technical Specification

TSC Technical Support Center

TSTF Technical Specification Task Force Traveler

UFSAR Updated Final Safety Analysis Report

USAS United States of America Standards

USE Upper-shelf Energy
xxii

VT Visual Examination

WCAP Westinghouse Commercial Atomic Power

WD Waste Disposal

WO Work Order

WOG Westinghouse Owners Group

ZA Auxiliary and Radwaste Area Ventilation

ZB Turbine and Administration Building Ventilation

ZC Primary Containment Ventilation

ZG Diesel Generator and Screenhouse Ventilation

ZN Control Room and Miscellaneous Area Ventilation
1-1

SECTION 1 

INTRODUCTION AND GENERAL DISCUSSION

1.1 

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

Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, as filed by Nuclear 

Management Company, LLC, (NMC or the applicant). By letter dated April 11, 2008, NMC 

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

PINGP operating licenses for an additional 20 years. The NRC staff (the staff) prepared this 

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

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

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

renewal review is Richard Plasse. Mr. Plasse may be contacted by telephone at 301-415-1427 

or by electronic mail at richard.plasse@nrc.gov. Alternatively, written correspondence may be 

sent to the following address:

Introduction

US Nuclear Regulatory Commission

Office of Nuclear Reactor Regulation

Division of License Renewal

Washington, D.C. 20555-0001

Attention: Richard Plasse, Mail Stop O11-F1

By letter dated September 15, 2008, the Commission issued an Order approving transfer of 

operating authority of Facility Operating License No. DPR-42 and DPR-60, from Nuclear 

Management Company, LLC, to Northern States Power Company, a Minnesota Corporation 

(NSPM), for PINGP, Units 1 and 2. For the purposes of the SER, the use of the term “applicant” 

refers to NMC up to September 15, 2008, and to NSPM on and after September 15, 2008.

In its April 11, 2008, submission letter, the applicant requested renewal of the operating licenses 

issued under Section 104b (Operating License Nos. DPR-42 and DPR-60) of the Atomic Energy

Act of 1954, as amended, for Units 1 and 2 for a period of 20 years beyond the current 

expirations at midnight August 9, 2013, for Unit 1, and at midnight October 29, 2014, for Unit 2. 

Prairie Island is located approximately 39 miles southeast of Minneapolis, Minnesota. The NRC 

issued the construction permits for Units 1 and 2 on June 25, 1968. The NRC issued the 

operating licenses for Unit 1 on August 9,1973, and on October 29,1974, for Unit 2. Units 1 and 

2 employ a pressurized water reactor design with a dry ambient containment. Westinghouse 

Electric Corporation supplied the nuclear steam supply system and Pioneer Service & 

Engineering Company originally designed the balance of the plant, and Northern States Power 

constructed the plant. The licensed power output of each unit is 1650 megawatt thermal with a 

gross electrical output of approximately 575 megawatt electric. The updated final safety analysis 

report (UFSAR) contains details of the plant and the site.
1-2

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 PINGP license renewal is based on the applicant’s LRA and on its responses to the 

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

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

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

information submitted through May 8, 2009. The staff reviewed information received after that 

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, at the 

NRC Public Document Room, located on the first floor of One White Flint North, 11555 Rockville 

Pike, Rockville, MD 20852-2738 (301-415-4737 / 800-397-4209), and the LRA at the Red Wing 

Public Library, 225 East Avenue, Red Wing, MN 55066. In addition, the public may find the 

LRA, as well as materials related to the license renewal review, on the NRC Web site at 

http://www.nrc.gov.

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

technical details considered in evaluating the safety aspects of the units’ proposed operation for 

an additional 20 years beyond the term of the current operating licenses. 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 

licenses. 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 will issue the draft, plant-specific Supplement 39 to 

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

Plants Regarding Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2 Draft Report 

for Comment,” Volumes 1 and 2, in October 2009. The supplement will discuss the 

environmental considerations related to license renewal for PINGP Units 1 and 2. The draft 

Supplement will be available on the NRC website at 

http://www.nrc.gov/reactors/operating/licensing/renewal.html.

1.2 

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

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

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

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

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

License Renewal Background
1-3

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

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

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

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

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

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

license renewal for nuclear power plants.

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

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

participated in an industry-sponsored demonstration program to apply 10 CFR Part 54 to a pilot 

plant and to gain the experience necessary to develop implementation guidance. To establish a 

scope of review for license renewal, 10 CFR Part 54 defined age-related degradation unique to 

license renewal; however, during the demonstration program, the staff found that adverse aging 

effects on plant systems and components are managed during the period of initial license and 

that the scope of the review did not allow sufficient credit for management programs, particularly 

the implementation of 10 CFR 50.65, “Requirements for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” which regulates management of plant-aging 

phenomena. Because of this finding, the staff amended 10 CFR Part 54 in 1995. As published 

May 8, 1995, in 60 FR 22461, amended 10 CFR Part 54 establishes a regulatory process that is 

simpler, more stable, and more predictable than the previous 10 CFR Part 54. In particular, as 

amended, 10 CFR Part 54 focuses on the management of adverse aging effects rather than on 

the identification of age-related degradation unique to license renewal. The staff made these 

rule changes to ensure that important systems, structures, and components (SSCs) will 

continue to perform their intended functions during the period of extended operation. In addition, 

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

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

Concurrent with these initiatives, the staff pursued a separate rulemaking effort (61 FR 28467, 

June 5, 1996) and amended 10 CFR Part 51 to focus the scope of the review of environmental 

impacts of license renewal in order to fulfill NRC responsibilities under the National 

Environmental Policy Act of 1969.

1.2.1 Safety Review

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

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

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

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

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

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

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

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

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

safety-related functions, or (3) are relied on to demonstrate compliance with the NRC’s 
1-4

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

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

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

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

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

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

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

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

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

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

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

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

monitoring, and maintenance. Surveillance and maintenance programs for active equipment, as 

well as other maintenance aspects of plant design and licensing basis, are required throughout 

the period of extended operation.

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

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

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

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

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

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

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

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

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

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

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

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

of 10 CFR Part 54 - The License Renewal Rule,” issued in June 2005. NEI 95-10 details an 

acceptable method of implementing 10 CFR Part 54. The staff also used the SRP-LR to review 

the LRA.

In the LRA, the applicant utilized the process defined in NUREG-1801, Revision 1, “Generic 

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

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

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

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

renewal review process. The GALL Report summarizes the aging management evaluations, 

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

industry. The report is also a quick reference for both applicants and staff reviewers to AMPs 

and activities that can manage aging adequately during the period of extended operation.

1.2.2 Environmental Review 

Part 51 of 10 CFR contains regulations on environmental protection regulations. In 

December 1996, the staff revised the environmental protection regulations to facilitate the 
1-5

environmental review for license renewal. The staff prepared the GEIS to document its 

evaluation of possible environmental impacts associated with nuclear power plant license 

renewals. For certain types of environmental impacts, the GEIS contains generic findings that 

apply to all nuclear power plants and are codified in Appendix B, “Environmental Effect of 

Renewing the Operating License of a Nuclear Power Plant,” to Subpart A, “National 

Environmental Policy Act - Regulations Implementing Section 102(2),” of 10 CFR Part 51. 

Pursuant to 10 CFR 51.53(c)(3)(i), a license renewal applicant may incorporate these generic 

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

report also must include analyses of environmental impacts that must be evaluated on a plantspecific basis (i.e., Category 2 issues).

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

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

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

the staff held a public meeting on July 30, 2008 at the Red Wing Public Library, 225 East 

Avenue, Red Wing, Minnesota, to identify plant-specific environmental issues. The draft, plantspecific Supplement 39 to the GEIS will document the results of the environmental review and 

make a preliminary recommendation as to the license renewal action, based on environmental 

considerations. The staff will hold another public meeting, currently planned for December 2009, 

in Red Wing, Minnesota, to discuss the draft, plant-specific GEIS Supplement 39.

1.3 

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.

Principal Review Matters 

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 in the LRA:

“NSPM requests that conforming changes be made to indemnity agreement No. B-60 for the 

Prairie Island Nuclear Generating Plant Units 1 and 2, as required, to ensure that the indemnity 

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

renewed licenses. NSPM understands that no changes may be necessary for this purpose if the 

current operating license numbers are retained.”

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

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

made and the 10 CFR 54.19(b) requirements have been met.

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

that the LRA contain (a) an integrated plant assessment, (b) a description of any CLB changes 
1-6

during the staff’s review of the LRA, (c) an evaluation of TLAAs, and (d) an FSAR 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 three months before the scheduled completion of the staff’s review, the applicant 

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

the LRA, including the UFSAR supplement. By letter dated April 13, 2009, the applicant 

submitted an LRA update that summarizes the CLB changes that have occurred during the 

staff’s review of the LRA. This submission satisfies 10 CFR 54.21(b) requirements and is still 

under staff review.

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 (TS) that are 

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

Appendix D, the applicant stated that no changes to the TS are necessary for issuance of the 

renewed PINGP operating licenses. This statement adequately addresses the 10 CFR 54.22 

requirement.

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

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

the staff’s evaluation of the LRA technical information.

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

ACRS 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.

1.4 

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

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

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

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

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

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

Interim Staff Guidance 

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

addresses them.
1-7

Table 1.4-1 Current Interim Staff Guidance

ISG Issue

(Approved ISG Number)

Purpose SER Section

Nickel-alloy components in the 

reactor coolant pressure boundary

(LR-ISG-19B)

Cracking of nickel-alloy components 

in the reactor pressure boundary.

ISG under development. NEI and 

EPRI-MRP will develop an 

augmented inspection program for 

GALL AMP XI.M11-B. This AMP will 

not be completed until the NRC 

approves an augmented inspection 

program for nickel-alloy base metal 

components and welds as proposed 

by EPRI-MRP.

3.0.3.1.17 and 3.0.3.3.1

Corrosion of drywell shell in Mark I 

containments

(LR-ISG-2006-01)

To address concerns related to 

corrosion of drywell shell in Mark I 

containments.

Not applicable (BWRs only)

1.5 

The staff issued the SER with Open Items on June 4, 2009, and identified the following open 

items (OIs). An item was considered open if, in the staff’s judgment, it has not been shown to 

meet all applicable regulatory requirements at the time of the issuance of the SER. The staff 

assigned a unique identifying number to each OI. By letters dated May 12, June 5, June 24, 

August 7, and August 21, 2009, the applicant provided additional information which enabled the 

staff to close out the OIs. 

Summary of Open Items 

OI 2.1.4.1.2-1: (SER Section 2.1.4.1.2 – 10 CFR 54.21(a) Classification of waste gas decay 

tank)

The staff has reviewed the applicant’s response to RAI 2.1-1, Part A, and determined the 

applicant’s position was not adequately justified. The elements of 10 CFR 54.4 (a)(1)(iii) that 

determine whether a safety-related SSC is within the scope of the license renewal rule are:

 • The SSC is relied upon to function.

 • The SSC functions during or following a design basis event.

 • The SSC prevents or mitigates the consequences of the design-basis accident.

 • The consequences of the design basis accident could result in offsite exposures 

comparable to those referred to in 10 CFR 50.67(b)(2) or 10 CFR 100.11.

UFSAR Section 14.5.3.1, “Gas Decay Tank Rupture,” states that a rupture of a gas decay tank 

is analyzed to define the limit of the hazard that could result from any malfunction in the 

gaseous radioactive waste disposal system. The UFSAR also states that the components of 

the waste gas system are not subjected to high pressures or stresses, they are a Class I design, 

and they are designed to standards such that a rupture or failure of the system is highly unlikely. 

The potential offsite exposures are listed in a table at the end of UFSAR Section 14.5.3 that also 

lists the limits of 10 CFR 100.11. 
1-8

Thus, the components of the radioactive waste gas system are designed to and relied upon to 

prevent potential offsite exposures. These components function as a pressure boundary to 

prevent a rupture that could release the contents of the waste gas decay tanks. The postulated 

rupture of a waste gas decay tank has been evaluated as a design-basis event in the PINGP

UFSAR.

The offsite dose consequences of the gas decay tank rupture are comparable to those referred 

to in 10 CFR 100.11 in the sense that the calculated offsite exposures for all design-basis 

accidents are compared to limits derived from those specified in 10 CFR 50.67(b)(2) or 10 CFR 

100.11. Although the potential offsite dose consequences may be a small fraction of those 

referenced in 10 CFR 100.11, the comparison remains necessary to confirm the acceptability of 

the plant design. This contrasts with the offsite consequences of other routine operational 

events (e.g., effluent releases) that are compared to limits derived from other regulations.

Thus, the staff determined that the waste gas decay tanks should be included within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(1)(iii). By letter dated June 5, 2009, the 

applicant stated the waste gas decay tanks have been reclassified as in scope for license 

renewal under 10 CFR 54.4(a)(1). The closure of this item is documented in SER Section 

2.1.4.1.

OI 3.0.3.1.21-1: (SER Section 3.0.3.1.21 – PWR Vessel Internals Program)

The staff reviewed the applicant’s amended plant-specific PWR Vessel Internals Program and 

the associated changes to LRA Commitment No. 25. In a letter dated May 12, 2009, NSPM

replaced the previous version of the PWR Vessel Internals Program with a plant-specific version 

of the program that is based on conformance with the NRC’s recommended program element 

criteria that are defined in Section A.1.2.3 of NUREG-1800, Revision 1, “Standard Review Plan 

for Review of License Renewal Applications for Nuclear Power Plants,” Appendix A.1, “Aging 

Management Review – Generic (Branch Technical Position RLSB-1).” Since the updated PWR 

Vessel Internals Program is defined as a new, plant-specific AMP for the LRA, the staff’s

evaluation of this AMP is deferred to Section 3.0.3.3.2 of this SER. In addition, the staff verified 

that the applicant’s UFSAR Supplement and the staff’s review of the revisions to LRA 

Commitment No. 25 are complete. The closure of this item is documented in SER Section 

3.0.3.1.21 and 3.0.3.3.2.

OI 3.0.3.2.17-1: (SER Section 3.0.3.2.17 – Structures Monitoring Program)

During the audit, the staff discovered an ongoing issue with water seepage from the refueling 

cavity into the containment sumps. In RAI B2.1.38-2 dated November 5, 2008, the staff 

requested the applicant provide information regarding the root cause analysis of the seepage, 

as well as corrective and preventive actions taken to correct the problem. In the LRA, this 

seepage issue is tracked under the Structures Monitoring Program, but the staff believes that it 

also applies to the IWE program due to the possibility of borated water coming into contact with 

the containment vessel.

By letter dated December 5, 2008, the applicant responded to RAI B2.1.38-2. The applicant 

stated that the condition was detected by the ASME Section XI, Subsection IWE Program while 

examining the Class MC pressure retaining vessel. Both the Structures Monitoring Program and 

the ASME Section XI, Subsection IWE Program took corrective actions to address the leakage. 
1-9

In addition, the applicant provided information during a public meeting on March 2, 2009. The 

staff reviewed the information provided in both the RAI response and during the public meeting,

and discovered that borated water was coming into contact with the containment vessel during 

refueling outages. Due to the leakage path of borated water along the bottom of the 

containment vessel, the staff determined that there is a possibility that portions of the 

containment vessel may remain wetted after refueling outages. By letter dated March 31, 2009, 

the staff issued follow-up RAI B2.1.38 asking the applicant to discuss its plan for assessing the 

current condition of the steel containment vessel and to explain how the IWE program, or a 

plant-specific program, will manage aging of the containment vessel, especially in inaccessible 

regions, during the period of extended operation. By letter dated April 6, 2009, the applicant 

responded to follow-up RAI B2.1.38. While reviewing the response dated April 6, 2009, the staff 

conducted an audit on May 28, 2009, to review related on-site documentation. In response to 

the information reviewed while on-site, as well as the information provided in the April 6 

response, the staff issued an additional follow-up RAI B2.1.38, by letter dated June 10, 2009. By 

letter dated June 24, 2009, the applicant responded to the follow-up RAI and also provided 

additional information in a letter dated August 7, 2009. Based on review of the applicant’s 

responses, OI 3.0.3.2.17-1 is closed. A detailed timeline and summary of the staff’s review and 

closure of OI 3.0.3.2.17-1 is discussed and documented under the Structures Monitoring 

Program in SER Section 3.0.3.2.17.

1.6 

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

August 21, 2009, the staff determines that no confirmatory items exist which would require a 

formal response from the applicant.

Summary of Confirmatory Items 

1.7 

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

the applicant, the staff identified four proposed license conditions.

Summary of Proposed License Conditions 

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

10 CFR 54.21(d) in the first UFSAR update required by 10 CFR 50.71(e) following the issuance 

of the renewed licenses.

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

be completed prior to the period of extended operation (Unit 1 8/9/2013 and Unit 2 10/29/2014).

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

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

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

the capsule withdrawal schedule, including spare capsules, must be approved by the staff prior 

to implementation. All capsules placed in storage must be maintained for future insertion. Any 

changes to storage requirements must be approved by the staff, as required by 10 CFR Part 50, 

Appendix H.

The fourth license condition requires an inspection plan for reactor internals will be submitted for 

NRC review and approval at least twenty-four months prior to the period of extended operation. 

In addition, the submittal will include any necessary revisions to the PINGP PWR Vessel 
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Internals Program, as well as any related changes to the PINGP scoping, screening and aging 

management review results for reactor internals, to conform to the NRC-approved Inspection 

and Evaluation Guidelines.
2-1

SECTION 2 

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

2.1 

2.1.1 Introduction

Scoping and Screening Methodology

Title 10, Section 54.21, “Contents of Application—Technical Information,” of the Code of Federal 

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

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

management review (AMR) for all of the structures, systems, and components (SSCs) within the 

scope of license renewal.

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

identifying SSCs at the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, within 

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

screening methodology of Northern States Power Company, a Minnesota Corporation (NSPM 

or the applicant) to determine whether it meets the scoping requirements of 10 CFR 54.4(a) and 

the screening requirements of 10 CFR 54.21.

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

considered the requirements of 10 CFR Part 54, “Requirements for Renewal of Operating 

Licenses for Nuclear Power Plants” (the Rule), statements of consideration related to the Rule, 

and the guidance of Nuclear Energy Institute (NEI) 95-10, Revision 6, “Industry Guideline for 

Implementing the Requirements of 10 CFR Part 54 -The License Renewal Rule,” dated June 

2005. Additionally, in developing this methodology, the applicant stated that it considered the 

correspondence between the staff, other applicants, and NEI.

2.1.2 Summary of Technical Information in the Application

In LRA Sections 2 and 3, the applicant provides technical information pursuant to 10 CFR 54.4, 

“Scope,” and 10 CFR 54.21(a). This safety evaluation report (SER), contains sections entitled 

“Summary of Technical Information in the Application,” which provide information taken directly 

from the LRA.

In LRA Section 2.1, the applicant describes the process it 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 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” 
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 (c) LRA Section 2.4, “Scoping and Screening Results: Containments, Structures, and 

Component Supports” 

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

Controls Systems” 

In LRA Section 3.0, Aging Management Review Methodology, the applicant describes 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” 

 (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 (TLAA), contains the applicant’s identification 

and evaluation of 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, AScoping 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

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)
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  Section 2.2, 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 PINGP, Units 1 

and 2, located near Welch, Minnesota, during the week of August 4-7, 2008. 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 topical 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 Appendix A, “Updated Final Safety Analysis Report (UFSAR) 

Supplement,” and Appendix B, “Aging Management Programs,” of the LRA. On a sampling 

basis, the staff performed a system review of the main steam system, residual heat removal 

system, turbine building, and the screenhouse, 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 October 24, 

2008, 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 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 the procedural guidance during the 

scoping and screening process.

2.1.3.1.1 Summary of Technical Information in the Application

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

renewal scoping and screening process:

  updated safety analysis report (UFSAR)

  technical specifications

  design-basis documents (DBDs)

  plant equipment database 
2-4

  Q-List

  Q-List extension

  controlled drawing file

  industry codes, standards, and regulations

  NRC docketed correspondence and documents

  technical correspondence, analyses, and reports

  calculations

  modifications and alterations

  nuclear steam supply system supplier, architect-engineer, vendor reports, specifications, 

and drawings

  plant drawings 

LRA Section 2.1.2.3, “SSC Functions,” states that information sources, including the UFSAR, 

docketed correspondence with the NRC, Maintenance Rule documents, and DBDs provided 

information on system-level and structure-level functions. Documentation of references used in 

this process was included for each function. According to the LRA, a list of functions was 

developed for systems, structures, and commodity groups at PINGP, which were evaluated 

against the criteria specified in 10 CFR 54.4 (a)(1), (2), or (3). LRA Section 2.1.2.3 further states 

that once system-level and structure-level functions were identified, the plant equipment 

database and other information sources were used to identify component functions and 

determine if these functions were in-scope for license renewal.

2.1.3.1.2 Staff Evaluation

Scoping and Screening Implementing Procedures

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 NRC staff positions documented in the SRP-LR), and the information in the 

applicant’s responses, dated December 5, 2008, to the staff’s requests for additional information 

(RAIs).

. 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 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. 

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.
2-5

Sources of Current Licensing Basis Information.

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

including the UFSAR, DBDs, and license renewal boundary drawings. In addition, the 

applicant’s license renewal process identified additional sources of plant information pertinent to 

the scoping and screening process, including, the UFSAR, DBDs, the plant equipment 

database, the Q-List and Q-List extension, NRC-docketed correspondence and documents, and 

plant drawings. 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 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 UFSAR). The CLB 

also includes licensee commitments remaining in effect that were made in docketed licensing 

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.

The plant equipment database, Q-List and Q-List extension, UFSAR, 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 

plant equipment database, the Q-List and Q-List extension, 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 PINGP 

documentation, the NRC staff concludes that the applicant has established adequate measures 

to control the integrity and reliability of PINGP system identification and safety classification 

data. Therefore, the staff concludes that the information sources used by PINGP 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 the SSCs that the applicant relied on to demonstrate compliance with the safetyrelated 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.
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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.

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 to develop the LRA were adequately implemented. The 

applicant applied the following quality assurance processes during the LRA development:

  The scoping and screening methodology was governed by written procedures and 

guidelines.

  The LRA was examined by the applicant’s team in a structured self-assessment.

  The LRA was examined by internal assessment teams, including a plant operation 

review committee, peer review validation, legal review, and regulatory affairs review. 

Additionally, a site VP review, validation, certification process, and source document 

change control were implemented. Each of these teams included different levels of plant 

and organizational management.

  Pre-activity briefings were conducted prior to new major evolutions.

  The LRA was examined by external assessment teams, including peer reviews done by 

teams of personnel from other license renewal applicants.

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 
2-7

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. The training included the 

following activities:

  Engineering supervisors had training and mentoring by experienced peers, and 

benchmarking through participation in an NEI Task Force and Working Groups. 

  Contractor staff had previous license renewal experience from other sites.

  Each license renewal staff member completed training in general license renewal 

requirements and project procedures, and training in discipline-specific areas.

  Initial qualification was completed before the project started and included the review of 

the license renewal process, license renewal project guidelines, and relevant industry 

documents such as 10 CFR Part 54 regulations, NEI 95-10, Regulatory Guide 1.188, 

“Standard Format and Content for Applications to Renew Nuclear Power Plant Operating 

Licenses,” SRP-LR, and NUREG-1801, “Generic Aging Lessons Learned Report,” 

Revision 1 (GALL Report). 

The staff reviewed the applicant’s written procedures and documentation of training activities 

and determined that the applicant had developed and implemented adequate procedures to 

monitor 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 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

Based on the 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 2.1.2.1 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 

Part 54.4 (a)(1), (2), and (3) to determine whether the item should be considered within the 

scope of license renewal. The applicant asserts that the scoping process identified SSCs that 

are safety-related and perform or support an intended function for responding to a design-basis 

event (DBE); are nonsafety-related, but their failure could prevent accomplishment of a safety-
2-8

related function; or support a specific requirement for one of the five regulated events applicable 

to license renewal. 

LRA Section 2.1.2.1 further states that even if only a portion of an SSC or commodity fulfilled a 

scoping criterion, the item was identified as in-scope for license renewal and received further 

evaluation. According to the LRA, those SSCs or commodities identified as not meeting any 

scoping criterion were not addressed further. LRA Section 2.1.2.1 asserted that the scoping 

methodology utilized by PINGP is consistent with the guidance provided by the NRC in the 

SRP-LR, by the industry in NEI 95-10, and by NRC Interim Staff Guidance.

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 2.1.2.4.1, “Scoping Criteria 1-Safety-Related SSCs,” states:

The PINGP definition of safety-related SSCs within the CLB is not completely consistent with 

the scoping criteria under 10 CFR 54.4(a)(1), and therefore the scoping methodology used at 

PINGP followed the criteria under 10 CFR 54.4(a)(1) and not the PINGP definition. The 

significant difference between the PINGP CLB definition of safety-related and the Rule is the 

CLB applicability to design basis accidents versus the broader Rule applicability to DBEs. The 

other difference is in the applicability of exposure guidelines; in addition to the guidelines of 10 

CFR 100, 10 CFR 54.4(a)(1)(iii) references the dose guidelines of 10 CFR 50.34(a)(1) and 10 

CFR 50.67(b)(2). For plants (including PINGP) with construction permits issued before January 

10, 1997, 10 CFR 50.34(a)(1) refers to the guidelines of 10 CFR 100, which are included in the 

PINGP definition of safety-related. The exposure guidelines of 10 CFR 50.67(b)(2) address the 

alternate source term, which PINGP has credited only for the refueling accident analysis. A 

review was performed of the systems and components that were credited in this limited use of 

10 CFR 50.67 to ensure the applicable SSCs were included in the scope of license renewal. As

described in LRA Section 2.1.2.3, SSC and commodity group functions were identified using a 

number of information sources. These functions were compared to scoping Criterion 1 to 

identify those that should be considered in-scope for license renewal for PINGP DBEs, 

regardless of their current classification in the plant equipment database or supporting Q-List 

information sources. To confirm the function scoping, results were compared to the current 

component quality classifications and differences were evaluated.

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 50.34(a)(1), 10 CFR 50.67(b)(2), or 10 CFR 100.11.
2-9

With regard to identification of DBEs, Section 2.1.3, “Review Procedures,” of the SRP-LR 

states:

The set of design basis events as defined in the rule is not limited to Chapter 15 (or equivalent) 

of the UFSAR. Examples of design basis events that may not be described in this chapter 

include external events, such as floods, storms, earthquakes, tornadoes, or hurricanes, and 

internal events, such as a high energy line break. Information regarding design basis events as 

defined in 10 CFR 50.49(b)(1) may be found in any chapter of the facility UFSAR, 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 PINGP. The staff reviewed the applicant’s basis 

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

events defined by 10 CFR 50.49(b)(1) and 10 CFR 54.4(a)(1). The PINGP UFSAR 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 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 

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 PINGP CLB definition of safety-related referred to 

10 CFR 50.67 (in specific circumstances) and 10 CFR 100. LRA Section 2.1.2 documents the 

applicant’s definition of safety-related as it relates to the definition in the Rule. Based on its 

review, the staff confirmed that the applicant correctly identified the applicable accident dose 

criteria for PINGP, Units 1 and 2, as set forth in 10 CFR 54.4(a)(1)(iii). The applicable CLB dose 

consequence DBA criteria is set forth in 10 CFR 100.11 for PINGP Units 1 and 2, with the 

exception that the requirements of 10 CFR 50.67(b)(2), which concern the use of an alternate 

source term in the dose analysis, are applicable to PINGP, Units 1 and 2, in specific 

circumstances described in the refueling accident analysis. The staff confirmed that the 

applicant had performed a review of the systems and components that were credited in this 

limited use of 10 CFR 50.67 and verified that the applicable SSCs were included within the 

scope of license renewal.

The staff reviewed a sample of the license renewal scoping results for the main steam system, 

residual heat removal system, the turbine building, and the screen house to provide additional 

assurance that the applicant adequately implemented their scoping methodology with respect to 

10 CFR 54.4(a)(1). The staff verified that the applicant developed the scoping results for each of 
2-10

the sampled systems consistent 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.

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. Request for Additional Information (RAI) 2.1-1, dated 

November 5, 2008, states that during the NRC scoping and screening methodology audit, 

performed August 4-7, 2008, the applicant indicated that there were plant-defined safety-related 

components that were not included within the scope for license renewal in accordance with 

10 CFR 54.4(a)(1), as follows:

(a) During the audit, the applicant stated that although the waste gas decay tanks 

were defined as safety-related per the plant’s definition, they were not in-scope

for license renewal because they did not meet the above criteria (i), (ii), or (iii). 

Specifically, for criteria (iii), the applicant stated that the plant’s criteria for safetyrelated SSCs were more conservative than the license renewal criteria because 

PINGP has committed to the more conservative 1% of the 10 CFR 100.11 

exposure guidelines following a design-basis accident. The applicant also 

documented that the term “comparable” in criteria (iii) has been defined by the 

nuclear industry as greater than or equal to 10% and the value is consistent with 

NRC guidance in Regulatory Guide 1.70, “Standard Format and Content of 

Safety Analysis Reports for Nuclear Power Plants.”

The staff requested that the applicant provide: (1) specific documentation, 

references, and citations that define the term “comparable,” as used in 10 CFR 

54.4(a)(1)(iii), to be greater than or equal to 10% and (2) a description of the 

methods used and the basis for conclusions, in determining that the safetyrelated waste gas decay tanks would not be included within the scope of license 

renewal in accordance with the requirements of 10 CFR 54.4(a)(1).

(b) During the audit, the applicant stated that the boric acid storage tanks were 

defined as safety-related per the plant’s definition, but were not within the scope 

of license renewal for 10 CFR 54.4(a)(1). The staff requested the applicant 

provide a description of the methods used and the basis for conclusions, in 

determining that the safety-related boric acid storage tanks would not be included 

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

10 CFR 54.4(a)(1).

The applicant responded to RAI 2.1-1 by letter dated December 5, 2008, which states:

(a) The term “comparable” in 10 CFR 54.4(a)(1)(iii) is not defined within the license renewal 

Rule, Statements of Consideration or industry license renewal guidance documents. 

While this language is not specific, it is reasonable and logical to interpret the words "... 

exposures comparable to those referred to in 10 CFR 50.34(a)(1), 50.67(b)(2), or 

100.11" as meaning "... exposures which approach the dose reference values (limits) 

defined in 10 CFR 50.34(a)(1), 50.67(b)(2), or 100.11."
2-11

The Standard Review Plan for Review of Safety Analysis Reports for Nuclear Power 

Plants (NUREG-0800), Section 15.0.3, states that the radiological consequences of 

design-basis accidents and transients should “not exceed,” be “well within,” or be a 

“small fraction” of the exposure guidelines of 10 CFR 100.11 (also see NUREG-0800 

Sections 15.3.3-15.3.4, 15.6.3 and BTP 11-5). This NRC guidance defines “not exceed” 

to mean less than or equal to 100% of 10 CFR 100.11 guideline exposures, “well within” 

to mean less than 25% of 10 CFR 100.11 guideline exposures, and the term “small 

fraction of” to mean less than 10% of 10 CFR 100.11 guideline exposures.

ANS-58.14, Safety and Pressure Integrity Classification Criteria for Light Water 

Reactors, Section 5.3.1.4, defines “comparable” as greater than or equal to 10 % of 

10 CFR 100.11 guideline exposures. This value is chosen because: (1) it is consistent 

with NUREG-0800 (i.e. “not exceed” and “well within” are “comparable” however, “small 

fraction” is not “comparable”); (2) philosophically, being within an order of magnitude is 

comparable while more than an order of magnitude is not; and (3) it yields results 

consistent with past and current industry and NRC practice. The standard goes on to 

state, "This amplification of the safety-related definition recognizes that there must be a 

threshold value for off-site exposures that defines the boundary between safety-related 

and nonsafety-related."

The waste gas decay tanks are designated as safety-related based on PINGP-unique 

criteria of 1% of 10 CFR 100 limits contained in the PINGP UFSAR and plant 

procedures. NEI 95-10 acknowledges that some components may be designated as 

safety-related, but not meet the definition of the Rule. Section 3.1.1 of NEI 95-10 states:

"It is conceivable that, because of plant unique considerations and preferences, 

applicants may have previously elected to designate some systems, structures and 

components as safety-related that do not perform any of the requirements of 54.4(a)(1). 

Therefore, a system, structure or component may not meet the requirements of 

54.4(a)(1) although it is designated as safety-related for plant- specific reasons."

As shown in UFSAR 14.5.3.2, a rupture of a waste gas decay tank does not result in 

offsite exposures comparable (i.e. greater than or equal to 10%) to those referred to in 

10 CFR 100 and therefore the tanks are not within the scope of license renewal for 10 

CFR 54.4(a)(1).

(b) The boric acid storage tanks are designated as safety-related based on plant 

preference. NEI 95-10 acknowledges that some components may be designated as 

safety-related, but not meet the definition of the Rule. Section 3.1.1 of NEI 95-10 states:

“It is conceivable that, because of plant unique considerations and preferences, 

applicants may have previously elected to designate some systems, structures and 

components as safety-related that do not perform any of the requirements of 54.4(a)(1). 

Therefore, a system, structure or component may not meet the requirements of 

54.4(a)(1) although it is designated as safety-related for plants specific reasons.”

License Amendments 156/147, dated April 16, 2001, removed the boric acid storage 

tanks (BASTs) from the Technical Specifications for the Safety Injection System 
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because the high concentration boric acid in the BASTs is unnecessary for accident 

mitigation. Therefore, the BASTs are not required to accomplish the functions described 

in 10 CFR 54(a)(1) and are not within the scope of license renewal for 10 CFR 

54.4(a)(1). The tanks are included within the scope of license renewal for 10 CFR 

54.4(a)(2).

The staff has reviewed the applicant’s response to RAI 2.1-1, Part A, and determined the 

applicant’s position was not adequately justified. The elements of 10 CFR 54.4 (a)(1)(iii) that 

determine whether an SSC is within the scope of SSCs that must be considered for aging 

management are:

 • The SSC is safety related.

 • The SSC is relied upon to function during or following a design-basis event.

 • The SSC prevents or mitigates the consequences of accidents (as documented in the 

applicant’s current licensing basis) which could result in potential offsite exposures 

comparable to those referred to in 10 CFR 50.7(b)(2) or 10 CFR 100.11.

UFSAR Section 14.5.3.1, “Gas Decay Tank Rupture,” states that a rupture of a gas decay tank 

is analyzed to define the limit of the hazard that could result from any malfunction in the 

gaseous radioactive waste disposal system. The UFSAR also states that the components of 

the waste gas system are not subjected to high pressures or stresses, they are a Class I design, 

and they are designed to standards such that a rupture or failure of the system is highly unlikely. 

The potential offsite exposures are listed in a table at the end of UFSAR Section 14.5.3 that also 

lists the limits of 10 CFR 100.11. 

Thus, the components of the radioactive waste gas system are designed to and relied upon to 

prevent potential offsite exposures. These components function as a pressure boundary to 

prevent a rupture that could release the contents of the waste gas decay tanks. The postulated 

rupture of a waste gas decay tank has been evaluated as a DBE in the PINGP UFSAR.

The offsite dose consequences of the gas decay tank rupture are comparable to those referred 

to in 10 CFR 100.11 in the sense that the calculated offsite exposures for all DBA are compared 

to limits derived from those specified in 10 CFR 50.67(b)(2) or 10 CFR 100.11. Although the 

potential offsite dose consequences may be a small fraction of those referenced in 

10 CFR 100.11, the comparison remains necessary to confirm the acceptability of the plant 

design. This contrasts with the offsite consequences of other routine operational events 

(e.g., effluent releases) that are compared to limits derived from other regulations.

Thus, the staff determined that the waste gas decay tanks should be included within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(1)(iii). This was SER OI 2.1.4.1.2-01. In 

its response dated June 5, 2009, the applicant stated the waste gas decay tanks have been 

reclassified as in scope for license renewal under 10 CFR 54.4(a)(1). In its response dated June 

24, 2009, the applicant provided revised scoping boundary drawings that identified the new 

boundaries resulting from the reclassification of the waste gas decay tanks to in scope for 

license renewal under 10 CFR 54.4(a)(1). The staff reviewed the revised scoping boundary 

drawings and determined that the applicant appropriately identified the mechanical components 

within the scope of license renewal and adequately identified the mechanical components 
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subject to an aging management review. Based on its review, the staff finds the applicant’s 

response to SER OI 2.1.4.1.2-01 acceptable and closed.

The staff reviewed the applicant’s response to RAI 2.1-1, Part B, and determined that the 

applicant had demonstrated that the safety-related boric acid storage tanks did not have an 

intended function meeting the criteria of 10 CFR 54.4 (a)(1) and therefore, have not included the 

boric acid storage tanks within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). The staff concludes that this resolves RAI 2.1-1 Part B.

2.1.4.1.3 Conclusion

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 2.1.2.4.2, “Scoping Criterion 2 - Non-Safety Related Affecting Safety-Related,” 

states: 

SSCs meeting Scoping Criterion 2 for PINGP are included in one of the following 

three categories:

• The plant's Current Licensing Basis (CLB). The PINGP CLB was used to 

identify nonsafety-related SSCs that have the potential to prevent 

satisfactory accomplishment of safety related SSC intended functions, 

and therefore are within the scope of license renewal for 

10 CFR 54.4(a)(2).

• Non-safety related SSCs directly connected to safety related SSCs 

(typically piping systems) up to and including the first seismic or 

equivalent anchor past the safety/non-safety interface are within the 

scope of license renewal for 10 CFR 54.4(a)(2).

• Non-safety related SSCs that are not directly connected to safety related 

SSCs, or are connected downstream of the first seismic or equivalent 

anchor past the safety/non-safety interface, but have a potential spatial 

interaction such that their failure could adversely impact the performance 

of a safety related SSC intended function, are within the scope of license 

renewal for 10 CFR 54.4(a)(2).

SSCs meeting scoping Criterion 2 in the first two categories were identified 

during document reviews including the UFSAR, plant drawings, design 

documents, piping analyses, plant equipment database, and other CLB 

documents. SSCs in the third category were identified by both document reviews 

and plant walkdowns to identify possible spatial interactions meeting the broader 

criteria established for license renewal.
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LRA Section 2.1.2.4.2 states in relation to nonsafety-related SSCs directly connected to safetyrelated SSCs: 

For nonsafety-related SSCs directly connected to safety related SSCs (typically 

piping and duct systems), the non-safety piping and supports, up to and including 

the first seismic or equivalent anchor beyond the safety/non-safety interface, are

within the scope of license renewal per 10 CFR 54.4(a)(2). As an alternative to 

specifically identifying a seismic anchor or series of equivalent anchors, a 

bounding approach was typically used, which includes enough of the non-safety 

piping run to ensure these anchors are included and thereby ensure the piping 

and anchor intended functions are maintained. The application of this approach 

is discussed in detail in project documents.

For piping and ducting systems in specific cases where use of the bounding

approach was not desirable, then the non-safety piping and supports beyond the 

safety related/non-safety interface were considered to be in scope for 

10 CFR 54.4(a)(2) up to and including the first seismic or equivalent anchor (i.e., 

device, equipment or structure that ensures that forces and moments are 

restrained in three orthogonal directions). Where a seismic or equivalent anchor 

was not clearly described, a combination of restraints and supports were used 

such that the non-safety piping and associated structures and components 

attached to safety related piping are included in scope up to a boundary point 

that encompasses at least two (2) supports in each of three (3) orthogonal 

directions. Non-safety related SSCs considered to be in scope for 

10 CFR 54.4(a)(2) using the criteria described above were marked “in license 

renewal boundary” in the license renewal database and highlighted “In Scope” on 

the license renewal Boundary Drawings.

LRA Section 2.1.2.4.2 states in relation to nonsafety-related SSCs not directly connected to 

safety-related SSCs: 

For nonsafety-related SSCs that are not directly connected to safety related 

SSCs, or are connected downstream of the first seismic or equivalent anchor 

past the safety/non-safety interface, the nonsafety-related SSCs may be in scope 

if their failure could prevent the performance of the system safety function for 

which the safety related SSC is required. To determine which nonsafety-related 

SSCs may be in scope for 10 CFR 54.4(a)(2), either of the following two options 

were used.

Mitigative Option. The mitigative option was utilized to exclude areas from 

nonsafety-related affecting safety-related NSAS scoping. Areas were excluded 

provided they did not contain any 10 CFR 54.4(a)(1) components and there are 

mitigative features that would prevent spatial interaction (such as spray, leakage 

or flooding) outside of the excluded area. Where the mitigative option is used to 

exclude areas from NSAS scoping, the mitigative features are within the scope of 

license renewal per 10 CFR 54.4(a)(2) and non-safety systems within these 

areas can be excluded from the scope of license renewal. These mitigative 

features are typically associated with the structures and are further evaluated in 
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the Civil/Structural AMRs. However, nonsafety-related SSCs directly connected 

to safety related SSCs remain in scope for license renewal in accordance with 

Section 2.1.2.4.2.2 even if these are partly or wholly located within exclusion 

areas. In addition, mitigative features currently credited in the CLB are included 

in the scope of license renewal for 10 CFR 54.4(a)(2) for providing a mitigative 

function. Guard pipes, jet impingement shields and pipe whip restraints are 

evaluated with the structures where they reside and are assumed to be within the 

scope of license renewal for 10 CFR 54.4(a)(2).

Preventive Option. The preventive option utilized in the PINGP license renewal 

process identifies nonsafety-related SSCs that have a spatial interaction (pipe 

whip, physical impacts due to high energy system piping falling due to flow 

accelerated corrosion failures, jet impingement and spray, drip or flooding from 

the nonsafety-related system) that could create additional failures of the safety 

related SSCs.

Non-Safety Related SSCs Containing Liquid and Steam

2.1.4.2.2 Staff Evaluation

. SSCs containing liquids 

or steam, including high energy, moderate and low energy systems, and located 

in structures housing 10 CFR 54.4(a)(1) SSCs are assumed to have a spatial 

interaction unless excluded by the mitigative option. Therefore, these SSCs, 

along with associated component supports, are included within the scope of 

license renewal for 10 CFR 54.4(a)(2).

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 

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

Regulatory Guide 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 high-energy 

line breaks (HELBs); nonsafety-related SSCs connected to safety-related SSCs; nonsafetyrelated 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 operating experience. NEI 95-10 further 

describes operating experience as all documented plant-specific and industry-wide 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 2.1.2.4.2 in which the applicant described the scoping methodology for nonsafety-
2-16

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 Required to Perform a Function that Supports a Safety-Related SSC. 

The staff determined that nonsafety-related SSCs required to remain functional to support a 

safety-related function 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 2.1.2.4.2 and the applicant’s 10 CFR 54.4(a)(2) implementing 

document. The staff confirmed that the applicant had reviewed the UFSAR, plant drawings, 

plant equipment database, Q-List, Q-List extension, and other CLB documents to identify the 

nonsafety-related systems and structures that function to support a safety-related system whose 

failure could prevent the performance of a safety-related intended function. The applicant also 

considered missiles, overhead handling systems, internal and external flooding, and HELBs. 

Accordingly, the staff finds that the applicant implemented an acceptable method for including 

nonsafety-related systems that perform functions that support safety-related intended functions, 

within the scope of license renewal as required by 10 CFR 54.4(a)(2).

Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs

The staff determined that in order to identify the nonsafety-related SSCs connected to safetyrelated 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 nonsafetyrelated piping systems to include within the scope of license renewal:

. 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 2.1.2.4.2 and the applicant’s 10 CFR 

54.4(a)(2) implementing document. The applicant had reviewed the safety-related to nonsafetyrelated 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. 

  Seismic anchors

  Equivalent anchors

  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 the LRA Section 2.1.2.4.2 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 
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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 2.1.2.4.2 and the applicant’s implementing document states that the applicant had 

used a mitigative approach when considering the impact of nonsafety-related SSCs on safetyrelated SSCs for occurrences discussed in the CLB. The staff reviewed the applicant’s CLB 

information, primarily contained in the UFSAR, related to missiles, crane load drops, flooding 

and high-energy line breaks. 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 that 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 Section 2.1.2.4.2 and the applicant’s implementing document states 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 that were located within the same space as safety-related SSCs. As 

described in the LRA and 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 its 

corresponding structures for potential spatial interaction, based on a review of the CLB and 

plant walkdowns. Nonsafety-related systems and components that contain liquid or steam and 

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 operating experience, 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).

LRA Section 2.1.2.5.5 states, “Abandoned equipment that is installed and connected to plant 

process pipes needs to be evaluated for non-safety attached to safety and non-safety affecting 

safety spatial interaction scoping criteria.” However, during the scoping and screening 

methodology audit, the applicant indicated that not all abandoned equipment had been verified 

as disconnected and drained, yet this abandoned equipment had not been included within the 

scope of license renewal. 
2-18

The staff determined that additional information would be required to complete the review of the 

applicant’s scoping methodology. RAI 2.1-2, dated November 5, 2008, states that during the 

NRC scoping and screening methodology audit, the applicant stated that there were certain 

nonsafety-related abandoned equipment that were not included within the scope for license 

renewal in accordance with 10 CFR 54.4(a)(2). The staff requested the applicant provide a 

description of the methods used and the basis for conclusions, in determining that nonsafetyrelated abandoned systems and attached piping, which had not been verified as disconnected 

and drained, were not included within the scope of license renewal in accordance with 10 CFR 

54.4(a)(2).

The applicant responded to RAI 2.1-2 by letter dated December 5, 2008, which states the 

applicant had performed field walkdowns to verify that an abandoned instrument air dryer and a 

caustic storage tank were disconnected and drained. The abandoned demineralizer head tank 

process pipe was also disconnected and drained; however, the overflow drain was still 

connected below grade. The applicant’s review of the demineralizer head tank overflow drain 

concluded that it did not have the potential for spatial interaction with safety-related SSCs and 

was not included within the scope of license renewal. The applicant’s response further states: 

Review of P&ID (Piping and Instrument Diagrams), isometric and physical 

drawings determined that the Steam Generator Blowdown Hold-Up Tank Filter 

#11 (Drawing LR-88740, location G-9) and #21 (Drawing LR-39250, location F-5) 

are disconnected from the process pipe. However, the drain lines, at valve BD12-3 and BD-12-4 respectively, are still connected to the Waste Disposal (WD) 

System aerated drains. (Note: Drawing LR-39250, location F-5, incorrectly shows 

this drain line as capped at valve BD-12-4.) Due to the system configuration, 

complete draining of the piping and components could not be verified, and 

therefore these components are brought into the scope of license renewal based 

on the criteria of 10 CFR 54.4(a)(2). The SGB Hold-Up Tank Filters and their 

interconnected piping and valves are connected to and evaluated with the WD 

System. Addition of these components does not result in any changes to the 

LRA.

Field walkdowns along with P&ID and physical drawing reviews determined that 

the Reactor Building Heating components (Drawing LR-39605-1, locations C-7 

and B-9) are disconnected. Due to the system configuration, complete draining of 

the piping and components could not be verified. Therefore, these components 

are brought into the scope of license renewal based on the criteria of 10 CFR 

54.4(a)(2). 

The staff determined that the applicant had performed a walkdown of abandoned equipment to 

determine whether the systems were disconnected, potentially contained fluid, and whether the 

abandoned equipment could have an effect on safety-related SSCs located in the same space. 

The staff determined that the applicant appropriately identified two abandoned systems, which 

could potentially affect safety-related SSCs, and included these nonsafety-related SSCs within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(2). The concern identified in 

RAI 2.1-2 is resolved.
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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 2.1-2, 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

LRA Section 2.1.2.4.3, “Scoping Criterion 3-SSCs Required by Other Regulations Identified in 

10 CFR Part 54,” describes the methodology for identifying those systems and structures within 

the scope of license renewal in accordance with the Commission’s criteria for five regulated 

events: (1) 10 CFR 50.48, “Fire Protection,” (2) 10 CFR 50.49, “Environmental Qualification of 

Electric Equipment Important to Safety for Nuclear Power Plants,” (3) 10 CFR 50.61, “Fracture 

Toughness Requirements for Protection Against Pressurized Thermal Shock Events,” 

(4) 10 CFR 50.62, “Requirements for Reduction of Risk from Anticipated Transients Without 

Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants,” and (5) 10 CFR 50.63, 

“Loss of All Alternating Current Power.”

Fire Protection. LRA Section 2.1.2.4.3, subsection “Fire Protection,” described scoping of 

systems and structures relied on in safety analyses or plant evaluations to perform a function 

that demonstrates compliance with the fire protection criterion. The LRA states that consistent 

with the requirements specified in 10 CFR 54.4(a)(3), all SSCs relied upon to perform a function 

that demonstrates compliance with the regulations for fire protection (10 CFR 50.48) is within 

the scope of license renewal. LRA Section 2.1.2.4.3 further states that the Safe Shutdown 

Analysis, Fire Hazards Analysis Report, UFSAR, drawings, Operations Manual, and other 

PINGP source documents were used to identify SSCs which perform fire protection functions 

and which support fire protection equipment relied upon to achieve post-fire safe shutdown. A 

list of equipment was compiled from this review and was compared to a list of the equipment 

designated as fire protection or Appendix R related in the plant equipment database. 

Components and commodities included on the SSEL [safe shutdown equipment list] are inscope for license renewal.

Environmental Qualification

LRA Section 2.1.2.4.3 further states that electrical components, which meet these criteria for 

PINGP, are on the Environmental Qualification Master List (EQML) for 10 CFR 50.49. The 

EQML was developed to encompass the requirements identified in 10 CFR 50.49(b). Safety-

. LRA Section 2.1.2.4.3, subsection “Environmental Qualification 

(EQ),” described scoping of systems and structures relied on in safety analyses or plant 

evaluations to perform a function in compliance with the EQ criterion. The LRA states that 

equipment was determined to be within the scope of license renewal in accordance with 

10 CFR 50.49(b)(1), 10 CFR 50.49(b)(2), and 10 CFR 50.49(b)(3), including safety-related 

electrical equipment, nonsafety-related electrical equipment whose failure under postulated 

environmental conditions could prevent compliance with safety functions of the safety-related 

equipment, and certain post-accident monitoring equipment. 
2-20

related electrical equipment, nonsafety-related electrical equipment whose failure could prevent 

accomplishment of safety functions, and certain post-accident monitoring equipment were 

identified. The LRA further states that the EQML is the current component list of EQ 

components and is used as the basis for license renewal identification of EQ components for 

purposes of scoping and screening. Environmental qualification basis information is included in 

the PINGP UFSAR, Section 8.9. Consistent with the requirements specified in 10 CFR 

54.4(a)(3), all SSCs relied upon to perform a function that demonstrates compliance with 10 

CFR 50.49 are within the scope of license renewal.

Pressurized Thermal Shock. LRA Section 2.1.2.4.3, subsection “Pressurized Thermal Shock 

(PTS),” described scoping of systems and structures relied on in safety analyses or plant 

evaluations to perform a function in compliance with the PTS criterion. The LRA Section 

2.1.2.4.3 states that a PTS event is an event or transient in pressurized-water reactors caused 

by severe overcooling (thermal shock) concurrent with or followed by significant pressure in the 

reactor vessel. A PTS concern arises if one of these transients acts on the beltline region of a 

reactor vessel where a reduced fracture resistance exists due to neutron irradiation. The LRA 

further states that per the requirements of 10 CFR 50.61 (PTS Rule), licensees of pressurized 

water reactors shall have projected values of reference temperature for pressurized thermal 

shock (RTPTS ), accepted by the NRC, for each reactor vessel beltline material for the end of life 

fluence of the material. The assessment of RTPTS must use the calculation procedures and 

screening criteria given in the PTS Rule, and must specify the basis for the projected value of 

RTPTS for each vessel beltline material. The assessment must be updated whenever there is a 

significant change in projected values of RTPTS or upon the request for a change in the 

expiration date for operation of the facility. LRA Section 2.1.2.4.3 further states the Unit 1 and 2 

Reactor Vessels are considered to be within the scope of 10 CFR 54.4(a)(3) for PTS. 

Anticipated Transient Without Scram. LRA Section 2.1.2.4.3, subsection “Anticipated Transients 

Without Scram (ATWS),” described scoping of systems and structures relied on in safety 

analyses or plant evaluations to perform a function in compliance with the ATWS criterion. LRA 

Section 2.1.2.4.3 states that in December 1996, PINGP reviewed the design basis for the 

Auxiliary Feedwater System and determined that the existing pump low discharge pressure set 

point did not adequately protect the auxiliary feedwater pumps (AFWP) from runout conditions. 

PINGP determined that the preferred method for correction of this issue was the installation of a 

diverse scram system similar to that described in 10 CFR Part 50.62 for Combustion 

Engineering and Babcock & Wilcox plants. The ATWS Mitigating System Actuation 

Circuitry/Diverse Scram System (AMSAC/DSS) is described in UFSAR Section 7.11. ATWS 

Event analysis can be found in UFSAR Section 14.8. LRA Section 2.1.2.4.3 further states that 

as described in UFSAR Section 7.11.6, “A reactor trip, a turbine trip and auxiliary feedwater 

pump start are required AMSAC/DSS functions, with securing of steam generator blowdown 

and sampling as recommended outputs.” Plant and vendor drawings, the UFSAR, docketed 

correspondence, modifications, and the plant equipment database were reviewed to identify 

components relied upon to mitigate the ATWS event. These components, relied upon to 

mitigate the ATWS event, are in-scope for license renewal.

Station Blackout. LRA Section 2.1.2.4.3, subsection “Station Blackout (SBO),” described 

scoping of systems and structures relied on in safety analyses or plant evaluations to perform a 

function in compliance with the SBO criterion. LRA Section 2.1.2.4.3 states that SBO rule 

implementation details for PINGP are established in docketed correspondence, SERs, and 
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supporting calculations. UFSAR Section 8.4 and Section 8.5 include summaries of the licensing 

criteria that are the CLB for resolution of this issue at PINGP. The LRA further states that in 

order to ensure a comprehensive list of SSCs required to satisfy 10 CFR 54.4(a)(3) for SBO 

was developed, the requirements and guidance associated with SBO implementation were 

reviewed to identify PINGP specific functional requirements and reliance on SSCs for 10 CFR 

50.63 compliance. Components relied upon at PINGP to perform an SBO function were 

identified through a review of plant-specific SBO calculations, the UFSAR, drawings, 

modifications, and the plant equipment database. 

LRA Section 2.1.2.4.3 further states that a review of one-line drawings and plant procedures for 

performing offsite power restoration was performed. Components explicitly relied upon in offsite 

power restoration procedures and their interconnections (busses, disconnect switches, etc.) are 

in-scope for license renewal. Components and commodities in-scope for license renewal are 

those from the plant 4.16kV busses, through and including the interconnecting transformers, 

disconnect switches, busses, etc., out to and including the switchyard devices that connect to 

offsite sources.

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 in the scope of license renewal required for post-fire 

safe shutdown, fire detection and suppression, and commitments made to Appendix A to 

Branch Technical Position APCSB 9.5-1 (BTP 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 UFSAR, Safe Shutdown Analysis, Fire Hazards 

Analysis Report, drawings, Operations Manual, and other PINGP 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 
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applicant’s scoping methodology was adequate 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 EQ master list 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 that 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 had 

required the applicant to review the activities performed to meet 10 CFR 50.61, which resulted 

in the inclusion of the Units 1 and 2 reactor vessels 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. 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. Accordingly, 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 generated a 

list of plant systems credited for ATWS mitigation based on review of the plant and vendor 

drawings, the UFSAR, 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 UFSAR, 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 finds that the scoping results included systems and structures that perform intended 

functions meeting 10 CFR 50.63 requirements. The staff determined, based on its review, that 

the applicant’s scoping methodology was adequate for identifying SSCs credited in complying 

with the SBO regulation within the scope of license renewal. 
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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. 

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 2.1.2.1 further states that the PINGP CLB documents, controlled drawings, and the 

plant equipment database were used for this review. Systems and components from the plant 

equipment database were included in the license renewal database population. Components in 

the plant equipment database were reviewed on a sampling basis to ensure systems, 

components, and commodity groups having potential to be considered in-scope for license 

renewal were not omitted. Additionally, plant walkdowns were conducted as necessary. In 

addition to the plant equipment database, the PINGP piping and instrumentation drawing 

(P&ID)s and other controlled drawings were used to identify components required to support 

system-level and structure-level license renewal functions.

. LRA Section 2.1.2.1, “Scoping Process Overview,” states 

that the scoping process categorized the entire plant in terms of SSCs and commodity groups 

with respect to license renewal. SSC and commodity group functions were identified and 

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

the item should be considered within the scope of license renewal. Even if only a portion of an 

SSC or commodity fulfilled a scoping criterion, the item was identified as in-scope for license 

renewal and received further evaluation. Those SSCs or commodities identified as not meeting 

any scoping criterion were not further processed. 

LRA Section 2.1.2.5.4, “System Level Functions,” [mechanical] states that the license renewal 

database, using the CLB resources discussed in LRA Section 2.1.1.1, was used to assign 

system level functions. LRA Section 2.1.1.1 “Plant Information Sources,” states that the 

information sources included the UFSAR, plant equipment database, the Q-List and Q-List 

extension which were used to assign system-level functions. LRA Section 2.1.1.1 further states 

that the Q-List defines the SSCs subject to the requirements of 10 CFR 50, Appendix B and that 

the Q-List Extension further identifies safety-related and nonsafety-related substructures, 

subsystems, and component parts of Q-Listed items. 

LRA Section 2.1.2.5, “Mechanical Scoping Methodology,” states that license renewal system 

boundaries were initially based on the associated plant equipment database system designators 

and were then modified as needed through a system and component function review that used 

the UFSAR, P&IDs, DBDs, other drawings, docketed correspondence, and other design 

documents. The results were captured in the license renewal database and depicted on the 

license renewal Boundary Drawings (for mechanical systems). LRA Section 2.1.2.6.3, 

“Evaluation Boundaries,” (structural) states that the civil/structural evaluation boundaries were 

defined by review of the UFSAR, plant site layout drawings, by plant walkdowns and by review 
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of the location of in-scope mechanical and electrical systems and components needed to 

perform the system’s intended functions.

LRA Section 2.1.2.7.1, “Discipline Specific Scoping Process,” [electrical] states the electrical 

and instrumentation and control (EIC) components without a mechanical intended function, 

which are associated with EIC or mechanical systems were classified and processed as 

commodity groups. Since components from the EIC systems were addressed in the commodity 

groups, no system-level functions were identified or considered for the IPA. Therefore, no EIC 

systems were eliminated from scope.

Component Level Scoping. LRA Section 2.1.2.5.3, “Evaluation Boundaries,” [mechanical] states 

that for mechanical systems, the evaluation boundaries were defined by tracing the flow paths 

needed to perform the system's intended functions. Components within these boundaries were 

considered to be within the scope of license renewal. LRA Section 2.1.2.6.3 states that a 

civil/structural license renewal boundary drawing was prepared to document the structures and 

components determined to be in-scope for license renewal. LRA Section 2.1.2.7.1 states that 

the EIC components without a mechanical intended function, which are associated with EIC or 

mechanical systems, were classified and processed as commodity groups. 

Insulation. LRA Section 2.1.2.5.5, “Special Considerations,” states that thermal insulation that 

performs an intended function as identified in 10 CFR 54.4(a) was included in the scope of 

license renewal. The components involved are relied on in safety analyses, plant evaluations, or 

license conditions and meet the license renewal scoping criteria of 10 CFR 54.4(a)(1) or (a)(3).

Consumables

Group (a): LRA Section 2.1.3.2.2 states that packing, gaskets, component seals and O-rings 

are commonly found in components such as valves, pumps, heat exchangers, piping, dampers, 

and ducts. Based on ANSI B31.1.0 and the ASME B&PV Code Section III, these 

subcomponents are not pressure-retaining parts. Therefore, these subcomponents are not 

relied on to perform a pressure-retaining function or other intended function and are not subject 

to an AMR.

. LRA Section 2.1.3.2.2, “Component Classification (Passive, Long-Lived),” states 

that consumables are a special class of components that can include packing, gaskets, 

component seals, O-rings, structural sealants, oil, grease, component filters, system filters, fire 

extinguishers, fire hoses, and air packs. Consumables were divided into the following four 

categories for the purpose of license renewal: (a) packing, gaskets, seals, and O-rings; 

(b) structural sealants; (c) oil, grease, and component filters; and (d) system filters, fire 

extinguishers, fire hoses, and air packs.

Group (b): LRA Section 2.1.3.2.2 states that structural sealants may perform functions without 

moving parts, or a change in configuration or properties, and they are not typically replaced. 

Those determined to perform component-intended functions in support of a larger structure 

were subject to an AMR.

Group (c): LRA Section 2.1.3.2.2 states that oil, grease and component filters are commonly 

found in components such as pumps, valves, diesel motors, fans, and dampers. These 

components are short-lived and are periodically replaced in accordance with procedures. 

Therefore, these components are not subject to an AMR. 
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Group (d): LRA Section 2.1.3.2.2 states that system filters, fire hoses, fire extinguishers, and air 

packs, are short-lived and are routinely tested, inspected, and replaced when necessary. 

System filters are monitored during testing and operation and are either replaced periodically or 

based on condition. Fire hoses and fire extinguishers are inspected and tested periodically and 

must be replaced if they do not pass the test or inspection. Breathing air apparatus and air 

cylinders are inspected and tested periodically and must be replaced if they do not pass the test 

or inspection. Criteria for inspection and replacement are based on accepted industry 

standards. Therefore, these components are not subject to an AMR. However, system filters or 

strainers that are not periodically replaced are subject to an AMR.

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 

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 that contained information that includes a description of the structure or system, a 

listing of functions performed by the system or structure, identification of intended functions, 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 systems, structures, and components 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

In addition to the information previously discussed in SER Section 2.1.4.4.1, LRA Section 

2.1.2.5 and subsections state that the mechanical discipline [personnel] were responsible for 

scoping evaluations for plant mechanical systems, including electrical and structural

components contained in these systems (unless reassigned to another discipline). License 
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renewal system boundaries were initially based on the associated plant equipment database 

system designators. These boundaries were then modified as needed through a system and 

component function review that used the UFSAR, P&IDs, DBDs, other drawings, docketed 

correspondence, and other design documents. Results were captured in the license renewal 

database and depicted on the license renewal boundary drawings for the mechanical 

components.

LRA Section 2.1.2.5 further states that components in the plant equipment database were input 

to the license renewal database. Additional components were added to the license renewal 

database when necessary. In some cases, asset groups were used where it was deemed 

efficient to process a single component type as one asset within a system, rather than many 

individual components having the same construction and function. The evaluation boundaries 

were defined by tracing the flow paths needed to perform the system's intended functions. 

Components within these boundaries are considered to be within the scope of license renewal. 

The license renewal database was used to assign system-level functions. Staged SSCs that are 

dedicated (reserved) for use in an application that, when installed, are relied upon to perform 10 

CFR 54.4(a) intended functions, were included in the scope of license renewal. 

2.1.4.5.2 Staff Evaluation

The staff evaluated LRA Section 2.1.2.4 and 2.1.2.5 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 UFSAR, DBDs, the plant 

equipment database, the Q-List and Q-List extension, NRC docketed correspondence and 

documents, and plant drawings. The evaluation boundaries for mechanical systems were 

documented on license renewal boundary drawings that were created by marking mechanical 

piping and instrumentation diagrams to indicate the components within the scope of license 

renewal. The staff determined that components within the evaluation boundary were reviewed to 

determine whether they perform an intended function. Intended functions were established 

based on whether 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 the LRA Section 2.1.2.5 

and the guidance contained in the SRP-LR, Section 2.1, and was adequately implemented. 
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On a sampling basis, the staff reviewed the applicant's scoping reports for the main steam 

system and decay heat removal system mechanical component types that 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 main steam 

and residual heat removal system 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 main steam and residual heat removal 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 had license renewal personnel 

knowledgeable about the system, and these personnel 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.

2.1.4.5.3 Conclusion

On the basis of its review of the LRA, scoping implementing procedures, 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

In addition to the information previously discussed in SER Section 2.1.4.4.1, LRA Section 

2.1.2.6, “Civil/Structural Scoping Methodology,” and subsections state that the civil/structural 

discipline [personnel] were responsible for the scoping evaluations for structures and structural 

commodity groups. The license applicant based its renewal civil/structural boundaries on the 

associated plant equipment database system designators and on the UFSAR classification. 

However, because very few structural elements are included in the plant equipment database, 

the applicant used the PINGP Structures Monitoring Program, UFSAR, DBDs, drawings, 

procedures, and walkdowns to develop a more comprehensive list of structures and commodity 

groups for license renewal.

LRA Section 2.1.2.6 and subsections further state that system-level functions and associated 

10 CFR Part 54 criteria applicable to the structure were identified during scoping. Information 

sources included the UFSAR, CLB documentation, DBDs, training materials, plant equipment 

database, drawings, specifications, codes/standards, design changes, procedures, and 

walkdowns of plant buildings.
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2.1.4.6.2 Staff Evaluation

The staff evaluated LRA Sections 2.1.2.4 and 2.1.2.6, and subsections, and the guidance 

contained in the implementing procedures and 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 the structures intended functions through 

a review of the plant equipment database, the PINGP Structures Monitoring Program, UFSAR, 

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).

The staff reviewed selected portions of the plant equipment database, the PINGP Structures 

Monitoring Program, UFSAR, 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 

and the screen house 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 

screen house 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 screen house 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, scoping 

implementing procedures, 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

In addition to the information previously discussed in Section 2.1.4.4.1, LRA Section 2.1.2.7, 

“Electrical/I&C Scoping Methodology,” and subsections state that the EIC components without a 

mechanical intended function, that are associated with EIC or mechanical systems, were 

classified and processed as commodity groups. The applicant stated that it formed commodity 

groups from components that were constructed from similar materials, exposed to similar 

environments, or performed similar intended functions regardless of the specific system or 

structure to which they were originally assigned. Since components from the EIC systems were 
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addressed in the commodity groups, the applicant stated that no system-level functions were 

identified or considered for the IPA. Therefore, no EIC systems were eliminated from scope.

LRA Section 2.1.2.7 and subsections state that information regarding the EIC commodities was 

identified from review of the UFSAR, plant equipment database, CLB documentation, DBDs, 

databases and documents, procedures, drawings, specifications, codes/standards, and system 

walkdowns. The applicant classified and processed the EIC components belonging to EIC 

commodities as commodities utilizing the In-Scope Bounding Approach (Plant Spaces 

Approach). The commodity classifications were based on NEI 95-10 Appendix B as a guideline. 

The applicant’s general approach was to assume that EIC commodities are in-scope for criteria 

10 CFR 54.4(a)(1), (2) and (3). 

2.1.4.7.2 Staff Evaluation

The staff evaluated LRA Sections 2.1.2.4 and 2.1.2.7, and subsections, 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 controls (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 UFSAR, 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 EIC components and also EIC 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, scoping source documents, 

implementing procedures, 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 

and perform or support an intended function meeting the criteria of 10 CFR 54.4(a)(1), (2) 

whose failure could affect safety-related functions, and (3) that are necessary to demonstrate 

compliance with the NRC's 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.
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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 2.1.3.2, “General Screening Methodology,” and subsections state that the 

screening process identifies the structures and components within the scope of license renewal 

that are subject to an Aging Management Review [AMR]. These structures and components are 

those that perform or support an intended function in support of the Systems, Structures or 

Commodity Group function(s) without moving parts or without a change in configuration or 

properties (referred to as passive) and are not subject to replacement based on qualified life or 

specified time period (referred to as long-lived). A component level intended function is one that 

supports the system level intended function; the plant systems, structures, and commodity 

groups that are within the scope of license renewal and their system level intended functions 

were previously identified during the scoping process. The screening process consists of 

identification of the components that are subject to an AMR (passive and long-lived) within the 

scope of license renewal and identification of the component level intended functions for 

equipment subject to an AMR. LRA Section 2.1.3.2 and subsections further state that the 

components (or commodity groups) that are subject to an AMR are those that perform a 

component level intended function without moving parts or a change in configuration or 

properties and are not subject to replacement based on a qualified life or specified frequency. 

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), 

and 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 function(s) will be maintained 

under all design conditions imposed by the plant-specific CLB for the period of extended 

operation.

The staff reviewed the methodology used by the applicant to 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 2.1.3.2 and subsections, the applicant discusses 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 

and Screening Results: Mechanical Systems,” LRA Section 2.4, “Scoping and Screening 

Results: Containment, Structures, and Component Supports,” and LRA Section 2.5, “Scoping 

and Screening Results: Electrical and Instrumentation and Control Systems.” These sections of 
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the LRA provide 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 main steam system, the residual heat removal system, the turbine building and 

the screen house.

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 component 

screening 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 in-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 is, therefore, 

acceptable.

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

LRA Sections 2.1.3.2 and subsections, and 2.1.3.3, “Mechanical Screening Methodology,” and 

subsections state that the screening process identifies the mechanical components within the 

scope of license renewal that are subject to an AMR. These structures and components are 

those that perform or support an intended function in support of the Systems, Structures or 

Commodity Group function(s) without moving parts or without a change in configuration or 

properties (referred to as passive) and are not subject to replacement based on qualified life or 

specified time period (referred to as long-lived). A component level intended function is one that 

supports the system level intended function; the plant systems, structures, and commodity 

groups that are within the scope of license renewal and their system level intended functions 

were previously identified during the scoping process. The screening process consists of 

identification of the components that are subject to an AMR (passive and long-lived) within the 

scope of license renewal and identification of the component level intended functions for 

equipment subject to an AMR. LRA Section 2.1.3.2 and subsections further state that the 

components (or commodity groups) that are subject to an AMR are those that perform a 

component level intended function without moving parts or a change in configuration or 

properties and are not subject to replacement based on a qualified life or specified frequency. 

LRA Section 2.1.3.3 states that when assigning component level license renewal intended 

functions, some components had more than one intended function. 

2.1.5.2.2 Staff Evaluation

The staff reviewed the mechanical screening methodology discussed and documented in LRA 

Sections 2.1.3.2 and subsections, and 2.1.3.3 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 
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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 UFSAR, plant equipment database, CLB 

documentation, DBDs, databases and documents, procedures, drawings, specifications, and 

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 main steam and residual heat removal 

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 UFSAR, plant equipment database, CLB documentation, DBDs, databases and 

documents, procedures, drawings, specifications, codes/standards and selected scoping and 

screening reports, and a sample of the main steam and residual heat removal systems 

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.

2.1.5.3 Structural Component Screening

2.1.5.3.1 Summary of Technical Information in the Application

LRA Sections 2.1.3.2 and subsections, and 2.1.3.4, “Civil/Structural Screening Methodology,” 

and subsections, state that the screening process identifies structural components within the 

scope of license renewal that are subject to an AMR. These structures and components are 

those that perform or support an intended function in support of the Systems, Structures or 

Commodity Group function(s) without moving parts or without a change in configuration or 

properties (referred to as passive) and are not subject to replacement based on qualified life or 
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specified time period (referred to as long-lived). A component level intended function is one that 

supports the system level intended function; the plant systems, structures, and commodity 

groups that are within the scope of license renewal and their system level intended functions 

were previously identified during the scoping process. The screening process consists of 

identification of the components that are subject to an AMR (passive and long-lived) within the 

scope of license renewal and identification of the component level intended functions for 

equipment subject to an AMR. 

2.1.5.3.2 Staff Evaluation

The staff reviewed the structural screening methodology discussed and documented in LRA 

Sections 2.1.3.2 and subsections, and 2.1.3.4 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 in 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 UFSAR, PINGP structures monitoring program 

documentation, DBDs, 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 boundary drawing to document the structures and components 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 and the screenhouse to verify proper 

implementation of the screening process. Based on these onsite review activities, the staff did 

not identify any discrepancies between the methodology documented and the implementation 

results. 

2.1.5.3.3 Conclusion

On the basis of its review of the LRA, implementing procedures, the UFSAR, the PINGP 

structures monitoring program documentation, DBDs, and scoping and screening reports, and a 

sampling review of the turbine building and screen house 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 2.1.3.2 and subsections, and 2.1.3.5, “Electrical/I&C Screening Methodology,” 

and subsections, state that the screening process identifies the components within the scope of 
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license renewal that are subject to an AMR. These structures and components are those that 

perform or support an intended function in support of the Systems, Structures, or Commodity 

Group function(s) without moving parts or without a change in configuration or properties 

(referred to as passive) and are not subject to replacement based on qualified life or specified 

time period (referred to as long-lived). A component level intended function is one that supports 

the system level intended function; the plant systems, structures, and commodity groups that 

are within the scope of license renewal and their system level intended functions were 

previously identified during the scoping process. The screening process consists of identification 

of the components that are subject to an AMR (passive and long-lived) within the scope of 

license renewal and identification of the component level intended functions for equipment 

subject to an AMR. 

LRA Section 2.1.3.5 and subsections further state that PINGP elected to include, as a 

commodity, insulated cable and connections within the scope of license renewal because of the 

complexity of identifying whether or not an individual insulated cable or connection supports an 

intended function. However, when individual cables and connections were identified during the 

AMR process as EQ, or as not providing an intended function, no further AMR was conducted. 

The applicant explained that the screening process completed the asset identification process, 

verified the identification of component types, and evaluated each of the component types 

against the screening criteria. The screening process evaluation also identified the component 

level intended functions that were assigned to component types in accordance with NEI 95-10 

and NUREG-1801. Following the development of a list of electrical commodity groups, the 

applicant screened out and removed from further consideration those commodity groups 

classified as active (from NEI 95-10, Appendix B). The applicant organized the remaining 

components into AMR commodity groups for AMR. 

LRA Section 2.1.3.5.1, “Screening of Electrical Components,” lists that the resulting AMR 

electrical commodity groups of long-lived passive components subject to an AMR are as 

follows:

  Cables and Connections (Insulation), includes splices, terminations, fuse blocks and 

connectors

  Cables and Connections Used in Instrumentation Circuits (Insulation), sensitive to 

reduction in conductor insulation resistance

  Inaccessible Medium Voltage Cables and Connections (Insulation),underground, buried

  Electrical Connector Contacts (metallic connector pins exposed to borated water)

  Electrical Penetrations (electrical insulation portions)

  Metal Enclosed Bus and Connections (Bus/Connections, Enclosure Assemblies, 

Insulation/Insulators)

  Fuse Holders (metallic parts), not part of a larger active assembly

  Cable Connections (metallic parts)

  Switchyard Bus and Connections
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  Transmission Conductors and Connections

  High-Voltage Insulators

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for electrical screening in LRA Sections 

2.1.3.2 and subsections, and 2.1.3.5 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. 

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 saw 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 checked to see whether if the screening methodology outlined in the LRA and 

implementing procedures were 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 to verify proper implementation of the screening 

process. Based on 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, implementing procedures, plant drawings, 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 a review of the LRA, the screening implementing procedures, 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, the staff confirms that the 
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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.

2.2 

2.2.1 Introduction 

Plant-Level Scoping Results 

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the 

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to 

determine which SSCs must be included within the scope of license renewal. The staff reviewed 

the plant-level scoping results to determine whether the applicant has properly identified all 

systems and structures relied upon to remain functional during DBEs, as required by 

10 CFR 54.4(a)(1), systems and structures the failure of which could prevent satisfactory 

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2), and systems 

and structures relied on in safety analyses or plant evaluations to perform functions required by 

regulations referenced in 10 CFR 54.4(a)(3). 

2.2.2 Summary of Technical Information in the Application 

LRA Table 2.2-1 lists those mechanical systems, electrical and I&C systems, and structures that 

are within the scope of license renewal. Also in LRA Table 2.2-1, the applicant listed the 

systems and structures that do not meet the criteria specified in 10 CFR 54.4(a) and are 

excluded from the scope of license renewal. Based on the DBEs considered in the CLB, other 

CLB information relating to nonsafety-related systems and structures, and certain regulated 

events, the applicant identified plant-level systems and structures within the scope of license 

renewal as defined by 10 CFR 54.4.

2.2.3 Staff Evaluation 

In LRA Section 2.1, the applicant described its methodology for identifying systems and 

structures within the scope of license renewal and subject to an AMR. The staff reviewed the 

scoping and screening methodology and provides its evaluation in SER Section 2.1. To verify 

that the applicant properly implemented its methodology, the staff’s review focused on the 

implementation results shown in LRA Table 2.2-1, to confirm that there were no omissions of 

plant-level systems and structures within the scope of license renewal.

The staff determined whether the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected 

systems and structures that the applicant did not identify as within the scope of license renewal 

to verify whether the systems and structures have any intended functions requiring their 

inclusion within the scope of license renewal. The staff’s review of the applicant’s 

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, “PlantLevel Scoping Results.”
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The staff’s review of LRA Section 2.2 identified areas where 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 2.2-01, dated November 5, 2008, the staff noted that the shield building ventilation 

system is addressed in LRA Section 2.3.3.14; however, the shield building special ventilation 

system cannot be found in the LRA. The staff asked the applicant to clarify that the shield 

building special ventilation system of LRA Section 2.3.3.6 and UFSAR Section 1.3.9 is the same 

system as the shield building ventilation subsystem described in LRA Section 2.3.3.14, or to 

provide the reasoning for not including the shield building special ventilation system in LRA 

Table 2.2-1.

In its response, dated December 5, 2008, the applicant stated that LRA Section 2.3.3.6 and 

UFSAR Section 1.3.9.f.2, “Shield Building Special Ventilation System,” is the same system 

described in LRA Section 2.3.3.14. 

Based on its review, the staff finds the applicant’s response to RAI 2.2-01 acceptable because it 

confirms that the shield building special ventilation system described in LRA Section 2.3.3.6 and 

UFSAR Section 1.3.9.f.2 is the same system as the shield building ventilation subsystem 

described in LRA Section 2.3.3.14 and thus has been addressed for scoping and screening 

purposes. Therefore, the staff’s concern described in RAI 2.2-01 is resolved. 

In RAI 2.2-02, dated November 5, 2008, the staff noted that the chemical lab and counting room 

ventilation system identified in UFSAR Table 12.2-1 could not be found in the LRA. The staff 

asked the applicant to clarify that the cold chemical lab of LRA Section 2.3.3.19 is the same 

system as the chemical lab and counting room ventilation system identified in UFSAR Table 

12.2-1 or to provide the reasoning for not including the chemical lab and counting room 

ventilation system in LRA Table 2.2-1.

In its response, dated December 5, 2008, the applicant stated the chemical lab and counting 

room ventilation system identified in UFSAR Table 12.2-1 is the same system described in LRA 

Section 2.3.3.1 as the hot lab/sample room ventilation subsystem.

Based on its review, the staff finds the applicant’s response to RAI 2.2-02 acceptable because 

the chemical lab and counting room ventilation system identified in UFSAR Table 12.2-1 is the 

same system described LRA Section 2.3.3.1 as the hot lab/sample room ventilation subsystem

and thus has been addressed for scoping and screening purposes. Therefore, the staff’s 

concern described in RAI 2.2-02 is resolved. 

In RAI 2.2-03, dated November 5, 2008, the staff noted that the generator cooling water system 

identified in UFSAR Table 12.2-1 could not be located in LRA Table 2.2-1. The applicant was 

requested to provide the reasoning for not including the generator cooling water system in Table 

2.2-1.

In its response, dated December 5, 2008, the applicant stated the generator cooling water 

system identified in UFSAR Table 12.2-1 is evaluated as part of LRA Section 2.3.4.8, “Turbine 

Generator and Support (TB) System,” and LRA Section 2.3.3.6, “Cooling Water (CL) System.”
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Based on its review, the staff finds the applicant’s response to RAI 2.2-03 acceptable because 

the generator cooling water system identified in UFSAR Table 12.2-1 is evaluated as part of the 

LRA Sections 2.3.4.8, “Turbine Generator and Support (TB) System,” and 2.3.3.6, “Cooling 

Water (CL) System.” Therefore, the staff’s concern described in RAI 2.2-03 is resolved. 

In RAI 2.2-04, dated November 5, 2008, the staff noted that the reactor gap cooling, reactor 

refueling cavity ventilation, and reactor support cooling systems identified in UFSAR Table 

12.2-1 could not be located in LRA Table 2.2-1, “Plant Level Scoping Results.” The staff asked 

the applicant to provide the reasoning for not including the reactor gap cooling, reactor refueling 

cavity ventilation and reactor support cooling systems in LRA Table 2.2-1.

In its response, dated December 5, 2008, the applicant stated the reactor gap cooling and 

reactor support cooling systems identified in UFSAR Table 12.2-1 are the same systems 

identified as reactor cavity cooling and reactor vessel support pad cooling subsystems identified 

respectively in LRA Section 2.3.3.14. The applicant explained that the reactor refueling cavity 

ventilation system identified in UFSAR Table 12.2-1 is no longer installed and therefore does 

not need to be included in the PINGP LRA. 

Based on its review, the staff finds the applicant’s response to RAI 2.2-04 acceptable because 

the reactor gap cooling and reactor support cooling systems identified in UFSAR Table 12.2-1 

are the same systems identified as reactor cavity cooling and reactor vessel support pad cooling 

subsystems identified respectively in LRA Section 2.3.3.14, and thus have been addressed for 

scoping and screening purposes. Because the reactor refueling cavity ventilation system is no 

longer installed, scoping and screening is not applicable to it. Therefore, the staff’s concern 

described in RAI 2.2-04 is resolved. 

In RAI 2.2-05, dated November 5, 2008, the staff noted that the acoustic monitoring and seismic 

monitoring systems identified in UFSAR Sections 4.4.2.4 and 7.9.3 respectively could not be 

located in LRA Table 2.2-1. The staff asked the applicant to explain why the acoustic monitoring 

and seismic monitoring systems were not listed in Table 2.2-1.

In its December 5, 2008 response, the applicant stated that the acoustic monitoring system 

components were initially included in the electrical event monitoring system. The seismic 

monitoring system components were initially included in the electrical miscellaneous plant 

instruments system. Components of these systems are now grouped in the electrical and I&C 

commodities with no system level intended functions identified in the LRA. The event monitoring 

and miscellaneous plant instruments system scoping results are presented in Table 2.2-1, Plant 

Level Scoping Results.

Based on its review, the staff finds the applicant’s response to RAI 2.2-05 acceptable because 

the acoustic monitoring system components are included in the event monitoring system and 

the seismic monitoring system is included in the miscellaneous plant instruments system with 

the scoping results in Table 2.2-1. Therefore, the staff’s concern described in RAI 2.2-05 is 

resolved. 
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2.2.4 Conclusion 

The staff reviewed LRA Section 2.2, the RAI responses, and the UFSAR 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 

This section documents the staff’s review of the applicant’s scoping and screening results for 

mechanical systems. Specifically, this section discusses the following:

Scoping and Screening Results: Mechanical Systems 

• reactor vessel, internals, and reactor coolant system (RCS)

• 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 section in the SER, which specifically addresses the 

applicant’s responses to the RAI(s).

In accordance with the requirement of 10 CFR 54.21(a)(1), the applicant must list passive, longlived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to verify that the applicant identified all 

mechanical system SCs that met the scoping criteria and were subject to an AMR, and to 

confirm that there were no omissions.

The staff’s evaluation was performed using the evaluation methodology described here, the 

guidance in SRP-LR Section 2.3, and took into account (where applicable) the system 

functions(s) described in the UFSAR. The objective was to determine whether the applicant 

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 were subject to 

an AMR in accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the LRA, applicable sections of the UFSAR, license 

renewal boundary 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 applicant 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 
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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 identifies the reactor vessel, internals and 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 LRA sections:

2.3.1.1 Pressurizer System

2.3.1.2 Reactor Coolant System

2.3.1.3 Reactor Internals System

2.3.1.4 Reactor Vessel System

2.3.1.5 Steam Generator System

The staff’s findings on review of LRA Sections 2.3.1.1 – 2.3.1.5 are in SER Sections 2.3.1.1 –

2.3.1.5, respectively.

2.3.1.1 Pressurizer System

2.3.1.1.1 Summary of Technical Information in the Application

LRA Section 2.3.1.1 describes the pressurizer system (PS). The PS is designed to maintain the 

required reactor coolant pressure during steady-state operation, limit the pressure changes 

caused by coolant thermal expansion and contraction during normal load transients, and 

prevents the pressure in the RCS from exceeding the design pressure. The PS consists of the 

pressurizer vessel, replaceable direct immersion heaters, a spray head, and other internal 

components. The surge line attached to the bottom of the pressurizer connects the pressurizer 

to the hot leg of a reactor coolant loop. In LRA Table 2.3.1-1, the applicant identifies the 

components it believes are subject to AMR for the PS by component type and intended function.

2.3.1.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the PS 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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2.3.1.2 Reactor Coolant System

2.3.1.2.1 Summary of Technical Information in the Application

LRA Section 2.3.1.2 describes the RCS. The RCS consists of two identical heat transfer loops 

connected in parallel to the reactor vessel. Each loop contains a reactor coolant pump, a steam 

generator, and a resistance temperature detector manifold. The RCS also includes pressurizer 

safety and relief valves, and a pressurizer relief tank, which provides operational pressure 

control. The pressurizer system is connected to the RCS by a surge line to accommodate 

volume changes of the coolant due to changes in coolant temperature. Borated demineralized 

water is circulated at a flow rate and temperature to achieve the proper reactor core thermal 

hydraulic performance. The RCS provides a boundary for containing the coolant under 

operating temperature and pressure conditions. It also serves to confine radioactive material 

and limit to acceptable values any release of radioactive material. In LRA Table 2.3.1-2, the 

applicant identifies the components it believes are subject to AMR for the RCS by component 

type and intended function.

2.3.1.2.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the RCS 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).

2.3.1.3 Reactor Internals System

2.3.1.3.1 Summary of Technical Information in the Application

LRA Section 2.3.1.3 describes the reactor internals system. The reactor 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 to 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. All reactor internals are removable from the vessel for the purpose of their 

inspection as well as the inspection of the vessel internal surface. In LRA Table 2.3.1-3, the 

applicant identifies the components it believes are subject to AMR for the reactor internals 

system by component type and intended function.

2.3.1.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the reactor internals system mechanical components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 
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the system components subject to an AMR in accordance with the requirements stated in 10 

CFR 54.21(a)(1).

2.3.1.4 Reactor Vessel System

2.3.1.4.1 Summary of Technical Information in the Application

LRA Section 2.3.1.4 describes the reactor vessel system. The reactor vessel is a vertical, 

cylindrical pressure vessel with a hemispherical bottom head and a flanged and gasketed, 

removable, upper closure head. The reactor vessel contains the core, core support structures, 

control rods, and other vessel internals associated with the core. Two metallic O-rings seal the 

reactor vessel when the reactor closure head is bolted in place. Control rod drive mechanisms 

(CRDMs) are positioned on the reactor closure head. The in-core instrumentation subsystem 

consists of stainless steel tubes that extend from the bottom of the reactor vessel down through 

the concrete shield area and up to a thimble seal table. There are two inlet and outlet nozzles 

spaced evenly around the vessel through which reactor coolant flows into and out of the reactor 

vessel. In LRA Table 2.3.1-4, the applicant identifies the components it believes are subject to 

an AMR for the reactor vessel system by component type and intended function.

2.3.1.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the reactor vessel 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).

2.3.1.5 Steam Generator System

2.3.1.5.1 Summary of Technical Information in the Application

LRA Section 2.3.1.5 describes the steam generator (SG) system. The SG system transfers heat 

from the RCS to the secondary systems during normal plant conditions, producing steam for 

use in the turbine generator. The SG system consists of two vertical shell and U-tube steam 

generators and the associated components. The Unit 1 SGs were designed and supplied by 

Framatome-ANP. The Unit 2 SGs were designed and supplied by Westinghouse. The heat 

transfer tubes are Inconel Alloy 690 for Unit 1 and Inconel Alloy 600 for Unit 2. Manways are 

provided to permit access to the U-tubes and moisture separating equipment. The steam-water 

mixture from the tube bundle passes through moisture separator equipment to ensure that highquality steam is produced by the SGs. In LRA Table 2.3.1-5, the applicant identifies the 

components it believes are subject to AMR for the SG system by component type and intended 

function.

2.3.1.5.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 
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appropriately identified the SG 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).

2.3.2 Engineered Safety Features 

LRA Section 2.3.2 identifies the engineered safety features SCs subject to an AMR for license 

renewal.

The applicant described the supporting SCs of the engineered safety features in the following 

LRA sections:

2.3.2.1 Containment Spray System

2.3.2.2 Residual Heat Removal System

2.3.2.3 Safety Injection System

The staff’s findings on review of LRA Sections 2.3.2.1–2.3.2.3 are in SER Sections 2.3.2.1–

2.3.2.3, respectively.

2.3.2.1 Containment Spray System 

2.3.2.1.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.1 describes the containment spray (CS) system. The CS system is a standby

system. It includes the caustic addition subsystem designed to add a caustic solution (sodium 

hydroxide (NaOH)) to the spray water to reduce the probability of stress corrosion cracking of 

stainless steel residual heat (RH) system components during the recirculation phase and to 

enhance the iodine absorption capacity of the containment spray. The CS system contains 

safety-related components relied upon to remain functional during and following DBEs. The 

failure of nonsafety-related SSCs in the CS system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In LRA Table 2.3.2-1, the applicant identifies CS 

system component types it believes are within the scope of license renewal and subject to an 

AMR.

2.3.2.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.1, UFSAR Sections 6.3.1.5, 6.4.1, 6.4.2.1, 6.4.3.2, 

14.9.6.3, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

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 RAIs 2.3.2.1-01 and 2.3.2.1-02, dated December 16, 2008, the staff noted instances where 

boundary drawings identified as not within the scope of license renewal the following 

components: a valve, its attached piping, and end cap, and a piping with end cap. These items 

are attached to piping that is within the scope of license renewal. The staff asked the applicant 
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to provide additional information clarifying why these items are not within the scope of license 

renewal.

In its response, dated January 15, 2009, the applicant stated that the valve, its attached piping, 

and end cap, and the piping with end cap, should be in the scope of license renewal per 

10 CFR 54.4(a)(1).

The staff reviewed the applicant’s responses. The staff finds the applicant’s responses to the 

RAIs 2.3.2.1-01 and 2.3.2.1-02 acceptable because the applicant clarified the status of items 

and added them to the scope of license renewal. Therefore, the staff’s concerns described in 

RAIs 2.3.2.1-01 and 2.3.2.1-02 are resolved.

2.3.2.1.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 containment spray 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 containment spray system mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.2.2 Residual Heat Removal System 

2.3.2.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.2 describes the residual heat removal (RHR) system. The RHR is a standby 

system. It consists of two redundant subsystems, each of which includes one pump and one 

heat exchanger, and associated piping, valves and instrumentation. The RHR system is an 

engineered safety system that serves dual functions. The RHR system 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 system is 

aligned to take suction from the refueling water storage tank (RWST) to provide emergency core 

cooling low head safety injection. It is also used to fill and drain the refueling cavity during plant 

shutdown conditions. In LRA Table 2.3.2-2, the applicant identifies the components it believes 

are subject to AMR for the RHR system by component type and intended function.

2.3.2.2.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the RHR 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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2.3.2.3 Safety Injection System 

2.3.2.3.1 Summary of Technical Information in the Application 

LRA Section 2.3.2.3 describes the safety injection (SI) system. The SI system is an engineered 

safety system used for emergency core cooling to deliver borated cooling water to the reactor 

core in the event of a loss-of-coolant accident. This limits the fuel clad temperature and ensures 

that the core will remain intact and in place with its heat transfer geometry preserved. The SI 

system for each unit consists of two accumulators, a RWST and two safety injection pumps. 

The RWST supplies borated water to the refueling cavity and SI accumulators. It also provides 

borated water to the safety injection pumps, residual heat removal pumps, and the containment 

spray pumps during accident conditions. After the injection phase, coolant spilled from the break 

is cooled and returned to the RCS by the RHR system. During the high head recirculation 

phase, suction to a safety injection pump is provided by the associated heat removal pump. In 

LRA Table 2.3.2-3, the applicant identifies the components it believes are subject to AMR for 

the SI system by component type and intended function.

2.3.2.3.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the SI 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 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:

2.3.3.1 Auxiliary and Radwaste Area Ventilation System

2.3.3.2 Chemical and Volume Control System

2.3.3.3 Component Cooling Water System

2.3.3.4 Containment Hydrogen Control System

2.3.3.5 Control Room and Miscellaneous Area Ventilation System

2.3.3.6 Cooling Water System

2.3.3.7 Diesel Generator and Screenhouse Ventilation System

2.3.3.8 Diesel Generators and Support System

2.3.3.9 Fire Protection System

2.3.3.10 Fuel Oil System

2.3.3.11 Heating System

2.3.3.12 Miscellaneous Gas System

2.3.3.13 Plant Sample System

2.3.3.14 Primary Containment Ventilation System

2.3.3.15 Radiation Monitoring System
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2.3.3.16 Spent Fuel Pool Cooling System

2.3.3.17 Station and Instrument Air System

2.3.3.18 Steam Exclusion System

2.3.3.19 Turbine and Administration Building Ventilation System

2.3.3.20 Waste Disposal System

2.3.3.21 Water Treatment System

The staff’s findings on review of LRA Sections 2.3.3.1–2.3.3.21 are in SER Sections 2.3.3.1–

2.3.3.21, respectively.

Auxiliary Systems Generic Requests for Additional Information. As part of the staff’s review, the 

following RAIs identified instances of boundary drawing errors where the continuation notation 

for piping from one boundary drawing to another boundary drawing could not be identified or 

was incorrect.

In RAI 2.3-01, dated November 19, 2008, 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 December 18, 2008 response, the applicant provided the continuation locations. However, 

for LRA Section 2.3.3.17, the applicant stated that the boundaries extend up to and include 

normally closed isolation valves or installed end devices providing a pressure boundary for the 

system, but did not provide continuations.

The staff requested that an NRC Inspection Team conduct an inspection to verify the applicant’s 

response for selected LRA Section 2.3.3.17 lines. The Inspection Team verified the applicant’s 

response and that all component types within the license renewal boundary are subject to AMR 

for the selected lines. The full description of this inspection is documented in NRC Inspection 

Report 05000282/2009006 and 05000306/2009006 dated March 27, 2009.

For LRA sections 2.3.4.5 and 2.3.4.6, the staff located the drawing continuations from the 

applicant’s response; however, several differences in the license renewal scoping criteria 

between the main drawing and continuation drawings were noted. In a February 26, 2009 letter, 

the applicant satisfactorily responded to these staff followup questions by clarifying which 

license renewal scoping criteria was correct.

Based on its review, the staff finds the applicant’s response to RAI 2.3-01 acceptable because 

the applicant provided the continuation locations and clarified which license renewal scoping 

criteria was correct. An NRC Inspection Team confirmed for those lines where a continuation 

was not provided that all component types within the license renewal boundary are identified 

and subject to an AMR. Therefore, the staff’s concern described in RAI 2.3-01 is resolved.

In RAI 2.3-02, dated November 19, 2008, the staff noted that during the scoping and screening 

review process the continuation from one drawing to another was potentially identified, but not 

definitively established. Accordingly, the staff made certain assumptions regarding continuation 

from one drawing to another. The staff asked the applicant to confirm the staff assumptions.
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In its response, dated December 18, 2008, the applicant provided the correct drawing 

continuation locations.

Based on its review, the staff finds the applicant’s response to RAI 2.3-02 acceptable because 

the applicant provided the correct drawing continuation locations and the staff assumed drawing 

continuations were determined to be correct. Therefore, the staff’s concern described in RAI

2.3-02 is resolved.

In RAI 2.3-03, dated November 19, 2008, the staff noted drawings that show a continuation 

without the submission of the continuation drawing. The staff asked the applicant to provide the 

continuation drawings or a corrected continuation.

In its response, dated December 18, 2008, the applicant provided corrected continuation 

locations. However, for LRA Section 2.3.3.17 the applicant stated that the boundaries extend up 

to and include normally closed isolation valves or installed end devices providing a pressure 

boundary for the system. The applicant, however, did not provide continuations.

The staff requested that an NRC Inspection Team conduct an inspection to verify the applicant’s 

response for selected LRA Section 2.3.3.17 lines. The Inspection Team verified the applicant’s 

response and that all component types within the license renewal boundary are identified and 

subject to an AMR. The full description of this inspection is documented in Inspection Report 

05000282/2009006 and 05000306/2009006, dated March 27, 2009.

Based on its review, the staff finds the applicant’s response to RAI 2.3-03 acceptable because 

the applicant provided the continuation locations. An NRC Inspection Team, confirmed for those 

lines where a continuation was not provided, that all component types within the license renewal 

boundary are identified and subject to an AMR. Therefore, the staff’s concern described in RAI 

2.3-03 is resolved.

2.3.3.1 Auxiliary and Radwaste Area Ventilation System 

2.3.3.1.1 Summary of Technical Information in the Application

LRA Section 2.3.3.1 describes the auxiliary and radwaste area ventilation (ZA) system. The ZA 

system includes several subsystems. The auxiliary building special ventilation (Category 1 

ventilation zone) subsystem is an auxiliary system designed to reliably collect significant 

portions of any potential containment system leakage that might bypass the shield building 

annulus or leakage from systems that could recirculate primary coolant during LOCA mitigation, 

and to cause it to pass through high-efficiency particulate air (HEPA) filters, and charcoal 

adsorbers before reaching the environment. Several other ventilation subsystems are also 

provided to exhaust air through activated charcoal beds and HEPA filters from areas subject to 

possible radioactive contamination. The ZA system also includes the auxiliary building normal 

ventilation, the hot lab/sample room ventilation, filter room ventilation, laundry room exhaust, 

and the radwaste and resin disposal building ventilation subsystems. In LRA Table 2.3.3-1, the 

applicant identifies ZA system component types it believes are within the scope of license 

renewal and subject to an AMR.
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2.3.3.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.1, UFSAR Sections 1.3.9, 9.1.1, 10.3.2, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 RAIs 2.3.3.1-01 and 2.3.3.1-02, dated December 16, 2008, the staff noted instances where 

boundary drawings identified portions of ductwork within the scope of license renewal that are 

connected to branch ductwork that is not shown to be within the scope of license renewal on the 

continuation boundary drawings. The staff requested the applicant to provide additional 

information clarifying why the branch ducts are not within the scope of license renewal.

In its response, dated January 15, 2009, the applicant stated that the ductwork referenced in the 

RAIs was within the scope of license renewal. The applicant also provided clarification that as 

an alternative to specifically identifying a seismic anchor or series of equivalent anchors, a 

bounding approach was used that included enough nonsafety-related ducting to ensure that 

these anchors are included, and thereby ensure the ducting- and anchor-intended functions are 

maintained. The applicant did not submit revised boundary drawings to reflect the ductwork 

being within the scope of licensing renewal.

The staff reviewed the applicant’s response. The staff finds the applicant’s response to these 

RAIs acceptable because the applicant clarified that the ducting in question was within the 

scope of license renewal. Therefore, the staff’s concerns described in RAIs 2.3.3.1-1 and 

2.3.3.1-2 are resolved.

In RAIs 2.3.3.1-03, 2.3.3.1-04, and 2.3.3.1-05, dated December 16, 2008, the staff noted 

sections of ductwork that were shown as out-of-scope, while dampers mounted in the ductwork 

were shown as in-scope of license renewal on the boundary drawings. The staff asked the 

applicant to provide clarification.

In its response, dated January 15, 2009, the applicant stated that while not explicitly shown on 

the drawings, the Category 1 ventilation zone boundary breaks are coincident with wall 

penetrations with the fire damper located within the wall penetration. The boundary drawings 

are correct as shown.

The staff reviewed the applicant’s response. The staff finds the applicant’s response acceptable 

based on the clarification that the Category 1 ventilation zone boundary breaks are at a 

structural penetration and the in-scope damper is located within the penetration. Therefore, the 

staff’s concerns described in RAIs 2.3.3.1-03, 2.3.3.1-04, and 2.3.3.1-05, are resolved.

In RAI 2.3.3.1-06 dated December 16, 2009, the staff noted that dampers located at the inlet to 

Unit 1 and Unit 2 auxiliary building makeup air units were shown as in-scope of license renewal, 

while the makeup air unit housings were not. The staff asked the applicant to provide 

clarification.
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In its response, dated January 15, 2009, the applicant stated drawing LR-39600 incorrectly 

marked the dampers in question. The applicant stated inlet dampers to the makeup air units are 

not within the scope of license renewal, and that for the 11, 12, 21, and 22 auxiliary building 

makeup air units and the duct between the dampers are correctly shown as not within the scope 

of license renewal. 

The staff reviewed the applicant’s response. The staff finds the applicant’s response acceptable 

based on the clarification that the inlet dampers are not within the scope of license renewal. 

Therefore, the staff’s concerns described in RAIs 2.3.3.1-06, is resolved.

In RAI 2.3-1 dated December 16, 2008, the staff asked a generic question: whether any fan 

housings on vaneaxial or propeller-style fans are credited as missile barriers and, if so, whether 

they should be considered in-scope of license renewal.

In its response, dated January 15, 2009, the applicant stated that the plant’s CLB does not 

credit vaneaxial or propeller fan housings as barriers for fan blade missiles.

The staff reviewed the applicant’s response to RAI 2.3-1. The staff finds the applicant’s 

response acceptable based on the clarification that the plant’s CLB does not credit vaneaxial or 

propeller fan housings as barriers for fan blade missiles. Therefore, the staff’s concerns 

described in RAIs 2.3.-1 is resolved.

2.3.3.1.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 auxiliary and radwaste area ventilation 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 and radwaste area ventilation system

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.2 Chemical and Volume Control System 

2.3.3.2.1 Summary of Technical Information in the Application 

LRA Section 2.3.3.2 describes the chemical and volume control (VC) system. The VC system is 

a support system for the RCS during all normal modes of plant operation. It provides boric acid 

injection, chemical additions for corrosion control, reactor coolant cleanup and degasification. It 

also provides reactor coolant makeup, reprocessing of water letdown from the RCS, and reactor 

coolant pump seal water injection. It includes the boron recycle and reactor makeup 

subsystems. The VC system for each unit consists of one volume control tank, three charging 

pumps, letdown and excess letdown heat exchangers, seal water heat exchanger, regenerative 

heat exchanger, letdown orifices, demineralizers, filters, piping, valves, and instrumentation. In 

LRA Table 2.3.3-2, the applicant identifies VC system component types it believes are within the 

scope of license renewal and subject to an AMR.
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2.3.3.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.2, UFSAR Sections 4.4.2.2, 10.1, 10.2.3, and 14.5.4.5, 

and the license renewal boundary drawings using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review identified areas in which 

additional information was necessary to complete the review of the applicant’s scoping and 

screening results. The applicant responded to the staff’s RAIs as discussed below.

In RAI 2.3.3.2-01, dated November 19, 2008, the staff noted drawings LR-XH-1001-5 and LRXH-1-39, location E-5, show three 10 CFR 54.4(a)(1) 3/4-inch drain lines from the seal water 

heat exchangers to valves 2VC-29-1, 2VC-29-2, 2VC-29-3, and VC-29-1, VC-29-2, VC-29-3 inscope for license renewal for 10 CFR 54.4(a)(1). Piping downstream of these valves is within 

the scope for license renewal for 10 CFR 54.4(a)(2). A QA type designation is not provided to 

justify the 10 CFR 54.4(a)(1) and 10 CFR 54.4(a)(2) boundaries. These three drain lines 

combine and continue to LR-39248 (D-8) and (D-5). A seismic anchor or seismic endpoint could 

not be located between the sump tank #121 and valves 2VC-29-1, 2VC-29-2, 2VC-29-3, and 

VC-29-1, VC-29-2, VC-29-3. The staff asked the applicant to confirm that a QA type boundary 

exists downstream of valves 2VC-29-1, 2VC-29-2, 2VC-29-3, and VC-29-1, VC-29-2, VC-29-3 

and to justify not including a seismic anchor downstream of valves 2VC-29-1, 2VC-29-2, 2VC29-3, and VC-29-1, VC-29-2, VC-29-3 and before sump tank #121.

In its response, dated December 18, 2008, the applicant stated a QA type boundary does exist 

at the above noted valve locations and that seismic anchors should be shown on drawing LR39248, locations D-5 and D-8, where the lines are depicted passing through the mezzanine floor 

at elevation 715 feet.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-01 acceptable 

because the applicant clarified that a QA boundary does exist at the noted locations and that 

seismic anchors are at the mezzanine floor. Therefore, the staff’s concern described in RAI 

2.3.3.2-01 is resolved.

In RAI 2.3.3.2-02, dated November 19, 2008, the staff noted drawings LR-XH-1001-5 and LRXH-1-39, location E-6, show 2-2-VC-183 and 2-VC-186 drain lines from the volume control tank 

(VCT) respectively to valves 2VC-11-60, and VC-11-60 in-scope for 10 CFR 54.4(a)(1). Piping 

downstream of these valves is in-scope for 10 CFR 54.4(a)(2). A QA type designation was not 

provided. These drain lines continue to drawing LR-39248, locations E-8 and E-5. A seismic 

anchor or seismic endpoint could not be located between the sump tank #121 and pipe sections 

2-2-VC-183 and 2-VC-186. The staff asked the applicant to confirm that a QA type boundary 

exists downstream of valves 2VC-11-60 and VC-11-60 and to justify not including a seismic 

anchor downstream of pipe sections 2VC-11-60, and VC-11-60 and before sump tank #121.

In its response, dated December 18, 2008, the applicant stated that a quality assurance (QA) 

type boundary does exist at the above noted valve locations and that a seismic anchor should 

be shown on drawing LR-39248, location G-7, upstream of valve WL-51-1, where the drawing 

currently depicts a wall.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-02 acceptable 

because the applicant clarified that a QA boundary does exist at the noted locations and that
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seismic anchors are at a wall penetration. Therefore, the staff’s concern described in RAI 

2.3.3.2-02 is resolved.

In RAI 2.3.3.2-03, dated November 19, 2008, the staff noted drawing LR-XH-1-40, locations 

D-2, D-4, and D-5, show 10 CFR 54.4(a)(1) drain lines from the holdup tanks to valves 2VC-11-

68, (no valve numbers located from tanks 11 and 121). Downstream of these valves is in-scope 

for 10 CFR 54.4(a)(2). A seismic anchor or seismic endpoint could not be located downstream 

of valve 2VC-11-68. The staff asked the applicant why it did not include seismic anchor 

downstream of the holdup tank drain valves 2VC-11-68 and those without valve numbers from 

tanks 11 and 121.

In its response, dated December 18, 2008, the applicant stated a QA type boundary should be 

shown on the downstream side of the drain valves and that a seismic anchor should be shown 

on drawing LR-39248, location G-7, upstream of valve WL-51-1, where the drawing currently 

depicts a wall.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-03 acceptable 

because the applicant clarified that a QA boundary does exist at the noted locations and 

described the location of the seismic anchor. Therefore, the staff’s concern described in RAI 

2.3.3.2-03 is resolved.

In RAI 2.3.3.2-04, dated November 19, 2008, the staff noted that drawing LR-XH-1001-4, 

location E-7, shows pipe section 3⁄4-CS-151R (at Seal 3) from RCP Loop A that is not in-scope 

for license renewal. The staff asked the applicant why it did not include pipe section 3⁄4-CS-151R 

from RCP Loop A in-scope for license renewal.

In its response, dated December 18, 2008, the applicant stated the subject line should have 

been shown as 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 2.3.3.2-04 acceptable 

because the applicant stated line 3⁄4-CS-151R is within the scope of license renewal for 

10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.3.2-04 is resolved.

In RAI 2.3.3.2-05, dated November 19, 2008, the staff noted on drawing LR-XH-1-41 from 

valves VC-11-120 and 2VC-11-120 through the boric acid transfer pumps and tanks and to the 

RWST are within the scope for license renewal for 10 CFR 54.4(a)(2). These lines are safetyrelated as QA Class 1B. The staff asked the applicant why it did not include these components 

in-scope for 10 CFR 54.4(a)(1).

In its response, dated December 18, 2008, the applicant stated the boric acid storage tanks and 

associated components are safety-related based on plant preference. License Amendments 

156/147 dated April 16, 2001, removed the boric acid storage tanks (BASTs) from the Technical 

Specifications for the safety injection system. Therefore the BASTs are not required to 

accomplish the functions described in 10 CFR 54.4(a)(1) and are not within the scope of license 

renewal for 10 CFR 54.4(a)(1).

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.2-05 acceptable 

because the applicant stated the boric acid storage tanks and associated components are 
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designated as safety-related based on plant preference and are no longer required to support a 

safety-related function; thus, they are not within the scope of license renewal for 10 CFR 

54.4(a)(1). The staff confirmed this by reviewing the SER issued with License Amendments 156 

and 147. Therefore, the staff’s concern described in RAI 2.3.3.2-05 is resolved.

2.3.3.2.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 VC 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 VC 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.3 Component Cooling Water System 

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 describes the component cooling (CC) system. The CC system is an 

auxiliary system that is designed to provide heat removal from safeguards equipment 

associated with heat removal from the RCS during and following DBEs and provide heat 

removal from safeguards and nonsafeguards equipment during normal conditions. The CC 

system is an operating system. The CC system for each PINGP unit consists of two heat 

exchangers, two pumps, surge tank and necessary piping, valves, and instrumentation 

designed to provide two interconnected cooling loops. In LRA Table 2.3.3-3, the applicant

identifies CC system component types it believes are within the scope of license renewal and 

subject to an AMR.

2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, UFSAR Section 10.4.2, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.3-01, dated November 19, 2008, the staff noted that restricting orifices located at 

license renewal drawing locations G-2, D-1, E-8, and D-11 on LR-39245-1 and B-8, E-8, B-1, 

and E-1 on drawing LR-39246-1 are in-scope for license renewal criterion 10 CFR 54.4(a)(1). In 

addition to the intended function of maintaining the pressure boundary, restricting orifices can 

also provide the intended function of flow restriction. The applicant was requested to provide 

additional information to explain why LRA Table 2.3.3-3 does not provide the intended function 

of flow restriction for restricting orifices.

In its response, dated December 18, 2008, the applicant stated in addition to a pressure 

boundary function, the restricting orifices have a “throttle” function for flow indication and alarm. 
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However, for these orifices, the “throttle” function is not an intended function and, therefore is 

not included in Table 2.3.3-3.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.3-01 acceptable 

because the applicant clarified that for these restricting orifices, the throttle function (i.e. flow 

indication and alarm) is not an intended function. Therefore, the staff’s concern described in RAI

2.3.3.3-01 is resolved.

In RAI 2.3.3.3-02, dated November 19, 2008, the staff noted that drawing LR-39245-2, location 

C-1, shows a 3-CC-9 pipeline that is in-scope for criterion 10 CFR 54.4(a)(1) that has a 

continuation note stating “From Unit 1 Component Cooling Heat Exchanger See LR-39245-1.” 

Drawing LR-39245-1, location F-7, also shows a 3-CC-9 pipeline that is in-scope for criterion 

10 CFR 54.4(a)(1) that has a continuation note stating “To #11 Seal Water Heat Exchanger See 

LR-39245-2.” The staff asked the applicant to explain why there are two 3-CC-9 pipelines.

In its response, dated December 18, 2008, the applicant stated that the line number 3-CC-9 

shown on Drawing LR-39245-1, location F-7, should be 3-CC-35 and provided the correct 

drawing continuation locations.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.3-02 acceptable 

because the applicant clarified that there is only one 3-CC-9 pipeline and provided the corrected 

pipeline number and drawing continuations. Therefore, the staff’s concern described in RAI

2.3.3.3-02 is resolved.

2.3.3.3.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 that the applicant has 

appropriately identified the CC 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 CC 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.4 Containment Hydrogen Control System 

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 describes the containment hydrogen control (HC) system. The HC system 

is an auxiliary system designed to provide a sampling path from the primary containment to a 

hydrogen analyzer and provide a method to reduce the containment pressure during normal 

conditions. The HC system is a standby system. The HC system contains safety-related 

components relied upon to remain functional during and following DBEs. The failure of 

nonsafety-related SSCs in the HC system potentially could prevent the satisfactory 

accomplishment of a safety-related function. In LRA Table 2.3.3-4, the applicant identifies HC 

system component types it believes are within the scope of license renewal and subject to an 

AMR.
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2.3.3.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.4, UFSAR Section 5.4.2, and the licensing renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.4-01 dated December 16, 2008, the staff noted instances where boundary drawings 

identified control valves as being within the scope of license renewal but the pneumatic tubing of 

the valve positioner connected to the valve was not shown to be within the scope of license 

renewal. The staff asked the applicant to verify that the boundary drawings were correct or to 

provide justification why the positioner’s tubing was not in-scope for license renewal.

In its response, dated January 15, 2009, the applicant stated the instrument air piping 

referenced in the RAIs was within the scope of license renewal. The applicant also provided 

clarification that for drawing clarity, station and instrument air (SA) system boundary breaks 

were generally not shown at the individual components. The applicant stated that the SA piping 

is evaluated in LRA Section 2.3.3.17.

The staff reviewed the applicant’s response to RAI 2.3.3.4-01 and finds it acceptable because 

the applicant stated that the SA piping referenced in the RAI is within the scope of license 

renewal and is evaluated in LRA Section 2.3.3.17.

2.3.3.4.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 HC 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 HC 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.5 Control Room and Miscellaneous Area Ventilation System 

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 describes the control room and miscellaneous area ventilation (ZN) 

system. The ZN system is an auxiliary system designed to provide a reliable means of cooling 

and filtering air supplied to the control room under both normal conditions and during and 

following DBEs, and includes the control room breathing air subsystem. The ZN system also 

includes the safeguards chilled water and the lab and service area air conditioning and chilledwater subsystems designed to remove heat from safeguards and non-safeguards areas, the 

battery room special exhaust ventilation subsystem designed to prevent the buildup of a 

combustible concentration of hydrogen gas in the battery rooms, and the service and computer 

ventilation subsystem designed to provide heat removal from the service building and the 
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computer room. The ZN system and subsystems are operating systems. In LRA Table 2.3.3-5, 

the applicant identifies ZN system component types it believes are within the scope of license 

renewal and subject to an AMR.

2.3.3.5.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.5, UFSAR Sections 2.9.4, 8.5.6, 10.3.3, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 RAIs 2.3.3.5-01 and 2.3.3.5-04 dated December 16, 2008, the staff noted instances where 

boundary drawings identified portions of ductwork as within the scope of license renewal that 

are connected to ductwork that is not shown to be within the scope of license renewal. The staff 

requested the applicant to verify the boundary drawings were correct or to provide justification 

why the duct sections were not in-scope for license renewal.

In its response, dated January 15, 2009, the applicant stated the ductwork referenced in the 

RAIs was within the scope of license renewal. The applicant also provided clarification that as 

an alternative to specifically identifying a seismic anchor or series of equivalent anchors, a 

bounding approach was used that included enough nonsafety-related ducting to ensure these 

anchors are included and thereby ensure the ducting and anchor intended functions are 

maintained. 

In RAI 2.3.3.5-02 dated December 16, 2008, the staff noted that in LR Drawing LR39603-1, the 

applicant marked a fire damper as not within the scope of license renewal, but marked the 

ductwork on either side of it as in scope. The staff asked the applicant to explain why it did not 

consider the fire damper to be in scope for license renewal. 

In its response, dated January 15, 2009, the applicant stated that the damper was incorrect and 

that the fire damper was is in-scope of license renewal.

The staff reviewed the applicant’s responses for RAIs 2.3.3.5-01, 2.3.3.5-02, and 2.3.3.5-04. 

The staff finds the applicant’s response acceptable based on the clarification that the ductwork 

and damper in question are in-scope for license renewal. Therefore, the staff’s concerns 

described in RAIs 2.3.3.5-01, 2.3.3.5-02, and 2.3.3.5-04 have been addressed.

In RAI 2.3.3.5-03 dated December 16, 2008, the staff asked the applicant to clarify whether the 

control room ventilation equipment is within the same protected ventilation zone as the control 

room and, specifically, whether there are any condensate drains on the air handling units that 

would be considered to be in scope as barriers to prevent the units from drawing in 

contaminated air.

In its response, dated January 15, 2009, the applicant identified the continuation drawings for 

the condensate drawings. The applicant indicated that the drawings incorrectly classified the 

condensate drains as in-scope under 10 CFR 54.4(a)(1) and that they are actually in-scope 

under 10 CFR54.4 (a)(2).
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The staff reviewed the applicant’s response. The applicant considered the equipment drains and 

any water traps (if installed) in the drain as a potential source of unfiltered in-leakage into the 

control room envelope. The applicant also considered the spatial interactions between the airhandling units and the floor due to the equipment drains. The applicant’s response is 

acceptable.

In RAIs 2.3.3.5-05, 2.3.3.5-06, and 2.3.3.5-07 dated December 16, 2008, the staff noted that fan 

housings were classified as out-of-scope, but that adjacent ductwork and cooling coils were 

classified as in scope under 10 CFR 54.4(a)(2). The staff asked the applicant to confirm that the 

fan housing were not in-scope and to justify that determination.

In its response, dated January 15, 2009, the applicant stated the fan housings are correctly 

identified as not in-scope of license renewal. The applicant explained that the adjacent ductwork 

and cooling coils are in-scope for license renewal to ensure that the structural support and 

integrity of the safety-related steam exclusions dampers is maintained.

The staff reviewed the applicant’s response for RAIs 2.3.3.5-05, 2.3.3.5-06, and 2.3.3.5-07 and 

finds it acceptable. Because the adjacent ductwork and cooling coils are not in-scope as 

pressure boundaries, the staff's concern that the fan housing may be in scope as pressure 

boundaries has been resolved.

2.3.3.5.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 that the applicant has 

appropriately identified the ZN system mechanical components as being within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

the ZN system mechanical components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.3.6 Cooling Water System

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 describes the cooling water (CL) system. The CL system is an auxiliary 

system that is designed to provide a water supply to the auxiliary feedwater pumps for RCS 

heat removal and provides a water supply for safeguards and non-safeguards equipment heat 

loads during normal conditions and during and following DBEs. The CL system also provides a 

normal or backup source of water to various plant equipment, including the fire protection 

headers. The CL system includes the filtered water, hypobromus acid feed, equipment heat 

removal, and the containment and auxiliary building cooling subsystems. The CL system is an 

operating system. The CL system consists of five pumps feeding a ring header that distributes 

cooling water throughout the plant and includes filters, heat exchangers, chillers, cooling coils 

and the necessary piping, valves and instrumentation. In LRA Table 2.3.3-6, the applicant

identifies CL system component types it believes are within the scope of license renewal and 

subject to an AMR.
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2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6, UFSAR Sections 1.3.9, 6.2.2.1.3, 10.1, 10.3.1.2.1, and 

10.4.1, and the license renewal boundary drawings using the evaluation methodology described 

in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 November 19, 2008, the staff noted that license renewal drawing LR86172-4, locations B-4 and B-8, show the inlet and outlet piping to the CRDM heat exchangers 

within the scope of license removal per 10 CFR 54.4(a)(2); however, CRDM cooling coil 

assemblies 117-141 and 217-141 are shown as not within the scope of license renewal. The 

staff asked the applicant to explain why the CRDM cooling coil assemblies are not within the 

scope of license renewal per 10 CFR 54.4(a).

In its response, dated December 18, 2008, the applicant stated that the CRDM cooling coil 

assemblies are within the scope of license renewal. The un-highlighted box containing the 

assembly description should be highlighted as 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 2.3.3.6-01 acceptable 

because the applicant clarified that the un-highlighted box containing the assembly description 

should be highlighted as within the scope of license renewal per 10 CFR 54.4(a)(2). Therefore, 

the staff’s concern described in RAI 2.3.3.6-01 is resolved.

In RAI 2.3.3.6-02, dated November 19, 2008, the staff noted license renewal drawing

LR-86172-4, location D-3, shows #13 Fan Coil Unit (FCU) for Unit 1 within the scope of license 

renewal per 10 CFR 54.4(a)(1). LR-86172-4, location D-2, shows FCU (#14) as not within the 

scope of license renewal. The staff asked the applicant to explain why #14 FCU is not within the 

scope of license renewal per 10 CFR 54.4(a).

In its response, dated December 18, 2008, the applicant stated the highlighting of #14 FCU is 

incorrect and should be highlighted as within the scope of license renewal per 

10 CFR 54.4(a)(1). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.6-02 acceptable 

because the applicant clarified the #14 FCU is within the scope of license renewal per 10 CFR 

54.4(a)(1). Therefore, the staff’s concern described in RAI 2.3.3.6-02 is resolved.

In RAI 2.3.3.6-03, dated November 19, 2008, the staff noted drawings LR-39216-2, location 

D-2, and LR-39217-1, location C11, show portions of 30-inch standpipes as within the scope of 

license renewal per 10 CFR 54.4(a)(2) and portions within the scope of license renewal per

10 CFR 54.4(a)(3). The transition from 10 CFR 54.4(a)(2) to 10 CFR 54.4(a)(3) criteria occurs in 

the middle of the pipe. The staff asked the applicant to clarify the criteria for being within the 

scope of license renewal for these standpipes or explain why portions of this piping have 

different criteria.
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In its response, dated December 18, 2008, the applicant stated that the highlighting of the 30-

inch standpipes is incorrect. The standpipe 10 CFR 54.4(a)(3) scoping boundary should extend 

to the downstream flange of valves CL-34-1 and 2CL-34-1. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.6-03 acceptable 

because the applicant clarified that the standpipes 10 CFR 54.4(a)(3) license renewal boundary 

extends to the downstream flange of valves CL-34-1 and 2CL-34-1. Therefore, the staff’s 

concern described in RAI 2.3.3.6-03 is resolved.

In RAI 2.3.3.6-04, dated November 19, 2008, the staff noted drawing LR-39223, location A-7, 

shows pipe section 2-CL-112 (after valve AF-25-6) as in-scope for license renewal per 10 CFR 

54.4(a)(3) or 10 CFR 54.4(a)(1). However, portions of the same pipe section (2-CL-112) before 

valve AF-25-6 and after the grid location A-5 are included in-scope for license renewal per 

10 CFR 54.4(a)(2). The staff noted similar line 2-CL-111 on LR-39222 is in-scope for 10 CFR 

54.4(a)(2). The staff asked the applicant to provide additional information explaining why the 

different criterion was used for this pipe section (2-CL-112).

In its response, dated December 18, 2008, the applicant stated on drawing LR-39223, location 

A-7, line 2-CL-112 between valve 2AF-25-6 and grid location A-5 is incorrectly highlighted and 

should be highlighted as 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 2.3.3.6-04 acceptable 

because the applicant stated that pipe section 2-CL-112 is in-scope per 10 CFR 54.4(a)(2). 

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, UFSAR, RAI responses, and boundary 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 CL 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 CL 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.7 Diesel Generator and Screenhouse Ventilation System 

2.3.3.7.1 Summary of Technical Information in the Application

LRA Section 2.3.3.7 describes the diesel generator and screenhouse ventilation (ZG) system. 

The D1/D2 diesel generator room ventilation, D5/D6 building HVAC and the screenhouse 

ventilation subsystems are designed to limit ambient temperature within equipment ratings when 

the associated diesel generators are operating. Portions of these subsystems provide fresh air 

and remove exhaust air to provide a suitable working environment, prevent the buildup of 

flammable atmosphere in certain rooms, and maintain temperatures required by machinery 

during normal plant operation. In LRA Table 2.3.3-7, the applicant identifies ZG system 

component types it believes are within the scope of license renewal and subject to an AMR.
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2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7, UFSAR Sections 8.4.1, 8.4.2, 10.3.12, and the license 

renewal boundary drawings using the evaluation methodology described in SER Section 2.3 

and the guidance in SRP-LR Section 2.3. The staff’s review 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 RAI as discussed below.

In RAI 2.3.3.7-01 dated December 16, 2008, the staff noted an instance where the description in 

LRA Section 2.3.3.7 seemed to differ from what was indicated as in-scope on the boundary 

drawings. The staff requested clarification why the exhaust fan housings were not shown as inscope for license renewal.

In its response, dated January 15, 2009, the applicant stated that only the diesel generator 

(room) exhaust fans are in-scope. The diesel outside exhaust fans are not relied upon during 

DBEs and do not perform a function necessary to the satisfactory accomplishment of a safetyrelated intended function.

The staff reviewed the applicant’s response to RAI 2.3.3.7-01. The staff finds the applicant’s 

response satisfactory because the applicant clarified that only the diesel generator (room) 

exhaust fans are in-scope because the diesel outside exhaust fans are not relied upon during 

DBEs and do not perform a safety-related intended function. Therefore, the staff’s concern 

described in RAI 2.3.3.2-03 is resolved.

2.3.3.7.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 ZG 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 ZG 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.8 Diesel Generators and Support System 

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 describes the diesel generator and support (DG) System. The DG System 

is an auxiliary system that is designed to provide backup power to safety-related, nonsafetyrelated and security equipment. In addition, the system includes diesel motors that provide the 

motive force for the cooling water pumps. The DG system includes the safety-related diesel 

generators, nonsafety-related diesel generators, guardhouse diesel generator and cooling water 

diesel driven pumps. The DG system is a standby system. The safety-related diesel generators 

for each PINGP Unit consist of two diesel generators, including starting air, lube oil, combustion 

air, exhaust air, engine cooling and fuel oil subsystems, and the necessary piping, valves and 
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instrumentation. In LRA Table 2.3.3-8, the applicant identifies DG system component types it 

believes are within the scope of license renewal and subject to an AMR.

2.3.3.8.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.8; UFSAR Sections 8.4.1, 8.4.2, 8.4.5, 10,4.1.2, and 

Tables 8.4-3, and 8.4-4 and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s 

review 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 2.3.3.8-01, dated November 19, 2008, the staff noted that drawings LR-11824, 

LR-118243, LR-118244, and LR-118245, locations C-4 and C-9, show diesel engine radiators 

that are in-scope of license renewal based on 10 CFR 54.4(a)(1). The radiators are not shown 

in LRA Table 2.3.3-8 as components subject to an AMR. The staff asked the applicant to 

provide additional information explaining why these radiators are not included in LRA Table 

2.3.3-8 as a component type subject to an AMR.

In its response, dated December 18, 2008, the applicant stated: “The D5 and D6 diesel engine 

radiators are evaluated as heat exchanger components and heat exchanger tubes and are 

included in LRA Table 2.3.3-8.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-01 acceptable 

because the applicant clarified that the radiators are evaluated as heat exchanger components 

and heat exchanger tubes and are included in LRA Table 2.3.3-8. Therefore, the staff’s concern 

described in RAI 2.3.3.8-01 is resolved.

In RAI 2.3.3.8-02, dated November 19, 2008, the staff noted that drawings LR-118248 and 

LR-118249, location B-6, show diesel fuel oil day tanks, which have flame arrestors that provide 

a pressure boundary that are in-scope for license renewal based on criterion 10 CFR 54.4(a)(1). 

The flame arrestors (flame arrestor housing for pressure boundary and flame arrestor element 

for flame arresting) are not shown in LRA Table 2.3.3-8 as components subject to an AMR. The 

staff asked the applicant to provide additional information explaining why the flame arrestor 

housing and element are not included in LRA Table 2.3.3-8 as component types subject to an 

AMR.

In its response, dated December 18, 2008, the applicant stated at the point that the 2-inch vent 

and flame arrestor connects to the fuel oil day tank, a license renewal system boundary break 

between the fuel oil system and diesel generator and support system should be shown. The 

applicant also stated that the flame arrestors are evaluated as part of the fuel oil system, 

LRA Section 2.3.3.10, and are included in Table 2.3.3-10. It was also noted that these 

components should include the intended function of “Fire Barrier.” The applicant submitted 

changes to LRA Table 3.3.2-10 to include the flame arrestor’s internal surfaces, which had been 

omitted. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-02 acceptable 

because the applicant clarified that the flame arrestors are evaluated in LRA Section 2.3.3.10, 
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Fuel Oil System, and are included as flame arrestors in Table 2.3.3-10. Changes concerning the 

flame arrestors were made in LRA Tables 2.3.3-10 and 3.3.2-10 and LRA Section 3.3.2.1.10. 

Therefore, the staff’s concern described in RAI 2.3.3.8-02 is resolved.

In RAI 2.3.3.8-03, dated November 19, 2008, the staff noted that drawings LR-118250 and 

LR-118251, locations D-3, and D-9, show diesel starting air pipelines with oiler components

in-scope for license renewal based on 10 CFR 54.4(a)(1). The oilers are not shown in LRA 

Table 2.3.3-8 as components subject to an AMR. The staff asked the applicant to provide 

additional information explaining why the oilers are not included in LRA Table 2.3.3-8 as a 

component type subject to an AMR.

In its response, dated December 18, 2008, the applicant stated the oilers are inline piping 

components, are evaluated as piping/fittings, and are included in Table 2.3.3-8.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-03 acceptable 

because the applicant clarified that the oiler components are included in LRA Table 2.3.3-8 and 

evaluated as piping/fittings. Therefore, the staff’s concern described in RAI 2.3.3.8-03 is 

resolved.

In RAI 2.3.3.8-04, dated November 19, 2008, the staff noted that drawing LR-39255-1, (location 

D-9) shows a 2-inch vent at the top of the D-1 and D-2 fuel oil day tanks, that are in-scope for 

criterion 10 CFR 54.4(a)(1). The 2-inch vents at the top of the D-1 and D-2 fuel oil day tanks do 

not have a symbol for a vent. The symbol provided is a box, which could be a flame arrestor. 

The D-5 and D-6 fuel oil day tanks shown on drawings LR-118248 and LR-118249, respectively, 

(location B-6) are also shown in-scope for 10 CFR 54.4(a)(1) and appear to have the symbol 

and description for a 2-inch vent and flame arrestor. The staff asked the applicant to provide 

additional information that clarifies whether the symbols at the top of the D-1 and D-2 fuel oil 

day tanks are a 2-inch vent and flame arrestor.

In its response, dated December 18, 2008, the applicant stated the box symbol represents a 

T-style outlet vent with material and function similar to the other fuel oil tank vent and flash 

arrestor assemblies, which are evaluated as flash arrestors, and are included in Table 2.3.3-10.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.8-04 acceptable 

because the applicant clarified that the symbols represent flash arrestors which are evaluated in 

LRA Table 2.3.3-10. Therefore, the staff’s concern described in RAI 2.3.3.8-04 is resolved.

2.3.3.8.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 DG 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 DG 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).
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2.3.3.9 Fire Protection System 

2.3.3.9.1 Summary of Technical Information in the Application

LRA Section 2.3.3.9 describes the fire protection (FP) system. The FP system is an auxiliary 

system designed to provide reasonable assurance, through defense-in-depth, that a fire will not 

prevent the performance of necessary safe shutdown functions and that radioactive releases to 

the environment in the event of a fire will be minimized. The FP system utilizes water spray, 

cardox, halon, hose stations and sprinklers to combat fire. Portable extinguishers are also 

provided extensively throughout the plant. The FP System includes the reactor coolant pump 

RCP lube oil collection, fire water, halon, carbon dioxide and fire detection subsystems. The fire 

water subsystem consists of two dedicated fire pumps, one motor-driven and one diesel-driven, 

filters and the necessary piping, valves and instrumentation. In LRA Table 2.3.3-9, the

applicant identifies FP system component types it believes are within the scope of license 

renewal and subject to an AMR.

2.3.3.9.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.9, UFSAR section 10.3.1, 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 UFSAR 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 PINGP, Units 1 and 2, fire protection CLB documents listed in the 

PINGP, Units 1 and 2, Operating License Condition 2.C.4

The staff also reviewed PINGP, Units 1 and 2, commitments to 10 CFR 50.48, “Fire protection” 

(i.e., approved fire protection program), responses to Appendix A to the Branch Technical 

Position (BTP), Auxiliary and Power Conversion Systems Branch (APCSB), 9.5-1, ”Guidelines 

for Fire Protection for Nuclear Power Plants,” May 1, 1976, documented in the PINGP, Units 1 

and 2, September 6, 1979, SER.

During its review of LRA Section 2.3.3.9, 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 2.3.3.9-1, dated November 19, 2008, the staff stated that Section 4.3.1.5 of the PINGP, 

Units 1 and 2, SER, dated September 6, 1979, discusses various types of wet-pipe automatic 

sprinkler, deluge, and pre-action dry-pipe sprinkler subsystems provided in the plant areas for 

fire suppression activities. The sprinkler subsystems in various areas are as follows:
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Wet Pipe Automatic Sprinkler Subsystems Area/Component

  Turbine Building–Turbine Lube Oil and Control Oil Piping 

Areas

  Air Compressor and Auxiliary Feedwater Pump Rooms

  Exit Stairwells

  Records Storage Area

  Decontamination Area

  Water Treatment Area

  Warehouse

  Hot Lab Area

Deluge Subsystems Area/Component

  Main Auxiliary and Startup Transformers

  Turbine Seal Oil Unit

  Turbine Lube Oil Reservoir

  Oil Storage Room

  Charcoal Filter–Auxiliary Building Special Exhaust Filter and 

the Shield Building Exhaust Filters

Pre-Action Sprinkler Subsystems Area/Component

  Turbine Generators Bearings

  Containment Cable Penetration Areas

  Screen House Pump Area (Both Levels) Including the Diesel 

Cooling Water Pumps and the Diesel Driven Fire Pump

The staff requested that the applicant verify whether the above suppression systems installed in 

various areas of the plant are in the scope of license renewal in accordance with 10 CFR 

54.4(a) and subject to an AMR in accordance with 10 CFR 54.21(a)(1). If they are excluded 

from the scope of license renewal and not subject to an AMR, the staff requested that the 

applicant provide justification for the exclusion.

In its response, dated December 11, 2008, the applicant stated that the wet-pipe automatic 

sprinkler, deluge, and pre-action sprinkler subsystems installed in various areas of the plant for 

fire suppression are in the scope of license renewal in accordance with 10 CFR 54.4(a) and are 

subject to an AMR in accordance with 10 CFR 54.21(a)(1). The applicant provided the following 

responses: 
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Wet Pipe Automatic Sprinkler Systems

The Air Compressor and Auxiliary Feedwater Pump Rooms Sprinkler subsystem is shown on 

Drawing LR-39228-2, location D-3, Air Compressor and Auxiliary Feedwater Pump Area 

Sprinkler System WPS-10.

. The Turbine Building–Turbine Lube Oil and Control Oil 

Piping Areas Sprinkler subsystems are shown on Drawings LR-39228-2 and 3. See Drawing 

LR-39228-2, location D-7, Turbine Oil Sprinkler System WPS-18. See Drawing LR-39228-3, 

location G-4, Turbine Oil Pipe Wet Pipe System WPS-21.

Exit stairwells used for egress or to allow access to manual fire suppression are provided with 

sprinkler systems throughout the plant. Exit stairwell sprinkler systems are shown on Drawings 

LR-100282 and LR-39228-2, 3, 4 and 5. See Drawing LR-100282, location D-4, Stairs Wet Pipe 

Sprinkler System. See Drawing LR-39228-2, location E-5, Stairway Sprinkler System SWP-3 

(incorrectly labeled WPS-18), location B-9, Stairway Sprinkler System SWP-5, and location G-9, 

Stairway Wet Pipe System SWP-6. See Drawing LR-39228-3, location E-2, Stairway Sprinkler 

System SWP-14 and location H-6, Stairway Sprinkler System SWP-13. See Drawing LR-39228-

4, location B-4, Stairway Sprinkler System SWP-12, location B-10, Stairway Sprinkler System 

SWP-4, location F-5, Stairway Sprinkler System SWP-1 and location C-6, Stairway Sprinkler 

System SWP-2. See Drawing LR-39228-5, location A-5, Stairwell sprinklers.

The Records Storage Area Sprinkler subsystem is shown on Drawing LR-39228-4, location G-8, 

Record Room System WPS-23.

The Decontamination Area at Access Control is protected by a wet pipe sprinkler subsystem 

shown on Drawing LR-39228-4, location A-8, Laundry Room, Toilet Room, Clothes Storage 

Room and Corridor Sprinkler Systems WPS-20.

The Water Treatment Area Sprinkler subsystem is shown on Drawing LR-39228-2, location E-9, 

Turbine Room (East Side) Sprinkler System WPS-9.

The Warehouse Sprinkler subsystems are shown on Drawing LR-39228-3. See location B-3, 

Warehouse Sprinkler and Hose Stations, and location F-9, Warehouse #2 Sprinkler System 

DE-3.

The Hot Lab Area Sprinkler subsystem is shown on Drawing LR-39228-4, location C-6, WPS-19 

Hot Chemical Laboratory.

Deluge Systems. The Main, Auxiliary, and Startup Transformers Deluge 

subsystems are shown on Drawings LR-39228-2 and LR-39228-3. See Drawing 

LR-39228-2, location B-6, B-7 and B-8, Transformer Sprinkler Systems DM-3, 

DM-2 and DM-1, respectively. See Drawing LR-39228-3, location D-2, D-4 and 

D-5, Transformer Sprinkler System DM-5, DM-4 and DM-6, respectively.

The Turbine Seal Oil Unit Deluge subsystems are shown on Drawings LR-39228-

2 and LR-39228-3. See Drawing LR-39228-2, location D-9, Hydrogen Seal Oil 

Unit Sprinkler System DA-1. See Drawing LR-39228-3, location G-2, Hydrogen 

Seal Oil Sprinkler System DA-5.
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The Turbine Lube Oil Reservoir Deluge subsystems are shown on Drawings LR39228-2 and LR-39228-3. See Drawing LR-39228-2, location D-4, Turbine Oil 

Reservoir Area Sprinkler System DA-3. See Drawing LR-39228-3, location G-6, 

Turbine Oil Reservoir Sprinkler System DA-4.

The Oil Storage Room Deluge subsystem is shown on Drawing LR-39228-2, location B-3, 

Turbine Oil Storage Room Sprinkler System DA-2.

The Charcoal Filter – Auxiliary Building Special Exhaust Filter and the Shield Building Exhaust 

Filters Deluge subsystems are shown on Drawing LR-39603-4, location C-4 through E-4 and 

location E-11 through G-11.

Pre-Action Sprinkler Systems

The Containment Cable Penetration Area Pre-Action Sprinkler subsystems are shown on 

Drawing LR-39228-4, location C-3, D-5, D-8 and C-10, Electrical Penetration Pre-Action System 

PAD-7, PAD-6, PAD-3 and PAD-4 respectively.

. The Turbine Generator Bearing Pre-Action subsystems are 

shown on Drawings LR-39228-2 and LR-39228-3. See Drawing LR-39228-2, location B-10, 

Turbine Bearing Fire Protection Pre-action System PA-14. See Drawing LR-39228-3, location B11, Turbine Bearing Fire Protection Pre-action System PA-15.

The Screen House Pump Area (Both Levels) including the Diesel Cooling Water Pumps and the 

Diesel Driven Fire Pump Pre-Action Sprinkler subsystem is shown on Drawing LR-39228-3, 

location B-8, Screenhouse Sprinkler System PAD-9.

The scoping boundaries extend up to and include the installed end devices such as sprinkler 

heads and spray nozzles. The interconnected piping/fittings, valves, sprinkler heads, spray 

nozzles, and in-line components are within the scope of license renewal and subject to AMR. 

Piping/fittings, valves, sprinkler heads, spray nozzles and other in-line components are included 

in LRA Table 2.3.3-9, and AMR aging management evaluations are included in Table 3.3.2-9.

Based on the review, the staff finds the applicant’s response to RAI 2.3.3.9-1 acceptable 

because wet-pipe automatic sprinkler, deluge, and pre-action sprinkler subsystems in question 

were identified to be within the scope of license renewal and subject to an AMR.

The staff has confirmed that the applicant correctly identified Wet Pipe Automatic Sprinkler 

Systems in Turbine Lube-Oil and Control-Oil Piping Areas, Air Compressor and Auxiliary 

Feedwater Pump Rooms, Exit Stairwells, Records Storage Area, Decontamination Area, Water 

Treatment Area, Warehouse, and Hot Lab Area; Deluge Systems in Main Auxiliary and Startup 

Transformers, Turbine Seal Oil Unit, Turbine Lube Oil Reservoir, Oil Storage Room, and 

Charcoal Filter–Auxiliary Building Special Exhaust Filter and the Shield Building Exhaust Filters; 

and Pre-Action Sprinkler Systems in Turbine Generators Bearings, Containment Cable 

Penetration Areas, and Screen House Pump Area (Both Levels), including the Diesel Cooling 

Water Pumps and the Diesel Driven Fire Pump. The staff concludes that above water-based fire 

suppression subsystems and their associated components are correctly included in the scope of 

license renewal and subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.9-

1 is resolved.
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In RAI 2.3.3.9-2, dated November 19, 2008, the staff stated that LRA Tables 2.3.3-9 and 3.3.2-9 

exclude several types of fire protection components that appear on the LRA drawings as within 

the scope of license renewal or discussed in PINGP CLB documents. These components are 

listed below:

• hose connections

• interior fire hose stations

• pipe supports

• couplings

• dikes for oil spill confinement

• floor drains and curbs for fire-fighting water

• backflow prevention devices

• trash grids and traveling screens

• flame retardant coating for cables

• fire retardant intumescent coating for polyurethane foam insulation 

• turbine building smoke removal system components

• air compressors for safe-shutdown operations

The staff asked the applicant to verify whether the components listed above are within scope of 

the license renewal in accordance with 10 CFR 54.4(a) and are subject to an AMR in 

accordance with 10 CFR 54.21(a)(1). If they are excluded from the scope of license renewal 

and not subject to an AMR, the staff requested that the applicant provide justification for the 

exclusion.

In its response, dated December 11, 2008, the applicant stated the following:

Fire protection hose connections are within the scope of license renewal. Hose 

connections from the plant fire header, hydrants and valves are evaluated as 

piping/fittings and are included in LRA Table 2.3.3-9 and Table 3.3.2-9. Fire 

hoses, including integral hose connections, are evaluated in LRA Section 

2.1.3.2.2. Fire hoses are inspected and tested periodically and must be replaced 

if they do not pass the test or inspection; these components are short lived and 

are not subject to Aging Management Review.

Interior fire hose stations are within the scope of license renewal. Interior fire 

hose stations components are evaluated as Piping/Fittings and Valves and are 

included in LRA Table 2.3.3-9 and Table 3.3.2-9.

Pipe supports for fire protection piping are within the scope of license renewal. 

See LRA Section 2.4.2 and Table 2.4.2-1 for supports, and Section 2.3.3.9 and 

Table 2.3.3-9 for fire protection piping. For additional detail and for aging 

management of fire protection pipe supports, see Table 3.5.2-2 for the 

component type, “Support (...non-ASME piping...).” 

Fire header couplings are within the scope of license renewal. Fire header couplings are 

evaluated as piping/fittings and are included in LRA Table 2.3.3-9 and Table 3.3.2-9.
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Dikes for oil spill confinement are addressed by the component types, “Concrete (curbs, walls, 

slabs)” and “Steel components (angles used to contain fuel oil leaks).” These component types, 

as used in the PINGP LRA, include structures that provide intended functions to direct flow 

and/or provide a fire barrier to prevent the spread of flammable liquids. These components are 

in-scope of license renewal and protect safety-related structures and safe shutdown systems 

from fire damage. Concrete floor depressions, part of the concrete slab design, are also used to 

direct the flow of flammable liquids. These components are located throughout safety-related 

structures and can be found in LRA Tables 2.4.1-1, 2.4.4-1, 2.4.5-1, and 2.4.9-1. For aging 

management of these concrete and steel components, see LRA Tables 3.5.2-1, 3.5.2-4, 3.5.2-5, 

and 3.5.2-9. 

There is a reinforced concrete wall surrounding the fuel oil receiving tank located outside, 

adjacent to the south wall of the D5/D6 Diesel Generator Building. However the wall is not inscope of license renewal. Since the tank performs a support function and not a confinement 

function, it is not in-scope of license renewal. 

Floor drains for fire fighting water are within the scope of license renewal and are evaluated in 

the Waste Disposal (WD) System. In general, floor drains are highlighted as within the scope of 

license renewal per 10 CFR 54.4(a)(2) due to flooding and/or spatial interaction intended 

functions. Where they may also have an 10 CFR 54.4(a)(3) function, this was not differentiated 

(for example, see Drawing LR-39248). The Turbine Oil Reservoir and Oil Storage Room drains 

are specifically discussed in Section 4.5 of the Safety Evaluation Report dated September 9, 

1979. These drains are depicted on Drawings LR-39231-1, locations G-3 and H-8, and LR39231-2, location H-4; and should be highlighted as within the scope of license renewal per 10 

CFR 54.4(a)(3). Floor drains are evaluated as Piping/Fittings and are included in LRA Table 

2.3.3-20 and Table 3.3.2-20. The following changes are required to the LRA: 

In LRA Section 2.3.3.20 under System Function Listing, the following function is added:

Comment: This system contains floor drains for fire fighting water and oil 

confinement, such as the Turbine Oil Reservoir and Oil Storage Room drains, 

that support a fire protection function.

In LRA Section 2.3.3.20 on Page 2.3-109, second paragraph, second sentence, “plant floor 

drains,” is added to the list of drains that comprise the Waste Liquid sub-system.

In LRA Section 2.3.3.20, Page 2.3-110, the third sentence of the fifth paragraph is revised to 

read as follows: “Portions of the WD System support Fire Protection or Station Blackout event 

requirements based on the criteria of 10 CFR 54.4(a)(3).” 

Code WD-FP

Contains SCs relied upon in safety 

analysis or plant evaluations to perform 

a function that demonstrates 

compliance with 10 CFR 50.48, Fire 

Protection.

Cri 1 Cri 2 Cri 3

FP EQ PTS AT SB

X
2-68

Curbs for fire fighting water are addressed by the component types, “Concrete (... walls, slabs 

and curbs...),” “Stainless steel components (... curbs and flow deflectors...),” and “Steel 

components (...curbs...).” These component types as used in the PINGP LRA include structures 

that provide an intended function to direct flow away from safety-related equipment in order to 

prevent water damage. These components are in-scope of license renewal, and are located 

throughout safety-related structures. They are included in LRA Tables 2.4.1-1, 2.4.4-1, 2.4.7-1, 

and 2.4.9-1. For aging management of these concrete, stainless steel, and steel components, 

see LRA Tables 3.5.2-1, 3.5.2-4, 3.5.2-7, and 3.5.2-9.

The PINGP Fire Protection (FP) System is supplied from the Mississippi River and does not 

include connections from potable water sources. Therefore, the PINGP FP system does not 

contain backflow prevention devices; as a result they are not included in LRA Table 2.3.3-9 and 

Table 3.3.2-9. The FP system does include check valves; these are included in LRA Table 

2.3.3-9 and Table 3.3.2-9.

Trash grids and traveling screens are addressed in LRA Section 2.3.4.3, Circulating Water (CW) 

System. The FP pumps draw water from behind the plant screenhouse trash grids and screens. 

During emergency operation, when the circulating water pumps are not in-service, the flows 

through the trash grids and screens would be insignificant and plugging or failure of the grids 

and screens is not credible. Therefore, trash grids and traveling screens are not relied upon to 

perform or support a License Renewal Fire Protection-related Intended Function.

Flame retardant coatings for cables used in penetration seals and used for cable encapsulation 

are in-scope of license renewal. They are included in LRA Table 2.4.5-1. For additional detail 

and for aging management of flame retardant coating for cables, see LRA Table 3.5.2-5 for the 

component types, “Fire barrier penetration seals” and “Fireproofing” for cable and cable tray. 

Fire retardant intumescent coatings were originally used on all polyurethane foam piping 

insulation in areas containing safety-related equipment. However, the intumescent coating 

performed unsatisfactorily and was replaced with materials identified as Armaflex (primer) and 

Flammastic (mastic sealant), which have better flame spread and smoke-density test results 

when compared to the intumescent coating. This was conveyed in a letter to the NRC dated 

May 4, 1992. The NRC approved the replacement materials in a letter dated January 14, 1993. 

These components are in-scope of license renewal, and are identified in Table 2.4.5-1 of the 

LRA as, “Fire barrier penetration seals” and “Fireproofing” components. LRA Table 3.5.2-5 

provides additional information on these component types and materials.

Turbine building roof exhaust fans, as well as smoke hatches that are fitted with automatic 

releases, are within the scope of license renewal. The turbine building roof exhaust fans are 

evaluated in LRA Section 2.3.3.19, Turbine and Administration Building (ZB) System (see 

Function ZB-FP) and are shown on Drawing LR-39601, location F-2, Turbine Building Roof Vent 

Fans. The fan and damper are integral to the fan housing and are evaluated as Fan Housings. 

They are included in LRA Table 2.3.3-19 and Table 3.3.2-19. The turbine building smoke 

hatches are evaluated in LRA Table 3.5.2-5.

Air compressors required for fire protection safe-shutdown operation are within the scope of 

license renewal. The station and instrument air compressors are evaluated in LRA Section 

2.3.3.17, Station and Instrument Air (SA) System (see Function SA-FP) and are shown on 
2-69

Drawings LR-39244 and LR-39253-3. The air compressors are active components and not 

subject to aging management review; as a result they are not included in LRA Table 2.3.3-17.

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: 

Although the description of the “piping/fittings and valves” line item provided in LRA 

Table 2.3.3-10 does not list these components specifically, the applicant states that it considers 

the hose connections, interior fire hose stations, and couplings, as included in LRA Table 

2.3.3-9 under the component type “piping/fittings and valves,” with the AMR results provided in 

LRA Table 3.3.2-9. Pipe supports for fire protection are included in LRA Section 2.4.2 and LRA 

Table 2.4.2-1 under the component type “supports,” with the AMR results provided in 

LRA Table 3.5.2-2. 

Dikes for oil spill confinement are included in the LRA Tables 2.4.1-1, 2.4.4-1, 2.4.5-1, and 

2.4.9-1 under “Concrete (...curbs, wall slabs)” with the AMR results provided in LRA Tables 

3.5.2-1, 3.5.2-4, 3.5.2-5, and 3.5.2-9

Floor drains for fire-fighting water are evaluated under the component type of piping/fitting as 

included in LRA Table 2.3.3-20 with the AMR results provided in LRA Table 3.3.2-20. Further, 

the applicant stated that LRA Section 2.3.3.20 on Page 2.3-109, second paragraph, second 

sentence, “plant floor drains,” is added to the list of drains that comprise the Waste Liquid 

subsystem. Also LRA Section 2.3.3.20, Page 2.3-110, the third sentence of the fifth paragraph 

is revised to read as follows: “Portions of the WD System support Fire Protection or Station 

Blackout event requirements based on the criteria of 10 CFR 54.4(a)(3).” 

Trash grids and travelling screens are evaluated in LRA Section 2.3.4.3, “Circulating Water 

(CW) System.” The FP pumps draw water from behind the plant screenhouse trash grids and 

screen. The applicant stated that during emergency operation, the CW pumps are unavailable. 

The flows through the trash grids and screens would be insignificant and plugging or failure of 

the grids and screens is not credible. Therefore, trash grids and traveling screens are not relied 

upon to perform or support a license renewal fire protection-related intended function. Based on 

its review, the staff finds the applicant’s response acceptable because it explained that the 

intended function supporting the fire pump suction supply is accomplished without trash grids 

and travelling screens. For normal and emergency operations without the CW pumps operating, 

a much lower volume of water flows through the traveling screens. The lower flow rates make it 

unlikely that debris could clog the travelling screens and prevent them from passing adequate 

flow. Additionally, the fire pump suction headers have their own strainers in-line, such that the 

loss of trash grids and travelling screens would not challenge the operation of these pumps until

pumps repair or replacement of the damaged component could be performed. 

Flame-retardant coatings for cables are included under components type “fire barrier 

penetration seals” and “fire proofing” in LRA Tables 2.4.5-1 and 3.5.2-5. Fire retardant 

intumescent coatings for all polyurethane foam piping was replaced with Armaflex (primer) and 

Flammastic (mastic sealant). These materials are included in the scope of license renewal and 

an AMR in Tables in LRA Tables 2.4.5-1 and 3.5.2-5 under component type “fire barrier 

penetration seals” and “fire proofing.”
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Turbine building smoke removal system components are evaluated in LRA Section 2.3.19 and 

are included in the LRA Tables 2.3.3-19, 3.3.2-19, and 3.5.2-5. 

Air compressors for fire protection safe-shutdown operation are within the scope of license 

renewal. The air compressors are active components and are not subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

The staff concludes that the air compressors for fire protection safe-shutdown operation are 

correctly excluded from Table 2.3.3-17 and are not subject to an AMR.

The staff found that the applicant appropriately excluded the backflow prevention devices from 

the line item descriptions in the LRA because the PINGP FP system does not contain backflow 

prevention devices, since the water for the FP system at PINGP is supplied from the Mississippi 

River.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.9-2 acceptable 

because it resolved the staff’s concerns regarding scoping and screening of FP system 

components listed in the RAI.

2.3.3.9.2 Conclusion 

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 FP 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 FP 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.10 Fuel Oil System

2.3.3.10.1 Summary of Technical Information in the Application

LRA Section 2.3.3.10 describes the fuel oil (FO) system. The FO system is an auxiliary system 

designed to receive and store diesel fuel oil and deliver it to both safety and nonsafety-related 

components consisting of diesel generators, diesel driven cooling water pumps, a heating boiler, 

and a diesel-driven fire pump. The FO system also provides a means of transferring fuel oil 

between fuel oil storage tanks and a means of filtering new and transferred oil. The FO system 

is a standby system. The FO system for Unit 1 consists of fuel oil storage tanks, pumps, filters 

and necessary piping, valves, and instruments. In LRA Table 2.3.3-10, the applicant identifies 

FO system component types it believes are within the scope of license renewal and subject to 

an AMR.

2.3.3.10.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 
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appropriately identified the FO 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).

2.3.3.11 Heating System 

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 describes the heating (HS) system. The HS system is an auxiliary system 

that provides a temperate environment in the plant buildings for the protection of equipment and 

the comfort of personnel. In addition, the HS system provides steam for the operation of the 

condensate tank freeze protection heater and cleaning hose stations. The system also supplies 

an alternate source of steam for hoggers, air ejectors, gland sealing steam, and the water box 

air ejectors. The HS system includes the process steam subsystem, which is designed to 

provide steam to the boric acid evaporators, boric acid batching tank, and the waste 

evaporators. The HS system is an operating system. The HS system is shared by Units 1 and 2 

and consists of a heating boiler, converters, coils, pumps, tanks, and the necessary piping, 

valves and instrumentation. In LRA Table 2.3.3-11, the applicant identifies HS system 

component types it believes are within the scope of license renewal and subject to an AMR.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12, UFSAR Sections 10.2.3, 11.1.4, and 11.3.2, and the 

license renewal boundary drawings using the evaluation methodology described in SER Section 

2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.11-01, dated December 2, 2008, the staff noted drawings for which drawing 

numbers and/or locations for the continuations could not be identified or could not be located. 

The applicant was requested to provide the drawing continuation locations.

In its response dated January 16, 2009, the applicant provided the continuation locations. The 

applicant also identified an additional component type, flexible connections, subject to an AMR. 

Revision to Tables 2.3.3-11 and 3.3.2-11 were provided in the applicant’s response to include 

the flexible connections.

Based upon its review, the staff finds the applicant’s response to RAI 2.3.3.11-01 acceptable 

because the applicant provided the continuation locations and identified additional components 

subject to an AMR and provided updated tables containing the flexible connections. Therefore, 

the staff’s concern described in RAI 2.3.3.11-01 is resolved.

In RAI 2.3.3.11-02, dated December 2, 2008, the staff noted on drawing LR-39605-1, locations 

C-2, D-5, G-6, and G-7, lines that appear to be vent lines with no continuation locations 

identified. The staff asked the applicant to confirm these lines are vent lines and identify the 

continuation locations.
2-72

In its response, dated January 16, 2009, the applicant clarified the purpose of the lines and 

identified the continuation locations. The applicant identified license renewal boundaries where 

they were not previously identified.

Based upon its review, the staff finds the applicant’s response to RAI 2.3.3.11-02 acceptable 

because the applicant clarified the purpose of the lines, identified the continuation locations, and 

identified license renewal boundaries where not previously identified.

In RAI 2.3.3.11-03, dated December 2, 2008, the staff noted on drawing LR-39605-1, location 

D-2, a gauge glass on the #121 Process Steam Condensate Return Unit not in-scope for 

license renewal while the #121 Process Steam Condensate Return Unit is in-scope. The staff 

asked the applicant to include the gauge glass as in-scope in accordance with 10 CFR 

54.4(a)(2) or provide justification for not including the gauge glass in-scope.

In its response, dated January 16, 2009, the applicant stated the gauge glass is in-scope for 

license renewal in accordance with 10 CFR 54.4(a)(2) and evaluated under the heading “sight 

glasses.”

Based upon its review, the staff finds the applicant’s response to RAI 2.3.3.11-03 acceptable 

because the applicant confirmed that the gauge glass is in-scope for license renewal in 

accordance with 10 CFR 54.4(a)(2).

In RAI 2.3.3.11-04, dated December 2, 2008, the staff noted on drawing LR-39605-3, location 

B-7, that valve HS-35A-1 and attached piping are not highlighted as in-scope for license 

renewal, but are directly connected to a 2-inch HWS line that is highlighted in-scope in 

accordance with 10 CFR 54.4(a)(2). The applicant was requested to provide a justification for 

not including valve HS-35A-1 and attached piping in-scope for license renewal.

In its response, dated January 16, 2009, the applicant stated the valve HS-35A-1 and attached 

piping are in-scope for license renewal.

Based upon its review, the staff finds the applicant’s response to RAI 2.3.3.11-04 acceptable 

because the applicant stated the valve and piping are in-scope for license renewal.

2.3.3.11.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 HS mechanical components within the scope of license renewal, as 

required by 10 CFR 54.4(a), and that the applicant has adequately identified the HS system 

mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.3.12 Miscellaneous Gas System

2.3.3.12.1 Summary of Technical Information in the Application

LRA Section 2.3.3.12 describes the miscellaneous gas (CG) system. The CG system is an 

auxiliary system that is designed to supply gases for various plant components. The CG system 

consists of the nitrogen, hydrogen, and carbon dioxide subsystems. Nitrogen is supplied to 

purge the vapor spaces of various Nuclear Steam Supply System (NSSS) components and to 

pressurize the SI accumulators and VC charging pump desurgers. Hydrogen is supplied to the 

turbine generators, VC system volume control tanks (VCTs) and other various NSSS 

components. Carbon dioxide is supplied to provide a purge gas to the turbine generators and to 

the incore instrumentation. The CG system is an operating system. The system consists of 

liquid storage tanks, high pressure banks, regulators and the necessary piping, valves and 

instrumentation. In LRA Table 2.3.3-12, the applicant identifies CG system component types it 

believes are within the scope of license renewal and subject to an AMR.

2.3.3.12.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.12, UFSAR Sections 9.3.2.1.4 and 9.3.2.1.5, and the 

license renewal boundary drawings using the evaluation methodology described in SER Section 

2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 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 2.3.3.12-01, dated November 19, 2008, the staff noted that drawing LR-39247, location 

C-9, shows one seismic anchor for the 1-inch nitrogen line supplying the Unit 2 containment 

where the line forms a T-junction. The staff asked the applicant to explain why it did not show a 

seismic anchor downstream of the T-junction.

In its response, dated December 18, 2008, the applicant stated in part: “...a seismic endpoint 

should be shown on the branch line opposite the seismic anchor.” 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-01 acceptable 

because the applicant stated that a seismic endpoint exits on the branch line opposite the 

seismic anchor. Therefore, the staff’s concern described in RAI 2.3.3.12-01 is resolved.

In RAI 2.3.3.12-02, dated November 19, 2008, the staff noted that drawing LR-39247, locations 

G-2 and G-5, identifies several flexible connectors for the hydraulic desurgers as being in-scope 

for 10 CFR 54.4(a)(2). In addition, a note on the drawing states the boundary ends at the 

flexible connection. LRA Table 2.3.3.12 does not include flexible connectors as a component 

type requiring an AMR. The staff asked applicant to explain why it did not include flexible 

connectors as a component type requiring an AMR in LRA Table 2.3.3-12. 

In its response, dated December 18, 2008, the applicant stated the stainless steel instrument 

tubing expansion loops are included in LRA Table 2.3.3-12 as piping/fitting components.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-02 acceptable 

because the applicant stated that the flexible connections are stainless steel instrument tubing 
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expansion loops and are included in LRA Table 2.3.3-12. Therefore, the staff’s concern 

described in RAI 2.3.3.12-02 is resolved.

2.3.3.12.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 CG 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 CG 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.13 Plant Sample System 

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 describes the plant sample (SM) system. The SM system is an auxiliary 

system that is designed to provide samples for laboratory analysis to evaluate reactor coolant 

and other auxiliary systems’ chemistry during normal operation. It has no emergency function. 

This system is normally isolated at the containment boundary. The SM system includes the 

Reactor Hot Sampling and the Sampling subsystems. The SM system is a standby system. The 

SM system for each PINGP Unit consists of sample connections, heat exchangers, pressure 

cylinders, sinks and necessary piping, valves, and instrumentation. In LRA Table 2.3.3-13, the 

applicant identifies SM system component types it believes are within the scope of license 

renewal and subject to an AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.13-01, UFSAR Section 10.3.5, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review identified an area in which additional 

information was necessary to complete the review of the applicant’s scoping and screening 

results. The applicant responded to the staff’s RAI as discussed below.

In RAI 2.3.3.13-01, dated November 19, 2008, the staff noted drawing LR-XH-248-1-3, location 

D2, shows hot lab pump HP2 discharge pressure indicator, PI-H3, as not in-scope for license 

renewal. The PI-C3 pressure indicator, which is similar to PI-H3, is in-scope for 10 CFR 

54.4(a)(2). The staff asked the applicant to provide additional information explaining why 

pressure indicator PI-H3 is not in-scope.

In its response, dated December 18, 2008, the applicant stated discharge pressure indicator PIH3 is within the scope of license renewal per 10 CFR 54.4(a)(2) and should be highlighted. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.13-01 acceptable 

because the applicant clarified that discharge pressure indicator PI-H3 is within the scope of 
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license renewal for 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.3.13-

01 is resolved.

2.3.3.13.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI response, and boundary 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 SM 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 SM 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1)

2.3.3.14 Primary Containment Ventilation System 

2.3.3.14.1 Summary of Technical Information in the Application

LRA Section 2.3.3.14 describes the primary containment ventilation (ZC) system. The ZC 

system includes several subsystems: The containment air cooling subsystem is designed to 

remove heat from containment during normal plant operation and during and following DBEs. 

The containment dome recirculation subsystem is designed to circulate and mix gases following 

a loss-of-coolant accident to prevent hydrogen accumulation. The containment vacuum relief 

subsystem is designed to protect the reactor containment vessel against excess differential 

pressures. The containment internal cleanup subsystem is designed to re-circulate containment 

air through filters to clean up containment atmosphere prior to limited personnel access. The 

containment purge and inservice purge subsystems are designed to provide fresh, tempered air 

for comfort during maintenance and refueling operations and to purge containment air through 

high efficiency particulate (HEPA) and charcoal filters. The spent fuel pool (SFP) normal and 

special ventilation sub-systems are designed to provide ventilation of the SFP area during 

normal operations and in the event that high radiation is detected. The shield building 

ventilation sub-system collects the leakage from the reactor containment vessel penetrations 

into the annulus of the shield building and discharges it through particulate, absolute and 

charcoal (PAC) filters to the monitored vent. Portions of ZC system is on standby and portions 

are in an operating mode. In LRA Table 2.3.3-14, the applicant identifies ZC system component 

types it believes are within the scope of license renewal and subject to an AMR.

2.3.3.14.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.14, UFSAR Sections 5.2.1, 5.2.2, 5.2.3, 5.3.2, 5.4.2.3, 

6.3.1, and 10.3.7, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

identified areas in which additional information was necessary to complete the review of the 

applicant’s scoping and screening results. The applicant responded to the staff’s RAIs as 

discussed below.

In RAI 2.3.3.14-01 dated December 16, 2008, the staff noted the boundary drawings identified 

containment dome air recirculation fans as out-of scope of license renewal, whereas the 
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remaining portion of the system is shown within the scope of license renewal. The staff asked 

the applicant to verify that the boundary drawings were correct or to provide justification why the 

containment dome air recirculation fans were not in-scope for license renewal.

In its response, dated January 15, 2009, the applicant stated that the scoping of the motor/fan 

assembly is incorrect and that the assembly should be within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(1). The applicant further stated that the motor/fan assembly is 

an active component, therefore, does not require AMR, and is not included in LRA Table 

2.3.3-14.

The staff reviewed the applicant’s response to RAI 2.3.3.14-01 and finds it acceptable because 

the applicant stated that the motor/fan assembly is in the scope of license renewal and, being 

an active component, is not subject to AMR.

In RAI 2.3.3.14-02, dated December 16, 2008, the staff noted a note in a boundary drawing 

referring to “spent fuel pool emergency ventilation.” The staff asked the applicant to describe 

this system or, if it is incorrect, to provide the correct name for “spent fuel pool special 

ventilation.”

In its response, dated January 15, 2009, the applicant stated the spent fuel pool emergency 

ventilation is the same system as discussed in LRA Section 2.3.3.14, spent fuel pool special 

ventilation subsystem and is evaluated as a part of the primary containment ventilation system.

The staff reviewed the applicant’s response to RAI 2.3.3.14-02 and finds it acceptable because 

the applicant clarified that the spent fuel pool emergency ventilation is the same as the spent 

fuel pool special ventilation subsystem which is a part of the primary containment ventilation 

system.

In RAI 2.3.3.14-03 dated December 16, 2008, the staff noted that the boundary drawings 

identified the inservice purge exhaust fans, which belong to the spent fuel pool special 

ventilation subsystem and are required to exhaust air in the event of high radiation and a fuel 

handling accident, as out-of-scope for license renewal. The staff asked the applicant whether 

the boundary drawings were correct, and if so, to explain why the inservice purge exhaust fans 

are out-of-scope for license renewal.

In its response dated January 15, 2009, the applicant stated that the scoping of the inservice 

purge exhaust fan motor/fan assembly is incorrect and that the assembly should be within the 

scope of license renewal per 10 CFR 54.4(a)(1). The applicant further stated that the motor/fan 

assembly is an active component that does not require AMR and is therefore not included in 

LRA Table 2.3.3-14.

The staff reviewed the applicant’s response to RAI 2.3.3.14-03 and finds it acceptable because 

the applicant stated that the motor/fan assembly is in the scope of license renewal and, being 

an active component, is not subject to AMR.
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2.3.3.14.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 ZC 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 ZC

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.15 Radiation Monitoring System 

2.3.3.15.1 Summary of Technical Information in the Application

LRA Section 2.3.3.15 describes the radiation monitoring (RD) system. The RD system is an 

auxiliary system designed to provide information to warn operations personnel of potential 

radiological hazards that have developed, give early warning of certain plant malfunctions 

indicated by changing radiological conditions, prevent or minimize the release of radioactivity by 

automatically isolating or redirecting plant processes, provide for routine monitoring of controlled 

plant offsite effluent releases, and provide accident monitoring information of plant conditions for 

use in accident assessment. The RD system includes the process, the area and the 

environmental radiation monitoring subsystems, and the health physics and laboratory radiation 

measuring subsystem. In LRA Table 2.3.3-15, the applicant identifies RD system component 

types it believes are within the scope of license renewal and subject to an AMR.

2.3.3.15.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the RD 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).

2.3.3.16 Spent Fuel Pool Cooling System 

2.3.3.16.1 Summary of Technical Information in the Application

LRA Section 2.3.3.16 describes the spent fuel pool cooling (SF) system. The SF system is an 

auxiliary system designed to remove the heat generated by stored spent fuel elements. The 

system provides purification of the spent fuel pool water, the RWST and the reactor cavity to 

reduce radiation levels and improve clarity. The SF system includes the spent fuel pool leakage 

and refueling pool cleanup subsystems. The SF system is an operating system. The SF system 

is shared by Unit 1 and Unit 2. The SF system consists of two pumps, two heat exchangers, 

filters, demineralizer, refueling water purification pumps, and the necessary piping (including the 

fuel transfer tube), valves, and instrumentation. In LRA Table 2.3.3-16, the applicant identifies 
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SF system component types it believes are within the scope of license renewal and subject to 

an AMR.

2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16; UFSAR Sections 1.2.8, 1.3.6, 10.2.1.2, 10.2.2, and 

Table 1.3-3, and the license renewal boundary drawings using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s review 

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 2.3.3.16-01, dated November 19, 2008, the staff noted that although the fuel-transfer 

tube is in-scope for license renewal per 10 CFR 54.4(a)(1) and (a)(3), there was little 

information describing the fuel-transfer tube or the license renewal boundary in the LRA. A 

drawing was not provided. The fuel-transfer tube and blind flange are also not included in LRA 

Table 2.3.3-16, “Spent Fuel Pool Cooling System.” The staff asked applicant to (1) provide 

reference to an LRA drawing showing the fuel-transfer tube and license renewal boundaries, 

and to (2) justify why the fuel-transfer tube and blank flange are not component types requiring 

an AMR in LRA Table 2.3.3-16. 

In its response, dated December 18, 2008, the applicant stated that UFSAR Figure 12.3-16 

shows the fuel transfer tubes. The fuel transfer tube is included in the portions of the spent fuel 

cooling system subject to an AMR, which is described in LRA Section 2.3.3.16. In addition to the 

fuel transfer tube, the blind flange and fuel transfer tube gate valve are also within the scope of 

license renewal and included in Table 2.3.3-16 as valves (transfer tube gate valve) and 

pipe/fittings (transfer tube and blind flange). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-01 acceptable 

because the applicant clarified that the fuel transfer tube gate valve is evaluated as a valve and 

the fuel transfer tube and blind flange are evaluated as piping/fittings in LRA Table 2.3.3-16. 

Therefore, the staff’s concern described in RAI 2.3.3.16-01 is resolved. 

2.3.3.16.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI response, and boundary 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 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 spent fuel pool cooling system mechanical components subject to an AMR in 

accordance with the requirements stated in 10 CFR 54.21(a)(1).
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2.3.3.17 Station and Instrument Air System 

2.3.3.17.1 Summary of Technical Information in the Application

LRA Section 2.3.3.17 describes the station and instrument air (SA) system. The SA system is 

an auxiliary system that is designed to provide a continuous supply of oil-free, dry, instrument 

air as required. The system also provides oil-free, compressed service air to hose stations 

throughout the plant and to the condensate polishing backwash air supply subsystem for resin 

backwashing operations. The SA system includes the backup accumulators and compressed air 

subsystems that provide backup air for the RCS power-operated relief valves (PORVs), the 

turbine driven auxiliary feedwater pump steam admission control valves, the CL system strainer 

backwash valves and the safeguards chilled water subsystem components. The SA system is 

an operating system. The instrument air subsystem consists of compressors, coolers, dryers, 

receivers and the necessary piping, valves and instrumentation to supply a common air header 

that supplies separate headers for each unit. In LRA Table 2.3.3-17, the applicant identifies SA 

system component types it believes are within the scope of license renewal and subject to an 

AMR.

2.3.3.17.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.17, UFSAR Sections 4.4.2.3.1, 8.4.2, 10.3.10.1, 10.4.1.2, 

10.4.3.2, 11.8.2.4, and 11.9.2.2 and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff’s review 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 2.3.3.17-01, dated November 19, 2008, the staff noted the boundary drawings of

LR-39253-3, location C-7, depicted several lines from air compressor #124 as in-scope for 

license renewal for 10 CFR 54.4(a)(2); whereas, similar lines from air compressor #125 are inscope for license renewal for 10 CFR 54.4(a)(3). The staff also noted that LRA Section 2.3.3-17, 

“Station and Instrument Air System,” does not indicate that any portion of the station and 

instrument air system is in-scope for 10 CFR 54.4(a)(2). The staff asked the applicant to provide 

additional information explaining why there is a different in-scope classification between the 

lines out of air compressors #124 and #125. In addition, the staff asked the applicant to explain 

why, if the sections of pipe currently in-scope for 10 CFR 54.4(a)(2) on license renewal drawing 

LR-39253-3 remain in-scope for 10 CFR 54.4(a)(2), LRA Section 2.3.3.17 does not address 

components in-scope for 10 CFR 54.4(a)(2).

In its response, dated December 18, 2008, the applicant clarified that air compressor #125 is 

used as a backup for fire protection safe shutdown, whereas air compressor #124 is not 

required for fire protection safe shutdown, and that the difference is the reason for the different 

in-scope classifications. The applicant also clarified that the lines that are shown in-scope due to 

the different scoping criteria are the cooling water system supply and return lines, and are 

evaluated in the cooling water system. 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-01 acceptable 

because the applicant clarified the scope classification of the lines from the air compressors as 
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well as the scope classification description in LRA Section 2.3.3.17. Therefore, the staff’s 

concern described in RAI 2.3.3.17-01 is resolved.

In RAI 2.3.3.17-02, dated November 19, 2008, the staff noted the boundary drawing 

LR-39253-3, location A-8, shows the 2-2CL-50 line as in-scope for license renewal for 

10 CFR 54.4(a)(3); whereas, the continuation of this 2-inch line on drawing LR-39217-1 is inscope for license renewal for 10 CFR 54.4(a)(2). The staff asked the applicant to explain the 

different in-scope classifications in drawing LR-39253-3 and the continuation on drawing 

LR-39217-1.

In its response, dated December 18, 2008, the applicant stated the scoping classification of line 

2-2CL-50 is incorrect. The line is in-scope for 10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-02 acceptable 

because the applicant clarified the scope classification of the 2-2CL-50 line continuation. 

Therefore, the staff’s concern described in RAI 2.3.3.17-02 is resolved.

In RAI 2.3.3.17-03, dated November 19, 2008, the staff noted that drawing LR-39244, location 

C-1, downstream of SA-85-2, shows a 1/2-inch line as not in-scope for license renewal. The line 

is directly connected to the safety valve and the upstream 3/4-inch line that are within the scope 

of license renewal. The staff asked the applicant to explain why these sections of pipe and 

components are not within the scope of license renewal and justify the boundary locations with 

respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated December 18, 2008, the applicant clarified that the scoping classification 

of the 1/2-inch line is incorrect. The 1/2-inch line is in-scope for license renewal per 

10 CFR 54.4(a)(3).

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-03 acceptable 

because the applicant clarified the scope classification of the 1/2-inch line. Therefore, the staff’s 

concern described in RAI 2.3.3.17-03 is resolved.

In RAI 2.3.3.17-04, dated November 19, 2008, the staff noted the boundary drawings LR-39244, 

location C-1, downstream of SA-115-1, shows a 3/8-inch line and the associated control valve 

CV 31148 as not in-scope for license renewal. This line is directly connected to a 1-inch line that 

is within the scope of license renewal. The staff asked the applicant to explain why the sections 

of pipe and components are not within the scope of license renewal and justify the boundary 

locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response, dated December 18, 2008, the applicant clarified that the scoping classification 

of the 3/8-inch line is incorrect. The 3/8-inch line is in-scope for license renewal per 

10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-04 acceptable 

because the applicant clarified the scope classification of the 3/8-inch line. Therefore, the staff’s 

concern described in RAI 2.3.3.17-04 is resolved.
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In RAI 2.3.3.17-05, dated November 19, 2008, the staff noted drawing LR-39243, locations F-8 

through F-10, upstream of 2SA-2-71, shows a 3-inch line as not in-scope for license renewal. 

This line is directly connected to the upstream 3-inch line and downstream 3-inch line, both of 

which are within the scope of license renewal. The staff asked the applicant to explain why this 

section of pipe are not within the scope of license renewal and justify the boundary locations 

with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response dated December 18, 2008, the applicant clarified that the scoping classification 

of the 3-inch line is incorrect and the line should be shown in-scope for license renewal per 

10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-05 acceptable 

because the applicant clarified the scope classification of the 3” line. Therefore, the staff’s 

concern described in RAI 2.3.3.17-05 is resolved.

In RAI 2.3.3.17-06, dated November 19, 2008, the staff noted drawings LR-39243, location D-9, 

shows a 1/2-inch line and valve 2SA-19-2 as not in-scope for license renewal. This line is 

directly connected to the 1-inch line that is within the scope of license renewal. The staff asked 

the applicant to explain why this section of pipe are not within the scope of license renewal and 

justify the boundary locations with respect to the applicable requirements of 10 CFR 54.4(a). 

In its response dated December 18, 2008, the applicant clarified that the scoping classification 

of the 1/2-inch line and valve 2SA-19-2 is incorrect. The 1/2-inch line and valve 2SA-19-2 are inscope for license renewal per 10 CFR 54.4(a)(3). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.17-06 acceptable 

because the applicant clarified the scope classification of the 1/2-inch line and valve 2SA-19-2. 

Therefore, the staff’s concern described in RAI 2.3.3.17-06 is resolved.

2.3.3.17.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 SA 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 SA 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.3.18 Steam Exclusion System 

2.3.3.18.1 Summary of Technical Information in the Application

LRA Section 2.3.3.18 describes the steam exclusion (SE) system, which is designed to provide 

ventilation isolation to protect the systems and components from potentially harsh environments 

due to a HELB. The failure of nonsafety-related SSCs in the SE system potentially could 

prevent the satisfactory accomplishment of a safety-related function. In LRA Table 2.3.3-18, the 
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applicant identifies SE system component types it believes are within the scope of license 

renewal and subject to an AMR. 

2.3.3.18.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the SE 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).

2.3.3.19 Turbine and Administration Building Ventilation System 

2.3.3.19.1 Summary of Technical Information in the Application

LRA Section 2.3.3.19 describes the turbine and administration building ventilation (ZB) system,

which includes several subsystems. The ZB system subsystems are auxiliary systems designed 

to provide tempered air and remove exhaust air to provide a suitable working environment and 

maintain temperatures required by machinery in various buildings and areas throughout the 

plant. In addition, the technical support center (TSC) ventilation and cleanup subsystem 

operates to provide emergency response facility habitability under accident conditions. The ZB 

system includes the turbine building, old admin building, new admin building, cold chemical lab, 

and TSC ventilation and cleanup subsystems. In LRA Table 2.3.3-19, the applicant identifies ZB 

system component types it believes are within the scope of license renewal and subject to an 

AMR.

2.3.3.19.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the ZB 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 ZB 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.20 Waste Disposal System 

2.3.3.20.1 Summary of Technical Information in the Application

LRA Section 2.3.3.20 describes the Waste Disposal (WD) system. The WD system is an 

auxiliary plant system that is designed to collect, process, store and dispose of all potentially 

radioactive reactor plant wastes while meeting the limits established by regulations for release 

of wastes from the plant site. The WD system consists of the waste liquid, waste gas and waste 

solid disposal subsystems and the site miscellaneous maintenance subsystem. The waste gas, 

waste liquid and site miscellaneous maintenance subsystems are operating systems. The waste 

solid subsystem is a standby system. The waste liquid disposal subsystem is shared by Unit 1 

and Unit 2, and consists of tanks, filters, pumps, ion exchangers, evaporators, and the 
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necessary piping, valves, and instrumentation. In LRA Table 2.3.3-20, the applicant identifies 

WD system component types its believes are within the scope of license renewal and subject to 

an AMR.

2.3.3.20.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.20, UFSAR Sections 1.2.9, 1.3.5, 9.1.1, 9.1.2, 9.3.2, 

9.4.2, 11.8.2.3, 14.5.3, and 14.5.3.2, and the license renewal boundary drawings using the 

evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

The staff’s review 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 2.3.3.20-01, dated November 19, 2008, the staff noted that drawing LR-XH-1-123, 

locations C-5 and C-7, shows two seismic endpoints on 3/8-inch reactor coolant drain tank 

piping exiting containment as not in-scope. The valves, 1-9159B and 2-9159B, that the seismic 

endpoints are connected to, are shown as within the scope of license renewal for 

10 CFR 54.4(a)(1). The staff asked the applicant why it did not include the seismic endpoint 

downstream of valves 1-9159B and 2-9159B within the scope of license renewal.

In its December 18, 2008 response, the applicant stated in part: 

...that the seismic endpoints represent points where the piping within the scope 

of license renewal is decoupled from the downstream piping. In this case, the 

smaller branch lines (3/8-inch tubing), do not provide support for the pressure 

boundary valves and the scoping boundary ends at each valve. The seismic 

endpoint symbol does not represent a component and is correctly shown as not 

within the scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-01 acceptable 

because the applicant clarified that the seismic endpoints do not provide support for the 

pressure boundary valves and the scoping boundary ends at each valve. Therefore, the staff’s 

concern described in RAI 2.3.3.20-01 is resolved. 

In RAI 2.3.3.20-02, dated November 19, 2008, the staff noted that drawing LR-XH-1-123, 

locations A-2 and A-10, shows 3/8-WL-1 and 3/8-2WL-1 lines in-scope for license renewal for 

10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). However, the continuation of this line on drawings LRXH-1-7, location D-8, and LR-XH-1001-3, location D-8, shows this line is in-scope for 

10 CFR 54.4(a)(2). The staff asked the applicant to explain why there is a different in-scope 

classification between drawing LR-XH-1-123 and the continuations on drawings LR-XH-1-7 and 

LR-XH-1001-3.

In its response, dated December 18, 2008, the applicant stated that the reactor flange leakoff 

lines are within the scope of license renewal per 10 CFR 54.4(a)(2) and should be highlighted.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-02 acceptable 

because the applicant clarified that the reactor flange leak off lines are within the scope of 
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license renewal per 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 

2.3.3.20-02 is resolved. 

In RAI 2.3.3.20-03, dated November 19, 2008, the staff noted that drawing LR-39248, location 

E-8, shows piping 2-WG-68 from the gas decay tank condensate drain pump as in-scope for 

license renewal for 10 CFR 54.4(a)(2). However, the continuation of this line on drawing 

LR-XH-1-124, location E-12, 1-inch piping 1-WG-68 shows this line as not in-scope for license 

renewal. The staff asked the applicant to explain why there is a different in-scope classification 

between drawing LR-39248 and the continuation on drawing LR-XH-1-124.

In its response, dated December 18, 2008, the applicant stated that the pit entry wall is shown 

on drawing LR-XH-1-124, location E-12, at the gas decay tank condensate drain pump 

discharge line, 1-WG-68. This wall provides the scoping break between the portion of the line 

that is within the scope of license renewal and the portion that is not within the scope of license 

renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-03 acceptable 

because the applicant clarified the location of the scoping break for the gas decay tank 

condensate drain pump discharge line. Therefore, the staff’s concern described in RAI 

2.3.3.20-03 is resolved. 

In RAI 2.3.3.20-04, dated November 19, 2008, the staff noted drawing LR-39248, location D-7, 

shows 3/8-inch tubing from valve 2CV-38-4 as in-scope for license renewal for 10 CFR 

54.4(a)(2). However, the continuation of this line on drawing LR-XH-1-1001-5, location F-2, 

shows valve 2CV-38-4 as in-scope for 10 CFR 54.4(a)(1) or 10 CFR 54.4(a)(3). The staff asked 

the applicant to explain why there is a different in-scope classification between drawing LR39248 and the continuation on drawing LR-1-1001-5.

In its response, dated December 18, 2008, the applicant stated the stem leak-off line and valve 

2VC-38-4 should be shown as within the scope of license renewal per 10 CFR 54.4(a)(2), not 

10 CFR 54.4(a)(1) or (a)(3).

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.20-04 acceptable 

because the applicant clarified that the CV-31211 stem leak-off line and valve 2VC-38-4 are 

within-scope of license renewal per 10 CFR 54.4(a)(2). Therefore, the staff’s concern described

in RAI 2.3.3.20-04 is resolved. 

In RAI 2.3.3.20-06, dated November 19, 2008, the staff noted that drawing LR-XH-1-124 shows 

nine gas decay tanks (#121, #122, #123, #124, #125, #126, #127, #128, and #129) as not inscope for license renewal. However, at multiple tank isolation valve locations, it shows that the 

tanks are classified as safety-related (QA Class IC). The staff asked applicant to explain why 

these QA Class IC gas decay tanks and associated components are not within the scope of 

license renewal for 10 CFR 54.21(a)(1). Resolution of this RAI and closure of SER OI 

2.1.4.1.2-01 is presented in SER section 2.1.4.1. 
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2.3.3.20.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI responses, and boundary 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 WD 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 

WD mechanical components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.21 Water Treatment System 

2.3.3.21.1 Summary of Technical Information in the Application

LRA Section 2.3.3.21 describes the water treatment (DE) system. The DE system is an auxiliary 

system that supplies demineralized and domestic (potable) water to meet plant requirements. 

The DE system includes the domestic water and sewer subsystems. The DE system is an 

operating system. The DE system is shared by Unit 1 and Unit 2, and consists of wells, tanks, 

pumps, ion exchangers, reverse osmosis units, and the necessary piping, valves, and 

instrumentation. In LRA Table 2.3.3-21, the applicant identifies DE system component types it 

believes are within the scope of license renewal and subject to an AMR.

2.3.3.21.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the DE 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 PINGP steam and power conversion systems SCs subject to an 

AMR for license renewal.

The applicant described the supporting SCs of the steam and power conversion systems in the 

following LRA sections:

2.3.4.1 Auxiliary Feedwater System

2.3.4.2 Bleed Steam System

2.3.4.3 Circulating Water System

2.3.4.4 Condensate System

2.3.4.5 Feedwater System

2.3.4.6 Main Steam System

2.3.4.7 Steam Generator Blowdown System

2.3.4.8 Turbine Generator System
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The staff’s findings on review of LRA Sections 2.3.4.1–2.3.4.8 are in SER Sections 2.3.4.1–

2.3.4.8, respectively.

2.3.4.1 Auxiliary Feedwater System

2.3.4.1.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the Auxiliary Feedwater (AF) system. The AF system is a steam 

and power conversion system that provides feedwater to the steam generators for heat removal 

from the RCS during and following DBEs, including loss of normal feedwater, steam generator 

tube rupture, main steam or feedwater line break, small break LOCA, and during normal 

operation, such as startup and shutdown, when the main feedwater system is not available. The 

AF system for each unit consists of one turbine-driven and one electric-driven pump and the 

necessary piping, valves and instrumentation. In LRA Table 2.3.4-1, the applicant identifies AF 

system component types it believes are within the scope of license renewal and subject to an 

AMR.

2.3.4.1.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the AF 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).

2.3.4.2 Bleed Steam System 

2.3.4.2.1 Summary of Technical Information in the Application

LRA Section 2.3.4.2 describes the bleed steam (BL) system. The BL system is a steam and 

power conversion system that is designed to improve turbine cycle efficiency by using turbine 

exhaust steam for feedwater heating. The BL system includes the heater vents subsystem. The 

BL system is an operating system. The BL system for each PINGP unit consists of the 

necessary piping, valves and instrumentation for supplying turbine exhaust steam to the 

feedwater heaters for feedwater heating. In LRA Table 2.3.4-2, the applicant identifies BL 

system component it believes are types within the scope of license renewal and subject to an 

AMR.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, UFSAR Section 11.7, and the license renewal 

boundary drawings using the evaluation methodology described in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. The staff’s review 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 RAIs as discussed below.
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In RAI 2.3.4.2-01, dated November 19, 2008, the staff noted drawing LR-39224, locations D-2, 

and E-2, depicted FW Heaters #15A and #15B as not in-scope for license renewal whereas the 

corresponding Unit 2 FW Heaters #25A and #25B are shown as in-scope on drawing LR-39225. 

The staff also noted that the FW heaters are not included in LRA Table 2.3.4-2 Bleed Steam 

System, as a component type subject to an AMR.

In its response, dated December 18, 2008, the applicant stated that the feedwater heaters #15A 

and #15B tubes are contained within the shell and that their failure will not affect any SR 

components. The applicant also stated that the shells and channel heads are shown as within 

the scope of license renewal per 10 CFR 54.4(a)(2). The applicant also explained that the 

feedwater heaters are evaluated and included as heat exchanger components in LRA Table 

2.3.4-5, Feedwater System.

The applicant also stated that the feedwater heater, and reheater tube and tubesheet scoping is 

generally incorrect on drawings LR-39224, and LR-39225. Drawings LR-39218 and 39219 also 

contain incorrect scoping for several reheater tubes and tubesheet. The applicant identified the 

correct systems, drawings, and tables that contain the components.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-01 acceptable 

because the applicant clarified the scope classification of the feedwater heaters in question and 

identified the component types subject to an AMR. The applicant identified other instances of 

incorrect scoping and stated where the correct scoping could be found for feedwater heaters 

and reheater tubes, and tubesheets. 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, UFSAR, RAI response, and boundary 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 BL 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 BL 

system mechanical components subject to an AMR in accordance with the requirements stated 

in 10 CFR 54.21(a)(1).

2.3.4.3 Circulating Water System 

2.3.4.3.1 Summary of Technical Information in the Application

LRA Section 2.3.4.3 describes the circulating water (CW) system. The CW system is a steam 

and power conversion system that provides the heat sink for the generating plant. In addition, 

the CW system supplies water to the CL system and the FP system and provides a means of 

back flushing the emergency cooling water (CL) intake line. The CW system includes the 

external and internal circulating water subsystems, the screen wash subsystem, the condenser 

tube cleaning subsystem and the condenser water box vent and drain subsystem. In LRA Table 

2.3.4-3, the applicant identifies CW system component types it believes are within the scope of 

license renewal and subject to an AMR.
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2.3.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.3, UFSAR Sections 2.9.3, 10.4.1.2.2, 11.5, Figures 

10.3-1, 11.1-16 and 11.1-17 and the license renewal boundary drawings using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3. The staff’s 

review 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 2.3.4.3-01, dated November 19, 2008, the staff noted drawing LR-39215-1, locations B-7, 

B-8, B-10, and B-11 depicted condensers #1A, #1B, #2A, and #2B as not in-scope for license 

renewal whereas the same condensers are shown as in-scope on drawing LR-39215-1 

locations E-2, E-3, E-5, and E-6.

In its response, dated December 18, 2008, the applicant stated the condensers should be 

highlighted to show them as within the scope for 10 CFR 54.4(a)(2). 

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.3.-01 acceptable 

because the condensers are in-scope for 10 CFR 54.4(a)(2). Therefore, the staff’s concern 

described in RAI 2.3.4.3.-01 is resolved.

2.3.4.3.3 Conclusion

The staff reviewed the LRA, UFSAR, RAI response, and boundary 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 CW 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 

CW system mechanical components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).

2.3.4.4 Condensate System 

2.3.4.4.1 Summary of Technical Information in the Application

LRA Section 2.3.4.4 describes the condensate (CD) system. The CD system is a steam and 

power conversion system that is designed to remove condensate from the hotwell of the 

condenser and supply the FW system for heat removal from the RC system at all load 

conditions. The CD system condensate storage tanks provide the normal source of water to the 

AF system for heat removal from the RC system during accident and normal plant conditions. 

The CD system includes the condensate polishing, chemical feed, gland seal water, and heater 

drain subsystems. The CD system is an operating system. The CD system for each Unit 

consists of the three condensate pumps, two parallel trains of feedwater heaters, drain coolers, 

turbine auxiliary component condensers, and the necessary piping, valves and instrumentation. 

In LRA Table 2.3.4-4, the applicant identifies CD system component types it believes are within 

the scope of license renewal and subject to an AMR.
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2.3.4.4.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the CD 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 CD 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.5 Feedwater System 

2.3.4.5.1 Summary of Technical Information in the Application

LRA Section 2.3.4.5 describes the main feedwater (FW) system. The FW system is a steam 

and power conversion system designed to provide feedwater to the steam generators for heat 

removal from the reactor coolant system during normal plant conditions, producing steam for 

use in the turbine-generator. The FW system is an operating system. The FW system for each 

PINGP unit consists of two motor-driven main feedwater pumps, heaters, flow nozzles and the 

necessary piping, valves and instrumentation. The FW system increases the pressure of the 

condensate for delivery through one stage of feedwater heating and the feedwater regulating 

valves to the steam generators. In LRA Table 2.3.4-5, the applicant identifies FW system 

component types it believes are within the scope of license renewal and subject to an AMR.

2.3.4.5.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the FW 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 FW 

system components subject to an AMR in accordance with the requirements stated in 10 CFR 

54.21(a)(1).

2.3.4.6 Main Steam System 

2.3.4.6.1 Summary of Technical Information in the Application

LRA Section 2.3.4.6 describes the main steam (MS) system. The MS system is a steam and 

power conversion system designed to remove heat from the reactor coolant under accident and 

normal plant conditions, producing steam for use in the turbine generator. The system can 

receive and dispose of the total heat existent or produced in the RCS following a turbine 

generator trip at full load. The MS system is an operating system. The MS system for each 

PINGP unit consists of the necessary piping, valves and instrumentation designed to conduct 

steam from each of the two steam generators within the reactor containment through a swingdisc type isolation valve and a swing-disc type non-return valve to the turbine stop and control 

valves. In LRA Table 2.3.4-6, the applicant identifies MS system component types it believes 

are within the scope of license renewal and subject to an AMR.
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2.3.4.6.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the MS 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).

2.3.4.7 Steam Generator Blowdown System 

2.3.4.7.1 Summary of Technical Information in the Application

LRA Section 2.3.4.6 describes the steam generator blowdown (SB) system. The SB system is a 

steam and power conversion system designed to remove chemical and particulate impurities 

from the steam generators and maintain chemical levels in the steam generators within an 

acceptable range. The SB system is an operating system. The SB system for each PINGP unit 

consists of a flash tank, heat exchangers, filters and transfer pump and the associated piping, 

valves and instrumentation. In LRA Table 2.3.4-7, the applicant identifies SB system component 

types it believes are within the scope of license renewal and subject to an AMR.

2.3.4.7.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the SB 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).

2.3.4.8 Turbine Generator and Support System 

2.3.4.8.1 Summary of Technical Information in the Application

LRA Section 2.3.4.6 describes the turbine generator and support (TB) system. The TB system is 

a steam and power conversion system that provides heat removal from the RC system during 

normal operation and the production of electricity. The system includes the air removal, electrohydraulic control, gland sealing steam, miscellaneous drains and vents, turbine building traps 

and drains, turbine oil, turbine and turbine moisture separator subsystems. The TB system and 

subsystems are operating systems. The TB system for each PINGP unit consists of the turbine 

generators, including the electro-hydraulic control, gland sealing steam, turbine, turbine 

moisture separator and turbine oil subsystems, turning gear, cylinder heating, hydrogen cooling, 

tanks, heat exchangers, pumps and the necessary piping, valves and instrumentation. In LRA 

Table 2.3.4-8, the applicant identifies TB system component types it believes are within the 

scope of license renewal and subject to an AMR.
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2.3.4.8.2 Conclusion

Based on the results of the staff evaluation discussed in Section 2.3 and on a review of the 

LRA, UFSAR, and applicable boundary drawings, the staff concludes that the applicant has 

appropriately identified the TB 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 

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. The following structures and structural components are addressed in this section:

Scoping and Screening Results: Containments, Structures, and Component 

Supports 

2.4.1 Auxiliary and Turbine Buildings

2.4.2 Component Supports

2.4.3 Cranes, Heavy Loads, Fuel Handling

2.4.4 D5/D6 Diesel Generator Building and Underground Storage Vault, Fuel Oil 

Transfer House, Old Service Building, and New Service Building

2.4.5 Fire Protection Barriers

2.4.6 Radwaste Building, Old Administration Building, and Administration Building 

Addition

2.4.7 Reactor Containment Vessels Unit 1 and Unit 2

2.4.8 SBO Yard Structures

2.4.9 Shield Buildings Unit 1 and Unit 2

2.4.10 Tank Foundations

2.4.11 Water Control Structures-Approach Canal, Emergency Cooling Water Intake, 

Intake Canal, and Screenhouse

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant identified and listed 

passive, long-lived SCs that it viewed as 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 if 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).
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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 UFSAR for each structure to determine if 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 UFSAR to determine if all intended functions delineated under 

10 CFR 54.4(a) were specified in the LRA. If discrepancies or omissions were identified, the 

staff requested additional information to resolve the issue.

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) if the functions are performed with moving parts or a change in configuration or properties, or 

(2) if 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). If discrepancies were identified, the staff requested additional information 

to resolve them. The staff requested additional information, by letter dated December 1, 2008, 

to resolve any lack of clarity, omissions or discrepancies identified.

2.4.1 Auxiliary Building and Turbine Building

2.4.1.1 Summary of Technical Information in the Application 

LRA Section 2.4.1 describes the auxiliary building and the turbine building, which are shared by 

the two units. The auxiliary building, an integral part of the power house complex, is a multi-level 

reinforced concrete and steel framed structure on a mat foundation and houses both safetyrelated and nonsafety-related SSCs. The mat foundation, reinforced concrete structure above 

the foundation, main load carrying structural steel frame, and the auxiliary building crane 

support steel are safety-related. The reinforced concrete structure acts as secondary 

containment and provides shelter and protection for safety-related SSCs. The structural steel 

frame provides shelter and protection for the auxiliary building crane and portions of the safetyrelated concrete structure. The auxiliary building houses the spent fuel pools, new fuel pit, the 

refueling water storage tanks and the control room. 

The turbine building is a multi-level reinforced concrete structure and steel framed structure, 

built on a 3 ft to 5 ft thick mat foundation, housing safety-related and non safety-related SSCs 

and providing a flood barrier. The safety-related portions of the turbine building include the 

reinforced concrete aisle, the main load carrying structural steel frame, and the turbine building 

crane structural steel support members. The structural steel frame provides shelter and 

protection and weatherproof enclosure for the SSCs in the reinforced concrete aisle. Non 

safety-related components of the auxiliary and turbine buildings include building secondary 

members, turbine generator foundation, steel siding, and others.

In LRA Table 2.4.1-1, the applicant identifies the components it believes are subject to aging 

management review for the auxiliary building and turbine building by component type and 

intended function. In the first column of LRA Table 3.5.2-1, the applicant lists the SCs included 

within each component type group in LRA Table 2.4.1-1.
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2.4.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.1, the first three columns of LRA Table 3.5.2-1, LR drawing 

LR-193817 and UFSAR Sections 1.3.2, 1.3.10 and 12.2, using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has not omitted, from the scope of license renewal, any 

SCs with intended functions, pursuant to 10 CFR 54.4(a). The staff then reviewed those SCs, 

that the applicant has identified as within the scope of license renewal, to verify that the 

applicant has not omitted any passive and long-lived SCs subject to an AMR, in accordance 

with the requirements of 10 CFR 54.21(a)(1).

The staff’s review of LRA Section 2.4.1 identified an area in which additional information was 

necessary to complete the review of the applicant’s scoping and screening results, and 

determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the 

screening criteria of 10 CFR 54.21(a)(1). The applicant responded to the staff’s RAI as 

discussed below.

Due to a lack of clarity in LRA Tables 2.4.1-1 and 3.5.2-1, in RAI 2.4.1-1 dated December 

1, 2008, the staff requested the applicant to confirm/clarify if the SFP divider gates, the SFP 

leak-chase channels, and the fuel transfer canal upending frame are structural components 

within the scope of license renewal and subject to an AMR. If the applicant viewed the 

structures and components as in-scope, the applicant was requested to include their scoping, 

screening and AMR results, as appropriate, or clarify the location in the LRA where these 

components are addressed. If the applicant took the position that the structures and 

components are not in-scope, the applicant was requested to provide a justification for 

exclusion.

In its response to RAI 2.4.1-1, dated December 11, 2008, the applicant stated that the SFP 

divider gates are not in-scope of license renewal since they do not perform a license renewal 

intended function. The applicant explained that, as discussed in UFSAR Section 10.2.2.3, to 

protect against complete loss of water in the SFP, the SFP cooling system piping connections 

enter the top of the pool. The drain connection from the transfer canal to the CVCS holdup tank 

recirculation pump is at the canal’s bottom. The applicant further explained that even if the water 

in the transfer canal were completely drained with the SFP gate removed, the active portion of 

the spent fuel would not be uncovered because the bottom of the gate connection in the wall 

separating the transfer canal from the SFP is at an elevation that would preclude complete 

drainage.

The applicant also stated in its response that the SFP leak-chase channels are in-scope of 

license renewal. The applicant clarified that these components are located in the Auxiliary 

Building, are fabricated from stainless steel, and are located in an embedded-in-concrete 

environment. The applicant clarified that the SFP leak-chase channel component is included in 

LRA Table 2.4.1-1 on page 2.4-9 as part of the “stainless steel components” group, and in LRA 

Table 3.5.2-1 on page 3.5-77 as part of line item, “stainless steel components (embedded 

members).”
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The applicant also stated that the fuel transfer canal upender (or tipping device) is in-scope of 

license renewal. The applicant clarified that the upending frame is part of the fuel transfer 

tipping device identified in LRA Section 2.4.3 on page 2.4-18 and included in LRA Table 3.5.2-3 

on pages 3.5-115 and 3.5-116 for aging management of the fuel transfer tipping devices.

Based on its review, the staff finds the applicant’s response to RAI 2.4.1-1 acceptable because 

the applicant has confirmed that the SFP leak-chase channels and the fuel transfer canal 

upending frame (or tipping device) are within the scope of LR and subject to an AMR and made 

reference to the location in the LRA where they were addressed. The staff confirmed that these 

components were included in the LRA tables and sections referenced by the applicant in its 

response. The staff finds that the SFP divider gates do not perform a LR-intended function and 

the explanation provided by the applicant justified its exclusion from the scope of LR. Thus, the 

staff’s concerns described in RAI 2.4.1-1 are resolved.

2.4.1.3 Conclusion 

The staff reviewed the LRA, UFSAR, RAI response, and related structural components to 

determine whether the applicant failed to identify any SCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the Auxiliary Building and 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 Component Supports 

2.4.2.1 Summary of Technical Information in the Application 

LRA Section 2.4.2 describes component supports as structural support members used to 

transfer loads from systems and components to building structures. They are located in 

buildings housing safety-related equipment, and at plant locations where in-scope equipment 

can be found. Since their components, materials, and environments are similar, the applicant 

evaluated component supports as a plant-wide commodity, rather than as commodities to a 

specific building. Component supports include insulation/insulation jacket and support members 

for mechanical equipment, electrical and I&C equipment. Support members include steel wideflange and I beams, channels, angles, tees, plates, bars, shims, clip angles, banding, build-up 

sections, rods, cables, bolts, nuts, washers, welds, spring hangers, guides, stops, slide plates, 

isolation elements, concrete anchors, grout and concrete local to the anchors, and grout pads 

beneath equipment. In LRA Table 2.4.2-1, the applicant identifies the components it believes

are subject to AMR for the component supports by component type and intended function. In 

the first column of LRA Table 3.5.2-2, the applicant lists the SCs included within each of the 

component type groups in LRA Table 2.4.2-1.

2.4.2.2 Conclusion 

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA 

Section 2.4.2, the first three columns of LRA Table 3.5.2-2, and UFSAR Section 12.2 to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 
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to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the component supports SCs within the scope of license renewal, as required by 

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.3 Cranes, Heavy Loads, and Fuel Handling System Components 

2.4.3.1 Summary of Technical Information in the Application 

LRA Section 2.4.3 describes the structural components of cranes, heavy loads, and the fuel 

handling system components within the scope of license renewal as all load carrying 

components associated with heavy load handling systems and light load refueling handling 

systems, which provide structural support to safety-related components relied upon to remain 

functional to ensure satisfactory accomplishment of any of the functions identified in

10 CFR 54.4(a)(1) and/or provide structural support to nonsafety-related components whose 

failure, per 10 CFR54.4(a)(2), could prevent satisfactory accomplishment of any of the functions 

identified in 10 CFR 54.4(a)(1). Cranes included are the containment polar cranes, turbine 

building cranes, auxiliary building crane, spent fuel pool bridge crane, crane above safeguard 

traveling screens, manipulator cranes and special lifting devices. In LRA Table 2.4.3-1, the 

applicant identifies the components it believes are subject to AMR for the cranes, heavy loads, 

and fuel handling systems by component type and intended function. In the first column of LRA 

Table 3.5.2-3, the applicant lists the SCs included within each of the component type groups in 

LRA Table 2.4.3-1.

2.4.3.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.3, the first three columns of LRA Table 3.5.2-3, and UFSAR

Sections 10.2, 12.2, UFSAR Tables 12.2-1 and 12.2-40, and UFSAR Figure 10.2-1 using the 

evaluation methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA

and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 

SCs with intended functions, pursuant to 10 CFR 54.4(a). The staff then reviewed those SCs 

that the applicant has identified as within the scope of license renewal to verify that the applicant 

has not omitted any passive and long-lived SCs subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1).

The staff’s review of LRA Section 2.4.3 identified an area in which additional information was 

necessary to complete the review of the applicant’s scoping and screening results, to determine 

whether the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening 

criteria of 10 CFR 54.21(a)(1). The applicant responded to the staff’s RAI as discussed below.

In RAI 2.4.3-1, dated December 1, 2008, the staff noted that in UFSAR Section 12.2.6, the 

applicant states that in order to assure the stability and prevent toppling and over-traveling of 

the containment polar crane or its components, the features incorporated in its design include 

the following: (i) up-kick lugs fastened to each truck; (ii) overturning locks fastened to each 

truck; and (iii) positive wheel stops. Also, in UFSAR Section 12.2.9, the applicant indicates that 

the spent fuel pool bridge crane, auxiliary building crane and the turbine building crane are 

protected against tipping, derailments and uncontrolled movements by features that include the 
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following: (i) crane bridge and trolley being equipped with fixed, fitted rail yokes; and (ii) positive 

wheel stops and bumpers. From LRA Section 2.4.3, Table 2.4.3-1 and Table 3.5.2-3, it was not 

clear to the staff whether the above noted structural components and fasteners of the cranes 

are included in-scope of license renewal and subject to an AMR. The staff requested the 

applicant to confirm that these crane components have been screened in as items requiring an 

AMR, and if so, to indicate where these items have been included in the LRA, and if not, to 

provide the technical bases for their exclusion.

In its response, dated December 11, 2008, the applicant stated that structural components and 

fasteners for the containment polar crane (up-kick lugs, overturning locks, positive wheel stops), 

spent fuel pool bridge crane, auxiliary building crane, and the turbine building crane (fixed, fitted 

rail yokes, and positive wheel stops and bumpers) identified in Sections 12.2.6 and 12.2.9 of the 

UFSAR, are in-scope of license renewal and subject to an AMR. The applicant further clarified 

that these components were characterized as miscellaneous load carrying components included 

in the description in LRA Section 2.4.3, and also included in LRA Table 2.4.3-1 under the 

component heading, “Cranes-Rails” and “Cranes-Structural Girders.” The applicant also clarified 

that these components are further defined in Table 3.5.2-3 as “Cranes - structural girders (load 

carrying structural members, welded and bolted connections ....),” and “Cranes-rails (rails and 

associated welded and bolted connections ....).” The applicant noted that bumpers are 

considered subcomponents of the crane structural assembly and are not explicitly called out. 

Based on its review, the staff finds the applicant’s response to RAI 2.4.3-1 acceptable because 

the applicant has confirmed that the specific crane structural components described in RAI 

2.4.3-1 are within the scope of LR and subject to AMR, and are either characterized as 

miscellaneous load carrying components or considered subcomponents of the crane structural 

assembly. The applicant further clarified that these components were included in LRA Table 

2.4.3-1 as part of the component heading, “Cranes - Rails” and “Cranes - Structural Girders” 

and were further defined in LRA Table 3.5.2-3 as part of “Cranes - structural girders (load 

carrying structural members, welded and bolted connections ....),” and “Cranes - rails (rails and 

associated welded and bolted connections ....).” The staff confirmed that these component 

headings were provided in LRA Tables 2.4.3-1 and 3.5.2-3. Thus, the staff’s concerns described 

in RAI 2.4.3-1 are resolved.

2.4.3.3 Conclusion 

The staff reviewed the LRA, RAI response, UFSAR, and related structural components to 

determine whether the applicant failed to identify any SCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the cranes, heavy loads, and fuel handling system SCs within the scope of license 

renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1).
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2.4.4 D5/D6 Diesel Generator Building and Underground Storage Vault, 

Fuel Oil Transfer House, Old Service Building, and New Service Building

2.4.4.1 Summary of Technical Information in the Application 

LRA Section 2.4.4 describes the D5/D6 diesel generator building and underground storage 

vault, fuel oil transfer house, old service building, and new service building. The D5/D6 diesel 

generator building is a safety-related reinforced concrete structure supported on a 4-foot-thick 

step-down independent mat foundation, located along the west wall of the Auxiliary Building and 

houses safety-related SSCs including the D5 and D6 diesel generators. Compressible material 

is used to achieve the specified spacing between the D5/D6 diesel generator building and 

adjacent auxiliary and turbine buildings. Exterior flood panels protect equipment from water 

intrusion from a design flood. 

Four safety-related fuel oil storage tanks are located in the Underground Storage Vault along 

the west wall of the D5/D6 diesel generator building. The safety-related reinforced concrete 

vault is a rectangular structure founded on engineered fill, consisting of a minimum 2-foot-thick 

foundation mat, 1.67-foot-thick exterior walls, and the 1.5-foot-thick roof slab at grade level. 

W24 x 84 steel beams are used to support the vault roof slab and other design loads. A 1-footthick internal partition wall divides the vault into two compartments. The walls provide fire and 

flood protection between each diesel generator set’s fuel supply equipment. The vault provides 

the required 3-hour rated fire protection barrier, as do vault penetrations at the D5/D6 interface. 

Additionally, the vault is designed to withstand the effects of tornado generated missiles, site 

flood, buoyancy forces, seismic loads, and vehicular traffic on its roof. 

The fuel oil transfer house, also known as the filter house, is a small structure located northeast 

of the Turbine Building. The structure is supported on reinforced concrete footings poured at an 

elevation of 689-feet and 9-inches, and reinforced concrete walls up to an elevation of 694 feet. 

A 1-foot-thick reinforced concrete floor slab rests on top of the concrete walls. Masonry block 

walls make up the exterior walls above the floor slab and extend up to the roof at an elevation of 

708 feet and 2 inches. Components in-scope of license renewal are located below the concrete 

floor slab. 

The old service building is a multi-level reinforced concrete and steel framed structure with its 

foundation in continuity with the Auxiliary/Turbine/Shield Building complex. It houses the 

safety-related D1/D2 emergency diesel generators and other nonsafety-related SSCs. 

The new service building is a three-story steel framed structure located adjacent to the east 

walls of the old service building and Turbine Building. Its reinforced concrete foundation is built 

on grade and is designed to accommodate various existing buried components including the 

circulating water concrete pipes. The D1/D2 fuel oil tank supply and return lines from the Fuel 

Oil Transfer House run through the concrete support bridges under the New Service Building 

ground floor. Housed within the structure are the 480-volt buses, batteries, and associated cable 

trays and conduits that are components relied on to perform a function in compliance with the 

SBO regulated event, as are the non-safeguards uninterruptible power supply and event 

monitoring inverters that are relied upon to perform a function in compliance with the ATWS 

regulated event. 
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In LRA Table 2.4.4-1, the applicant identifies the components it believes are subject to an AMR 

for the D5/D6 diesel generator building and underground storage vault, fuel oil transfer house, 

old service building, and new service building by component type and intended function. In the 

first column of LRA Table 3.5.2-4, the applicant lists the SCs included within each of the 

component type groups in LRA Table 2.4.4-1.

2.4.4.2 Conclusion 

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA 

Section 2.4.4, the first three columns of LRA Table 3.5.2-4, LR drawing LR-193817 and UFSAR

Sections 1.3.2, 1.3.10, 7.11 and 12.2 to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant failed to identify any SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the D5/D6 diesel generator building and 

underground storage vault, fuel oil transfer house, old service building, and new service building 

SCs within the scope of license renewal, as required by 10 CFR 54.4(a), and those subject to 

an AMR, as required by 10 CFR 54.21(a)(1).

2.4.5 Fire Protection Barriers 

2.4.5.1 Summary of Technical Information in the Application 

LRA Section 2.4.5 describes the fire protection barriers, which provide fire protection to plant 

SSCs important to nuclear safety so that safe shutdown can be achieved and maintained. 

Additionally, fire protection barriers are relied on to minimize the effects of a fire and to prevent 

the release of radiation to the environment. PINGP is divided into separate fire areas by 

concrete walls, floors, and ceilings, referred to as principal fire barriers. Openings or 

penetrations in principal fire barriers that allow passage of personnel, material or SSCs are 

sealed with fireproofing materials or fire-rated doors to prevent fire from spreading from one 

area to another. These fire protection barriers are intended to maintain the fire-resistive integrity 

of the principal barrier. In LRA Table 2.4.5-1, the applicant identifies the components it believes 

are subject to AMR for the fire protection barriers by component type and intended function. In 

the first column of LRA Table 3.5.2-5, the applicant lists the SCs included within each of the 

component type groups in LRA Table 2.4.5-1.

2.4.5.2 Conclusion 

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA

Section 2.4.5, the first three columns of LRA Table 3.5.2-5 and UFSAR Section 10.3 to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the fire protection barriers SCs within the scope of license renewal, as required by 

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).
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2.4.6 Radwaste Building, Old Administration Building, and Administration Building 

Addition 

2.4.6.1 Summary of Technical Information in the Application 

LRA Section 2.4.6 describes the radwaste building, old administration building, and the 

administration building addition. The radwaste building is a concrete and steel framed structure 

with an insulated metal siding exterior and is supported by mat foundation and perimeter 

footings. The radwaste building houses radioactive waste handling, treatment, storage, 

collection and disposal facilities for both units. The radwaste building components such as 

sumps, dikes, curbs, walls, or vaults are specifically constructed to retain any spilled liquids. 

The rectangular steel-framed old administration building with insulated metal siding is part of the 

original construction and is located adjacent to the north wall of the turbine building with its 

center portion located immediately above the safety-related reinforced concrete aisle of the 

turbine building. In order to meet space requirements for offices, storage areas, lockers, etc, a 

five-story administration building addition with reinforced concrete footings and pier foundations 

was later constructed. The addition is a U-shaped structure that wraps around the north, east, 

and west sides of the old administration building. 

The applicant identified the radwaste building, old administration building and administration 

building addition as in-scope of LR based on 10 CFR 54.4(a)(2) criterion since they are located 

adjacent to the auxiliary and turbine buildings. In LRA Table 2.4.6-1, the applicant identifies the 

components subject to an AMR for the radwaste building, old administration building, and 

administration building addition by component type and intended function. In the first column of 

LRA Table 3.5.2-6, the applicant lists the SCs included within each of the component type 

groups in LRA Table 2.4.6-1.

2.4.6.2 Conclusion 

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA 

Section 2.4.6, the first three columns of LRA Table 3.5.2-6, LR drawing LR-193817, and UFSAR

Sections 1.3.2, 1.3.10, 9.2, and 12.2 to determine whether the applicant failed to identify any 

SSCs within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant failed to identify any SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the radwaste building, old administration 

building, and the administration building addition SCs within the scope of license renewal, as 

required by 10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.4.7 Reactor Containment Vessels, Unit 1 and Unit 2

2.4.7.1 Summary of Technical Information in the Application 

LRA Section 2.4.7 describes the reactor containment vessels (RCV) for Units 1 and 2, which 

form the primary containment system. The RCV for each unit is a free-standing, low-leakage 

steel vessel, including penetrations, isolation systems, and heat removal systems designed to 

withstand the internal pressure accompanying a loss-of-coolant accident. The RCV consists of 

steel cylinder walls, a hemispherical dome, and an ellipsoidal bottom. A five-foot wide-annular 
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space between the RCV walls and the shield building walls, and a seven-foot clearance 

between the top of the vessel and shield building roof dome allows for maintenance and visual 

inspection of the RCV. The RCV internal structures are, for the most part, conventional 

reinforced concrete. The concrete forms floor slabs and compartments that support and protect 

the reactor pressure vessel (RPV) and components associated with engineered safeguards 

systems, and it provides the primary biological shield for the RPV. The RCV major internal 

structural components include the reactor/refueling cavity/biological shield wall, the steam 

generator and pressurizer vaults, the refueling floor, operating floor, the mezzanine floor, and 

the basement floor. In LRA Table 2.4.7-1, the applicant identifies the components it believes are 

subject to an AMR for the reactor containment vessels by component type and intended 

function. In the first column of LRA Table 3.5.2-7, the applicant lists the SCs included within 

each of the component type groups in LRA Table 2.4.7-1.

2.4.7.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.7, the first three columns of LRA Table 3.5.2-7, LR drawing 

LR-19381, UFSAR Sections 5.1, 5.2, 12.2, and 12.3 using the evaluation methodology 

described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has not omitted, from the scope of license renewal, any 

SCs with intended functions, pursuant to 10 CFR 54.4(a). The staff then reviewed those SCs, 

that the applicant has identified as within the scope of license renewal, to verify that the 

applicant has not omitted any passive and long-lived SCs subject to an AMR, in accordance 

with the requirements of 10 CFR 54.21(a)(1).

The staff’s review of LRA Section 2.4.7 identified areas in which additional information was 

necessary to complete the review of the applicant’s scoping and screening results, to determine 

whether the applicant properly applied the scoping criteria of 10 CFR 54.4(a) and the screening 

criteria of 10 CFR 54.21(a)(1). The applicant responded to the staff’s RAIs as discussed below.

In RAI 2.4.7-1, dated December 1, 2008, the staff noted that in LRA Section 2.4.7, the system 

function listing under Code RCV-04, “Reactor Containment Vessels and their internal structures 

provide shielding against high energy line breaks,” indicates scoping under 10 CFR 54.4(a)(2)

and corresponds to all nonsafety-related systems, structures and components, whose failure 

could prevent satisfactory accomplishment of any of the functions identified in 10 CFR 

54.4(a)(1). The staff further noted that the comment under this item on LRA page 2.4-38 states 

that, “Reactor Containment Vessels and their internal structures are designed to withstand the 

effects of high-energy line breaks without loss of function. Reinforced concrete walls and steel 

structures inside each Reactor Containment Vessel shield safety-related equipment from the 

effects of an HELB.” The staff noted that the above stated structures and structural components 

are generally safety-related and are in-scope in accordance with 10 CFR 54.4(a)(1), and 

requested the applicant to address the apparent inconsistency.

In its response, dated December 11, 2008, the applicant stated that 10 CFR 54.4(a)(2), as it 

applies to Code RCV-04 on page 2.4-38 of the LRA, is used to describe the HELB protection 

function applicable to certain nonsafety-related concrete and steel structures inside each 

Reactor Containment Vessel including whip restraints and jet impingement shields whose only 
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function is to provide HELB protection for safety-related equipment. The applicant added that 

NEI 95-10, Appendix F, Section 3.4 states that:

“NSR whip restraints, jet impingement shields, blowout panels, etc., that are 

designed and installed to protect SR equipment from the effects of a HELB, are 

within the scope of license renewal per 10 CFR 54.4(a)(2).” 

The applicant further explained that there are also concrete and steel structures inside the 

reactor containment vessels that perform an HELB function in combination with safety-related 

functions such as missile protection and structural support to safety-related components. In an 

attempt to avoid confusion, the HELB system function was only used to identify nonsafetyrelated structures whose only function is to provide HELB protection for safety-related 

equipment. The applicant added that LRA Table 3.5.2-7 provides a list of safety-related 

concrete and steel structures with multiple functions, one of which is HELB protection.

Based on its review, the staff finds the applicant’s response to RAI 2.4.7-1 acceptable because 

the applicant clarified and explained that 10 CFR 54.4(a)(2), as it applies to Code RCV-04 on 

page 2.4-38 of the LRA, is only used to describe the HELB protection function applicable to 

certain nonsafety-related concrete and steel structures such as whip restraints and jet 

impingement shields inside each Reactor Containment Vessel whose only function is to provide 

HELB protection for safety-related equipment. Therefore, the staff confirms that 10 CFR 

54.4(a)(2) is appropriate for including such nonsafety-related components that perform only an 

HELB function in-scope of LR. Thus, the staff’s concern described in RAI 2.4.7-1 is resolved.

Because of lack of clarity in LRA Tables 2.4.2-1, 2.4.7-1, 3.5.2-2, 3.5.2-7 and the corresponding 

LRA sections, in RAI 2.4.7-2 dated December 1, 2008, the staff requested the applicant to

identify the portions of the LRA that address the scoping, screening and AMR results of 

structural supports (vertical and lateral, as appropriate) for steam generators, reactor coolant 

pumps and the reactor vessel included or, if excluded, to justify their exclusion.

In its response to RAI 2.4.7-2, dated December 11, 2008, the applicant stated that supports for 

the reactor vessels, steam generators, and reactor coolant pumps are identified in the PINGP 

UFSAR, Section 12.2.4 and Table 12.2-1, as Class 1 structures consistent with Chapter III.B1.1 

of NUREG-1801. LRA Table 3.5.2-2 refers to them by the component type, “Support (Class 1 

vessels, exchangers, and pumps).” The applicant noted that only the Unit 2 steam generator 

supports and the Unit 1 and Unit 2 reactor coolant pump supports are installed using high 

strength bolts; and, therefore, Table 3.5.2-2 specifically identifies these supports for this 

application. The applicant further clarified that LRA Section 2.4.2 includes a list of in-scope 

component supports, which includes pressure vessels, heat exchangers, and pumps, and 

LRA Table 2.4.2-1 combines all in-scope supports under the component heading, “Support.” 

Based on its review, the staff finds the applicant’s response to RAI 2.4.7-2 acceptable because 

the applicant has confirmed that the structural supports for steam generators, reactor coolant 

pumps and the reactor vessel are in-scope of LR and subject to an AMR and clarified that they 

are included as part of the component type “Support” in LRA Table 2.4.2-1 and as part of the 

component type line items, “Support (members, connections, and anchorage to building 

structure for Class 1 vessels, exchangers, pumps, valves, piping, insulation and miscellaneous 

equipment items)” and “Support (high strength bolts for Unit 2 steam generators and Units 1 and 
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2 reactor coolant pumps)” in LRA Table 3.5.2-2. The staff confirmed that these line items were 

included in LRA Tables 2.4.2-1 and 3.5.2-2, and that the description in LRA Section 2.4.2 

included support members for pumps, heat exchangers and vessels (Reference LRA pages 2.4-

10 and 2.4-11), as stated by the applicant. The staff also confirmed that steam generators, 

reactor coolant pumps and the reactor vessel and their supports are classified as Class 1 in 

UFSAR Table 12.2. Thus, the staff’s concern described in RAI 2.4.7-2 is resolved.

2.4.7.3 Conclusion 

The staff reviewed the LRA, UFSAR, RAI responses, and related structural components to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that there is reasonable assurance 

that the applicant has adequately identified the RCVs (Units 1 and 2) SCs within the scope of 

license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1). 

2.4.8 SBO Yard Structures

2.4.8.1 Summary of Technical Information in the Application 

LRA Section 2.4.8 describes the SBO yard structures system that include SSCs that serve a 

structural function related to supporting certain electrical equipment and conductors required to 

restore offsite power following an SBO event defined in 10 CFR 50.63. Some of this same 

equipment is also used to supply offsite power for safe shutdown in response to certain fire 

scenarios postulated in accordance with 10 CFR 50.48. Offsite power is restored to vital buses 

in Unit 1 following SBO via the 1R or CT-11 transformers, and to vital buses in Unit 2 via the 

2RS or CT-12 transformers.

The substation control house, a steel framed and metal sided single story building supported by 

a concrete slab and located in the switchyard, houses the electrical controls, metering devices 

and emergency power sources essential to the operation of the switchyard equipment. 

The cooling tower equipment house, a single story concrete block building supported by a 

concrete slab and located outside of the protected area fence about 400 feet south of the Unit 1 

Reactor Building, contains circulating water system electrical equipment as well as equipment 

used to route electrical power during recovery from a SBO event. 

Three transmission towers support the 161 kilo-volt conductors that run from the disconnect in 

the switchyard to the 1R transformer, which is adjacent to the north side of the turbine building. 

The 68-foot-high steel towers are supported on concrete piers that extend down to concrete 

foundation slabs placed on granular soil about 7.5 feet below grade. 

Outdoor electrical equipment support structures within the scope of the SBO yard structures 

system are those that support power transformers, transformer oil tanks, disconnects, breakers, 

control/metering devices, bus duct and rigid insulators. 
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The single manhole structure within the scope of the SBO yard structures system is located 

about 100 feet west of the security building and provides access to splices in the 13.8 kV cables 

that run from the switchyard to the cooling tower equipment house. The structure, which has no 

bottom slab, is a pre-fabricated concrete box founded on granular soil about 8.5 feet below plant 

grade.

In LRA Table 2.4.8-1, the applicant identifies the components it believes are subject to AMR for 

the SBO yard structures by component type and intended function. In the first column of LRA 

Table 3.5.2-8, the applicant lists the SCs included within each of the component type groups in 

LRA Table 2.4.8-1.

2.4.8.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.8, the first three columns of LRA Table 3.5.2-8, LR drawing 

LR-193817 and UFSAR Section 8 using the evaluation methodology described in SER 

Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has not omitted, from the scope of license renewal, any 

SCs with intended functions, pursuant to 10 CFR 54.4(a). The staff then reviewed those SCs, 

that the applicant has identified as within the scope of license renewal, to verify that the 

applicant has not omitted any passive and long-lived SCs subject to an AMR, in accordance 

with the requirements of 10 CFR 54.21(a)(1).

During its review of LRA Sections 2.4.8, the staff identified an area in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for structures. Therefore, the staff issued an RAI concerning the specific issue, to 

determine whether the applicant properly applied the scoping criteria pursuant to 

10 CFR 54.4(a) and the screening criteria in accordance with 10 CFR 54.21(a)(1). The following 

discussion describes the staff’s RAI related to LRA Section 2.4.8 and the applicant’s response.

In RAI 2.4.8-1, dated December 1, 2008, the staff requested the applicant to state whether there 

are any ductbanks and manholes in the yard that are safety-related or important-to-safety or 

required for regulated events that may be within the scope of license renewal and subject to an 

AMR, and if so, to provide their scoping, screening and AMR results.

In its response to RAI 2.4.8-1, dated December 11, 2008, the applicant stated that there are no 

ductbanks in-scope of license renewal, and only one manhole is in-scope of LR and subject to 

an AMR. The applicant explained that the single manhole, in-scope for the SBO regulated 

event, is located about 100 feet west of the security building and is described in LRA Section 

2.4.8. It provides access to splices in the 13.8 kilo-volt cables that run from the switchyard to the 

cooling tower equipment house. The applicant stated that LR Boundary drawing LR-193817, 

entitled, “PINGP Site Layout of the Owner Controlled Area,” provides its location (Item 57, 

coordinate D6). The applicant also stated that LRA Table 2.4.8-1 identified its components as 

“Concrete” and “Steel Components” and that LRA Table 3.5.2-8 further defines the concrete 

portion of the structure as “Concrete (cable vault),” and its metal components as “Steel 

components (miscellaneous structures/equipment items).” The applicant added that aging 
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effects for the manhole structure are managed by the Structures Monitoring Program based on 

the results of the AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.4.8-1 acceptable because 

the applicant has confirmed that there are no ductbanks that are in-scope of license renewal 

and clarified that the SCs of the one manhole structure that is in-scope of license renewal, and 

subject to an AMR, were included as part of line items “Concrete” and “Steel Components” in 

LRA Table 2.4.8-1. The applicant further clarified that LRA Table 3.5.2-8 further defines the 

concrete portion of the structure as part of line item “Concrete (cable vault),” and its metal 

components as part of line item “Steel components (miscellaneous structures/equipment 

items).” The staff confirms that these line items were included in the stated LRA tables. 

Therefore, the staff’s concerns described in RAI 2.4.8-1 are resolved.

2.4.8.3 Conclusion 

The staff reviewed the LRA, UFSAR, the RAI response, and related structural components to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the SBO 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).

2.4.9 Shield Buildings, Unit 1 and Unit 2

2.4.9.1 Summary of Technical Information in the Application 

LRA Section 2.4.9.1 describes shield buildings for Units 1 and 2. The shield building for each 

unit is a medium leakage conventional reinforced concrete cylinder with a shallow dome roof 

and a mat foundation. Each shield building encloses the reactor containment vessel, the access 

openings, the equipment hatch, and that portion of all penetrations that are associated with the 

primary containment. The annular space between the RCV and the shield building allows for 

building maintenance and visual inspection of the reactor containment vessel. The mat 

foundation is common to the reactor containment vessel and also has structural continuity, 

provided by keyed construction joints, with auxiliary building and turbine building foundations. 

Each shield building, with its penetration seals and ventilation system, forms a secondary 

containment system. Its cylindrical reinforced concrete serves as radiation shielding during 

normal operation. Following a loss of coolant accident (LOCA), potential fission-product leakage 

into the annular space between the shield building and reactor containment vessel is captured 

by the shield building vent system, which continuously filters and recirculates annulus air. 

Following a LOCA, the shield building’s vent system must be capable of bringing the annulus to 

a negative pressure with respect to the auxiliary building, and then maintaining a negative 

pressure. The shield building is primarily a shielding structure and, as such, it is not subjected to 

the internal pressure loads of the containment pressure vessel. 

In LRA Table 2.4.9-1, the applicant identifies the components it believes are subject to AMR for 

the shielding building (Unit 1 and Unit 2) by component type and intended function. In the first 
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column of LRA Table 3.5.2-9, the applicant lists the SCs included within each of the component 

type groups in LRA Table 2.4.9-1.

2.4.9.2 Conclusion 

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA 

Section 2.4.9, the first three columns of LRA Table 3.5.2-9, LR drawing LR-193817, and UFSAR

Sections 5.3, and 12.2 to determine whether the applicant failed to identify any SSCs within the 

scope of license renewal. In addition, the staff’s review determined whether the applicant failed 

to identify any SCs subject to an AMR. On the basis of its review, the staff concludes that the 

applicant has adequately identified the shielding 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).

2.4.10 Tank Foundations 

2.4.10.1 Summary of Technical Information in the Application 

LRA Section 2.4.10 describes the tank foundations. There are seven diesel fuel oil storage 

tanks, supported on reinforced concrete mat foundations, which are directly buried on site, and 

are used to supply fuel oil to the D1/D2 diesel generators, two diesel driven cooling water 

pumps, and a diesel-driven fire pump.

Four tanks, supplying fuel to the D1/D2 diesel generators, are buried east of the old service 

building. Two tanks, supplying fuel oil to the diesel driven cooling water pumps, are buried east 

of the screenhouse. The remaining tank supplies fuel oil to the diesel-driven fire pump located in 

the screenhouse. 

There are three condensate storage tanks on site and are supported on reinforced concrete 

slabs on grade. The #11 Unit 1 storage tank is located east of the turbine building, and #21 and 

#22 Unit 2 storage tanks are located south of the D5/D6 diesel generator building. The 

condensate storage tanks provide normal and emergency makeup water to the condensate 

system, and also provide water for the AF system and suction head to the AF pumps. 

The fuel oil receiving tank, supported on a raised reinforced concrete foundation surrounded by 

a concrete dike wall, is the piping design anchor point for one 2" pipe and one 3" pipe that are 

in-scope of license renewal based on criterion 10 CFR 54.4(a)(2). 

In LRA Table 2.4.10-1, the applicant identifies the components subject to AMR for the tank 

foundations by component type and intended function. In the first column of LRA Table 3.5.2-10, 

the applicant lists the SCs included within each of the component type groups in LRA Table 

2.4.10-1.

2.4.10.2 Conclusion

The staff followed the evaluation methodology discussed in Section 2.4 and reviewed LRA 

Section 2.4.10, the first three columns of LRA Table 3.5.2-10, LR drawing LR-193817 and 

UFSAR Sections 10.3 and 11.9 to determine whether the applicant failed to identify any SSCs 
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within the scope of license renewal. In addition, the staff’s review determined whether the 

applicant failed to identify any SCs subject to an AMR. On the basis of its review, the staff 

concludes that the applicant has adequately identified the tank foundation SCs within the scope 

of license renewal, as required by 10 CFR 54.4(a), and those subject to an AMR, as required by 

10 CFR 54.21(a)(1).

2.4.11 Water Control Structures-Approach Canal, Emergency Cooling Water Intake, 

Intake Canal, and Screenhouse

2.4.11.1 Summary of Technical Information in the Application 

LRA Section 2.4.11 describes the water control structures, which include the Approach Canal, 

the emergency cooling water intake, the intake canal, and the screenhouse. 

The Approach Canal is a body of water that extends from the main flow of the Mississippi River 

to the intake screenhouse and is classified as safety-related. During normal plant operations, 

the approach canal’s primary purpose is to direct water from the Mississippi River to the intake 

screenhouse located northeast of the powerhouse. During a postulated DBE, the approach 

canal supplies water to the emergency cooling water intake (ECI) line.

The ECI is a safety-related structure that serves as an inlet to the 36 inch emergency cooling 

water pipe located in the Approach Canal that runs from the ECI to the screenhouse where it 

supplies the emergency cooling water bay. The purpose of the ECI is to provide an alternate 

source of cooling water suction, with the intake canal, for the safety-related cooling water pumps 

located in the screenhouse needed to maintain safe shutdown of both units after a DBE. 

The intake canal is a safety-related body of water that extends from the intake screenhouse 

located northeast of the powerhouse, to the screenhouse located just north of the powerhouse. 

The intake canal’s primary purpose is to direct water from the Intake screenhouse to the 

screenhouse to use as a source of plant cooling water. During normal plant operations, the 

intake canal supplies cooling water suction to the circulating water pumps located in the 

screenhouse. During a postulated DBE, the intake canal supplies water to the circulating water 

bays and emergency intake bay located within the screenhouse where it supplies the safetyrelated cooling water pumps to facilitate plant shutdown.

The screenhouse is a stand-alone reinforced concrete and steel framed structure shared by the 

two units, and is located north of the turbine-auxiliary-shield building complex. The screenhouse 

structure provides shelter and protection to several safety-related pumps and associated piping 

and equipment. Water flows from the intake canal into the screenhouse, past the trash racks 

and traveling screens, and into the cooling water pump bays. 

In LRA Table 2.4.11-1, the applicant identifies the components it believes are subject to an AMR

for the water control structures, which include the approach canal, the emergency cooling water 

intake, the intake canal, and the screenhouse by component type and intended function. In the 

first column of LRA Table 3.5.2-11, the applicant lists the SCs included within each of the 

component type groups in LRA Table 2.4.11-1.
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2.4.11.2 Staff Evaluation 

The staff reviewed LRA Section 2.4.11, the first three columns of LRA Table 3.5.2-11, LR 

drawing LR-193817, and UFSAR Sections 1.3.2, 1.3.10, 10.4 and 12.2 using the evaluation 

methodology described in SER Section 2.4 and the guidance in SRP-LR Section 2.4.

During its review, the staff evaluated the structural component functions described in the LRA 

and UFSAR to verify that the applicant has not omitted from the scope of license renewal any 

SCs with intended functions, pursuant to 10 CFR 54.4(a). The staff then reviewed those SCs 

that the applicant has identified as within the scope of license renewal to verify that the applicant 

has not omitted any passive and long-lived SCs subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1).

During its review of the LRA Section 2.4.11, the staff identified an area in which additional 

information was necessary to complete the evaluation of the applicant’s scoping and screening 

results for structures. Therefore, the staff issued an RAI concerning the specific issue, to 

determine whether the applicant properly applied the scoping criteria pursuant to 

10 CFR 54.4(a) and the screening criteria in accordance with 10 CFR 54.21(a)(1). The following 

discussion describes the staff’s RAI related to the LRA Section 2.4.11 and the applicant’s 

response.

In RAI 2.4.11-1, dated December 1, 2008, the staff noted that Section 1.3.2 of the UFSAR

states that the plant screenhouse houses the cooling water pumps, fire pumps, circulating water 

pumps, trash racks and traveling screens. Due to lack of clarity in LRA Tables 2.4.11-1 and 

3.5.2-11, the staff requested the applicant to confirm the inclusion or exclusion of the trash racks 

and traveling screens as structural components within the scope of license renewal and subject 

to an AMR, and accordingly address its scoping, screening and AMR or justify exclusion. 

In its response, dated December 11, 2008, the applicant stated that the trash racks and 

traveling screen support components are in-scope of license renewal, and the aging effects are 

managed by RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program. The applicant clarified that LRA Table 2.4.11-1 identifies the components as 

“Steel Components” and LRA Table 3.5.2-11 further defines the components as “Steel 

Components (screenhouse trash racks, safeguards traveling screen frames, safeguards bay 

gates, fasteners).” The applicant further clarified that the traveling screen portion of the screen 

assembly is active and therefore, does not require an AMR. 

Based on its review, the staff finds the applicant’s response to RAI 2.4.11-1 acceptable because 

the applicant has confirmed that trash racks and traveling screen support components are 

in-scope of license renewal, and subject to an AMR. The applicant clarified that these 

components are included as part of line item, “Steel Components” in LRA Table 2.4.11-1 and as 

part of line item, “Steel components (screenhouse trash racks, safeguards traveling screen 

frames, safeguards bay gates, fasteners)” in LRA Table 3.5.2-11, which the staff confirmed. The 

staff agrees that the traveling screen portion of the screen assembly is not subject to an AMR 

since it is an active component. Therefore, the staff’s concerns described in RAI 2.4.11-1 are 

resolved.
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2.4.11.3 Conclusion 

The staff reviewed the LRA, UFSAR, RAI response, and related structural components to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff’s review determined whether the applicant failed to identify any SCs subject 

to an AMR. On the basis of its review, the staff concludes that the applicant has adequately 

identified the water control structures—approach canal, emergency cooling water intake, intake 

canal, and screenhouse SCs—within the scope of license renewal, as required by 

10 CFR 54.4(a), and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5 

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 the following:

Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems 

2.5.1 Cables and Connections (Insulation), includes splices, terminations, fuse blocks 

and connectors

2.5.2 Cables and Connections Used in Instrumentation Circuits (Insulation), sensitive 

to reduction in conductor insulation resistance 

2.5.3 Inaccessible Medium Voltage Cables and Connections (Insulation), underground, 

buried 

2.5.4 Electrical Connector Contacts (metallic connector pins exposed to borated water)

2.5.5 Electrical Penetrations (electrical insulation portions)

2.5.6 Metal Enclosed Bus and Connections (Bus/Connections, Enclosure Assemblies, 

Insulation/Insulators)

2.5.7 Fuse Holders (metallic parts), not part of a larger active assembly

2.5.8 Cable Connections (metallic parts) 

2.5.9 Switchyard Bus and Connections

2.5.10 Transmission Conductors and Connections 

2.5.11 High-Voltage Insulators

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff's review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

electrical and I&C system components that meet the scoping criteria and 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 has identified, in accordance 

with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that 

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant’s 
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screening results to verify that all passive, long-lived components were subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections, focusing on 

components that have not been identified as within the scope of license renewal. The staff 

reviewed relevant licensing basis documents, including the UFSAR, for each electrical and I&C 

system to determine whether the applicant has omitted from the scope of license renewal 

components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed 

the licensing basis documents to determine whether the LRA specified all intended functions 

delineated under 10 CFR 54.4(a). The staff requested additional information to resolve any 

omissions or discrepancies identified.

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SCs with intended functions, the staff sought to determine whether (1) the functions are 

performed with moving parts or a change in configuration or properties or (2) the SCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SCs were subject to an AMR, as required by 10 CFR 54.21(a)(1). The staff requested 

additional information to resolve any omissions or discrepancies identified.

2.5.1 Electrical 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 default inclusion of plant electrical and I&C 

systems in the scope of license renewal reflects the method for the integrated plant 

assessments (IPA) of electrical systems. This method is different from those for mechanical 

systems and structures. 

The basic philosophy of the electrical and I&C components IPA is that components are included 

in the scoping review unless specifically screened out. The electrical and I&C IPA began by 

grouping all components into commodity groups of similar electrical and I&C components with 

common characteristics and by determining component level intended functions of the 

commodity groups.

The IPA eliminated commodity groups and specific plant systems from further review as the 

intended functions of commodity groups were examined. In addition to the plant electrical 

systems, certain switchyard components required to restore offsite power following SBO were 

included conservatively within the scope of license renewal even though those components are 

not relied on in safety analyses or plant evaluations for functions that demonstrate compliance 

with the SBO regulations. The offsite power system evaluation boundaries are described next.

The offsite power system provides the electrical interconnection between PINGP and the offsite 

transmission network. The offsite power sources required to support SBO recovery actions 

supply the CT-11 transformer (345kv disconnect), CT-12 transformer (13.8kv disconnect), 1R 

(161 kV) and 2RS (345 kV) transformers as stated in section 2.5 of the April 11, 2008 LRA ,
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Enclosure 1, of the applicant’s letter dated May 16, 2008, and the applicant’s letter dated 

December 11, 2008, the applicant specifically stated that the offsite power recovery path 

includes the No. 1 cooling tower transformer, No.10 transformer, transformers 1R (161 kV) and 

2RS (345 kV), the 345 kV and 161 kV switchyard circuit breakers supplying the No. 1 cooling 

tower transformer, the No.10 transformer, the 1R and 2RS transformers, the circuit breaker-totransformer and transformer-to-onsite electrical distribution interconnections, control circuits, 

and structures.

LRA Table 2.5-1 identifies electrical and I&C systems component types within the scope of 

license renewal and subject to an AMR: 

• cable connections (metallic parts)

• electrical cables and connections (insulations), splices, terminations, fuse holders, 

connectors not subject to 10 CFR 50.49 EQ requirements

• electrical cables and connections not subject to 10 CFR 50.49 EQ requirements in 

instrumentation circuits

• electrical connections not subject to 10 CFR 50.49 EQ requirements exposed to borated 

water leakage

• fuse holders - metallic parts

• high-voltage insulators

• inaccessible medium-voltage (2kV to 35kV) cables and connections (e.g., underground 

in conduit or direct buried) not subject to 10 CFR 50.49 EQ requirements

• metal enclosed bus (non-segregated bus), bus/connections (Units 1 and 2)

• metal enclosed bus (non-segregated bus), enclosure assemblies (Units 1 and 2)

• metal enclosed bus and connections (enclosure assembly-seals)

• electrical penetrations (electrical insulation portions)

• metal enclosed bus (non-segregated bus), insulation/insulators (Units 1 and 2)

• switchyard bus (switchyard bus for SBO recovery) and connections (Units 1 and 2)

• transmission conductors (transmission conductors for SBO recovery path) and 

connections

The intended functions of the electrical and I&C systems component types within the scope of 

license renewal include:

  electrical connections to electrical circuit sections for voltage, current, or signal delivery

  electrical conductor insulation and support

  structural or functional support to safety-related equipment
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2.5.1.2 Staff Evaluation 

The staff reviewed LRA Section 2.5 and Unit 1 and Unit 2 UFSAR 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 UFSAR 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).

General Design Criterion 17 of 10 CFR Part 50, Appendix A, requires, in part, 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, "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 the following: 

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.

In its original application dated April 11, 2008, the applicant described the SBO recovery path 

that was in the scope of license renewal. The applicant initially stated that the SBO recovery 

path included all the components and connections from offsite power source including 

switchyard transformers, high side disconnects, conductors, transformers, buses up to the 

PINGP Units 1 and 2 safeguards buses. In a letter dated May 16, 2008, the applicant revised 

the scope of the SBO recovery path for license renewal purposes to include all components 

starting from the transmission line breakers, conductors and connections, up to the safeguard 

buses in both PINGP Units. The staff finds that the revised scope of the license renewal SBO 

recovery path is consistent with the scope of NUREG 1801, Revision 1, and, therefore, is 

acceptable. In addition, the applicant also revised Section 2.5.10 of the LRA in the May 16, 

2008 letter to reflect the revised scope of the license renewal SBO recovery path. The staff finds 

that the revision to Section 2.5.10 of the LRA is consistent with NUREG 1801, Revision 1, and, 

therefore, is acceptable. 
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During its review of LRA Section 2.5, the staff identified a need for additional information and 

therefore issued RAI 2.5 dated November 20, 2008, regarding the inclusion of control circuits of 

the switchyard circuit breakers (at the transmission voltage) in the scope of license renewal. 

In its response, dated December 11, 2008, the applicant stated that the control circuits for the 

switchyard circuit breaker are included in the scope of license renewal as they are part of the 

SBO recovery path. The staff finds that the applicant’s response is consistent with NUREG 

1801, Revision 1 and therefore is acceptable.

The staff reviewed Section 2.5 of the LRA and determined that further clarification on LRA 

Section 2.5.4 was warranted to ensure that scope described in this section is consistent with the 

scope described in NUREG 1801, Revision 1. The staff discussed this point of clarification with 

the applicant during a teleconference on January 09, 2009 which is described in the applicant’s 

request for additional information response letter dated January 16, 2009. Regarding LRA 

Section 2.5.4, the staff had a concern that the wording “metallic connector pins” was too specific 

and may not fully cover the scope of NUREG 1801, Revision 1. The applicant understood the 

staff’s concern and agreed to revise the “metallic connector pins” to “electrical connector 

contacts or electrical pin connectors or metallic connector pins” to be consistent with NUREG 

1801, Revision 1, and indicated that they will address this change in a formal letter. The staff 

verified this change by reviewing the applicant’s letter dated January 16, 2009, and finds that it 

is consistent with NUREG 1801, Revision 1, and therefore, is acceptable.

2.5.1.3 Conclusion 

The staff reviewed the LRA, UFSAR, and request for additional information responses to 

determine whether the applicant failed to identify any SSCs within the scope of license renewal. 

In addition, the staff sought to determine whether the applicant failed to identify any components 

subject to an AMR. On the basis of its review, the staff concludes that there is reasonable 

assurance that the applicant has adequately identified the electrical and I&C systems 

components within the scope of license renewal consistent with NUREG 1801, Revision 1, 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 

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review and 

Implementation Results” and determines that the applicant's scoping and screening 

methodology was consistent with 10 CFR 54.21(a)(1) and the staff's positions on the treatment 

of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs 

subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).

Conclusion for Scoping and Screening 

With regard to these matters the staff concludes that there is reasonable assurance that the 

applicant will continue to conduct the activities authorized by the renewed licenses in 

accordance with the CLB and any changes to the CLB in order to comply with 10 CFR 54.29(a), 

in accordance with the Atomic Energy Act of 1954, as amended, 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 Prairie Island Nuclear Generating Plant 

(PINGP), Units 1 and 2, by the staff of the U.S. Nuclear Regulatory Commission (NRC)/(the 

staff). In Appendix B of its license renewal application (LRA), Northern States Power, a 

Minnesota Corporation (NSPM or the applicant) described the 43 AMPs that it relies on to 

manage or monitor the aging of passive, long-lived structures and components (SCs).

In LRA Section 3, the applicant provided the results of the AMRs for those SCs identified in LRA 

Section 2 as within the scope of license renewal and subject to an AMR.

3.0 Applicant’s Use of the Generic Aging Lessons Learned Report

In preparing its LRA, the applicant credited NUREG-1801, Revision 1, “Generic Aging Lessons 

Learned (GALL) Report,” (the GALL Report) dated September 2005. The GALL Report contains 

the staff’s generic evaluation of the existing plant programs and documents the technical basis 

for determining where existing programs are adequate without modification, and where existing 

programs should be augmented for the period of extended operation. The evaluation results 

documented in the GALL Report indicate that many of the existing programs are adequate to 

manage the aging effects for particular license renewal SCs. The GALL Report also contains 

recommendations on specific areas for which existing programs should be augmented for 

license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its 

programs correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or 

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

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, 

improving the efficiency and effectiveness of the license renewal review process. The GALL 

Report also serves as a quick reference for applicants and staff reviewers to AMPs and 

activities that the staff has determined will adequately manage or monitor aging during the 

period of extended operation.

The GALL Report identifies the following: (1) systems, structures, and components (SSCs), 

(2) SC materials, (3) environments to which the SCs are exposed, (4) the aging effects of the 

materials and environments, (5) the AMPs credited with managing or monitoring the aging 

effects, and (6) recommendations for further applicant evaluations of aging management for 

certain component types.

To determine whether use of the GALL Report would improve the efficiency of LRA review, the 

staff conducted a demonstration of the GALL Report process in order to model the format and 

content of safety evaluations based on it. The results of the demonstration project confirmed 

that the GALL Report process will improve the efficiency and effectiveness of LRA review while 

maintaining the staff’s focus on public health and safety. NUREG-1800, Revision 1, “Standard 
3-2

Review Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR), 

dated September 2005, was prepared based on both the GALL Report model and lessons 

learned from the demonstration project.

The staff‘s review was in accordance with Title 10, Part 54, of the Code of Federal Regulations

(10 CFR Part 54), “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” 

and the guidance of the SRP-LR and the GALL Report.

In addition to its review of the LRA, the staff conducted an on-site audit of selected AMRs and 

associated AMPs, during the week of September 08, 2008. The onsite audits and reviews are 

designed for maximum efficiency of the staff’s LRA review. The applicant can respond to 

questions, the staff can readily evaluate the applicant’s responses, the need for formal 

correspondence between the staff and the applicant is reduced, and the result is an 

improvement in review efficiency.

3.0.1 Format of the License Renewal Application 

The applicant submitted an application that follows the standard LRA format agreed to by the 

staff and the Nuclear Energy Institute (NEI) by letter dated April 7, 2003 (ML030990052). This 

revised LRA format incorporates lessons learned from the staff’s reviews of the previous five 

LRAs, which used a format developed from information gained during a staff-NEI demonstration 

project conducted to evaluate the use of the GALL Report in the LRA review process.

The organization of LRA Section 3 parallels that of SRP-LR Chapter 3. LRA Section 3 presents 

AMR results information in the following two table types:

 (1) Table 1s: Table 3.x.1 – where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, and “1” indicates that this table type is the 

first in LRA Section 3.

 (2) Table 2s: Table 3.x.2-y – where “3” indicates the LRA section number, “x” indicates the 

subsection number from the GALL Report, “2” indicates that this table type is the second 

in LRA Section 3, and “y” indicates the system table number.

The content of the previous LRAs and of the PINGP application is essentially the same. The 

intent of the revised format of the PINGP LRA was to modify the tables in LRA Section 3 to 

provide additional information that would assist in the staff’s review. In its Table 1s, the applicant 

summarized the portions of the application that it considered to be consistent with the GALL 

Report. In its Table 2s, the applicant identified the linkage between the scoping and screening 

results in LRA Section 2 and the AMRs in LRA Section 3.

3.0.1.1 Overview of Table 1s 

Each Table 1 compares in summary how the facility aligns with the programs in the 

corresponding tables in the GALL Report. The tables are essentially the same as Tables 1 

through 6 in the GALL Report, except that the “Type” column has been replaced by an “Item 

Number” column and the “Item Number in GALL” column has been replaced by a “Discussion” 

column. The “Item Number” column is a means for the staff reviewer to cross-reference 
3-3

Table 2s with Table 1s. In the “Discussion” column the applicant provided clarifying information. 

The following are examples of information that might be contained within this column:

 • further evaluation recommended - information or reference to the information’s location

 • the name of a plant-specific program

 • exceptions to GALL Report assumptions

 • discussion of how the line is consistent with the corresponding line item in the GALL 

Report when the consistency may not be obvious

 • discussion of how the item is different from the corresponding line item in the GALL 

Report (e.g., when an exception is taken to a GALL AMP)

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding GALL Report table row so that the consistency can be checked easily.

3.0.1.2 Overview of Table 2s 

Each Table 2 provides the detailed results of the AMRs for components identified in LRA 

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures 

within a specific system grouping (e.g., RCS, engineered safety features (ESF), auxiliary 

systems, etc.). For example, the ESF group has tables specific to the containment spray 

system, containment isolation system, and emergency core cooling system. Each Table 2 

consists of nine columns:

 • Component Type – The first column lists LRA Section 2 component types subject to an 

AMR in alphabetical order.

 • Intended Function – The second column identifies the license renewal intended 

functions, including abbreviations, where applicable, for the listed component types. 

Definitions and abbreviations of intended functions are in LRA Table 2.0-1.

 • Material – The third column lists the particular construction material(s) for the component 

type.

 • Environment – The fourth column lists the environments to which the component types 

are exposed. Internal and external service environments are indicated with a list of these 

environments in LRA Tables 3.0-1, 3.0-2, and 3.0-3.

 • Aging Effect Requiring Management – The fifth column lists aging effects requiring 

management (AERMs). As part of the AMR process, the applicant determined any 

AERMs for each combination of material and environment.

 • AMPs – The sixth column lists the AMPs that the applicant uses to manage the identified 

aging effects.

 • NUREG-1801 Vol. 2 Item – The seventh column lists the GALL Report item(s) identified 

in the LRA as similar to the AMR results. The applicant compared each combination of 

component type, material, environment, AERM, and AMP in LRA Table 2 with the GALL 

Report items. If there are no corresponding items in the GALL Report, the applicant 
3-4

leaves the column blank in order to identify the AMR results in the LRA tables 

corresponding to the items in the GALL Report tables.

 • Table 1 Item – The eighth column lists the corresponding summary item number from 

LRA Table 1. If the applicant identifies in each LRA Table 2 AMR results consistent with 

the GALL Report, the Table 1 line item summary number should be listed in LRA 

Table 2. If there is no corresponding item in the GALL Report, column eight is left blank. 

In this manner, the information from the two tables can be correlated.

 • Notes – The ninth column lists the corresponding notes used to identify how the 

information in each Table 2 aligns with the information in the GALL Report. The notes, 

identified by letters, were developed by an NEI work group and will be used in future 

LRAs. Any plant-specific notes identified by numbers provide additional information 

about the consistency of the line item with the GALL Report.

3.0.2 Staff’s Review Process 

The staff conducted three types of evaluations of the AMRs and AMPs.

 (1) For items that the applicant stated were consistent with the GALL Report, the staff 

conducted either an audit or a technical review to determine consistency.

 (2) For items that the applicant stated were consistent with the GALL Report with 

exceptions, enhancements, or both, the staff conducted either an audit or a technical 

review of the item to determine consistency. In addition, the staff conducted either an 

audit or a technical review of the applicant’s technical justifications for the exceptions or 

the adequacy of the enhancements.

The SRP-LR states that an applicant may take one or more exceptions to specific GALL 

AMP elements; however, any deviation from or exception to the GALL AMP should be 

described and justified. Therefore, the staff considers exceptions as being portions of the 

GALL AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program to address aging 

effects that does not meet all the program elements defined in the GALL AMP. However, 

the applicant may make a commitment to augment the existing program to satisfy the 

GALL AMP prior to the period of extended operation. Therefore, the staff considers 

these augmentations or additions to be enhancements. Enhancements include, but are 

not limited to, activities needed to ensure consistency with the GALL Report 

recommendations. Enhancements may expand, but not reduce, the scope of an AMP.

 (3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements.

The staff used audits and technical reviews of the applicant’s AMPs and AMRs to determine 

whether the aging effects on SCs can be adequately managed to maintain their intended 

function(s) consistent with the plant’s current licensing basis (CLB) for the period of extended 

operation, as required by 10 CFR Part 54.
3-5

3.0.2.1 Review of AMPs 

For AMPs for which the applicant claimed consistency with the GALL AMPs, the staff conducted 

either an audit or a technical review to verify the claim. For each AMP with one or more 

deviations, the staff evaluated each deviation to determine whether the deviation was 

acceptable and whether the modified AMP would adequately manage the aging effect(s) for 

which it was credited. For AMPs not evaluated in the GALL Report, the staff performed a full 

review to determine their adequacy. The staff evaluated the AMPs against the following 

10 program elements defined in SRP-LR Appendix A.

(1) Scope of the Program – Scope of the program should include the specific SCs subject to 

an AMR for license renewal.

(2) Preventive Actions – Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected – Parameters monitored or inspected should be 

linked to the degradation of the particular structure or component intended function(s).

(4) Detection of Aging Effects – Detection of aging effects should occur before there is a 

loss of structure or component intended function(s). This includes aspects such as 

method or technique (e.g., visual, volumetric, surface inspection), frequency, sample 

size, data collection, and timing of new/one-time inspections to ensure timely detection 

of aging effects.

(5) Monitoring and Trending – Monitoring and trending should predict the extent of 

degradation, as well as provide or allow for timely corrective or mitigative actions.

(6) Acceptance Criteria – Criteria against which the need for corrective action will be 

evaluated, should ensure that the structure or component intended function(s) are 

maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.

(8) Confirmation Process – Confirmation process should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are 

effective.

(9) Administrative Controls - Administrative controls should provide for a formal review and 

approval process.

(10) Operating Experience – Operating experience of the AMP, including past corrective 

actions resulting in program enhancements or additional programs, should provide 

objective evidence to support the conclusion that the effects of aging will be adequately 

managed so that the SC intended function(s) will be maintained during the period of 

extended operation.

The staff completed an independent review of the applicant’s operating experience (OE) cited in 

the LRA to evaluate the incorporation of site specific and industry OE into PINGP AMPs. In 

addition the inspection staff from Region III completed additional reviews of OE as part of their 

license renewal scoping, screening and aging management review documented in Inspection 

Report 05000282/2009006 and 05000306/2009006. 
3-6

Operating experience plays an important role in license renewal and figures prominently in an

applicant’s LRA. The SRP-LR provides guidance to the NRC staff on assessing the 10 program 

elements for each aging management program submitted in a license renewal application. OE 

is listed as one of these elements, and defined in the GALL Report.

Operating experience is also an important part of two other aging management program 

elements: specifically, detection of aging effects, and monitoring and trending. The SRP also 

calls attention to the importance of the applicants plant-specific OE in relation to scoping and 

screening, aging management review, and time-limited aging analysis activities (TLAA).

During the aging management audit at PINGP, the staff reviewed samples of the applicant’s 

condition reports and interviewed site staff personnel to independently verify that the applicant 

adequately incorporated OE into the respective AMP as appropriate. Specific cases of these 

reviews are described in the associated AMP evaluations by the staff. Details of the staff’s audit 

evaluation of program elements (1) through (6) and (10) are documented in SER Section 3.0.3.

The staff reviewed the applicant’s QA program and documented its evaluations in SER 

Section 3.0.4. The staff’s evaluation of the QA program included assessment of the “corrective 

actions,” “confirmation process,” and “administrative controls” program elements.

3.0.2.2 Review of AMR Results 

Each LRA Table 2 contains information concerning whether or not the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG-1801 Vol. 2 Item,” 

correlate to an AMR combination as identified in the GALL Report. The staff also conducted onsite audits to verify these correlations. A blank in column seven indicates that the applicant was 

unable to identify an appropriate correlation in the GALL Report. The staff also conducted a 

technical review of combinations not consistent with the GALL Report. The next column, 

“Table 1 Item,” refers to a number indicating the correlating row in Table 1.

3.0.2.3 UFSAR Supplement 

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed 

the updated final safety analysis report (UFSAR) supplement, which summarizes the applicant’s 

programs and activities for managing aging effects for the period of extended operation, as 

required by 10 CFR 54.21(d).

3.0.2.4 Documentation and Documents Reviewed 

In its review, the staff used the LRA, LRA supplements, the SRP-LR, and the GALL Report.

During the on-site audit, the staff also examined the applicant’s justifications to verify that the 

applicant’s activities and programs will adequately manage the effects of aging on SCs. The 

staff also conducted detailed discussions and interviews with the applicant’s license renewal 
3-7

project personnel and others with technical expertise relevant to aging management. The staff's 

audit activities are documented in the Audit Report (ADAMS Accession No. ML090850009).

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 systems or structures that credit the AMPs and the 

GALL AMP with which the applicant claimed consistency and shows the section of this SER in 

which the staff’s evaluation of the program is documented.

Table 3.0.3-1 PINGP Aging Management Programs

PINGP AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report

Comparison

GALL 

Report

AMPs

LRA Systems or 

Structures

That Credit the AMP

Staff's

SER Section

10 CFR 50, 

Appendix J

(B2.1.1)

Existing Consistent XI.S4 structures and component 

supports

3.0.3.1.1

Aboveground Steel 

Tanks

(B2.1.2)

New Consistent XI.M29 steam and power 

conversion systems

3.0.3.1.2

ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD

(B2.1.3)

Existing Consistent XI.M1 reactor vessel, internals and 

reactor coolant system, 

engineered safety features 

and auxiliary systems

3.0.3.1.3

ASME Section XI, 

Subsection IWE 

(B2.1.4)

Existing Consistent XI.S1 structures and component 

supports

3.0.3.1.4

ASME Section XI,

Subsection IWF 

(B2.1.5)

Existing Consistent XI.S3 structures and component 

supports

3.0.3.1.5

Bolting Integrity

(B2.1.6)

Existing Consistent with 

exception and 

enhancement

XI.M18 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems

3.0.3.2.1

Boric Acid Corrosion

(B2.1.7)

Existing Consistent XI.M10 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems / 

structures and component 

supports

3.0.3.1.6
3-8

PINGP AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report

Comparison

GALL 

Report

AMPs

LRA Systems or 

Structures

That Credit the AMP

Staff's

SER Section

Buried Piping and 

Tanks Inspection 

(B2.1.8)

New Consistent XI.M34 auxiliary systems 3.0.3.1.7

Closed-Cycle 

Cooling Water 

System

(B2.1.9)

Existing Consistent with 

exceptions and 

enhancement

XI.M21 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

3.0.3.2.2

Compressed Air 

Monitoring 

(B2.1.10)

Existing Consistent with 

exceptions and 

enhancements

XI.M24 auxiliary systems 3.0.3.2.3

Electrical Cable 

Connections Not 

Subject to 10 CFR 

50.49 

Environmental 

Qualification 

Requirements 

(B2.1.11)

New Consistent with 

exceptions

XI.E6 electrical and 

instrumentation and controls

3.0.3.2.4

Electrical Cables 

and Connections 

Not Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements

(B2.1.12)

New Consistent XI.E1 electrical and 

instrumentation and controls

3.0.3.1.8

Electrical Cables 

and Connections 

Not Subject to 10 

CFR 50.49 

Environmental 

Qualification 

Requirements Used 

in Instrumentation 

Circuits

(B2.1.13)

New Consistent XI.E2 electrical and 

instrumentation and controls

3.0.3.1.9

External Surfaces

Monitoring

(B2.1.14)

Existing Consistent with 

enhancements

X.M36 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems / 

structures and component 

supports

3.0.3.2.5

Fire Protection

(B2.1.15)

Existing Consistent with 

exception and 

enhancements

XI.M26 auxiliary systems 3.0.3.2.6
3-9

PINGP AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report

Comparison

GALL 

Report

AMPs

LRA Systems or 

Structures

That Credit the AMP

Staff's

SER Section

Fire Water System

(B2.1.16)

Existing Consistent with 

enhancement 

XI.M27 auxiliary systems 3.0.3.2.7

Flow-Accelerated 

Corrosion

(B2.1.17)

Existing Consistent with 

exception

XI.M17 auxiliary systems / steam 

and power conversion 

systems

3.0.3.1.10

Flux Thimble Tube 

Inspection

(B2.1.18)

Existing Consistent with 

enhancement

XI.M37 reactor vessel, internals and 

reactor coolant system

3.0.3.2.8

Fuel Oil Chemistry

(B2.1.19)

Existing Consistent with 

exception and 

enhancement

XI.M30 auxiliary systems 3.0.3.2.9

Fuse Holders

(B2.1.20)

New Consistent XI.E5 electrical and 

instrumentation and controls

3.0.3.1.11

Inaccessible 

Medium Voltage 

Cables Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements

(B2.1.21)

New Consistent XI.E3 electrical and 

instrumentation and controls

3.0.3.1.12

Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components

(B2.1.22)

New Consistent XI.M38 engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems / 

structures and component 

supports

3.0.3.1.13

Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems 

(B2.1.23)

Existing Consistent with 

enhancement

XI.M23 structures and component 

supports

3.0.3.2.10

Lubricating Oil

Analysis

(B2.1.24)

Existing Consistent XI.M39 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems

3.0.3.1.14

Masonry Wall

(B2.1.25)

Existing Consistent XI.S5 structures and component 

supports

3.0.3.1.15

Metal-Enclosed Bus

(B2.1.26)

New Consistent XI.E4 electrical and 

instrumentation and controls

3.0.3.1.16
3-10

PINGP AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report

Comparison

GALL 

Report

AMPs

LRA Systems or 

Structures

That Credit the AMP

Staff's

SER Section

Nickel-Alloy Nozzles 

and Penetrations

(B2.1.27)

Existing Plant-specific XI.M11 reactor vessel, internals and 

reactor coolant system

3.0.3.1.17

and 3.0.3.3.1

Nickel-Alloy 

Penetration Nozzles 

Welded to the 

Upper Reactor 

Vessel Closure 

Heads of 

Pressurized Water 

Reactors 

(B2.1.28)

Existing Consistent with 

enhancement

XI.M11A reactor vessel, internals and 

reactor coolant system

3.0.3.2.11

One-Time 

Inspection 

(B2.1.29)

New Consistent XI.M32 reactor vessel, internals and 

reactor coolant system 

/engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems

3.0.3.1.18

One-Time 

Inspection of ASME 

Code Class 1 SmallBore Piping 

(B2.1.30)

New Consistent XI.M35 engineered safety features 

systems /reactor vessel, 

internals and reactor coolant 

system

3.0.3.1.19

Open-Cycle Cooling 

Water System

(B2.1.31)

Existing Consistent XI.M20 auxiliary systems/ steam 

and power conversion 

systems

3.0.3.1.20

Protective Coating 

Monitoring and 

Maintenance 

Program (B2.1.41)

Existing Consistent XI.S8 structures and component 

supports

3.0.3.1.24

PWR Vessel 

Internals

(B2.1.32)

New Plant-specific XI.M16 reactor vessel, internals and 

reactor coolant system

3.0.3.3.2

Reactor Head 

Closure Studs

(B2.1.33)

Existing Consistent with 

enhancement 

XI.M3 reactor vessel, internals and 

reactor coolant system

3.0.3.2.12

Reactor Vessel 

Surveillance

(B2.1.34)

Existing Consistent with 

enhancement

XI.M31 reactor vessel, internals and 

reactor coolant system

3.0.3.2.13
3-11

PINGP AMP

(LRA Section)

New or 

Existing 

AMP

GALL Report

Comparison

GALL 

Report

AMPs

LRA Systems or 

Structures

That Credit the AMP

Staff's

SER Section

RG 1.127, 

Inspection of WaterControl Structures 

Associated with 

Nuclear Power 

Plants

(B2.1.35)

Existing Consistent with 

enhancement

XI.S7 structures and component 

supports

3.0.3.2.14

Selective Leaching 

of Materials

(B2.1.36)

New Consistent with 

exception

XI.M33 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems

3.0.3.2.15

Steam Generator 

Tube Integrity

(B2.1.37)

Existing Consistent with 

exception

XI.M19 reactor vessel, internals and 

reactor coolant system

3.0.3.2.16

Structures 

Monitoring

(B2.1.38)

Existing Consistent with 

enhancement

XI.S6 structures and component 

supports

3.0.3.2.17

Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)

(B2.1.39)

New Consistent XI.M12 reactor vessel, internals and 

reactor coolant system

3.0.3.1.22

Water Chemistry

(B2.1.40)

Existing Consistent with 

exception and 

enhancement

XI.M2 reactor vessel, internals and 

reactor coolant system / 

engineered safety features 

systems / auxiliary systems 

/ steam and power 

conversion systems / 

structures and component 

supports

3.0.3.2.18

Environmental 

Qualification (EQ) of 

Electrical 

Components 

(B3.1)

Existing Consistent X.E1 electrical and 

instrumentation and controls

3.0.3.1.23

Metal Fatigue of 

Reactor Coolant 

Pressure Boundary

(B3.2)

Existing Consistent with 

enhancement

X.M1 reactor vessel, internals and 

reactor coolant system 

3.0.3.2.19
3-12

3.0.3.1 AMPs Consistent with the GALL Report 

In LRA Appendix B, the applicant identified the following AMPs as consistent with the GALL 

Report:

 • 10 CFR Part 50, Appendix J Program

 • Aboveground Steel Tanks Program

 • ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

 • ASME Section XI, Subsection IWE Program

 • ASME Section XI, Subsection IWF Program

 • Boric Acid Corrosion Program

 • Buried Piping and Tanks Inspection Program

 • Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program

 • Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits Program

 • Flow-Accelerated Corrosion Program[1]

 • Fuse Holders Program

 • Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program

 • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

 • Lubricating Oil Analysis Program

 • Masonry Wall Program

 • Metal-Enclosed Bus Program

 • Nickel-Alloy Nozzles and Penetrations Program

 • One-Time Inspection Program

 • One-Time Inspection of ASME Code Class 1 Small Bore Piping Program

 • Open-Cycle Cooling Water System Program

 • PWR Vessel Internals Program

 • Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program

 • Environmental Qualification (EQ) of Electrical Components Program

 • Protective Coating Monitoring and Maintenance Program 

[1]: In a letter dated March 12, 2009, the applicant amended its Flow-Accelerated Corrosion 

Program to comply with the latest EPRI guidance. The amended AMP is consistent with an 

exception to the GALL Report.
3-13

3.0.3.1.1 10 CFR Part 50, Appendix J

Summary of Technical Information in the Application. LRA Section B2.1.1 describes the existing 

10 CFR Part 50, Appendix J Program as consistent with GALL AMP XI.S4, “10 CFR 50, 

Appendix J.” The applicant stated leak rate tests assure that leakage through the primary 

containment and systems and components penetrating primary containment does not exceed 

allowable values as specified in the Technical Specifications. The applicant further stated that 

periodic surveillance of reactor containment penetration and isolation valves is performed so 

that proper maintenance and repairs are made. The applicant uses Option B, the performancebased approach, to implement the requirement of containment leak rate monitoring and testing.

Staff Evaluation. During its audit, the staff interviewed the applicant’s technical staff and 

reviewed the applicant’s claim of consistency with the GALL Report. The staff audited the 

10 CFR Part 50, Appendix J Program on-site basis documents to determine their consistency 

with GALL AMP XI.S4. Specifically, the staff reviewed the program elements and associated onsite documents and found that they are consistent with GALL AMP XI.S4. On the basis of its 

review, the staff finds the applicant’s 10 CFR Part 50, Appendix J Program consistent with the 

program elements of GALL AMP XI.S4, and therefore acceptable.

Operating Experience. The staff also reviewed the operating experience (OE) described in LRA 

Section B2.1.1. The applicant stated that PINGP has experienced significant leakage through 

airlock door operating shaft seals, which was resolved by replacing the seals with a type less 

susceptible to leakage, and performing more frequent tests. The applicant further stated that 

other issues such as valve degradation and airlock seal damage have been addressed through 

routine maintenance. During the audit, the staff found that significant leakage was discovered 

through the Unit 2 maintenance airlock door operating shaft seals during a Type B test in 1989. 

The staff reviewed historic test data for the particular airlock, which showed that repairs 

successfully addressed the leak, although leak rates remained relatively high until 2002. During 

this review the staff also found that the Type B & C allowable leak rates since 1998 were 

changed from 154,800 to 43,331 cc/min on the provided surveillance procedures. In 

RAI B2.1.1-1 dated November 5, 2008, the staff requested that the applicant address the time 

between initial discovery and successful repair of the maintenance airlock door leak as well as 

the change in the allowable leak rates.

In its response dated December 5, 2008, the applicant addressed RAI B2.1.1-1. The applicant 

explained that prior to December 2000, the maintenance airlock seals consisted of mechanical 

seals or a packing arrangement. The mechanical seals were not very tolerant of shaft

misalignment, while the packing arrangement was difficult to inspect and maintain due to 

cramped working conditions. The applicant further explained that in December 2000 a new 

airlock shaft seal design was approved by the PINGP modification process and installed. The 

new design utilizes O-rings and allows for a greater amount of misalignment and does not 

require routine maintenance. The applicant also explained that the Type B & C allowable leak 

rates were reduced due to excessive control room in-leakage during testing. The lower 

containment leak rate was the value used in the LOCA control room dose evaluation, which 

became the limiting value when the control room seals were found to be faulty. This lower value 

was used until the control room seals were repaired or replaced and the control room in-leakage 

was shown to be at acceptable levels. Once the in-leakage was reduced to acceptable levels, 

the containment leakage acceptance criteria was returned to the original value of 154,800 
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cc/min. Based on its review, the staff finds the applicant’s response to RAI B2.1.1-1 acceptable 

because it adequately explains the improvement in leak rates that occurred in 2002, as well as 

the high leak rates between 1989 and 2002. The response also explains the reduction in the 

Type B & C allowable leak rates. The staff’s concerns described in RAI B2.1.1-1 are resolved. 

The staff did not identify any age-related related issues not bounded by the industry OE.

On the basis of its review and the applicant’s response to RAI B2.1.1-1, 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 element acceptable.

UFSAR Supplement. In LRA Section A2.1, the applicant provided the UFSAR supplement for 

the 10 CFR Part 50, Appendix J Program. The staff reviewed this section and determines that 

the information in the UFSAR 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 10 CFR Part 50, Appendix J Program, 

including the applicant’s response to RAI B2.1.1-1, 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 UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.

3.0.3.1.2 Aboveground Steel Tanks 

Summary of Technical Information in the Application. LRA Section B2.1.2 describes the new 

Aboveground Steel Tanks Program as consistent with GALL AMP XI.M29 “Aboveground Steel 

Tanks.” The applicant has credited this program for managing the aging effect of loss of material 

for carbon steel tanks that rest on either soil or concrete that are in-scope. The applicant further 

stated that a visual inspection will be utilized for the external surfaces of the tanks until the 

contact of the tank wall with the foundation and a ultrasonic test will be performed on the tank 

bottom to determine if there is significant degradation on the inaccessible surface of the tank 

bottom. The applicant also stated that this program will provide for inspection of those outdoor 

tanks that are fully covered by insulation by periodically removing insulation to perform a direct 

inspection of the tank exterior wall.

Staff Evaluation. During its audit, the staff reviewed the applicant=s claim of consistency with the 

GALL Report. The staff’s summary of its on-site review of AMP B2.1.2, Aboveground Steel 

Tanks Program, is documented in the staff’s Audit Summary Report Section for this AMP. 

In comparing the seven program elements in the applicant’s program to those in 

GALL AMP XI.M29, the staff noted that the program elements in which the applicant’s AMP 

claimed to be consistent with GALL were consistent with the corresponding program element 

criteria recommended in the program elements of GALL AMP XI.M29.

During the audit, the staff noted that in the applicant’s program basis document under the 

program element, “monitoring and trending,” the applicant discussed that the inspection 
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frequency for the visual inspection of the accessible external tank surface will be performed at 

least once per refueling cycle. The staff noted that this is consistent with the recommendations 

provided in GALL AMP XI.M29; however, the staff determined that additional information was 

needed regarding the inspection frequency of the inaccessible surfaces of the carbon steel 

tanks (i.e. tank bottoms) and of the tank exteriors of those outdoor carbon steel tanks that are 

fully insulated. The staff also noted that the applicant stated in its program basis document that 

the inspection scope and frequency will be adjusted based on the results of the previous 

inspections and OE. Therefore, by letter dated November 5, 2008, the staff issued RAI B2.1.2-1 

requesting the applicant clarify the following:

(a) clarify the inspection frequency for the inaccessible surfaces (tank bottoms) 

of the tanks in the scope of this program;

(b) clarify the inspection frequency for the tank exterior of the insulated tanks that 

require the periodic removal of the insulation near the bottom of the tanks; 

and

(c) clarify and justify the number of inspections that will be performed on the 

external (accessible) surfaces, the inaccessible surfaces (tank bottoms), and 

the tank exteriors that require removal of insulation in-scope of this program, 

before the inspection scope/frequency will be adjusted.

The applicant responded to RAI B2.1.2-1 by letter dated December 5, 2008. The applicant 

stated in its response to part (a) that this program will include a one-time inspection of the 

inaccessible surfaces (tank bottoms) of one of the three condensate storage tanks (CSTs)

within the 10-year period prior to entering the period of extended operation. The applicant 

further stated that an ultrasonic inspection technique will be utilized to ensure that degradation 

is not occurring on the external surface of the tank bottom. The staff noted that based on the 

inspection results that any indications or relevant conditions of degradation will be compared to 

the tank design thickness and corrosion allowance. The staff further noted that the applicant 

may perform additional inspections on the three CSTs based on the plant-specific inspection 

results and industry experience. The staff also noted that the applicant’s approach of a one-time 

inspection of the inaccessible tank surface is consistent with the recommendations of the 

program element, “monitoring and trending,” of GALL AMP XI.M29. By letter dated August 7, 

2009, the applicant amended the first two sentences in its response to RAI B2.1.2-1 to state that 

this program will perform at least one ultrasonic inspection of the tank bottom for each of the 

three CSTs to ensure that degradation due to corrosion is not occurring on the inaccessible 

surface of each tank. On the basis of its review, the staff finds the applicant’s amended 

response acceptable because the applicant will perform a one-time ultrasonic inspection of the 

tank bottoms for each of the three CSTs and may perform additional inspections on these tanks 

based on the results of the inspections, which is consistent with the “monitoring and trending” 

program element recommendations provided in GALL AMP XI.M29.

The applicant stated in its response to part (b) that the entire exterior surface of the insulation 

for the insulated tanks will be inspected visually at least once per refueling cycle. The staff noted 

that the recommendations provided in the “monitoring and trending” program element of GALL 

AMP XI.M29 states in part that “plant system walkdowns during each outage provide for timely 

detection of aging effects.” The applicant stated this inspection will identify damage to the 

insulation or its outer covering that would allow water to penetrate and for discoloration or other 
3-16

signs that the insulation has been wetted. The applicant further stated that sample sections of 

the insulation near the bottom of these tanks (i.e., locations of highest potential for wetted 

insulation) will be removed from one of the three CSTs once per refueling cycle, to allow for 

direct inspection of the exterior of the tank. The staff noted that results from these inspections 

will be evaluated to determine if additional direct visual inspections are required in order to 

ensure there is adequate aging management. On the basis of its review, the staff finds the 

applicant’s response and aging management basis for visual examinations to be acceptable 

because of the following: (1) the applicant will be performing its visual inspections at least once 

per refueling cycle of the exterior surface of the insulation for these tanks, consistent with the 

recommendations of GALL AMP XI.M29; (2) the applicant will be removing sample sections of 

the insulation from the tank surfaces in those areas considered to have the highest potential for 

wetting; (3) the visual examinations are capable of detecting cracking or loss of material that 

affects the exterior surfaces of the tanks; and (4) the removal of the insulation in these areas will 

provide access for direct visual inspection of the tank exterior surfaces, which will preclude the 

insulation from concealing any evidence of corrosion on the external tank surfaces.

The applicant stated in its response to part (c) that the tanks in the scope of this program will be 

inspected at intervals that will detect loss of material due to corrosion and will be managed such 

that the components will be capable of performing their intended functions during the period of 

extended operation. The staff noted that two pre-coat slurry tanks were removed from the scope 

of this program because these tanks are normally dry and are only used during refueling 

outages and thus do not meet the criteria in 10 CFR 54.4(a)(1), (2) or (3). The staff further noted 

that the three insulated CSTs are the only tanks within the scope of this program, and as stated 

previously by the applicant, a visual inspection of the exterior insulation of these tanks will be 

performed at least once per refueling cycle, which is consistent with the recommendations 

provided in GALL AMP XI.M29, and sample sections of the insulation will be removed to 

facilitate direct visual inspection of the tank exterior surfaces. The staff’s evaluation of the 

inspection frequency for the inaccessible surfaces is discussed in part (a) of the applicant’s 

response to RAI B2.1.2-1. The applicant further stated that the inspection frequency may be 

adjusted as needed based on plant-specific inspection results and industry OE. The staff noted 

that applicant’s proposal to adjust the inspection frequency is consistent with recommendations 

provided in the GALL Report. The staff further noted that if inspection results indicate that 

corrosion is occurring, this will be entered into the applicant’s corrective actions program to 

determine further service, adequacy of current inspection frequency and required corrective 

actions. On the basis of its review, the staff finds the applicant’s response acceptable because 

(1) the applicant will be performing its visual inspections at least once per refueling cycle of the 

exterior surface of the insulation for these tanks, consistent with the recommendations of GALL 

AMP XI.M29; (2) the applicant will be removing sample sections of the insulation with the 

highest potential for wetting to allow for direct visual inspection of the tank exterior, which will be 

capable of detecting any corrosion or degradation behind the insulation; and (3) the applicant’s 

proposal to adjust the inspection frequency is consistent with the recommendations in the GALL 

Report.

The staff noted that the Aboveground Steel Tanks Program includes LRA Commitment No. 3, 

which was placed on the LRA in the applicant’s letter of January 20, 2009, and in which the 

applicant committed to implementing this program prior to entering the period of extended 

operation. The staff finds this commitment to be acceptable because the applicant’s 
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commitment to implement the program prior to the period of extended operation satisfies the 

staff’s implementation time-frame statement for LRA commitments in SRP-LR Section 3.0.1.

On the basis of its review, as discussed above, the staff finds the applicant’s response to RAI 

B2.1.2-1 and the applicant’s basis for inspecting these tanks, as committed to in LRA 

Commitment No. 3 to be acceptable because the aging management basis is consistent with 

the program elements of GALL AMP XI.M29. RAI B.2.1.2-1 is resolved.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.2, the 

applicant’s condition reports (CRs) during the on-site audit and interviewed the applicant’s 

technical staff to confirm that the plant-specific OE did not reveal any degradation not bounded 

by industry experience. During its review of the applicant’s OE the staff noted that during a 

periodic structures inspection performed by the applicant in 2007, corrosion on the covering of 

the insulation and coating degradation on the hatch covers was discovered. The staff noted that 

this degradation was located on the accessible exterior surface of the outdoor CSTs. As a result 

of the inspection findings, the applicant stated that it entered its discovery into its corrective 

actions program. The applicant also issued action reports (ARs) and work requests in order to 

address these issues of degradation. The staff noted that the applicant was able to detect 

degradation on the aboveground steel tank with a visual inspection during a routine structures 

inspection prior to the loss of intended functions of the tanks and the applicant has taken 

appropriate measure to have the degradation repaired and the work is currently in the planning 

stages, as part of PINGP’s corrective actions.

The staff confirmed that the applicant has taken appropriate corrective actions for the OE that is 

applicable to the Aboveground Steel Tanks Program and noted that there were not any aging 

effects or age-related degradation that could not be detected in accordance with the AMPs'

inspection methods or that are not bounded by the ability of the AMP to detect the aging effects.

The staff confirmed that the OE program element satisfies the criterion defined in the GALL 

Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this program element 

acceptable.

UFSAR Supplement. In LRA Section A2.2 the applicant provided the UFSAR supplement for the 

Aboveground Steel Tanks Program. The staff reviewed the supplement and verified that, in LRA 

Commitment No. 3 of the Preliminary License Renewal Commitments in letter dated January 9, 

2009, the applicant committed to implementing this program prior to the period of extended 

operation as described in LRA Section B2.1.2. The staff finds the UFSAR supplement for this 

AMP acceptable because it is consistent with the corresponding description in SRP-LR 

Table 3.3-2 and because the summary description includes the bases for determining that aging 

effects will be managed, as committed to in LRA Commitment No. 3. The staff determines that 

the information in the UFSAR 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 Aboveground Steel Tanks Program, the 

staff finds all program elements consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 
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for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.1.3 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

Summary of Technical Information in the Application. LRA Section B2.1.3 describes the 

applicant’s existing American Society of Mechanical Engineers (ASME) Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program. The applicant stated that the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program provides for 

condition monitoring of ASME Class 1, 2 and 3 pressure-retaining components, their welded 

integral attachments, and bolting. The program is implemented in accordance with the 

requirements of 10 CFR 50.55a, with specified limitations, modifications and NRC-approved 

alternatives, and utilizes ASME Section XI, Subsections IWB, IWC, and IWD. The program 

includes periodic visual, surface, and/or volumetric examinations and leakage tests of Class 1, 

2, and 3 pressure-retaining components, their welded integral attachments, and bolting. 

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the applicant’s ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program, and determined that it is 

adequate to manage the aging effects for which the LRA credits it.

LRA Section B2.1.3 provides the program description, statement of consistency with the GALL 

Report, OE, and the conclusion that the PINGP Inservice Inspection program will provide 

reasonable assurance that aging effects will be adequately managed through the period of 

extended operation. The applicant stated that the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program is consistent with the recommendations of aging 

management program (AMP) XI.M1, “ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD," with no exceptions or enhancements.

During the on-site review, the staff reviewed documents supporting the applicant’s conclusion 

that the program elements are consistent with the elements in the GALL AMP. The staff noted 

that where the applicant claimed the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program to be consistent with elements of the GALL AMP XI.M1, the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program elements are 

consistent with the GALL AMP XI.M1. However, in LRA Appendix B2.1.3, the applicant 

describes the present Inservice Inspection (ISI) program, approved by the staff for the fourth ISI 

interval, which utilizes 1998 Edition of the ASME Code Section XI, Subsections IWB, IWC, and 

IWD, inclusive of the 2000 Addenda. Therefore, specified limitations, modifications and NRCapproved alternatives described in Appendix B2.1.3 only apply to the fourth ISI interval. The 

LRA does not state how the ISI program will be implemented during the period of extended 

operation. The staff issued RAI B2.1.3-1 dated December 5, 2008, asking the applicant to 

describe how the ISI program will be implemented during the period of extended operation.

In a letter dated December 18, 2008, the applicant responded to RAI B2.1.3-1 stating that future 

inspection intervals will be in accordance with 10 CFR 50.55a and that all relief requests will be 

submitted to the staff for approval. Therefore, the staff finds that future inspection intervals are 

acceptable because the applicant will implement inspections in accordance with (1) applicable 
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regulations and (2) NRC approved ASME Code cases and relief requests. In addition, this is in 

compliance with the requirements in 10 CFR 50.55a.

The staff noted that, in its final statement of consideration (SOC) on the updates of 

10 CFR 50.55a, “codes and standards” (Federal Register (FR) Volume 73, No. 176, pages 

52730 – 52750), the staff mandated new augmented inspection requirements for upper reactor 

vessel closure head (RVCH) penetration nozzles that are made from nickel-alloy materials or 

that are structurally welded to the upper RVCH using bimetallic (i.e., nickel-alloy) weld filler 

metals. For these components, the updated rule imposed: (1) new augmented non-visual 

inspection methods for the components in accordance with the methods and criteria in ASME 

Code Case N-729-1, as defined, referenced and subject to the limitations in 10 CFR 

50.55a(g)(6)(ii)(D), and (2) new augmented bare metal visual examinations requirements in 

accordance with the methods and criteria in ASME Code Case N-722, as defined, referenced 

and subject to the limitations in 10 CFR 50.55a(g)(6)(ii)(E). The referenced SOC makes the 

following statement with respect to PWR applicants whose LRAs include AMPs corresponding 

to GALL AMP XI.M-11A and whose LRAs are currently under review:

“For new or current license renewal applicants, they may reference conformance GALL 

AMP XI.M11A and compliance with the augmented inspection requirements in paragraphs 

10 CFR 50.55a(g)(6)(ii)(D) and (E) without the need for taking an exception to the program 

elements in GALL AMP XI.M11A.”

In its final statement of consideration (SOC) on the updates of 10 CFR 50.55a, the staff also 

mandated new augmented inspection requirements for partial or full penetration welds in 

Class 1 components fabricated with Alloy 600/82/182 material pressure boundary leakage in 

pressurized water reactor (PWR) plants. For these components, the updated rule imposed 

augmentation of the applicant’s Inservice Inspection Program (ISI) program by implementing the 

visual inspection methods of ASME Code Case N-722 subject to the limitations in 10 CFR 

50.55a(g)(6)(ii)(E).

The staff noted that in Commitment No. 1, the applicant committed to submit amendments to 

the PINGP LRA (including any changes to the UFSAR supplements and Commitment List for 

the LRA) pursuant to the LRA update requirements in 10 CFR 54.21(b), which requires that 

each year following submittal of the LRA and at least three months before scheduled completion 

of the NRC review, an amendment to the LRA be submitted that identifies any change to the 

CLB of the facility that materially affects the contents of the LRA, including the Updated Final 

Safety Analysis Report (UFSAR) supplement. Based on the applicant’s Commitment No. 1, the 

staff finds the applicant will implement the new mandated augmented inspection requirements in 

10 CFR 50.55a(g)(6)(ii)(D) and (E).

The applicant’s ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program (B2.1.3) states that the provisions of ASME Section XI are augmented by additional 

inspections to detect general and pitting corrosion on the shell to transition cone weld of the 

Westinghouse Model 51 steam generators in Unit 2. Westinghouse Model 51 steam generators 

have a high stress region at the shell to transition cone weld, and corrosion of the steam 

generator shell is known to exist. The staff noted that the inspection method was not identified in 

the applicant’s AMP. During discussions between the staff and the applicant, the applicant 

stated that the visual inspection of the interior of the transition cone weld is performed for one 
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steam generator during each refueling outage. The staff finds visual inspection of the interior 

circumference of the transition cone weld an acceptable method to detect degradation as 

recommended by Information Notice No. 90-04, “Cracking of the Upper Shell-to-Cone Girth 

Welds in Steam Generators.

Based on its review, the staff finds the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program consistent with the program elements of GALL AMP XI.M1, and 

therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.3. The 

applicant stated that Implementation of the ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program provides reasonable assurance that aging effects will be managed 

such that structures, systems, and components within the scope of this program will continue to 

perform their intended function(s) during the period of extended operation and OE indicates the 

IWB, IWC, and IWD Program is effective in monitoring and detecting degradation and taking 

effective corrective actions as needed when acceptance criteria are not met.

The staff audited the OE reports and interviewed the applicant’s technical staff. During review of 

LRA B2.1.3, “Operating Experience” the staff noted that there were two cracking instances due 

to intergranular stress corrosion cracking (IGSCC) of Safety Injection Accumulator Tanks.

Cracks were repaired and augmented inspection procedures were implemented as follows:

(1) safety injection accumulator tank nozzles will be examined on a 10-year frequency, 

and

(2) procedures were developed to perform external ultrasonic examination (UT)

examinations and internal visual and dye penetrant examinations of safety injection 

accumulators.

The staff noted that the documentation provided by the applicant during the onsite review 

supports the applicant’s statements, regarding OE and confirmed that the plant-specific OE did 

not reveal any degradation not bounded by industry experience. The staff finds that the ability of 

the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to detect 

cracking in the safety injection accumulators and the applicant’s adjustment of this AMP to 

perform augmented UT, visual and dye penetration inspections of the accumulators provides 

objective evidence that supports the conclusion that the AMP will manage the effects of aging 

during the period of extended operation in accordance with SRP-LR Appendix A, Section 

A.1.2.3.10. Based on this determination, the staff finds this program element acceptable.

UFSAR Supplement. In LRA, Appendix A, Section A2.3, the applicant provided its UFSAR

Supplement for the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program. The staff verified that provisions of the UFSAR Supplement are in accordance with 

SRP-LR, Table 3.1-2, ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.

The staff noted that the UFSAR Supplement includes provisions to augment the ASME Section 

XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to inspect the Unit 2 

Westinghouse Model 51 steam generators for pitting and general corrosion of the transition 

cone welds. The staff also noted that the UFSAR Supplement provides for periodic update of 

the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program to 
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implement changes to 10 CFR 50.55a. The staff finds this to be acceptable because it is in 

compliance with the requirements of 10 CFR 50.55a.

The staff noted that in the applicant’s Commitment No. 1, the applicant committed to submit 

changes to the LRA that are required based on changes to the Current Licensing Basis (CLB), 

which affect the contents of the LRA, including UFSAR Supplements summary sections for the 

LRA. Thus, the staff also noted that the scope of the commitment includes the need to update 

the program elements of the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and 

IWD Program in order to incorporate the new augmented inspection requirements for upper 

reactor vessel closure head (RVCH) penetration nozzles that were mandated in 10 CFR 

50.55a(g)(6)(ii)(D) and (E), and for Alloy 600 base metal components and Alloy 82 or 182 weld 

components in reactor coolant pressure boundary Class 1 components that were mandated in 

accordance with 10 CFR 50.55a(g)(6)(ii)(E). The staff finds this to be acceptable because it is in 

compliance with the requirements 10 CFR 54.21(b).

The staff determined that the UFSAR Supplement for the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program is an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program, the staff determines that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR 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 ASME Section XI, Subsection IWE 

Technical Information in the Application. LRA Section B2.1.4 describes the existing ASME 

Section XI, Subsection IWE Program as consistent with GALL AMP XI.S1 “ASME Section XI, 

Subsection IWE.” The applicant stated the program provides for condition monitoring of Class 

MC pressure-retaining components and related items, including integral attachments, seals, 

gaskets, moisture barriers, and pressure-retaining bolting. The program is implemented in 

accordance with the requirements of 10 CFR 50.55a and utilizes ASME Section XI, Subsection 

IWE, 1992 Edition including the 1992 Addenda for the current inspection interval. The program 

will use the ASME Code edition consistent with the provisions of 10 CFR 50.55a during the 

period of extended operation.

Staff Evaluation. During the audit, the staff interviewed the applicant’s technical staff and 

reviewed the applicant’s ASME Section XI, Subsection IWE basis documents to determine the 

program’s consistency with GALL AMP XI.S1. Specifically, the staff reviewed the program 

elements and the associated onsite documents. On the basis of its review, the staff finds the 

applicant’s ASME Section XI, Subsection IWE Program consistent with the program elements of 

GALL AMP XI.S1, and therefore acceptable.
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Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.4. The 

applicant stated that PINGP has had issues with minor coating degradation, which were 

identified and corrected. During the audit, the staff asked the applicant why the coating 

degradation was not captured under a coating AMP. The applicant explained that an AMP was 

not needed for coatings because they are not credited for aging management of the 

containment. Although the coatings are not credited for aging management, the staff believes 

their failure could result in the failure of a safety system to perform its intended function. In RAI 

B2.1.4-1 dated November 5, 2008, the staff requested that the applicant justify not having an 

AMP for coatings.

In its response dated December 5, 2008, the applicant stated that coatings inside containment 

provide protection for the underlying base metal but are not relied upon to mitigate any aging 

effect. The Containment Inservice Inspection and Containment Leak Rate Programs are 

credited with managing the containment vessel for loss of material due to corrosion. The 

applicant further stated that both programs look for evidence of flaking, blistering, peeling, 

discoloration, corrosion and other signs of distress. Suspect areas are accepted by engineering 

evaluation or corrected by repair or replacement. The RAI response also explains that PINGP 

has performed an analysis of the susceptibility of the Emergency Core Cooling System (ECCS) 

and Core Spray System (CSS) recirculation functions to adverse effects of post-accident debris 

blockage. The analysis assumed that all qualified coating within the zone of influence of the 

worst case pipe break fail and that all unqualified coatings inside containment fail. The applicant 

concluded that the analysis demonstrated that debris will not prevent a safety-related 

component from performing its intended function. The applicant further stated that since the 

failed coatings would not prevent a safety-related component from performing its safety 

function, the coatings inside containment do not fall within the scope of 10 CFR 54.4(a)(2). In 

addition, by letter dated March 12, 2009, the applicant added the Protective Coating Monitoring 

and Maintenance Program. The applicant does not credit this program for prevention of 

corrosion on carbon steel components. Rather, this program is used to ensure that the amount 

of failure of coatings that occurs during a LOCA does not exceed the design limits for the 

strainers. This program is reviewed in SER Section 3.0.3.1.24, which included a more detailed 

discussion of the program and the staff’s review.

Based on its review, the staff finds the applicant’s response to RAI B2.1.4-1 acceptable because 

PINGP has programs in place to capture, evaluate and correct degraded coatings and has 

performed an analysis which demonstrates that failed coatings inside containment will not 

prevent a safety system from performing its intended function. The staff’s concern described in 

RAI B2.1.4-1 is resolved. 

During the audit, the staff also noted that PINGP had identified an ongoing issue with water 

seepage from the refueling cavity into the containment sumps. In RAI B2.1.38-2 dated 

November 5, 2008, the staff requested the applicant provide information regarding the root 

cause analysis of the seepage, as well as corrective and preventive actions taken to correct the 

problem. In the LRA, this seepage issue is tracked under the Structures Monitoring Program, 

but the staff believes that it also applies to the IWE program due to the possibility of borated 

water coming into contact with the containment vessel.

By letter dated December 5, 2008, the applicant responded to RAI B2.1.38-2. The applicant 

stated that the condition was detected by the ASME Section XI, Subsection IWE Program while 
3-23

examining the Class MC pressure retaining vessel. Both the Structures Monitoring Program and 

the ASME Section XI, Subsection IWE Program took corrective actions to address the leakage. 

In addition, the applicant provided information during a public meeting on March 2, 2009. The 

staff reviewed the information provided in the RAI response and during the public meeting, and 

discovered that borated water was coming into contact with the containment vessel during 

refueling outages. Due to the leakage path of borated water along the bottom of the 

containment vessel, the staff noted that there is a possibility that portions of the containment 

vessel may remain wetted after refueling outages. By letter dated March 31, 2009, the staff 

issued follow-up RAI B2.1.38 asking the applicant to discuss its plan for assessing the current 

condition of the steel containment vessel and to explain how the IWE program, or a plant 

specific program, will manage aging of the vessel, especially in inaccessible regions, during the 

period of extended operation. The staff also conducted an audit on May 28, 2009, to review 

related on-site documentation. As a result of the audit, the staff issued additional RAIs. The 

applicant responded to the RAIs and committed to inspect the containment vessel and concrete 

in areas exposed to leakage (Commitments 41, 42, and 44). Any indications of degradation will 

be entered in to the applicant’s Corrective Action Program and the affects on the structural 

integrity of the containment will be evaluated.

Based on the applicant’s responses and the commitments, OI 3.0.3.2.17-1 is closed. A detailed 

timeline and summary of the staff’s review and closure of OI 3.0.3.2.17-1 is discussed and 

documented under the Structures Monitoring Program in SER Section 3.0.3.2.17. The 

applicant’s commitment to inspect the containment vessel in an area susceptible to corrosion, 

along with the fact that PINGP has no current signs of containment degradation, provides 

assurance that the IWE and Structures Monitoring Programs will effectively manage aging of the 

containment vessel during the period of extended operation. The additional inspections provide 

assurance that either the containment has not experienced significant degradation, or existing 

degradation will be captured and evaluated prior to the period of extended operation.

On the basis of its review, including review of the RAI responses and the review and closure of 

OI 3.0.3.2.17-1, 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 element acceptable.

UFSAR Supplement. In LRA Section A2.4, the applicant provided the UFSAR supplement for 

the ASME Section XI, Subsection IWE Program. The staff reviewed this section and determined 

that the information in the UFSAR 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 response to RAI B2.1.4-1 and RAI B2.1.38-2, and the closure 

of Open Item 3.0.3.2.17-1, 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 UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).
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3.0.3.1.5 ASME Section XI, Subsection IWF 

Summary of Technical Information in the Application. LRA Section B2.1.5 describes the existing 

ASME Section XI, Subsection IWF Program as consistent with GALL AMP XI.S3 “ASME 

Section XI, Subsection IWF.” The applicant stated the program provides for condition monitoring 

of Class 1, 2, and 3 component supports. The applicant stated that there are no Class MC 

component supports installed at PINGP. The applicant further stated the program is 

implemented in accordance with the requirements of 10 CFR 50.55a and utilizes ASME Section 

XI, Subsection IWF, 1998 Edition, including the 1998, 1999 and 2000 Addenda for the current 

inspection interval. The program will use the ASME Code edition consistent with the provisions 

of 10 CFR 50.55a during the period of extended operation.

Staff Evaluation. During its audit, the staff interviewed the applicant’s technical staff and 

reviewed the applicant’s ASME Section XI, Subsection IWF Program basis documents to 

determine the program’s consistency with GALL AMP XI.S3. Specifically, the staff reviewed the 

program elements and the associated onsite documents. During its audit, the staff noted that 

the PINGP IWF basis document states the program includes inspections of concrete and 

grouting for component support building structure attachments. The staff questioned why 

concrete inspections fell under the IWF Program. The applicant explained that this only relates 

to localized areas where the support is anchored; a different program (Structures Monitoring 

Program) is responsible for inspecting general concrete. This was verified by the staff in the site 

procedures. The staff found this explanation acceptable because it aligns the inspections with 

the proper GALL AMPs. On the basis of its review, the staff finds the applicant’s ASME Section 

XI, Subsection IWF Program consistent with the program elements of GALL AMP XI.S3, and 

therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.5. The 

applicant stated that minor conditions, such as improper can settings and unacceptable arc 

strikes have been identified and corrected. During the audit, the staff reviewed samples of CRs

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 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 

element acceptable. 

UFSAR Supplement. In LRA Section A2.5, the applicant provided the UFSAR supplement for 

the ASME Section XI, Subsection IWF Program. The staff reviewed this section and determined

that the information in the UFSAR 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 IWF 

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 
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period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR 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 Boric Acid Corrosion 

Summary of Technical Information in the Application. LRA Section B2.1.7 describes the Boric 

Acid Corrosion program as an existing program that is consistent with GALL AMP XI.M10, 

“Boric Acid Corrosion.” The applicant stated that this program includes periodic visual 

examinations of the reactor coolant pressure boundary and other systems containing borated 

water for evidence of leakage and corrosion. The applicant also stated that adjacent structures, 

components (including electrical), and supports are also examined for boric acid accumulation 

and corrosion. The applicant further stated that this program includes evaluations, assessments, 

and corrective actions for observed leakage sources and any affected SCs. The applicant also 

indicated that the Boric Acid Corrosion Program includes provisions for triggering evaluations 

and assessments when leakage is discovered while performing other plant walkdowns or 

maintenance activities.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff confirmed that the applicant’s program contains all of the program 

elements of the referenced GALL AMP. The staff also conducted on-site interviews with the 

applicant on its program in order to confirm these results. 

The staff reviewed the applicant’s license renewal basis document for the Boric Acid Corrosion 

Program and confirmed that the program scope includes those steel (including carbon steel, 

alloy steel, and cast iron), copper alloy, and aluminum alloy systems and components that could 

be affected by the impacts of borated water leakage and boric acid corrosion. In comparing the 

program elements in the applicant’s program to those in GALL AMP XI.M10, the staff confirmed 

that the program elements in the applicant’s program are consistent with the recommended

program elements of GALL AMP XI.M10.

In comparing the program elements in the applicant’s AMP to those in GALL AMP XI.M10, the 

staff found that the applicant has identified all the systems and components included in the 

scope of the Boric Acid Corrosion Control Program. This includes those steel, copper alloy, or 

aluminum alloy components that are in the vicinity of Class 1 nickel-alloy components, where 

the potential exists for cracks to initiate and grow through wall because of stress corrosion 

cracking (SCC) and which have the potential to be a source of borated water leakage. This 

includes any steel, copper alloy, or aluminum alloy components in the vicinity of the RPV 

closure head penetration nozzles, RPV inlet and outlet safe-end welds, pressurizer penetration 

or steam space nozzles, or other nickel-alloy components in the reactor coolant pressure 

boundary. Based on its review, the staff finds the applicant’s Boric Acid Corrosion Program 

consistent with the program elements of GALL AMP XI.M10 and therefore acceptable.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.7 and 

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 also confirmed that 

applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 
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and are evaluated in the GALL Report. Furthermore, the staff confirmed that the applicant has 

addressed OE identified after the issuance of the GALL Report. 

The staff also reviewed the OE discussion in the applicant’s license renewal basis document for 

the Boric Acid Corrosion Program. The staff reviewed a sample of the CRs and confirmed that 

the applicant has identified boric acid corrosion and has implemented appropriate corrective 

actions. 

In the OE element of LRA Section B2.1.7, the applicant stated that PINGP found borated water 

leakage and boric acid crystal accumulations. The staff issued RAI B2.1.7-1 by letter dated 

November 5, 2008, to ask the applicant to (a) clarify what type of corrective actions are 

implemented for steel, copper alloy, and aluminum components that are exposed to borated 

water leakage or to boric acid residues that has precipitated out as a result of previous borated 

water leakage; (b) clarify whether the program permits PINGP to leave any boric acid residues 

in place, and if so, how the program assesses the impacts of boric acid residues on the 

structural integrity of impacted components if the residues are left in place for any period of 

time; (c) identify all relevant PINGP OE with borated water leakage or boric acid residues over 

the past five years; and (d) discuss the corrective actions that were taken on the impacted steel, 

copper alloy or aluminum alloy components in order to correct the adverse conditions.

In its letter dated December 5, 2008, in response to RAI B2.1.7-1, the applicant stated, in part, 

that:

Corrective actions taken as a result of the identification of borated water leakage 

or boric acid residue may include a combination of cleaning, repair, and/or 

replacement activities. The PINGP Boric Acid Corrosion Program requires 

complete removal of boric acid crystal buildup or deposits as part of the 

corrective action. Active leakage, depending upon the source and the cause, 

may be corrected via gasket replacement, valve packing 

adjustment/replacement, joint disassembly/reassembly, component replacement, 

or other appropriate maintenance activities.

The applicant further stated that "The PINGP Boric Acid Corrosion Program does allow 

boric acid residues to be left in place if supported by evaluation." For ASME pressure 

boundary components, ASME Section XI, IWA-5250, provides requirements for 

corrective measures. Based on these requirements, if left in service, 10% wall loss will 

not occur prior to the time the component will be repaired, or, if greater than 10% wall 

loss were to occur, an operability evaluation will be performed with the reduced wall 

thickness. This evaluation considers corrosion rates and mechanisms like surface 

temperature, material susceptibility, leakage rates, etc. For non-ASME or non-pressure 

boundary components, those indications that affect susceptible materials of ASME 

Section XI components are evaluated. These evaluations consider corrosion rates, boric 

acid concentrations, leak rates, re-inspection interval, and possible compensatory 

measures as necessary. For mechanical joints, leakage is inspected and monitored to 

trend/evaluate changes in leakage and the basis documented.

In a February 3, 2009 teleconference, the staff questioned the previous discussion of the 

response to RAI AMP B2.1.7-1 because it could be interpreted to indicate that boric acid residue 
3-27

could be left on ferritic components for extended periods. The staff requested the applicant to 

clarify the response. In its letter dated February 6, 2009, the applicant clarified its response as 

follows:

At PINGP, boric acid residue is not normally left in place for extended periods of 

time. Identified boric acid leaks are cleaned and repaired effectively. Boric acid 

discovered in critical locations such as the reactor vessel head and other reactor 

coolant pressure boundary components that are only accessible for inspection 

during outages would be cleaned prior to startup from the outage. Boric acid 

residue or active leakage discovered in locations that are not reasonably 

accessible for cleaning or repair due to plant conditions may be allowed to 

remain in place for a limited period of time (e.g., until the next outage when 

access becomes available), but only after an evaluation has confirmed that the 

continued presence of boric acid would be acceptable for the expected time 

period.

Upon identification of borated water leakage or boric acid residue, the PINGP 

Boric Acid Corrosion Program evaluates the condition to determine if the boric 

acid residues can be left in place until such time as corrective actions, as 

previously discussed in Part A of the Northern States Power Company (NSPM)

response, can be initiated at the earliest possible convenience.

In its letter dated December 5, 2008, in response to RAI B2.1.7-1, the applicant further stated, in 

part, that:

A document review of Corrective Action Program issues, NRC Inspection 

Reports, Program Self Assessments, Program Health Reports, and INPO 

Evaluations dating back to 2000, revealed instances where borated water or 

boric acid crystals were identified. Leakage or boric acid residue was observed 

on various valve stems, tubing fittings, valve-to-body joints, valve bellows, and 

flanged joints. The causes of the boric acid leakage were attributed to a variety of 

issues such as packing leakage; instrument tube fittings stripped or misaligned; 

valve bellows leakage; broken lock washers; failed O-rings; and gasket failures 

on valve body-to-bonnet joints, orifice flanges, and heat exchanger shell/channel 

head connections. Corrective actions involved cleaning the boric acid residue; 

replacing carbon steel studs and nuts with stainless steel; replacing valves and 

manifolds; adjusting or replacing valve packing; disassembling, cleaning, 

inspecting and replacing gaskets on valves, heat exchangers, and other flanged 

connections; adjusting the torque on valve body-to-bonnet and heat exchanger 

shell/channel head studs; replacing O-rings on transmitters; and tightening, 

rethreading, or replacing fittings. The boric acid leakage observed did not affect 

the structural integrity of any components.

The PINGP System Engineering staff is responsible for evaluating modifications 

to equipment, procedures, or specifications based on incidents involving 

corrosion or potential corrosion. Considerations include (1) reducing the 

probability of leakage in susceptible areas and (2) use of corrosion resistant 
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materials for items such as body-to-bonnet valve studs or the application of 

protective coatings, cladding or leakage collection methods.

As an example of such corrective actions, PINGP Engineering implemented 

enhancements to valve packing procedures in order to address a number of 

packing leakage issues. The valve packing procedures were revised to 

incorporate improved valve repacking methods and techniques. Some of the key 

elements included instructions for packing consolidation, use of live-load packing 

assemblies, and the installation of hardened steel washers under the gland nut 

for better force transmission.

The staff reviewed the applicant’s response and noted that the applicant has provided 

appropriate description of corrective actions that are implemented when boric acid corrosion is 

detected on metallic components. The staff noted that the applicant has clarified that boric acid 

leaks are cleaned and repaired effectively. The applicant has also provided specific examples of 

plant OE and corrective actions implemented as a result of this OE. During the audit, the staff 

reviewed several CRs that addressed boric acid leakage from valve packing glands, body-tobonnet joints, and other mechanical joints. The staff noted that the applicant, as part of 

corrective actions, addressed these leaks by enhancing the valve packing procedures to 

improve valve packing methods, and adjusting torques on mechanical joints or replacing Orings. The staff finds these corrective actions will mitigate boric acid leakages because the 

applicant has addressed the root cause of the leakages and took the appropriate corrective 

actions to resolve them. On that basis that the applicant has (1) processes in place to identify 

and address boric acid leakages, (2) clarified that boric acid residue is not normally left in place 

for extended periods of time, (3) identified boric acid leaks are cleaned and repaired effectively, 

(4) identified specific plant OE, and (5) discussed the corrective actions taken, the staff finds the 

applicant response acceptable and the staff considers RAI B2.1.7-1 resolved.

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.7, the applicant provided the UFSAR supplement for 

the Boric Acid Corrosion Program. The staff verified that the applicant’s UFSAR supplement 

summary description for the Boric Acid Corrosion Program conforms to the staff’s 

recommended FSAR supplement guidance for these types of programs as found in SRP-LR 

Table 3.1-2. 

Based on this review, the staff finds that UFSAR supplement Section A2.7 provides an 

acceptable UFSAR supplement summary description of the applicant’s Boric Acid Corrosion 

Program because it is consistent with the UFSAR supplement summary description in the SRPLR for Boric Acid Corrosion Program.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s Boric Acid Corrosion Program 

and the applicant’s response to the staff’s RAI, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff concludes that the applicant demonstrated that the 
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effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(3). The staff also reviewed the UFSAR 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 Buried Piping and Tanks Inspection 

Summary of Technical Information in the Application. LRA Section B2.1.8 describes the 

applicant’s new Buried Piping and Tanks Inspection Program. The applicant stated that this 

program manages loss of material on the external surfaces of carbon steel and cast iron 

components that are buried in soil or sand.

Staff Evaluation. During its audit, the staff confirmed the applicant=s claim of consistency with 

the GALL Report.

LRA Section B2.1.8 provides the program description, statement of consistency with the GALL 

Report, OE, and the applicant’s conclusion that the PINGP Buried Piping and Tanks Inspection 

AMP will provide reasonable assurance that loss of material will be adequately managed 

through the period of extended operation. The applicant stated that the Buried Piping and Tanks 

Inspection Program is consistent with the 10 elements of AMP XI.M34, “Buried Piping and 

Tanks Inspection,” with no exceptions and no enhancements.

The staff confirmed that, for those program element aspects that the applicant claimed as being 

consistent with the recommended program elements in GALL AMP XI.M34, “Buried Piping and 

Tanks Inspection” were consistent with the recommended program elements in the GALL AMP, 

with the exception of the "detection of aging effects" element in the applicant’s AMP that the 

staff determined were in need of additional clarification and for which requests for additional 

information (RAIs) were issued to the applicant for resolution. 

The staff noted that the applicant indicates that it will perform opportunistic or focused 

excavations and will perform subsequent visual inspections on buried piping and tanks.

However, the staff also noted that the applicant’s inspection method bases did not provide the 

basis the applicant would use to select buried piping or tank components for inspection or the 

basis that would it would use to expand the inspection scope if degradation was detected in the 

buried piping or tank components as a result of implementing this AMP. In RAI B2.1.8-2 dated 

December 5, 2008, the staff requested that the applicant identify the methods that it will use to 

select components for inspection and to expand the inspection scope if degradation is detected 

in the components.

In a letter dated December 18, 2008, the applicant responded to RAI B2.1.8-2 stating that there 

are no specific areas that are more prone to corrosion than others because the below ground 

environment is relatively benign and there has been no indication of loss of material on the 

outside of buried piping. Therefore, the applicant stated that locations for focused excavations 

will be based on industry experience and any degradation will be evaluated through the 

corrective action program and the results of this process will be used to identify susceptible 

locations for further inspections. The staff finds that the applicant’s method to identify areas for 

focused inspections and potential expansion of inspection scope acceptable because initial 
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inspections will be based on industry experience and, if necessary, expanded inspection scope 

will be based on the applicant’s corrective action process should degradation be found.

Based on its review, the staff finds the Buried Piping and Tanks Inspection Program consistent 

with the program elements of GALL AMP XI.M34 and therefore acceptable.

Operating Experience. The applicant stated that the Buried Piping and Tanks Inspection 

Program is a new program, and therefore, has no OE related to program implementation. The 

applicant also stated that a review of OE did reveal that portions of the Cooling Water and Fire 

Protection Systems' buried piping were replaced in 1992 as a result of microbiologically 

influenced corrosion (MIC) indications on the internal surfaces of dead-leg portions of these 

systems. No external surface degradation or anomalies were identified.

The staff audited the OE reports and interviewed the applicant’s technical staff. The staff noted 

that high tritium levels were discovered in on-site and off-site groundwater during the early days 

of plant operation but the OE element of AMP B2.1.8 did not discuss what caused the high 

tritium and whether or not the tritium source was buried tanks or piping. Discussion between the 

staff and the applicant during the audit indicated that the source of tritium contamination was not 

buried piping and that no system with buried piping in scope of license renewal that contains

radioactive materials or has fluids that are contaminated. Therefore, the staff determined that 

OE dealing with tritium contamination does not need to be included in the OE element of AMP 

B2.1.8 because the source of tritium contamination is not buried piping.

The staff noted that portions of buried coated carbon steel piping of the Cooling Water and Fire 

Protection Systems have been replaced as a result of MIC indications on the piping inside 

diameter. However, it is not clear to the staff what replacement material(s) were used or if 

coating or wrapping was used. In RAI B2.1.8-1 dated December 5, 2008, the staff requested 

that the applicant identify the replacement piping materials, including identification of any 

coatings and/or wrappings that were included in the design of the replacement piping 

components.

In a letter dated December 18, 2008, the applicant responded to RAI B2.1.8-1 stating that the 

Cooling Water System piping replacement materials were ASTM A106, Grade B and ASTM 

A155, Grade KC-70, Class I carbon steel piping and that the piping was coated with a coal tar 

enamel and wrapped. The staff verified that the Fire Protection (FP) System replacement piping 

materials were Class 52 and Class 53 ductile cast iron piping with a bituminous external 

coating. The staff finds the carbon steel and ductile cast iron replacement materials acceptable 

because they were coated or wrapped and because this is consistent with 

the recommended “preventive actions” program element criterion for wrapping or coating buried 

piping components in GALL AMP XI.M34.

The staff noted that the documentation provided by the applicant during the onsite review 

supports the applicant’s statements regarding OE and confirmed that the plant-specific OE at 

PINGP for buried piping and tank components did not identify any degradation in the buried 

piping and tank components that is not bounded by industry experience or by the ability of the 

program elements of this AMP to manage the effects of aging attributed to the components. 

Based on this review, the staff finds that the applicant’s identification of relevant OE for the 

buried piping components demonstrates that the applicant’s program is capable of identifying 
3-31

age-related degradation problems in the buried piping and tank components and that the 

applicant takes prompt corrective actions to evaluate, repair or replace any affected buried 

components. 

The staff confirmed that the Aoperating 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 

element acceptable.

UFSAR Supplement. In LRA Section A2.8, the applicant provided its UFSAR Supplement for 

the Buried Piping and Tanks Inspection Program in PINGP LRA, Appendix A, Section A2.8. The 

staff verified that UFSAR Supplement summary description in UFSAR Supplement Section A2.8 

is in conformance with the UFSAR Supplement for Buried Piping and Tanks Inspection Program 

that is recommended in SRP-LR, Table 3.3-2, ”FSAR Supplement for Aging Management of 

Auxiliary System.” The staff also verified that in Commitment No. 5 of the License Renewal 

Commitments that the applicant committed to implement the Buried Piping and Tanks 

Inspection Program before the period of extended operation and continue it through the period 

of extended operation.

The staff finds that the UFSAR Supplement for the Buried Piping and Tanks Inspection Program 

provides an adequate summary description as identified in the SRP-LR UFSAR, Table 3.3-2 as 

required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant=s Buried Piping and Tanks Inspection 

Program, the staff finds all program elements consistent with the GALL Report. The staff 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR 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 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B2.1.12 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements AMP 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 AMP will provide reasonable assurance that the applicable electrical components will 

perform their intended function(s) for the period of extended operation. The applicant also stated 

that the program conducts periodic visual inspections on a representative sample of accessible 

cables and connections in identified adverse localized environments to confirm insulation 

integrity.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff reviewed and compared the “scope of program,” “preventive actions,” 

“parameters monitored/detected,” “detection of aging effects,” “monitoring and trending,” 

“acceptance criteria,” and “operating experience” program elements of the AMP to the 
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corresponding program element criteria in GALL AMP XI.E1, “Electrical Cables and 

Connections Not Subject to 10 CFR50.49 Environmental Qualification Requirements.” 

The staff’s review of the “corrective actions,” “administrative controls,” and “confirmation 

process” program elements for the new Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements AMP was performed as part of the staff’s 

review of the QA attributes of the AMPs and is discussed in SER Section 3.0.4.

The staff compared the program elements in the applicant’s program to those in GALL AMP 

XI.E1. The staff noted that the program elements that the applicant claimed to be consistent 

with the GALL Report were consistent with the corresponding program element in the GALL 

AMP XI.E1. 

Based on its review, the staff finds the Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements Program consistent with the program 

elements of GALL AMP XI.E1, and therefore acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.12. The 

applicant stated that at PINGP there have been instances where adverse localized 

environments for electrical cables and connections were suspected to have caused localized 

cable and connection insulation degradation. The noted cases of degradation resulted in the 

replacement or rework of the affected cable or connection jacket/insulation.

The staff reviewed the CRs on these events in the license renewal basis binder for the AMP

during its on-site review of the AMP. The staff determined that the CRs demonstrated that the 

applicant had implemented appropriate corrective actions.

The staff finds that the plant-specific OE is bounded by industry OE as described in GALL 

XI.E1. Industry OE has shown that adverse localized environments for electrical cables and 

connections caused by heat or radiation may exist next to or above (within three feet of) steam 

generators, pressurizers or hot process pipes, such as feedwater lines. These adverse localized 

environments have been found to cause degradation of the insulating materials on electrical 

cables and connections. Therefore, the staff determines that the applicant has adequately 

addressed this element. 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 element acceptable.

UFSAR Supplement. In LRA Section A2.12, the applicant provided the UFSAR supplement for 

the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements AMP. The staff reviewed this section and determined that the information in the 

UFSAR supplement is an adequate summary description of the program, as required by 10 

CFR 54.21(d). 

The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 9.

Conclusion. On the basis of its review of the applicant’s Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements AMP, the staff finds all 
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program elements consistent with the GALL Report. The staff concludes that the applicant has 

demonstrated that effects of aging will be adequately managed so that the intended function(s) 

will be maintained consistent with the CLB for the period of extended operation as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 10 

CFR 54.21(d).

3.0.3.1.9 Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Used in Instrumentation Circuits 

Summary of Technical Information in the Application. LRA Section B2.1.13 describes the new 

Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program as consistent with GALL AMP XI.E2, 

“Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits.” The applicant stated that this AMP will manage 

the aging effect of reduced insulation resistance on non-EQ sensitive (high-voltage, low signal) 

instrumentation circuit cables and connections exposed to adverse localized environments and

maintain electrical circuit integrity throughout the period of extended operation. The applicant 

also stated that this program includes either periodic review of surveillance data or testing of 

cables and connections for non-EQ sensitive instrumentation circuits in-scope of license 

renewal.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff reviewed and compared the “scope of program,” “preventive actions,” 

“parameters monitored/detected,” “detection of aging effects,” “monitoring and trending,” 

“acceptance criteria,” and “operating experience” program elements of the AMP to the 

corresponding program element criteria in GALL AMP XI.E2, “Electrical Cables and 

Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in 

Instrumentation Circuits.”

The staff’s review of the “corrective actions,” “administrative controls,” and “confirmation

process” program elements for the new Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits 

Program was performed as part of the staff’s review of the QA attributes of the AMPs and is 

discussed in SER Section 3.0.4.

The staff compared the program elements in the applicant’s program to those in GALL AMP 

XI.E2. The staff noted that the program elements that the applicant claimed to be consistent 

with the GALL Report were consistent with the corresponding program element in GALL AMP 

XI.E2. 

Based on its review, the staff finds the Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits 

Program consistent with the program elements of GALL AMP XI.E2, and therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.13. The 

applicant stated that plant-specific OE has shown a few cases where adverse localized 

environments for sensitive instrumentation cables and connections have been suspected to 
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cause instances of adverse or erratic signals. The identified cases of degradation resulted in the 

replacement or rework of the affected cable or connection. 

The staff also reviewed the CRs on these events in the license renewal basis binder for the 

AMP as part of its on-site review of the AMP. The staff determined that the CRs demonstrated 

that the applicant had implemented appropriate corrective actions.

The staff also verified that the aging effects are bounded by those identified in the GALL AMP 

XI.E2. Industry OE has identified a case where a change in temperature across a high range 

radiation monitor cable in containment resulted in a substantial change in the reading of the 

monitor. Changes in instrument calibration can be caused by degradation of the circuit cable 

and are a possible indication of electrical cable degradation. Therefore, the staff determines that 

the applicant has adequately addressed this element. 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 element acceptable. 

UFSAR Supplement. In LRA Section A2.13, the applicant provided the UFSAR supplement for 

the Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Used in Instrumentation Circuits Program. The staff reviewed this section and 

determines that the information in the UFSAR supplement is an adequate summary description 

of the program, as required by 10 CFR 54.21(d). 

The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 10.

Conclusion. On the basis of its review of the applicant’s Electrical Cables and Connections Not 

Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation 

Circuits Program, the staff finds that all program elements are consistent with the GALL Report.

The staff concludes that the applicant has demonstrated that effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR 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 Flow-Accelerated Corrosion 

Summary of Technical Information in the Application. LRA Section B2.1.17 describes the FlowAccelerated Corrosion (FAC) Program as an existing program that is consistent with GALL AMP 

XI.M17, “Flow-Accelerated Corrosion.” The applicant stated that the FAC Program is a condition 

monitoring program based on the Electric Power Research Institute (EPRI) guidelines in 

Nuclear Safety Analysis Center (NSAC)-202L-R2 for carbon steel and bronze components 

containing high-energy single phase or two phase fluids. The applicant further stated that the 

program manages loss of material due to FAC in piping and components by (a) conducting an 

analysis to determine critical locations, (b) performing baseline inspections to determine the 

extent of thinning at these locations, and (c) performing follow-up inspections to confirm the 

predictions of the rate of thinning, and repairing or replacing components as necessary.
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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 confirmed that the applicant’s program contains all of the elements 

of the referenced GALL Report program. On-site interviews were also held to confirm these 

results.

The staff reviewed the applicant’s license renewal basis document and confirmed that the 

program scope includes the systems and components that could be affected by loss of material 

as a result of FAC. In comparing the program elements in the applicant’s program to those in 

GALL AMP XI.M17, the staff noted that the program elements in the applicant’s AMP that the 

applicant claimed to be consistent with the GALL Report were consistent with the corresponding 

program element criteria recommended in the program elements of GALL AMP XI.M17, with the 

exception of “monitoring and trending” program element aspects identified. The staff determined 

there was a need for additional information for these aspects.

The “monitoring and trending” program element in GALL AMP XI.M17 states that

CHECWORKS or a similar predictive code is used to predict component degradation in the 

systems conducive to FAC, as indicated by specific plant data, including material, 

hydrodynamic, and operating conditions. The applicant stated that CHECWORKS was 

implemented in late 2004. The staff issued RAI B2.1.17-1 by letter dated November 5, 2008, 

requesting the applicant to provide any OE such as excessive FAC requiring repair or 

replacement of piping that was the basis for converting to CHECWORKS.

In its letter dated December 5, 2008, in response to RAI B2.1.17-1, the applicant stated that 

prior to 2004 the PINGP FAC Program utilized a software application referred to as the Pipe 

Thinning Inspection Program (PTIP), which was developed by NSPM. The applicant further 

stated that the software program lacked certain features (e.g., had no predictive capability, did 

not consider plant chemistry, offered limited trending ability) and did not meet the NMC standard 

for a predictive code for the FAC Program. The applicant also stated that this resulted in its 

replacement in 2004 with the EPRI CHECWORKS SFA (Steam/Feedwater Application), which 

was considered both the industry standard and the NMC standard. The applicant indicated that 

it upgraded to the CHECWORKS SFA model in order to improve its FAC Program through 

implementation of a more robust predictive code and that there were no FAC-related failures 

identified at PINGP that prompted the upgrade to CHECWORKS.

The staff reviewed the applicant response and noted that the applicant converted to 

CHECWORKS because it was a significantly better program than what it was using at that time. 

It is considered the industry standard and is recommended in the GALL AMP XI.M17 as a 

predictive code that could be used to predict component degradation because it provides a 

bounding analysis for FAC. The staff also noted that there were no FAC-related failures that 

prompted the upgrade to CHECWORKS. On the basis that the applicant converted to 

CHECWORKS because it is an industry standard and not because of significant FAC-related 

failures, the staff finds the applicant response acceptable. Thus, RAI B.2.17-1 is resolved.

The staff’s review of the program basis document indicated that the applicant, as part of the 

program requirement, compares actual measured wall thickness of the component with 

CHECWORKS predictions of wall thickness for that component. The staff issued RAI B2.1.17-2 

by letter dated November 5, 2008, requesting the applicant to confirm whether it has established 

a correlation between predicted results and actual wall thickness measurements, and whether 
3-36

PINGP had ever experienced excessive loss of material by FAC that was not predicted by 

CHECWORKS modeling results.

In its letter dated December 5, 2008, in response to RAI B2.1.17-2, the applicant stated that:

Wear rate analyses are performed using the CHECWORKS SFA model. A 

Pass 1 Wear Rate Analysis is an analysis based solely on the plant predictive 

model, and is not enhanced by results of the plant wall thickness measurements. 

A Pass 2 Wear Rate Analysis generates predicted wear rate and remaining 

service life similar to a Pass 1 Wear Rate Analysis with one significant difference; 

results incorporate inspection data. Pass 1 Analysis results are not relied on by 

themselves to select locations for examination.

After each inspection period, a Pass 2 Analysis is performed on each Analysis 

Line. An Analysis Line is defined as one or more physical lines of piping that 

have been analyzed together in the CHECWORKS model. As an output of the 

Pass 2 Analysis, CHECWORKS correlates the measured wear to the predicted 

wear for each Analysis Line.

When calculating a component's remaining service life (RSL) and schedule for 

examination, both the measured wear rate and CHECWORKS predicted wear 

rate, among other things, are considered. The CHECWORKS predicted wear 

rate from a Pass 2 Analysis provides an important input to these FAC Program 

considerations, especially after an Analysis Line has accumulated sufficient field 

measurement data to indicate a reliable correlation with predictions. 

A Pass 2 Analysis has been completed through the current operating cycle for 

each Unit. The predictive plant model includes inspection data of the most recent 

outage for both Units (Refueling Outage 25; March 2008 for Unit 1, October 2008 

for Unit 2). In general, the field measured wear shows a moderate to good 

correlation (within +/- 50%) to the CHECWORKS predicted wear. PINGP has not 

experienced excessive flow accelerated corrosion (FAC) that was not predicted 

by CHECWORKS.

The staff reviewed the applicant’s response and noted that the applicant has performed a Pass 

2 Analysis for each unit, which includes the inspection data from the most recent outages. The 

staff noted that the applicant has established a moderate to good correlation between the 

measured wall thickness and the CHECWORKS predicted wall thickness. The applicant is using 

the actual measured wall thickness and the wear rates to predict remaining life and future 

inspection intervals. GALL AMP XI.M17, in the “acceptance criteria” program element states 

that inspection results are input into CHECWORKS to calculate the number of refueling cycles 

remaining before the component reaches the minimum allowable wall thickness. The staff finds 

the applicant response acceptable because (1) the applicant performs a Pass 2 Analysis that 

correlates measured wear to predict wear for each analysis line, (2) the applicant has not 

experienced excessive FAC that was not predicted by CHECWORKS and (3) the results of 

each inspection is input into CHECWORKS to determine remaining life as recommended by 

GALL AMP XI.M17. Thus, RAI B2.17-2 is resolved.
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The staff’s review of the program basis document indicated that system changes could increase 

wear rates or subsequent reinspection could indicate significantly higher wear rates. The staff 

issued RAI B2.1.17-3, by letter dated November 5, 2008, requesting the applicant identify what 

process or procedure is used to address changes in the chemical, operating and flow conditions 

that could impact remaining life predictions, and how these changes are factored into the FAC 

Program so that the remaining service life can be re-evaluated.

In its letter dated December 5, 2008, in response to RAI B2.1.17-3, the applicant stated the 

following:

PINGP Flow-Accelerated Corrosion (FAC) procedures require that if system 

conditions appear to have changed in such a way as to increase wear rates, or 

subsequent re-inspections indicate that wear rates are significantly higher than 

previously predicted, then consideration should be given to conducting 

inspections at an increased frequency. Additionally, plant operating conditions 

are taken into consideration for FAC based upon recommendations from the 

PINGP System Engineering, Chemistry, Operations and Maintenance 

Departments.

The PINGP Strategic Water Chemistry Plan recognizes the importance of 

minimizing FAC on the secondary cycle components. FAC is mainly influenced 

by the at-temperature, pH and oxygen content around the secondary cycle. The 

PINGP amine chemistry control program is optimized to minimize FAC of 

secondary system components. The Chemistry Department maintains the 

system chemistries in accordance with site-specific chemistry procedures to 

minimize the effects of corrosion. The procedures provide for water sampling, 

chemical treatment application and corrosion monitoring of applicable systems. 

Secondary chemistry is reviewed and is input into the Unit 1 and Unit 2 

CHECWORKS SFA model.

PINGP modification design procedures require notification of the FAC Program 

Owner when plant modifications are determined to impact the FAC Program. 

Design considerations that may impact the FAC Program include changes to 

system flow rates, temperatures, pressures, water chemistry, valve lineups, 

materials, system configuration, piping or component geometries, or revisions to 

isometric drawings. Upon notification, the FAC Program Owner provides 

applicable design inputs to the modification, or evaluates the impact of the 

modification on the FAC Program.

Changes to system parameters, such as component material, water chemistry, 

and power level, are factored into the PINGP CHECWORKS SFA model so that 

the remaining service life can be reevaluated. Conversely, the CHECWORKS 

SFA model is also used to provide input to material changes, water chemistry 

changes, and piping design. The FAC Program, through the use of 

CHECWORKS SFA, is used to reduce the site’s susceptibility to FAC, thereby 

increasing plant safety.

The staff reviewed the applicant's response and noted that the applicant has procedures in 

place such that system operation changes are identified and included in the CHECWORKS
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software program. The staff finds the applicant’s response acceptable because (1) the applicant 

ensures the quality of secondary water is maintained within acceptable limits, (2) FAC Program 

owner is notified of system modifications so that the owner is aware of the changes prior to 

implementation of the modification, and (3) the changes to system parameters are factored into 

the CHECWORKS software so that the remaining service life can be more accurately predicted 

based on the changed system parameters. The staff finds that this is consistent with GALL AMP 

XI.M17 recommendation that CHECWORKS predictive code is used to predict component 

degradation, as indicated by specific plant data, including material, hydrodynamic, and 

operating conditions. Based on this review, the staff finds that the applicant has processes in 

place to ensure that changes in the chemical, operating and flow conditions that could affect 

remaining life predictions are factored into the FAC program. Thus, RAI B2.1.17-3 is resolved.

The “monitoring and trending” program element in GALL AMP XI.M17 states that inspection 

results are evaluated to determine if additional inspections are needed. The staff issued RAI 

B2.1.17-4 dated November 5, 2008, to request the applicant (a) provide information on how 

PINGP expands sample size; (b) provide the acceptance criterion used for sample expansion 

and whether it is related to thickness or to wear rates; and (c) indicate whether there is a 

different value used for safety-related and nonsafety-related piping.

In its letter dated December 5, 2008, in response to RAI B2.1.17-4, the applicant stated the 

following:

(a) In accordance with the PINGP Flow-Accelerated Corrosion (FAC) Program 

implementing procedure, the criteria for sample expansion and the sample 

expansion guidelines are as follows:

"To ensure CHECWORKS SFA model prediction accuracy the following sample 

expansion guidelines have been established.

(1) If examination results are unexpected and inconsistent with predictions, and 

have a significant negative effect on component remaining service life, and 

are solely attributable to FAC wear and not weld prep (counterbore), then the 

sample should be expanded to include the following (unless they have been 

examined within three inspection periods):

(a) Any component within two diameters downstream of the component 

displaying significant wear or within two diameters upstream if that 

component is an expander or expanding elbow.

(b) A minimum of the next two most susceptible components from the 

relative wear ranking in the same train as that containing the piping 

component displaying significant wear.

(c) Corresponding components in each other train of a multi-train run 

with a configuration similar to that of the piping component displaying 

significant wear.

(2) If inspections of the expanded sample specified under Item (1) above detect 

additional components with significant FAC wear, then the sample should be 

further expanded to include:
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(a) Any component within two diameters downstream of the component 

displaying significant wear or within two diameters upstream if that 

component is an expander or expanding elbow.

(b) A minimum of the next two most susceptible components from the 

relative wear ranking in the same train as that containing the piping 

component displaying significant wear.

(3) If inspections of the expanded sample specified under Item (2) above detect 

additional components with significant wear, then expansion of the sample 

specified under Item (2) should be repeated until no additional components 

with significant wear are detected.

The sample expansion guidelines are intended to add more examination data to 

calibrate the CHECWORKS SFA model, thereby increasing the accuracy of the 

prediction."

 (b) Sample expansion is based upon wall thickness (e.g., measured wall thickness 

significantly less than predicted wall thickness) and wear rate (e.g., results 

negatively affecting remaining service life).

 (c) The FAC Program is applicable to both safety-related and nonsafety-related piping 

systems susceptible to FAC. The inspection sample is a subset of the systems that 

make up the overall program scope and generally represents the most FACsusceptible piping in the plant. The sample expansion guidelines are applicable to 

all in-scope piping, and are applied consistently to both safety-related and 

nonsafety-related piping.

The staff reviewed the applicant's response and noted that the applicant provided the sample 

expansion criteria, which includes additional components within two pipe diameters upstream or 

downstream of the degraded component, the two most susceptible components in the same 

train, and corresponding with two components in another train of a multi-train system. In 

addition, the staff noted that the applicant will increase the sample size until no additional 

components with significant wear are detected. The staff finds the applicant response 

acceptable because the sample expansion scope includes the appropriate locations to 

determine the extent of degraded components, and the applicant is consistent with the GALL 

AMP XI.M17 recommendation of evaluating the results of the inspection to determine if 

additional inspections are needed. In its response to Part B, the staff noted that the applicant 

uses both the wall thickness and wear rate as a basis for sample expansion. The staff finds the 

applicant’s response to (b) acceptable because using both the actual measured wall thickness 

and the wear rate in combination provides a more realistic basis for calculating remaining life 

and for sample expansion. In response to (c), the staff noted that the applicant applies the FAC 

Program to safety-related and nonsafety-related systems. The staff determined that the 

CHECWORKS model identifies the most FAC-susceptible piping in the plant irrespective of 

safety or nonsafety-related system. The staff finds the applicant’s response to (c) acceptable 

because the FAC Program and the CHECWORKS model does not distinguish between safetyand nonsafety-related systems, but determines the most FAC-susceptible piping, and uses the 

same sample expansion criteria for safety and nonsafety-related systems. RAI B2.1.17-4 is 

resolved.
3-40

The “detection of aging effects” program element in GALL AMP XI.M17 states that the extent 

and schedule of the inspections assure detection of wall thinning before the loss of intended 

function. The staff issued RAI B2.1.17-5, by letter dated November 5, 2008, to request the 

applicant to indicate how PINGP calculates minimum permitted wall thickness to avoid loss of 

intended function and how it is used for the determination of the schedule of inspections in the 

FAC analysis.

In its letter dated December 5, 2008, in response to RAI B2.1.17-5, the applicant stated that:

Per the requirements of the PINGP Flow-Accelerated Corrosion (FAC) Program, 

the minimum permitted wall thickness or Code Minimum Wall Thickness (tmin) is 

calculated in accordance with the original construction code, which is USAS 

B31.1.0, Power Piping, 1967 Edition. Additionally, the program may define a 

Critical Wall Thickness (tcrit) for a component, as determined by engineering 

analysis. The critical wall thickness is typically a larger value than tmin. In turn, 

the remaining service life for a component is the estimated number of years until 

the wall thickness violates tmin, tcrit, or other established acceptance criteria. The 

remaining service life is based on measured wear rates or the predicted wear 

rates calculated by the CHECWORKS SFA application. The remaining service 

life is used to determine the appropriate future inspection schedule.

The FAC Program schedules follow-on examinations for specific components 

based upon previous examinations and evaluation results. Follow-on 

examinations are scheduled no later than the normal inspection period (e.g., 

refueling outage) preceding the end of the predicted FAC remaining service life 

of the component. Engineering judgment and an appropriate safety factor (per 

the guidance of NSAC-202L, "Recommendations for an Effective FlowAccelerated Corrosion Program") are utilized when scheduling follow-on exams. 

Typically, follow-on examinations are scheduled at half of the remaining service 

life and no later than the normal inspection period prior to the point at which the 

calculated tmin or tcrit is reached.

The extent and schedule of the examinations assure detection of wall thinning 

before the loss of intended function.

The staff reviewed the applicant response and noted that the applicant uses the B31.1.0 Code 

to determine the minimum permitted wall thickness. The staff also noted that the applicant uses 

a critical wall thickness value larger than the minimum to determine the remaining service life. 

The staff reviewed EPRI guidelines in NSAC-202L-R2, Section 4.4.3, Follow-On Inspections, 

which states that the next inspection for each component be scheduled for no later than the 

normally scheduled refueling outage preceding the end of the predicted FAC service life of the 

component plus an appropriate safety factor. Since the GALL AMP XI.M17 relies on 

implementation of EPRI guidelines in NSAC-202L-R2 for an effective FAC program, the staff 

finds that the applicant is consistent with GALL AMP XI.M17. The staff finds the applicant’s 

response acceptable because the applicant is using the original construction code to determine 

minimum wall thickness, the applicant uses an acceptable wall thickness value to determine 

remaining service life, and based on the wear rates determines the intervals of follow-on 

inspections, and is consistent with GALL AMP XI.M17. RAI B2.1.17-5 is resolved.
3-41

In a letter dated March 12, 2009, the applicant revised the LRA for the FAC Program to update 

to the latest EPRI guidance, which is an exception to the GALL Report XI.M17, FlowAccelerated Corrosion. In the letter, the applicant states the following for the Program 

Description:

The Flow-Accelerated Corrosion (FAC) Program is a condition monitoring 

program established in accordance with the Electric Power Research Institute 

(EPRI) guidelines in Nuclear Safety Analysis Center (NSAC)-202L-R3 for carbon 

steel and bronze components containing high-energy single phase or two phase 

fluids. The program manages loss of material due to FAC in piping and 

components by (a) conducting an analysis to determine critical locations, (b) 

performing baseline inspections to determine the extent of thinning at these 

locations, and (c) performing follow-up inspections to confirm the predictions of 

the rate of thinning, or repairing or replacing components as necessary. This 

program complies with PINGP’s response to NRC Generic Letter 89-08.

This change in the LRA produces an exception to the GALL Report. The applicant stated in the 

letter the following:

Exceptions to NUREG-1801

Program Elements Affected

Scope of Program, Detection of Aging Effects

PINGP implements the guidance provided in EPRI NSAC-202L-R3, 

“Recommendations for and Effective Flow-Accelerated Corrosion Program,” 

May 2006, in lieu of the NUREG-1801 recommendation of EPRI 

NSAC-202L-R2, “Recommendations for and Effective Flow-Accelerated 

Corrosion Program,” April 1999. EPRI NSAC-202L-R3 is the most recent 

revision of this document, and it provides more prescriptive guidance based 

on the latest industry OE. Use of the current guideline is an acceptable 

method to maintain the FAC-susceptible systems at PINGP.

The staff finds that this exception is acceptable because the revised guideline is more 

prescriptive than the guidance referenced in the GALL Report. Most of the recent applicants 

have also switched to the latest EPRI guidance and the latest guidance will be incorporated in 

the next update to the GALL Report.

Based on its review and resolution of the RAIs as described above, the staff finds the FAC 

Program consistent, with acceptable exception, with the program elements of GALL 

AMP XI.M17, and therefore acceptable.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.17 and 

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 also confirmed that 

applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 

and are evaluated in the GALL Report. 
3-42

The staff also reviewed the applicant’s OE discussion that was provided in the applicant’s 

license renewal basis document for the FAC Program. The staff reviewed a sample of CRs and 

confirmed that the applicant had identified age-related degradation and implemented 

appropriate corrective actions.

The staff reviewed the Unit 1 Outage Summary Report for FAC inspections performed from April 

to June 2006. The staff noted that a total of 74 components were ultrasonically inspected for 

FAC. In addition, the staff noted that there were nine locations added as a result of scope 

expansion. The staff also noted that there were three minimum wall violations and seven 

components were replaced as a result of the FAC inspections.

The staff also reviewed the Unit 2 Outage Summary Report for FAC inspections performed from 

November to December 2006. The staff noted that a total of 93 components were ultrasonically 

inspected for FAC wear. In addition, the staff noted that there were 16 locations added as a 

result of scope expansion. The staff also noted that there was one minimum wall violation and 

one component was replaced as a result of the FAC inspections. The staff noted that the 

applicant replaced the component with like-for like material; however, the Outage Summary 

Reports recommended that future replacements of small-bore heater drain lines should utilize

FAC resistant material.

Furthermore, the staff confirmed that the applicant has addressed OE identified after the 

issuance of the GALL Report. The staff finds that the applicant’s FAC Program, with the 

corrective actions discussed in the LRA, has been effective in identifying, monitoring, and 

correcting the effects of FAC and can be expected to ensure that piping wall thickness will be 

maintained above the minimum required by design.

The staff confirmed that the OE 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 element acceptable. 

UFSAR Supplement. In LRA Section A2.17, the applicant provided the UFSAR supplement for 

the FAC Program. The staff verified that the UFSAR supplement summary description for the 

FAC Program was in conformance with the staff’s recommended UFSAR supplement for these 

types of programs provided in Table 3.4-2 of the SRP-LR. 

Based on this review, the staff determines that UFSAR supplement Section A2.17 provides an 

acceptable UFSAR supplement summary description of the applicant’s FAC because it is 

consistent with those UFSAR supplement summary description in the SRP-LR for FAC 

Program.

The staff determines that the information in the UFSAR 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 FAC Program and the 

applicant’s response to the staff’s RAIs, the staff finds all program elements consistent, with an 

acceptable exception, with the GALL Report. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 
3-43

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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 Fuse Holders 

Summary of Technical Information in the Application. LRA Section B2.1.20, describes the Fuse 

Holders Program as a new program that is consistent with GALL AMP XI.E5, “Fuse Holders.”

The applicant states that the Fuse Holders Program is a condition-monitoring program that 

implements periodic visual inspections and tests on fuse holders in-scope of license renewal, 

located in passive enclosures and assemblies, and exposed to environments that potentially 

could lead to electrical circuit failures if left unmanaged. The applicant further states that the 

fuse holders (metallic clamps) program manages the effects of aging from adverse localized 

environments caused from the following aging stressors, as applicable: fatigue, mechanical 

stress, vibration, chemical contamination, and corrosion. The applicant also states that fuse 

holders determined to be operating in an adverse localized environment will be visually 

inspected and tested at least once every 10 years. The first visual inspections and tests will be 

completed before the period of extended operation. The applicant also states that the specific 

type of test to be performed will be determined prior to the initial test, and is to be a proven test 

for detecting deterioration of metallic clamps of the fuse holders, such as thermography, contact 

resistance testing, or other appropriate testing.

Staff Evaluation. During the audit, the staff reviewed the applicant’s claim of consistency with 

the GALL Report. GALL AMP XI.E5 under “program description” states that the AMP for fuse 

holders (metallic clamps) needs to account for the following stressors, if applicable: fatigue, 

mechanical stress, vibration, chemical contamination, and corrosion. The applicant’s Fuse 

Holder Program under the same program element only listed fuse holders (metallic clamps) in 

adverse localized environments. Adverse localized environment is defined in the GALL Report 

as high heat, high radiation, or high moisture. Fuse holders could be exposed to the above 

stressors in a mild environment not necessarily in an adverse localized environment. In a letter 

dated November 5, 2008, the staff issued RAI B2.1.20-1 and requested the applicant to explain 

how the environment of the applicant’s fuse holder program is consistent with those in the GALL 

AMP XI.E5. 

In a letter dated December 5, 2008, the applicant responded that the use of the terminology 

"adverse localized environment" in the Fuse Holders Program was intended to encompass the 

term "stressors" in the GALL Report. To remove confusion, the applicant revised the affected 

LRA sections to remove reference to "adverse localized environments" in the descriptions of the 

Fuse Holder Program, as follows:

In LRA Section A2.20, "Fuse Holders Program," on Page A-9, the existing program description 

is replaced in its entirety with a new program description, to read as follows:

The Fuse Holders Program is a condition monitoring program that implements 

periodic visual inspections and tests of fuse holders in scope of License 

Renewal, located in passive enclosures and assemblies, and exposed to 

stressors that could affect the electrical circuit (metallic connection with the fuse) 

if left unmanaged during the period of extended operation. The Fuse Holders 
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Program accounts for the following stressors, if applicable: fatigue, mechanical 

stress, vibration, chemical contamination, and corrosion. Fuse holders 

determined to be exposed to stressors subject to aging effects will be visually 

inspected and tested at least once every 10 years. The first visual inspections 

and tests will be completed before the period of extended operation. The specific 

type of test to be performed will be determined prior to the initial test, and is to be 

a proven test for detecting deterioration of metallic clamps of the fuse

holders, such as thermography, contact resistance testing, or other appropriate 

testing. This program will be implemented prior to the period of extended 

operation.

In LRA Section B2.1.20, "Fuse Holders Program," on Page B-48, the applicant replaced the 

existing Program Description in its entirety with a new program description, to read as follows:

The Fuse Holders Program is a condition monitoring program that implements 

periodic visual inspections and tests on fuse holders in scope of license renewal, 

located in passive enclosures and assemblies, and exposed to stressors that 

could affect circuit integrity if left unmanaged. The AMP for fuse holders (metallic 

clamps) manages the effects of aging from the following stressors, as applicable: 

fatigue, mechanical stress, vibration, chemical contamination, and corrosion.

Fuse holders are reviewed, inspected and/or tested to determine if they are 

exposed to stressors that could aversely affect circuit integrity (metallic 

connection with the fuse) if left unmanaged during the period of extended 

operation. A stressor could affect circuit integrity if it promotes loose connections 

from clip relaxation/fatigue (ohmic heating, thermal cycling or electrical 

transients, mechanical fatigue caused by frequent removal/replacement of the 

fuse, or vibration), or if it exposes the fuse holder to chemical contamination or 

moisture that would promote corrosion and oxidation of the metallic fuse clips.

Fuse holders requiring aging management will be visually inspected and tested 

at least once every 10 years. The first visual inspections and tests will be 

completed before the period of extended operation. The specific type of test to be 

performed will be determined prior to the initial test, and is to be a proven test for 

detecting deterioration of metallic clamps of the fuse holders, such as 

thermography, contact resistance testing, or other appropriate testing.

In LRA Table 3.0-3, "Electrical Service Environments," on Page 3.0-19, the applicant deleted 

the last line item on the page (Mechanical Cycling) in its entirety and replaced it with the

following:

“Stressors: Fuse Holders (Metallic Parts - clips) exposed to the following stressors, if

applicable: fatigue, mechanical stress, vibration, chemical contamination, and corrosion.”

In LRA Section 3.6.2.1.7, on Page 3.6-7, under Environment, the applicant replaces the two 

bullet items "Adverse localized environment (causing corrosion and/or fatigue)" and "Mechanical 

Cycling" with the single new bullet environment "Stressors."
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In LRA Table 3.6.2-1, "Electrical Components - Electrical Commodity Groups - Summary of 

Aging Management Evaluation," on Page 3.6-20, for the line item "Fuse Holders (metallic parts) 

not part of a larger active assembly," the applicant replaces the existing entries under 

Environment, "Adverse localized environment, Mechanical Cycling" with the new

entry "Stressors."

The staff finds the applicant response acceptable because the applicant revised various LRA 

sections to remove a reference to “adverse localized environments” and replaced them with the 

applicable stressors as described in GALL AMP XI.E5 for fuse holders (metallic clamps). These 

stressors are fatigue, mechanical stress, vibration, chemical contamination, and corrosion. With 

these revisions, the staff finds the applicant’s Fuse Holders AMP is consistent with the GALL 

AMP XI.E5. 

Based on its review of the LRA, including the applicant’s response to RAI B2.1.20-1, the staff 

finds the applicant’s Fuse Holders Program consistent with the program elements of GALL 

AMP XI.E5, and therefore acceptable.

Operating Experience. In LRA Section B2.1.20, the applicant states that the Fuse Holders 

Program is a new program, and, therefore, has no OE related to program implementation. The 

applicant conducted a review of plant-specific OE and did not identify any fuse connection 

failure from potential age-related causes. The applicant’s plant OE review did identify fuse 

enclosure issues involving water intrusion from event driven causes (e.g., water leaked into 

conduit and emptied into enclosure). These moisture intrusion events for enclosures exposed to 

this stressor could promote a corrosion of the metallic contact surfaces, leading to increased 

contact resistance and circuit failure if left unmanaged. The applicant also states that 

inspections and testing (thermography) were performed on fuse holders in-scope of license 

renewal in terminal boxes and junction boxes located outside containment. This initial inspection 

and testing revealed that some enclosures had significant signs of oxidation that could 

adversely affect the fuse holders if not repaired or reworked. The applicant entered these 

conditions into the Corrective Action Program for disposition. For adverse aging environments, 

this program will ensure the integrity of fuse holders in-scope of License Renewal and located in 

passive enclosures during the period of extended operation.

The staff reviewed the OE provided in the LRA and in the basis documents that were available 

during the audits. Based on the review of the applicant-identified OE, the staff has confirmed 

that the applicant has identified aging effects for fuse holders, e.g., increased contact resistance 

due to corrosion and taken appropriate corrective actions to address the fuse holder corrosion 

issue. Therefore, the staff determines that the applicant has adequately addressed this element.

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 

element acceptable.

UFSAR Supplement. In LRA Section A2.20, the applicant provided the UFSAR supplement for 

the Fuse Holders Program. The staff reviewed this section and determined that the information 

in UFSAR supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d).
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The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 16.

Conclusion. On the basis of its audit and reviews of the applicant's Fuse Holders Program, 

including the applicant’s response to RAI B2.1.20-1, the staff finds all program elements 

consistent with the GALL Report. The staff concludes that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(3). The staff also reviewed the UFSAR 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 Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B2.1.21 describes the new 

Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as consistent with GALL AMP XI.E3, “Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” The applicant 

stated that this AMP will conduct periodic tests to provide an indication of the condition of the 

conductor insulation for medium voltage cables in-scope of license renewal exposed to adverse 

localized environments (i.e., periods of high moisture greater than a few days at a time) and 

subjected to voltage stress. The applicant also stated that periodic inspections of the 

underground medium voltage cable manhole for the accumulation of water (and draining if 

necessary) will be conducted to minimize prolonged high moisture conditions that promote the 

growth of water trees.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff reviewed and compared the “scope of program,” “preventive actions,” 

“parameters monitored/detected,” “detection of aging effects,” “monitoring and trending,” 

“acceptance criteria,” and “operating experience” program elements of the AMP to the 

corresponding program element criteria in GALL AMP XI.E3, “Inaccessible Medium Voltage 

Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.”

The staff’s review of the “corrective actions,” “administrative controls,” and “confirmation

process” program elements for the new Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program was performed as part of the 

staff’s review of the QA attributes of the AMPs and is discussed in SER Section 3.0.4.

The staff compared the programs elements in the applicant’s program to those in GALL AMP 

XI.E3. The staff noted that the program elements that the applicant claimed to be consistent 

with GALL were consistent with the corresponding program elements in GALL AMP XI.E3. 

Based on its review, the staff finds the Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Program consistent with the program 

elements of GALL AMP XI.E3, and therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.21. The 

applicant stated that in response to NRC Generic Letter 2007-01, “Inaccessible or Underground 
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Power Cable Failures that Disable Accident Mitigation Systems or Cause Plant Transients,” 

dated February 7, 2007, the applicant reported that three underground medium voltage power 

cable failures had occurred. The staff noted PINGP has OE with two medium voltage cable 

failures and a failed megger test. Corrective actions have been taken to address all cable failure 

issues by replacing failed cables. The applicant also responded that it intended to implement an 

“Underground Cable Maintenance Program” by the end of 2007 due to its history with cable 

failures. During the AMP audit, the staff found that the applicant had not yet implemented this 

program. The applicant created Action Report #01150075 in response to the site not having 

implemented the response to NRC Generic Letter (GL) 2007-01. The staff reviewed and 

referred this issue to the Reactor Oversight Process. During a follow-up Regional License 

Renewal Inspection, the staff revisited this issued and noted that PINGP had a cable condition

monitoring program (H43) in place as of March 2008 and the actual testing of the cables is 

governed by Procedures PE 4826 (testing of cables rated less than 600 volts) and PE 4825 

(testing of cables rated greater than 600 volts). The applicant stated that Preventive 

Maintenance Change Requests (PMCRS) 01123654 (low voltage cables) and 01123652 

(medium voltage cables) have been generated by the licensee to complete testing of cables 

within the next four refueling outages for each unit. The full description of this inspection is 

documented in Inspection Report 0500282/2009006 and 0500306/2009006 dated March 27, 

2009.

The staff reviewed CRs as part of its on-site review of the AMP. In reviewing OE for PINGP, the 

staff observed that the applicant had two separate cable failures and one additional failed cable 

test. As noted above, corrective actions have been taken to address all cable failure issues by 

replacing failed cables. The staff determined that the CRs demonstrated that the applicant had 

implemented appropriate corrective actions. The staff also verified that the aging effects are 

bounded by those identified in the GALL AMP XI.E3. Therefore, the staff determines that the 

applicant has adequately addressed this element. 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 element acceptable. 

UFSAR Supplement. In LRA Section A2.21, the applicant provided the UFSAR supplement for 

the Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program. The staff reviewed this section and determines that the 

information in the UFSAR supplement provided an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 17.

Conclusion. On the basis of its review of the applicant’s Inaccessible Medium Voltage Cables 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program, the staff finds 

all program elements are consistent with the GALL Report. The staff concludes that the 

applicant has demonstrated that effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).
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3.0.3.1.13 Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Summary of Technical Information in the Application. LRA Section B2.1.22 describes the new 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program as 

consistent with GALL AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components.” The applicant stated that this is a new program and will be credited to 

manage loss of material and cracking for the internal surfaces of mechanical components in the 

scope of this program. The applicant stated that this program provides for internal visual 

inspections during scheduled preventive and corrective maintenance activities or during 

routinely scheduled tasks such as surveillance procedures when the internal surfaces are 

accessible for these inspections.

Staff Evaluation. During its audit, the staff reviewed the applicant=s claim of consistency with the 

GALL Report. The staff’s summary of its on-site review of AMP B2.1.22, Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components, is documented in staff’s Audit 

Summary Report Section for this AMP.

In comparing the seven programs elements in the applicant’s program to those in 

GALL AMP XI.M38, the staff noted that the program elements which the applicant claimed its

AMP were consistent with the GALL Report were consistent with the corresponding program 

element criteria recommended in the program elements of GALL AMP XI.M38 with the 

exception of those areas in which the staff determined there was a need for additional 

clarification, for which RAIs were issued. The OE program element is discussed separately 

below.

The staff noted that GALL AMP XI.M38 recommends that only steel components are managed 

for the aging effect of loss of material. However, during the staff’s review of LRA Section 

B2.1.22 and of the AMR line items that credit this program for aging management in LRA 

Section 3.0, the staff noted that the applicant has expanded the scope of materials to include 

additional metallic components, other than steel, and has also credited this program with 

managing cracking due to SCC in stainless steel components. Therefore by letter dated 

November 5, 2008, the staff issued RAI B2.1.22-1 requesting the applicant to:

(a) justify why the expansion in the scope of materials to include additional 

metallic components other than steel, and in the scope of aging effects to 

include cracking due to SCC are not considered an enhancement to the 

program;

(b) justify how this program will adequately manage the aging effect of loss of 

material and any associated aging mechanisms, as it applies to the additional 

metallic components added to the scope of this program; and

(c) identify and justify the inspection techniques that will be used by this program 

that will be capable of detecting cracking due to SCC in stainless steel 

components or provide an appropriate program to manage cracking due to 

SCC for stainless steel components.

The applicant responded to RAI B2.1.22-1 by letter dated December 5, 2008. The applicant 

stated in Part A of its response that its program as described in LRA Section B2.1.22 is a new 
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program and therefore enhancements are not applicable. The applicant further stated that 

enhancements are only applicable to existing plant programs. The staff noted in Section 3.0 of 

the SRP-LR that enhancements are revisions or additions to existing AMPs. The staff 

determined that the applicant has appropriately not identified the expansion in-scope of 

materials and aging effects as enhancements. The staff finds the applicant’s response to Part A 

to be acceptable because the applicant’s program does not meet the definition of an 

enhancement in the SRP-LR and the staff will evaluate the adequacy of these expansions in its

evaluation of Parts B and C of the RAI.

The applicant responded to Part B of the RAI by stating that the program is utilizing established 

visual techniques that are capable of detecting loss of material due to corrosion and fouling. The 

applicant further stated that the inspections will be performed periodically such that aging effects 

will be detected prior to the loss of intended functions. The staff noted that the presence of 

corrosion or fouling can be identified by the applicant as localized discoloration and surface 

irregularities such as rust, scale/deposits, surface pitting, surface discontinuities, and coating 

degradation. The staff noted that metallic components, including aluminum, brass and bronze, 

CASS, copper alloy, copper-nickel and stainless steel, would exhibit indications of loss of 

material on the surface similar to a steel material and that visual inspections will be capable of 

detecting any surface breaking flaws (i.e., cracks or surfaces areas that have exhibited loss of 

material) that occur on the same side as that being examined. On the basis of its review, the 

staff finds Part B of the applicant’s response to be acceptable because the applicant will be 

performing visual inspections that are capable of detecting loss of material in metallic 

components as they display indications of corrosion similar to steel, for which GALL AMP 

XI.M38 was intended to detect.

The applicant responded to Part C of the RAI by stating that the use of this program will only be 

used to detect cracking due to SCC for stainless steel flexible connections that are exposed to a 

diesel exhaust environment. The applicant further stated that the inspection techniques that will 

be utilized to detect this aging effect are either a visual inspection with a magnified resolution as 

described in 10 CFR 50.55a(b)(2)(xxi)(A) or an ultrasonic inspection method. The staff further 

noted that the inspection method described in 10 CFR 50.55a(b)(2)(xxi)(A), is an enhanced VT1 inspection technique, and that GALL AMP XI.M32 recommends the use of an enhanced VT-1 

or ultrasonic inspection technique as an acceptable means to detect cracking due to SCC. The 

staff noted that the inspection techniques described by the applicant will be performed by 

qualified personnel in accordance with PINGP procedures and processes. On the basis of its 

review, the staff finds the applicant’s response to Part C of RAI acceptable because (1) the 

applicant’s inspection techniques, enhanced VT-1 or ultrasonic methods, to detect cracking due 

to SCC are consistent with the recommendations of GALL AMP XI.M32, (2) the applicant’s 

enhanced VT-1 technique is in accordance with 10 CFR 50.55a(b)(2)(xxi)(A) and (3) these 

inspections will be performed by qualified personnel in accordance with approved PINGP 

procedures and processes.

The staff noted that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Program includes LRA Commitment No. 18, which was placed on the LRA in the applicant’s 

letter of April 13. 2009, and in which the applicant committed to implement this program prior to 

entering the period of extended operation and use of either an enhanced VT-1 or ultrasonic 

inspection techniques to detect cracking due to SCC.
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On the basis of its review, the staff finds the applicant’s response to RAI B2.1.22-1 acceptable 

as described above and therefore the staff finds the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components, as committed to in LRA Commitment No. 18, to 

be consistent with the program elements of GALL AMP XI.M38, with acceptable augmentations 

as described, and is therefore acceptable. RAI B2.1.22-1 is resolved.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.22 and 

audited the OE reports, including a sample of CRs, and interviewed the applicant’s technical 

staff to confirm that the plant-specific OE did not reveal any degradation not bounded by 

industry experience.

During its review, the staff noted that the Unit 1 24-CL-16 Cooling Water piping downstream of 

the MV-32037 had experienced wall thinning below the ASME B31.1 piping code minimum wall 

thickness. The applicant had noted this area was not leaking and had initiated corrective actions 

to address this issue. The applicant utilized nondestructive examination (NDE) methods to 

measure the flaw and then performed an evaluation to ensure the piping would continue to meet 

its design requirements. The applicant concluded that the piping was degraded but remained 

operable. Per ASME Code Case N 513-2 the applicant was required to take further actions and 

have them tracked. As required, the applicant performed a re-inspection and noted that the flaw 

size was unchanged from the original report, the applicant performed an augmented UT 

inspection of an expanded sample size of components that did not indicate a minimum wall 

thickness of the examined components and the applicant repaired/replaced the degraded piping 

during the refueling outage in December 2006.

The staff also noted that the applicant discovered a pin-hole leak in the turbine oil cooler (CW27-2) valve body. Subsequent UT results and evaluation by the applicant determined that the 

cause of the pin-hole is the result of MIC. The applicant replaced the valve during the Unit 1 

refueling outage in November 2002.

The staff reviewed the OE provided in the LRA and interviewed the applicant’s technical staff to 

confirm that the OE did not reveal degradations that are not bounded by industry experience. 

The staff confirmed that there has not been any crack-related or loss-of-material-related OE that 

is not bounded by the ability of the program to detect loss of material or cracking in the 

components managed by the AMP or to take appropriate corrective actions if these aging 

effects are detected. The staff confirmed that the OE program element satisfies the criterion 

defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, the staff finds this 

program element acceptable.

UFSAR Supplement. In LRA Section A2.22, the applicant provided the UFSAR Supplement for 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components. The staff 

reviewed the supplement and verified that, in LRA Commitment No. 18 of the Preliminary 

License Renewal Commitments in a letter dated April 13, 2009, the applicant committed to 

implementing this program prior to the period of extended operation as described in LRA 

Section B2.1.22. The staff finds the UFSAR Supplement for this AMP acceptable because it is 

consistent with the corresponding description in SRP-LR Table 3.3-2 and because the summary 

description includes the bases for determining that aging effects will be managed, as committed 

to in LRA Commitment No. 18. The staff determined that the information in the UFSAR
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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 Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components, the staff finds that all program elements are 

consistent with the GALL Report. The staff concludes that the applicant has demonstrated that 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.1.14 Lubricating Oil Analysis 

Summary of Technical Information in the Application. LRA Section B2.1.24 describes the 

applicant’s existing Lubricating Oil Analysis Program as consistent with GALL AMP XI.M39, 

"Lubricating Oil Analysis." The applicant stated that the PINGP Lubricating Oil Analysis Program 

obtains and analyzes lubricating and hydraulic oil samples from plant equipment to ensure that 

the oil quality is maintained within established limits. The program calls for maintaining oil 

contaminants (primarily water and particulates which may be indicative of in-leakage and

corrosion product buildup) within acceptable limits to preserve an operating environment that is 

not conducive to loss of material, cracking, or heat transfer degradation.

Staff Evaluation. During its audit, the staff confirmed the applicant=s claim of consistency with 

the GALL Report. LRA Section B2.1.24 provides the applicant’s program description, statement 

of consistency with the GALL Report, OE, and its conclusion that the PINGP Lubricating Oil 

Analysis AMP will provide reasonable assurance that aging effects due to cracking and loss of 

heat transfer capability will be adequately managed through the period of extended operation.

The applicant stated that the Lubricating Oil Analysis Program is consistent with the 

10 elements of AMP XI.M39, “Lubricating Oil Analysis,” with no exceptions or enhancements.

During the on-site review, the staff reviewed documents supporting the applicant’s conclusion 

that the program elements are consistent with the elements in the GALL AMP. Based on its 

review, the staff determined that the program elements for the applicant’s Lubricating Oil 

Analysis Program are consistent with the program elements of GALL AMP XI.M39. Based on 

this review, the staff finds that the program elements for the applicant’s Lubricating Oil Analysis 

Program are acceptable.

Operating Experience. The applicant stated that the Lubricating Oil Analysis program has been 

effective in preventing component failures due to oil contamination or degradation. The 

applicant noted that in some instances where oil samples contained water or particulate 

contamination in excess of the established limits, appropriate actions were taken in accordance 

with the Corrective Action Program to correct the identified conditions, and no instances of 

component failures attributed to lubricating oil contamination or degradation have been 

identified.
3-52

The applicant also stated that the management of aging effects is achieved through objective 

evidence showing that aging effects/mechanisms are being adequately managed consistent 

with the CLB for the period of extended operation.

The staff audited the OE reports, including a sample of CRs available in the Corrective Action 

Program, and interviewed the applicant’s technical staff. This staff noted that the CRs did not

include any reports where wear or equipment failure had resulted because of poor lubricating oil 

quality, which is an indication of the effectiveness of the applicant’s Lubricating Oil Analysis

Program. 

The staff noted that the documentation provided by the applicant during the onsite review 

supports the applicant’s statements regarding OE and confirmed that the plant-specific OE did 

not reveal any degradation not bounded by industry experience. 

The staff confirmed that the Aoperating 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 

element acceptable.

UFSAR Supplement. The applicant provided its UFSAR Supplement for the Lubricating Oil 

Analysis Program in LRA, Appendix A, Section A2.24. The staff verified that provisions of the 

UFSAR Supplement for the Lubricating Oil Analysis Program is in conformance with the 

recommended UFSAR Supplement summary description for Lubricating Oil Analysis Programs 

in SRP-LR, Tables 3.3.1-2, 3.2-2, 3.3-2 and 3.4-2. Based on this review, staff finds that the 

applicant’s UFSAR Supplement for the Lubricating Oil Analysis Program is acceptable.

The staff finds that the UFSAR Supplement for the Lubricating Oil Analysis Program 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 Lubricating Oil Analysis Program, the 

staff finds 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 UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.1.15 Masonry Wall Program

Summary of Technical Information in the Application. LRA Section B2.1.25 describes the 

existing Masonry Wall Program as consistent with GALL AMP XI.S5, “Masonry Wall Program.” 

This program will manage aging effects so that the evaluation basis established for each 

masonry wall within the scope of license renewal remains valid through the period of extended 

operation.

The applicant stated that the program includes all masonry walls identified as performing 

intended functions in accordance with 10 CFR 54.4. Included components are the 10 CFR 

50.48 and 10 CFR 50.63 required masonry walls, flood barriers, HELB shielding, missile 
3-53

barriers, structural supports for masonry walls, radiation shielding masonry walls, and masonry 

walls with the potential to affect safety-related components.

The applicant further stated that the steel supports and steel bracing of masonry walls in-scope

of license renewal are inspected as part of the Structures Monitoring Program. The applicant 

also stated that masonry walls are visually examined at a frequency selected to ensure there is 

no loss of intended function between inspections. 

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the associated basis documents to 

determine whether the AMP remains adequate to manage the aging effects for which it is 

credited in the LRA.

The staff interviewed the applicant’s technical staff and reviewed those portions of the Masonry 

Wall Program for which the applicant claims consistency with GALL AMP XI.S5.

During its review, the staff asked for the visual examination frequency for the program and its 

technical basis. In its response, the applicant stated that the inspection is implemented by the 

Structures Monitoring Program and consists of visual inspection for cracking in joints, 

deterioration of penetrations, missing or broken blocks, missing mortar, and general mechanical 

soundness of steel supports. The applicant also stated that visual inspections are conducted at 

least every five years to ensure no loss of intended function between inspections. Based on its 

review, the staff finds the Masonry Wall Program consistent with the program elements of GALL 

AMP XI.S5, and therefore is acceptable.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.25, and 

Operation Experience Review Report (Masonry Walls section), and interviewed the applicant’s 

technical staff to confirm that the plant-specific OE has been reviewed by the applicant and was 

evaluated as intended in the GALL Report. During its audit, the staff found some minor 

indications that did not affect the structural integrity of any of the structures reviewed. 

Furthermore, the staff confirmed that the applicant had addressed OE identified after the 

issuance of the GALL Report. The staff finds that the applicant’s Masonry Wall Program, with 

the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and 

correcting the aging effects on masonry walls. The staff also confirmed that plant-specific OE

did not reveal any degradation not bounded by industry experience. 

The staff confirmed that the Aoperating 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 

element acceptable.

UFSAR Supplement. In LRA Section A2.25, “Masonry Wall Program,” the applicant provided the 

UFSAR supplement for the Masonry Wall Program. The staff reviewed this section and 

determines that the information in the UFSAR 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 Masonry Wall 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 function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.1.16 Metal-Enclosed Bus

Summary of Technical Information in the Application. LRA Section B2.1.26 describes the MetalEnclosed Bus Program as a new program that is consistent with GALL AMP XI.E4, “MetalEnclosed Bus.” The applicant states the Metal-Enclosed Bus (MEB) Program is a conditionmonitoring program that inspects representative samples of the interiors of non-segregated 

4160V phase bus between station offsite source auxiliary transformers and plant buses. The 

applicant also states that the inspection may include thermography and/or electrical resistance 

testing to ensure the integrity of bus connections. The program manages the aging effect of 

reduction of insulation resistance in insulation components, loose connections, and corrosion 

from moisture or debris intrusion in non-segregated bus ducts. In addition, the applicant states 

that the interior visual inspection will be conducted at least once every five years, or, if 

conducted with thermography or electrical resistance testing, at least once every 10 years. The 

applicant further states that the first inspections and/or tests will be completed before the period 

of extended operation.

Staff Evaluation. During the audit, the staff reviewed the applicant’s claim of consistency with 

the GALL Report. In LRA Section B2.1.26, the applicant claims that its Metal Enclosed Bus 

program is consistent with GALL AMP XI.E4. The scope of program in GALL AMP XI.E4 is to 

inspect all MEBs within the scope of program and a sample of accessible bolted connections. In 

AMP B2.1.26, the applicant will only inspect representative samples of MEBs within the scope 

of license renewal. In a letter dated November 5, 2008 (RAI B2.1.26-1), the staff requested the 

applicant to explain how the scope of applicant’s MEB program is consistent with that in the 

GALL AMP XI.E4. In response to the staff’s request, in a letter dated December 5, 2008, the 

applicant stated that to be consistent with NUREG-1801 Program XI.E4, LRA Sections A2.26 

and B2.1.26 are revised as follows:

In LRA Section A2.26, "Metal Enclosed Bus Program," on Page A-11, the first 

paragraph is revised by deleting the words "representative samples of" from the 

second line.

In LRA Section B2.1.26, "Metal Enclosed Bus Program," on Page B-57, the 

Program Description is revised in its entirety to read as follows:

"The Metal-Enclosed Bus Program is a condition monitoring program that 

inspects the interiors of non-segregated 4160V phase bus between station offsite 

source auxiliary transformers and plant buses. Internal visual inspection is 

performed to observe signs of aging of the bus insulation materials such as 

cracking and discoloration, evidence of loose connections, and signs of moisture 

and debris intrusion. Internal bus supports are visually examined for structural 

integrity and signs of cracks. The inspection may also include thermography 

and/or electrical resistance testing to ensure the integrity of bus connections. The 

program manages the aging effect of reduction of insulation resistance in 
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insulation components, loose connections, and corrosion from moisture/debris 

intrusion in non-segregated bus ducts. The scope of the Metal-Enclosed Bus 

Program applies to MEB within the scope of license renewal. The internal portion 

of the MEB will be visually inspected every 10 years. For bolted connections, a 

sample of accessible bolted connections will be checked for loose connection by 

thermography, resistance measurement, or by an alternative internal bolted 

connection visual inspection to detect surface anomalies of the insulating 

material covering the connection. If selected, the loose connection

thermography or resistance measurement will be performed every 10 years, or if 

selected, an alternative internal bolted connection visual inspection will be 

performed every 5 years. The first inspections and tests will be completed before 

the period of extended operation."

The staff finds the applicant’s response acceptable because with the proposed LRA 

amendment as described above, the scope of the applicant’s MEB Program is now 

consistent with that in GALL AMP XI.E4, because it includes all metal enclosed buses 

within the scope of license renewal. These MEBs include non-segregated 4160 V phase 

bus between station offsite source auxiliary transformers and plant buses. The staff also 

finds that the program description is consistent with that in the GALL AMP XI.E4. 

GALL AMP XI.E4, Metal Enclosed Bus, will provide for inspection of the interior of MEBs and 

GALL AMP XI.S6, Structures Monitoring Program, will inspect the exterior of the enclosure 

assembly. In PINGP AMP B2.1.26, under program element 3 (parameters monitored/inspected), 

the applicant stated that AMP B2.1.26 will inspect both the exterior and interior of MEBs such as 

housings and housing seals. This appeared to be an exception to GALL Report. In a letter dated 

November 5, 2008 (RAI B2.1.26-2), the staff requested the applicant to explain why this is not 

an exception to the GALL Report XI.E4 and provide technical basis for this exception. In 

response to the staff’s request, in the letter dated December 5, 2008, the applicant stated that 

LRA Section B2.1.38, the Structures Monitoring Program, provides for periodic MEB inspections 

to monitor the exterior condition of the enclosure assembly steel and elastomers. The applicant 

further stated that both the PINGP MEB Program and the Structures Monitoring Program (with 

enhancement) are consistent with the GALL Report. The applicant also stated that, as a rule, 

including activities in an AMP that exceed the minimum standards for that program in 

NUREG-1801 would not be considered an exception to NUREG-1801. However, for clarity, the 

applicant stated that the program basis document for the MEB Program has been revised to 

delete external inspection statements from its scope.

The staff finds the applicant’s response acceptable because the applicant has revised the 

program basis document for the MEB program to delete external inspection from its scope.

These inspections are performed under the Structures Monitoring Program, which is consistent 

with those in the GALL AMP XI.S6.

Under element 3 (parameters monitored/inspected), GALL AMP XI.E4 states that the internal 

bus support will be inspected for structural integrity and signs of cracks. In PINGP AMP B2.1.26, 

the applicant did not include inspection of internal bus supports. In a letter dated November 5, 

2008 (RAI B2.1.26-3), the staff requested the applicant to explain why the internal bus supports 

were not included in this element. In response to the staff’s request, in a letter dated 

December 5, 2008, the applicant stated that in PINGP LRA Appendix B2.1.26, the Metal-
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Enclosed Bus Program includes visual inspection of the internal bus supports for structural 

integrity and signs of cracks. The applicant further stated that the Program Basis Document for 

MEB has been revised to explicitly list the inspection of internal bus supports for structural 

integrity and signs of cracks in the discussion for Element 3. The staff finds the applicant’s 

response acceptable because the revised basis document includes inspection of the internal 

bus support for structural integrity; the applicant's MEB Element 3 is now consistent with that in 

the GALL AMP XI.E4 (i.e., parameters monitored/inspected).

Under program element 6 (Acceptance Criteria), the GALL AMP XI.E4 states that bolted 

connections need to be below the maximum allowed temperature for the application when 

thermography is used or a low resistance value appropriate for the application when resistance 

measurement is used. MEBs are to be free from unacceptable visual indications of surface 

anomalies, which suggest that conductor insulation degradation exists. In addition, no 

unacceptable indication of corrosion, cracks, foreign debris, excessive dust buildup or evidence 

of moisture intrusion is to exist. In the same program element, the applicant states that the 

acceptance criteria for each inspection and test is defined by the specific type of test performed.

The staff noted that acceptance criteria of the program and its basis should be described. The 

acceptance criteria, against which the need for correction actions will be evaluated, should 

ensure that the structure and component intended function(s) are maintained under all CLB 

design conditions during the period of extended operation. The applicant has not described 

acceptance criteria for program Element 6 of AMP B2.1.26. In a letter dated November 5, 2008 

(RAI B2.1.26-4), the staff requested the applicant to describe acceptance criteria for each 

inspection and/or test and compare these acceptance criteria against those in GALL AMP 

XI.E4. In response to the staff’s request, in a letter dated December 5, 2008, the applicant 

stated that the Program Basis Document for the MEB Program has been revised to clarify the 

intent of the acceptance criteria. The applicant also stated that thermography inspection 

acceptance criterion for bolted connections are to maintain temperatures below the maximum 

allowed temperature for the application. When resistance measurement is performed, a low 

resistance acceptance value is used, appropriate for the application. MEB manufacturer design 

information may be used as a basis for acceptance criteria. For the alternative internal bolted 

connection visual inspection, the acceptance criteria for insulated bolted connections are to be 

free from unacceptable visual indications of surface anomalies, which suggest that conductor 

insulation degradation exists. The applicant further stated that when the alternative visual 

inspection for bolted connections is used, the absence of discoloration, cracking, chipping or 

surface contamination will provide positive indication that the bolted connections are not loose.

For the internal visual inspection, the applicant stated that the acceptance criteria would be no 

unacceptable indication of corrosion, cracks, foreign debris, excessive dust buildup, or evidence 

of moisture intrusion. Internal bus supports are visually inspected for indication of reduced 

structural integrity and signs of cracks. The applicant also stated that an unacceptable indication 

is defined as a noted condition or situation that, if left un-managed, could lead to a loss of 

intended function. 

The staff reviewed the information provided and found the applicant’s response acceptable 

because the applicant has revised the program basis document to describe the acceptance 

criteria for each inspection and/or testing. This should ensure that the component intended 

function(s) are maintained consistent with the CLB. In addition, the acceptance criteria 

described above are consistent with GALL AMP XI.E4, Element 6 (Acceptance Criteria).
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Based on its review, including the applicant’s response to staff’s RAI numbers B2.1.26-1, 2, 3, 

and 4, the staff finds that the applicant’s MEB Program is consistent with the program elements 

of GALL AMP XI.E4, and therefore acceptable. 

Operating Experience. The staff reviewed the OE described in LRA B2.1.26. In LRA Section 

B2.1.26, the applicant states that the MEB Program is a new program, and, therefore, it has no 

OE related to program implementation. The applicant performed a review of plant OE which 

reveals that previous periodic inspections of bus ducts have identified degraded components 

that were repaired/replaced to prevent electrical failures. In the plant basis documents, the 

applicant states that past inspections discovered corroded interior parts of metal-enclosed bus 

sections in the 1MX/1MY Bus Duct as a result of moisture intrusion, and expanded the scope of 

inspection to internal electrical components in other metal-enclosed bus ducts having the same 

configuration and environments (outdoors). The staff reviewed a CR investigating the root cause 

for the 1MX/1MY degradation and verified that the applicant appropriately identified the root 

causes and took appropriate corrective actions to address bus duct degradation issues

The staff reviewed the OE provided in the LRA and in the basis documents that were available 

during the audits. Based on the review of the industry and applicant-identified OE, the staff has 

confirmed that the applicant has addressed OE related to this program, and has identified the 

applicable aging effects, i.e., moisture or debris buildup internal to the metal enclosed bus, 

which are the aging effects identified by the GALL Report for this program. Therefore, the staff 

determines that the applicant has adequately addressed this element. The staff confirmed that 

the OE program element satisfies the criteria defined in the GALL Report and in SRP-LR 

Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Appendix A, Section A2.26, the applicant provided the UFSAR

supplement for the AMP MEB Program. The staff reviewed this section and determined that the 

information in the UFSAR supplement provides an adequate summary description of the 

program, as required by 10 CFR 54.21(d). 

The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 20.

Conclusion. On the basis of its review of the applicant’s MEB Program, including the applicant’s 

responses to RAIs B2.1.26-1, 2, 3, and 4, the staff finds all program elements consistent with 

the GALL Report. The staff concludes that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d). 

3.0.3.1.17 Nickel-alloy Nozzles and Penetrations 

Summary of Technical Information in the Application. In the PINGP LRA Section B2.1.27, the 

applicant commits to comply with applicable NRC orders, and implement applicable NRC 

Bulletins, Generic Letters, and staff-accepted industry guidelines to manage cracking due to 

primary water stress corrosion cracking (PWSCC). In this LRA Section, the applicant stated that 
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AMP B2.1.27 is a new program that will be implemented before the period of extended 

operation.

By letter dated March 27, 2009, the applicant amended the Nickel-Alloy Nozzles and 

Penetrations Program to redefine the program as an existing plant-specific AMP for the LRA 

that incorporates the ten program elements for AMPs, as recommended in SRP-LR Appendix A, 

Section A.1.2.3, and to delete the commitment in the previous version of the AMP and its

Commitment No. 21 from the LRA. 

Staff Evaluation. The staff noted that the original version of the applicant’s Nickel-Alloy Nozzles 

and Penetration Program indicated that the program will comply with all NRC Orders Generic 

Letters, and Bulletins related to PWSCC of nickel-alloys, and that the applicant reflected these 

activities as an LRA enhancement that is defined in LRA Commitment No. 21.

The staff also noted that by letter dated March 27, 2009, the applicant amended AMP B2.1.27, 

Nickel-Alloy Nozzles and Penetrations Program, to redefine the program as an existing plantspecific AMP for the LRA that incorporates the ten program elements for AMPs, as 

recommended in SRP-LR Appendix A, Section A.1.2.3, and to delete the commitment in the 

previous version of the AMP and in Commitment No. 21 from the scope of the LRA.

The staff evaluates the amended Nickel-Alloy Nozzles and Penetrations Program and the plantspecific program elements for this AMP in SER Section 3.0.3.3.1.

Operating Experience. In LRA Section B2.1.27, the applicant committed to comply with 

applicable NRC orders, and implement applicable NRC Bulletins, Generic Letters, and staffaccepted industry guidelines with regard to nickel-alloy components. However, no OE with 

regard to nickel-alloy components was provided in LRA Section B2.1.27. The staff issued RAI 

B2.1.27-1, dated December 5, 2008, to request plant-specific OE with regard to nickel-alloy 

components other than those of the closure head.

The staff also noted that by letter dated March 27, 2009, the applicant amended AMP B2.1.27, 

Nickel-Alloy Nozzles and Penetrations Program, to redefine the program as an existing plantspecific AMP for the LRA that incorporates the ten program elements for AMPs, as 

recommended in SRP-LR Appendix A, Section A.1.2.3, and to delete the commitment in the 

previous version of the AMP and in Commitment No. 21 from the scope of the LRA.

The staff evaluated the amended Nickel-Alloy Nozzles and Penetrations Program in SER 

Section 3.0.3.3.1.

UFSAR Supplement. The applicant provided its UFSAR Supplement for the Nickel-Alloy 

Nozzles and Penetrations Program in PINGP LRA, Appendix A, Section A2.27. The staff 

verified that provisions of the UFSAR Supplement are acceptable because these provisions are 

in conformance with the staff's recommendations in SRP-LR Section 3.1.2.2.13.

In a letter dated March 27, 2009, the applicant amended the LRA UFSAR Supplement A2.27 to 

(1) delete LRA Commitment No. 21 on UFSAR Supplement summary description A2.27 from 

the scope of the LRA, and (2) reflect the new augmented inspection activities and requirements 

for the non-upper RVCH penetration nozzle ASME Code Class 1 nickel-alloy components. The 
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staff’s evaluation of the amended UFSAR Supplement summary description A2.27 for the 

Nickel-Alloy Nozzles and Penetration Program is given in SER Section 3.0.3.3.1. 

Conclusion. The staff’s conclusion on the acceptability of AMP B2.1.27, Nickel-Alloy Nozzles 

and Penetrations Program and on the acceptability of the amended UFSAR Supplement 

summary description for this program is given in SER Section 3.0.3.3.1. 

3.0.3.1.18 One-Time Inspection 

Summary of Technical Information in the Application. LRA Section B2.1.29 describes the new 

One-Time Inspection Program as consistent with GALL AMP XI.M32, “One-Time Inspection.” 

The applicant stated that the One-Time Inspection Program provides additional assurance, 

through sampling inspections using nondestructive examination (NDE) techniques, that aging is 

not occurring or that the rate of degradation is so insignificant that additional aging management 

actions are not needed. The applicant also stated that the program includes measures to verify 

the effectiveness of other AMPs, such as the Water Chemistry Program, in mitigating aging 

effects and, in other cases, to confirm that a separate AMP is not needed when significant aging 

is not expected to occur. The applicant further stated that if aging effects are identified that 

could adversely impact an intended function prior to the end of the period of extended operation, 

additional actions will be taken to correct the condition, perform additional inspections, and 

perform periodic inspections, as needed. Elements of the One-Time Inspection Program include

the following: (a) determination of the sample size based on an assessment of materials of 

fabrication, environment, plausible aging effects, and OE; (b) identification of inspection 

locations in the system, component, or structure based on the aging effect; (c) determination of 

the examination technique, including acceptance criteria that would be effective in managing the 

aging effect being examined; and (d) evaluation of the need for follow-up examination if 

degradation is identified that could jeopardize an intended function prior to the end of the period 

of extended operation. The applicant stated that the program must be implemented prior to the 

period of extended operation, should rely only on results of inspections performed within the 

10-year period preceding the period of extended operation, and expires at the time of entry into 

the period of extended operation.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the applicant’s program basis document, 

on-site procedures, CRs, and other plant documents that were included in the applicant’s 

license renewal program basis document binder for the One-Time Inspection Program and that 

contained relevant information supporting the applicant’s evaluation of this AMP.

In the program basis document the applicant stated that the One-Time Inspection Program 

relies upon established nondestructive examination (NDE) techniques of the ASME Code 

Section XI Inservice Inspection Program or may use alternate NDE techniques not specified by 

ASME Code Section XI, if appropriate. The applicant stated that sampling approaches at other 

sites holding renewed licenses will be considered, including the methodology discussed in EPRI 

TR-107514, “Age-Related Degradation Inspection Methods and Demonstration,” which was 

cited by the applicant as one industry source to be considered in developing the One-Time 

Inspection Program.
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The staff noted that the applicant’s One-Time Inspection Program includes inspections to verify 

the effectiveness of the Water Chemistry Program to mitigate aging effects with emphasis on 

low flow/stagnant piping areas; to verify the effectiveness of the Fuel Oil Chemistry Program to 

mitigate aging effects with emphasis on low flow/stagnant areas of piping and tank bottoms 

associated with fuel oil storage and delivery systems; and to verify the effectiveness of the 

Lubricating Oil Analysis Program to ensure that water and other contaminants are not present in 

tanks or vessels containing lubricating oil.

The staff noted that potential aging effects monitored or inspected by the applicant’s One-Time 

Inspection Program are loss of material due to corrosion, cracking due to SCC or intergranular 

stress corrosion cracking (IGSCC), and heat transfer reduction due to fouling; and the 

applicant’s program uses visual examinations and other NDE techniques, including those 

inspection methods specified in the ASME Code Section XI, to inspect components on a 

sampling basis for signs of degradation due to aging. The staff also noted that examinations rely 

on qualified inspectors, using acceptance criteria and evaluation techniques consistent with the 

ASME Code; and when alternate inspection methods not included in ASME Code Section XI are 

used, the One-Time Inspection Program includes documentation to specify the components to 

be examined, the examination techniques, acceptance criteria, flaw evaluation requirements, 

and technical justification of suitability to detect the aging effect of interest. Although site 

implementing procedures for the One-Time Inspection Program have not currently been issued, 

the staff noted that the applicant’s program basis document states that NDE techniques for 

detecting a specific aging effect will be consistent with the examples listed in GALL AMP XI.M32 

(e.g., VT-3 or equivalent and/or volumetric to detect microbiological influenced corrosion). The 

staff finds that these features of the One-Time Inspection Program are consistent with 

recommendations in GALL AMP XI.M32.

The staff compared program’s elements in the applicant’s program to those in GALL 

AMP XI.M32 and found that the program elements in the AMP, which the applicant claims to be 

consistent with the GALL Report are consistent with the corresponding program element criteria 

recommended in GALL AMP XI.M32. The staff’s reviewer did not identify any differences 

between recommendations in the GALL Report and the applicant’s consistency claims. 

In its April 11, 2008, LRA submittal letter, and again in its letter of January 20, 2009, the 

applicant provided a list of “Preliminary License Renewal Commitments.” This list includes 

Commitment No. 23 stating that a One-Time Inspection Program, with program features as 

described in the LRA, will be completed. The implementation schedule for this commitment is 

prior to the period of extended operation for each of the applicant’s nuclear units. The LRA 

describes the applicant’s One-Time Inspection Program as consistent with GALL AMP XI.M32 

with no exceptions. Because this commitment provides assurance that the applicant will 

implement a One-Time Inspection Program consistent with the recommendations for GALL 

AMP XI.M32 prior to the period of extended operation, the staff finds this commitment to be 

acceptable.

Based on its review, the staff finds the One-Time Inspection Program consistent with the 

program elements of GALL AMP XI.M32, and therefore acceptable.

Operating Experience. In LRA Section B2.1.29, the applicant stated that the One-Time 

Inspection Program is a new program and there is no OE related to program implementation. 
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The applicant also stated that both plant and industry OE will be used to establish sample size, 

inspection locations, and examination techniques for inspections under this program.

The staff noted that although the applicant has no experience with the One-Time Inspection 

Program, the applicant does have related OE using the NDE techniques implemented by that 

program. During the on-site audit, the staff reviewed OE and selected corrective action reports 

that demonstrate the applicant’s ability to perform various NDEs, such as visual examinations, 

enhanced visual examinations, and ultrasonic examinations, that are used in the One-Time 

Inspection Program. The staff confirmed that for existing condition monitoring programs, the 

applicant has demonstrated capability to detect indications of degradation, and to take 

appropriate corrective actions based on the indications that have been found. The applicant’s 

One-Time Inspection Program is a new one-time condition-monitoring program for a select 

number of components in the plant that has yet to be implemented at the facility. Since the 

applicant has demonstrated that its current existing condition monitoring programs have the 

ability to detect the aging effects for which it is credited and since the staff has verified that the

program elements of this AMP are consistent with those in AMP XI.M32, “One-Time Inspection,“ 

the staff finds that the applicant’s One-Time Inspection Program, when implemented, will be 

capable of identifying the aging effects for which the AMP is credited and for taking appropriate 

corrective actions under the applicant’s 10 CFR Part 50, Appendix B Quality Assurance 

Program if aging is detected through implementation of the program. 

Based on this review, the staff finds that the applicant’s One-Time Inspection Program will be 

capable of achieving its objective of verifying the effectiveness of other AMPs and of confirming 

that age-related degradation is not occurring or is occurring very slowly so as not to affect 

component or structure intended functions during the period of extended operation, and of 

taking appropriate corrective actions when indications of degradation are detected as a result of 

implementation of the AMP.

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 

element acceptable.

UFSAR Supplement. In LRA Section A2.29, the applicant provided the UFSAR supplement for 

the One-Time Inspection Program. The staff verified that the UFSAR supplement summary for 

the One-Time Inspection Program conforms with the staff’s recommended UFSAR supplement 

for this type of program as described in the SRP-LR. 

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant has included completion of the One-Time Inspection 

Program prior to the period of extended operation as Commitment No. 23 of the final list of 

License Renewal Commitments.

Based on this review, the staff finds that the UFSAR supplement summary in LRA 

Section A2.29 provides an acceptable description of the applicant’s One-Time Inspection 

Program because it is consistent with the UFSAR supplement summary description 

recommended in the SRP-LR for the One-Time Inspection program.
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The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection 

Program, the staff finds all program elements consistent with the GALL Report. In addition, the 

staff confirms that license renewal Commitment No. 23 will ensure that the One-Time Inspection 

Program is completed prior to the period of extended operation. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d). 

3.0.3.1.19 One-Time Inspection of ASME Code Class 1 Small Bore Piping 

Summary of Technical Information in the Application. LRA section B2.1.30 describes the new 

One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program” as consistent with 

GALL AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” The 

applicant stated that this one-time inspection is a condition-monitoring program that provides 

additional assurance that aging of Class 1 small-bore piping either is not occurring or is 

insignificant, such that a new plant-specific AMP is not warranted.

The applicant stated that the program inspects for the presence of cracking by performing onetime volumetric examinations on a small sample of butt welds in Class 1 piping less than 4-inch 

nominal pipe size. The applicant also stated that one-time inspections are performed at 

locations that are determined to be potentially susceptible to cracking, on the basis of the

methodology of the site-specific, NRC approved, risk informed inservice inspection program.

The applicant further stated that if evidence of aging-related cracking is identified by this onetime inspection program, a periodic inspection program will be implemented to manage 

applicable aging effects during the period of extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. In comparing the elements in the applicant’s program to those in GALL AMP 

XI.M35, the staff noted that the program elements in the applicant’s AMP claimed to be 

consistent with the GALL Report were consistent with the corresponding program element 

criteria recommended in the program elements of GALL AMP XI.M35. The staff also confirmed 

that the plant program contains all of the elements of the referenced GALL AMP. On-site 

interviews were also held to confirm these results.

Based on its review, the staff finds the One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping Program consistent with the program elements of GALL AMP XI.M35, and therefore 

acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.30 and 

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 also confirmed that 

applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 

and are evaluated in the GALL Report. 
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The applicant stated that the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

Program is a new program, and therefore, has no OE related to program implementation. The 

applicant also stated that both plant and industry OE will be used to establish the program. The 

applicant stated that the specific examination techniques utilized will be qualified prior to 

performing the examinations.

In LRA Section B2.1.30, the applicant stated that it had conducted 41 UT examinations of 

ASME Class 1 and 2 small-bore piping welds during the 2006 refueling outages at Units 1 and 

2. The applicant stated that it had not detected any rejectable indications in either Unit 1 or 

Unit 2.

Based upon a review of previous OE, the staff determined that the applicant has not identified 

any cracking of ASME Code Class 1 small-bore piping. Furthermore, the staff verified that the 

applicant has addressed OE identified after the issuance of the GALL Report. Based on its 

review, the staff finds that the applicant’s One-Time Inspection of ASME Code Class 1 SmallBore Piping Program can be expected to ensure that effects of aging will be adequately 

managed during the period of extended operation because plant and industry OE will be 

considered in developing the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

Program and the specific examination techniques utilized will be qualified prior to performing the 

examinations. 

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.30, the applicant provided the UFSAR supplement for 

the One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program. The staff verified

that the UFSAR supplement summary description for the One-Time Inspection of ASME Code 

Class 1 Small-Bore Piping Program was in conformance with the staff’s recommended UFSAR

supplement for these types of programs provided in Table 3.1-2 of the SRP-LR.

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant has included Commitment No. 24 in the License Renewal 

Commitment List, which states that the One-Time Inspection of ASME Code Class 1 Small-Bore 

Piping Program will be implemented prior to the period of extended operation.

Based on this review, the staff determines that UFSAR supplement Section A2.30 provides an 

acceptable UFSAR supplement summary description of the applicant’s One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping Program because it is consistent with the UFSAR

supplement summary description in the SRP-LR for One-Time Inspection of ASME Code Class 

1 Small-Bore Piping Program.

The staff determined that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis on its review of the applicant’s One-Time Inspection of ASME Code 

Class 1 Small-Bore Piping 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 
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will be adequately managed so that the intended function will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the UFSAR supplement for this AMP and concludes that it provides an adequate 

summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.20 Open-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B2.1.31 describes the 

existing Open-Cycle Cooling Water System (OCCW) Program as consistent with GALL AMP

XI.M20, “Open-Cycle Cooling Water System.” The applicant stated that the Open-Cycle Cooling 

Water System Program implements the commitments made in its response to NRC Generic 

Letter 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” to ensure 

that the effects of aging in OCCW systems, and in components serviced by the OCCW systems, 

will be managed for the period of extended operation. The applicant also stated that this 

program manages aging effects associated with metallic components exposed to a raw water 

environment. The aging effects managed by this program are corrosion, erosion, and fouling 

(including silting and coating failure). The applicant further stated that the program includes 

routine inspections and maintenance activities, tests to verify heat transfer capabilities, and 

surveillance and control of fouling.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the applicant’s program basis document, 

on-site procedures, corrective action reports, and other plant documents that were included in 

the applicant’s license renewal program basis document binder for the OOCW Program and that 

contained information supporting the applicant’s evaluation of this AMP.

The staff noted that the applicant’s OCCW System Program manages aging effects in 

components exposed to a raw water environment and serviced by the open-cycle cooling water 

system. The staff also noted that the applicant credits the AMP with managing aging effects of 

loss of material due to general, pitting, crevice, and galvanic corrosion, due to MIC, and due to 

erosion, and heat transfer degradation due to fouling. The staff noted that the AMP uses 

periodic visual inspections to check for degradation of protective coatings and for silting and 

includes use of chemical control and periodic visual inspections to reduce incidents of flow 

blockage due to microscopic or macroscopic biofouling. It manages heat exchanger 

performance through performance testing, inspections and cleaning performed through either 

periodic surveillance testing or preventive maintenance procedures. It also uses periodic eddy 

current testing (ECT) to trend and evaluate operation of balance of plant heat exchangers. The 

staff finds these features of the applicant’s AMP to be consistent with recommendations in 

GALL AMP XI.M20.

The staff also noted that the applicant’s open-cycle cooling water systems are constructed of 

various materials, including carbon steel, cast iron, copper alloy, copper-nickel, brass, bronze, 

and stainless steel. The cooling water headers and certain heat exchanger components also 

have a protective coating applied. The staff noted that periodic cleaning and system flushing is 

used to remove accumulations of fouling agents, corrosion products and silt, and the applicant’s 

OCCW System Program follows the guidance of NRC GL-89-13. The staff confirmed that 

inspection scope, methods, and testing frequencies are in accordance with the applicant’s 
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commitments made in response to NRC GL 89-13. The staff finds these aspects of the 

applicant’s AMP to be consistent with recommendations in GALL AMP XI.M20.

The staff compared program elements in the applicant’s program to those in GALL AMP XI.M20 

and found that the program elements in the AMP that the applicant claims to be consistent with 

the GALL Report are consistent with the corresponding program element criteria recommended 

in GALL AMP XI.M20. The staff did not identify any differences between recommendations in 

the GALL Report and the applicant’s consistency claims. 

Based on its review, the staff finds the Open-Cycle Cooling Water System Program consistent 

with the program elements of GALL AMP XI.M20, and therefore acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.31. The 

applicant stated that a review of OE for the Open-Cycle Cooling Water System Program 

identified no adverse trends or issues with program performance. The applicant also stated that 

the review revealed a number of examples where equipment issues have been identified and 

are being managed under the Open-Cycle Cooling Water System Program, including 

accumulations of silt, corrosion products, and debris in cooling water piping, valves, and heat 

exchangers; accumulation of biological growth (mussels, clams, and shells) in river cooling 

water piping and intake bays; instances of MIC causing pitting attack of cooling water pipe; and 

instances of heat exchanger tubes requiring plugging due to corrosion. The applicant further 

stated that the conditions were identified and corrected prior to causing a significant impact to 

safe operation or loss of intended functions.

The staff reviewed the OE discussion that was provided in the applicant’s license renewal 

program basis document binder for the Open-Cycle Cooling Water System Program. The staff 

confirmed that the applicant’s review of OE included evaluation of both industry and plantspecific events that have occurred since issuance of the GALL Report, Revision 1. The staff 

reviewed additional selected corrective action reports (ARs) related to the applicant’s OpenCycle Cooling Water System Program and interviewed the applicant’s subject matter experts for 

the Open-Cycle Cooling Water System Program. The staff also reviewed specific corrective 

action reports including ones where the applicant found low wall thickness due to loss of 

material, corrosion deposits attributed to MIC attack in piping, and heat exchanger fouling. The 

staff noted that for all of these examples, the applicant’s Open-Cycle Cooling Water System 

Program demonstrated its capability to identify, evaluate and correct age-related degradation for 

components and equipment within the scope of the program. Based on its review of the plantspecific OE, the staff confirmed that the applicant’s program has demonstrated capability to 

detect the aging effects which it is credited to manage, and when the program has detected 

indications of aging, it has implemented corrective actions adequate to prevent loss of license 

renewal intended function in the affected components.

Based on this review, the staff finds (1) that the OE for this AMP demonstrates that the 

applicant’s Open-Cycle Cooling Water System Program has implemented the recommendations 

of NRC GL 89-13 and is effective in managing aging effects due to biofouling, corrosion, 

erosion, and fouling due to protective coating failures and silting in components serviced by the 

open-cycle cooling water system, and (2) that the applicant is taking appropriate corrective 

actions when deficiencies are found through implementation of this program.
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UFSAR Supplement. In LRA Section A2.31, the applicant provided the UFSAR supplement for 

the Open-Cycle Cooling Water System Program. The staff verified that the UFSAR supplement 

summary for the Open-Cycle Cooling Water System Program conforms with the staff’s 

recommended UFSAR supplement for this type of program as described in the SRP-LR.

Based on this review, the staff finds that the UFSAR supplement summary in LRA 

Section A2.31 provides an acceptable description of the applicant’s Open-Cycle Cooling Water 

System Program because it is consistent with the UFSAR supplement summary description 

recommended in the SRP-LR for an Open-Cycle Cooling Water System program.

The staff determines that the information in the UFSAR 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 Open-Cycle Cooling Water 

System 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 function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed 

the UFSAR supplement for this AMP and concludes that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.21 PWR Vessel Internals

In a letter dated May 12, 2009, NSPM replaced the previous version of the PWR Vessel 

Internals Program with a plant-specific version of the program that is based on conformance 

with the NRC’s recommended program element criteria that are defined in Section A.1.2.3 of 

NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” Appendix A.1, “Aging Management Review – Generic (Branch 

Technical Position RLSB-1).” Since the updated PWR Vessel Internals Program is defined as a 

new, plant-specific AMP for the LRA, the staff evaluation of this AMP is deferred to Section 

3.0.3.3.2 of this SER.

3.0.3.1.22 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) 

Summary of Technical Information in Application. The thermal aging embrittlement of Cast 

Austenitic Stainless Steel (CASS) program manages the loss of fracture toughness due to 

thermal aging embrittlement of CASS components, other than pumps casings and valve bodies 

that are exposed to reactor coolant operating temperatures. The applicant states that this 

program augments the PINGP ASME Code, Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program. According to the applicant, the CASS pump casings and valve bodies 

are excluded from screening for susceptibility to thermal aging based on the assessment 

documented in the letter dated May 19, 2000, from Christopher Grimes, NRC, to Douglas 

Walters, Nuclear Energy Institute (NEI), “Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel Components.” The CASS pump casings and valve bodies are adequately 

addressed by existing ASME Code, Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program requirements. 
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The applicant states that the thermal aging embrittlement of CASS Program is a new AMP for 

PINGP and that this program will be consistent with the recommendations of the GALL Report, 

Chapter XI, XI.M12, “Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS).”

The applicant claims no exceptions to the GALL Report and states that the program will be 

implemented prior to the period of extended operation.

Staff Evaluation. The staff reviewed LRA Appendix B2.1.39 to verify, pursuant to 

10 CFR 54.21(c)(1)(iii), that the thermal aging embrittlement of CASS Program will adequately 

manage the aging effects in CASS components for the period of extended operation.

According to the GALL Report, Chapter XI, XI.M12, reactor coolant system components are 

inspected in accordance with the ASME Code, Section XI. This inspection will be augmented to 

detect the effects of loss of fracture toughness due to thermal aging embrittlement of CASS 

components. The CASS AMP includes: (a) determination of the susceptibility of CASS 

components to thermal aging embrittlement based on casting method, molybdenum content, 

and percent ferrite, and (b) for potentially susceptible components, aging management is 

accomplished through either enhanced volumetric examination or plant or component-specific 

flaw tolerance evaluation. Additional inspection or evaluations to demonstrate that the material 

has adequate fracture toughness are not required for components that are not susceptible to 

thermal aging embrittlement. The applicant has stated that the subject AMP is new to PINGP 

and that this program will be consistent with the recommendations of the GALL Report, Chapter 

XI, XI.M12.

Based on the staff’s review of the applicant’s AMP description as provided in LRA Appendix 

B2.1.39, the staff finds the program will provide reasonable assurance that aging effects will be 

managed such that the CASS components within the scope of the program will continue to 

perform their intended function(s) during the period of extended operation.

Operating Experience. In LRA Section B2.1.39, the applicant stated that the Thermal Aging 

Embrittlement of Cast Austenitic Stainless Steel Program is a new program to be implemented 

prior to the period of extended operation, and therefore, it has no OE related to program 

implementation. GALL AMP XI.M12 states that the CASS Program was developed by using 

research data obtained on both laboratory-aged and service-aged materials.

The staff noted that the applicant has conducted evaluations and analyses to identify which 

CASS components are susceptible to thermal aging embrittlement and that program 

development is continuing. The staff confirmed element satisfies the criterion defined in the 

GALL Report and in SRP-LR Section A.1.2.3.10. The staff finds this program element 

acceptable.

UFSAR Supplement. In LRA Section A2.39, the applicant provided the UFSAR supplement for 

the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program. The staff verified 

that the UFSAR supplement summary description for the Thermal Aging Embrittlement of Cast 

Austenitic Stainless Steel (CASS) Program was in conformance with the staff’s recommended 

UFSAR supplement for these types of programs provided in Table 3.1-2 of the SRP-LR.
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On the basis of its review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address the thermal aging embrittlement of CASS 

program for managing the aging effects of CASS components is adequate.

Conclusion. Based on the staff’s review as discussed in the above evaluation, the staff 

concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

Thermal Aging Embrittlement of Cast Austenitic Stainless Steels Program will adequately 

manage the aging effects of CASS components for the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

Thermal Aging Embrittlement of Cast Austenitic Stainless Steels Program, as required by 

10 CFR 54.21(d).

3.0.3.1.23 Environmental Qualification of Electric Components Program

Summary of Technical Information in the Application. LRA Section B3.1 describes the existing 

Environmental Qualification (EQ) of Electrical Components Program (EQ Program) as 

consistent with the GALL AMP X.E1, “EQ of Electric Components Program.” The applicant 

states that the EQ program implements the requirements of 10 CFR 50.49 and the guidance 

provided in Regulatory Guide 1.89, “Environmental Qualification of Certain Electrical Equipment 

Important to Safety for Nuclear Plants,” Revision 1. The EQ Program has been established to 

demonstrate that certain electrical components located in harsh plant environments are qualified 

to perform their safety functions in those harsh environments, consistent with 10 CFR 50.49 

requirements. The applicant also states that EQ Program manages component thermal, 

radiation, and cyclical aging with aging evaluations based on 10 CFR 50.49(f) qualification 

methods. The applicant further stated that, as required by 10 CFR 50.49, EQ components not 

qualified for the current license term are to be refurbished or replaced, or have their qualification 

extended by reanalysis, prior to reaching the aging limits established in the evaluation. Aging 

evaluations for EQ components that specify a qualification of at least 40 years are considered 

time-limited aging analyses (TLAAs) for license renewal.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claims of consistency with 

the GALL report. In LRA Section B3.1, the applicant claimed that its EQ Program is consistent 

with GALL AMP X.E1. However, during its audit, the staff found that the applicant’s EQ Program 

did not describe reanalysis attributes. These attributes are important for extending the qualified 

life of components managed by this program. GALL AMP X.E1 describes reanalysis attributes 

under the program description. In a letter dated November 5, 2008, the staff issued RAI B3.1-2 

to request the applicant to provide a description of reanalysis attributes. In response to the 

staff’s request, in a letter dated December 5, 2008, the applicant stated that a detailed 

description of the reanalysis attributes of the EQ Program was provided in PINGP LRA Section 

4.4.1. For completeness, the applicant stated that this description is also being incorporated into 

the program description. On LRA page B-83, Section B3.1, Environmental Qualification (EQ) of 

Electrical Components Program, the applicant added the following information to the end of the 

existing Program Description:

Analytical Methods - The PINGP EQ Program uses the same analytical models 

in the reanalysis of an aging evaluation as those previously applied for the 

current evaluation. Arrhenius methodology is an acceptable model for performing 

a thermal aging evaluation. The analytical method used for a radiation aging 
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evaluation is to demonstrate qualification for the total integrated dose (that is, 

normal radiation dose for the projected installed life plus accident radiation dose). 

For License Renewal acceptable methods for establishing the 60-year normal 

radiation dose includes multiplying the 40-year normal radiation dose by 1.5 (that 

is, 60 years/40 years) or using the actual calculated value for 60 years. The 

result is added to the accident radiation dose to obtain the total integrated dose 

for the component.

Data Collection and Reduction Methods - Reducing excess conservatism in the

component service conditions (for example, temperature, radiation, and cycles)

used in the prior aging evaluation is the primary method used for a reanalysis per 

the EQ Program.

Underlying Assumptions - EQ component aging evaluations contain sufficient 

conservatism to account for most environmental changes occurring due to plant 

modifications and events. When unexpected adverse conditions are identified 

during operational or maintenance activities that affect the normal operating 

environment of a qualified component, the affected EQ component is evaluated 

and appropriate corrective actions are taken, which may include changes to the 

qualification bases and conclusions.

Acceptance Criteria and Corrective Action - The reanalysis of an aging 

evaluation could extend the qualification of the component. If the qualification 

cannot be extended by reanalysis, the component is maintained, replaced, or requalified prior to exceeding the period for which the current qualification remains 

valid. 

The staff finds the applicant’s response acceptable because it now provides a complete 

description of reanalysis attributes in the EQ program. These attributes are important for 

extending the qualified life of components managed by this program. The reanalysis attributes 

are consistent with those in GALL AMP X.E1 and the issues raised in RAI B3.1-2 are resolved.

The staff also found that the scope of the EQ Program is not consistent with that in GALL 

AMP X.E1. The scope of the applicant’s EQ Program only included electrical cables and 

connections subject to 10 CFR 50.49 EQ requirements while the scope of GALL AMP X.E1 

includes all electrical components that are important to safety and could be exposed to harsh 

environment accident conditions. The electrical components important to safety includes safetyrelated, nonsafety-related whose failure could prevent satisfactory accomplishment of safety 

functions, and certain post-accident monitoring equipment as identified in Regulatory Guide 

(RG) 1.97, “Instrumentation for Light-Water-Cooled Nuclear Power Plant to Assess Plant and 

Environment Conditions During and Following an Accident.” In a letter dated November 5, 2008, 

the staff issued RAI B3.1-1 to request the applicant to explain how the scope of the applicant’s 

EQ program is consistent with the scope of GALL AMP X.E1 when it only included electrical 

cables and connections within the scope of the EQ program. In response to the staff request, in 

a letter dated December 5, 2008, the applicant stated that as described in PINGP LRA Section 

B3.1, the scope applies to certain electrical components subject to EQ and the guidance 

provided in Regulatory Guide 1.89, Revision 1. The applicant also stated that this is consistent 

with the program scope identified in the GALL Report EQ Program. The applicant further stated 
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that PINGP program basis document for the EQ Program does not intend to restrict the program 

to cables and connections. The applicant further stated that it revised the LRA to clarify the 

description of the EQ Program as follows:

In LRA Table 3.6.2-1, "Electrical Components - Electrical Commodity Groups -

Summary of Aging Management Evaluation," on Page 3.6-19, the first Component Type

row entry for EQ is replaced to read as follows:

Electrical Components Subject to 10 CFR 50.49 Environmental 

Qualifications Requirements

The staff finds the applicant response acceptable because the applicant clarified the 

scope of its EQ program and revised the LRA to include all electrical components 

subject to 10 CFR 50.49. Electrical components subject to 10 CFR 50.49 includes 

electrical components important to safety located in a harsh environment. The electrical 

components important to safety includes safety-related, nonsafety-related whose failure 

could prevent satisfactory accomplishment of safety functions, and certain post-accident 

monitoring equipment as identified in RG 1.97, “Instrumentation for Light-Water-Cooled 

Nuclear Power Plant to Assess Plant and Environment Conditions During and Following 

an Accident. The scope of the applicant’s EQ program is now consistent with that in the 

GALL AMP X.E1 and the issues raised in RAI B3.1-1 are resolved.

Operating Experience. The staff also reviewed the relevant OE provided in the LRA and in the 

plant’s basis documents during the audit to confirm that plant-specific OE revealed no 

degradation not bounded by industry experience. In LRA Section B3.1, the applicant states that 

a review of OE for the PINGP EQ Program identified no adverse trends or issues with program 

performance. Minor issues, such as improper splice configurations in the field differing from the 

tested configuration and normal temperature reference improvements, have been identified and 

corrected prior to causing any significant impact to safe operation or loss of intended functions.

In the basis documents, the applicant stated that PINGP OE shows some past issues. The EQ 

program and design engineering used informal and non-controlled temperature monitoring data, 

which affects the integrity of the EQ qualification files. The applicant upgraded EQ files and 

revised the EQ procedures to improve the program process to maintain basis references. The 

applicant also stated that the analysis in UFSAR Appendix G, Figure 3.G.1, shows Shield 

Building Annulus response to large break loss of coolant accident (LBLOCA), that used results 

in peak containment shell temperature of 222 oF, with a corresponding peak Shield Building 

temperature of 161 oF. More recent analyses resulted in higher peak containment shell 

temperature of 245 oF for LBLOCA and 266 oF for main steam line break, making the analysis in 

UFSAR Appendix G not conservative and inadequate for EQ purposes. The applicant assessed 

all components, their respective EQ files, and determined that all components were capable of 

performing their design functions. The non-conformance was limited to EQ file documentation. 

The applicant upgraded the EQ files to include the new temperature data. These issues were 

identified by the PINGP Corrective Action Program for resolution and compliance to all 

regulatory and EQ Program requirements. The staff confirmed that the applicant’s response was 

appropriate. 

The staff finds that the OEs identified above and those identified in program basis documents 

demonstrated that identification of program weakness and timely corrective actions as part of 
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the EQ program provides assurance that the program will remain effective in assuring that 

equipment is maintained within its qualification basis and qualified life. The staff confirmed that 

the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A3.1, the applicant provided a UFSAR supplement for EQ 

of Electrical Components Program. The staff reviewed this section to determine if the 

information in the UFSAR supplement provides an adequate description of the program as 

required by 10 CFR 54.21(d). The staff found the applicant’s summary of the EQ of Electric 

Components Program inadequate because it did not include reanalysis attributes that are 

important for extending the qualified life of components managed by this program. The 

reanalysis addresses attributes of analytical method, data collection and reduction method, 

underlying assumptions, acceptance criteria, and corrective actions. In a letter dated November 

5, 2008, the staff issued RAI B3.1-3 to request the applicant to provide an adequate summary 

description of the EQ Program. In response to the staff’s request, in a letter dated December 5, 

2008, the applicant stated that in LRA Section A3.1, Environmental Qualification of Electrical 

Components Program, on Page A-17, it added the following paragraph to the end of the existing 

program description, to read as follows:

“Reanalysis is an acceptable alternative for extending the qualified life of an EQ 

component. 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 staff finds the applicant’s response acceptable because the applicant provides an adequate 

summary of the EQ Program, which is consistent with those in SRP Section 4.4, Table 4.4-2.

The staff determines that the information in the UFSAR supplement as supplemented by the 

information in the applicant’s response to RAI B3.1-3 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 Program and the applicant’s 

response to the staff’s RAIs B3.1-1, B3.1-2, and B3.1-3, the staff finds all program elements 

consistent with the GALL Report. The staff concludes that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP and concludes that it 

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.1.24 Protective Coating Monitoring and Maintenance Program

Summary of Technical Information In the Application. By letter dated March 12, 2009, the 

applicant added an additional AMP, the Protective Coating Monitoring and Maintenance 

Program. The applicant does not credit this program for prevention of corrosion carbon steel 

components. Rather, this program is used to ensure that the amount of failed coatings that 

occurs during a LOCA does not exceed the design limits for the strainers. Additional discussion 

on issues related to the strainers is given in LRA Section 2.1.1.4.3 describes the Generic Safety 
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Issue (GSI) -191, Assessment of Debris Accumulation on Pressurized Water Reactor (PWR) 

Sump Performance and states: 

GSI-191 addresses the potential for blockage of containment sump strainers that 

filter debris from water supplied to the emergency core cooling system pumps 

following a postulated loss-of-coolant accident (LOCA). The NRC has addressed 

this issue in Regulatory Guide 1.54 (Reference 7), Generic Letter 2004-02

(Reference 8), Generic Letter 98-04 (Reference 9) and other communications.

The issue is based on containment sump strainer design and on the identification 

of new potential sources of debris, including failed containment coatings that 

have the potential to block the sump strainers. PINGP has replaced the 

containment sump strainers (containment sump B strainers) in both Units in 

response to the GSI-191 concerns. The replacement containment sump B 

strainers are the subject of an AMR as documented in Section 3.2.

PINGP does not credit coatings inside the containment to assure that the 

intended functions of coated structures and components are maintained. The 

contribution of coatings to containment debris is event driven and is not related to 

aging. Therefore, those coatings do not have an intended function. In addition, 

the issue is not related to the 40-year term of the current operating license; and 

therefore, is not a TLAA.

The Protective Coating Monitoring and Maintenance Program monitors the performance of 

Service Level I coated surfaces inside of containment using periodic inspections. This program 

also provides guidance on the procurement and maintenance of Service Level I coatings.

Staff Evaluation. By letter dated March 12, 2009, the applicant submitted the Protective Coating 

Monitoring and Maintenance Program, which the applicant claimed is consistent with the GALL 

Report. The staff reviewed the applicant’s claim of consistency with the GALL Report.

The applicant provided an element-by-element comparison of the Protective Coating Monitoring 

and Maintenance Program with GALL AMP XI.S8, “Protective Coating Monitoring and 

Maintenance Program.” The staff reviewed the element-by-element comparison and did not find 

any exceptions or enhancements or a finding of unacceptability for any of elements. The 

program consists of a visual inspection of the Service Level I coatings looking for any visible 

defects, such as blistering, cracking, flaking, peeling, delamination, discoloration, or mechanical 

damage to the coating. The presence of any rust will be noted. The qualification of individuals 

who coordinate and perform coating condition assessments meet or exceed the ASTM standard 

for qualifications. The inspection plan and methods for performing the inspection follow the 

appropriate ASTM standard. The findings are recorded on Inspection Data Sheets and recorded 

using photographs. A containment coating report is written to document activities performed to 

verify that the coatings continue to meet the design and licensing basis. Any coating that is 

found to be damaged or degraded is either repaired, replaced, or evaluated to determine 

whether it can remain in service. Any damaged or degraded coating that is left in service is 

entered into the Unqualified and Degraded (Qualified) Coatings Log and evaluated against the 

established acceptance criteria and previous assessment results to ensure the total volume of 

coatings postulated to fail during a LOCA is less than the design limits.
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The staff confirmed that the applicant has demonstrated that the condition of Service Level I 

containment coatings are adequately managed to ensure that post-accident accumulation of 

failed coating debris on containment sump B strainers does not exceed the strainers design 

limits, consistent with the CLB, for the period of extended operation.

Based on its review, the staff finds the Protective Coating Monitoring and Maintenance Program

consistent with the program elements of GALL AMP XI.S8, and therefore acceptable.

Operating Experience. The staff also reviewed the OE described in a letter dated March 12, 

2009. The applicant stated that the Protective Coating Monitoring and Maintenance Program is 

an existing program that incorporates both industry and plant-specific OE to provide added 

assurance that the condition of coatings inside containment will be managed effectively during 

the period of extended operation.

Unit 1 Containment was inspected in May 2006, and chipping was observed near the drain at 

the 695-foot elevation in zone B that covered a four square foot area. Flaking and chipping was 

observed inside the Regenerative Heat Exchanger Room at elevation 695 feet that covered an 

area of five square feet.

Unit 2 Containment was inspected in November 2006, and flaking was observed on grating 

below RCS piping in the 21 RCP/SG vault lower level that covered a six square foot area.

Delamination and chipping was also observed on the ladder to lower level 21 RCP/SG vault that 

covered a small area not considered by the applicant to be significant.

The most recent inspection of Unit 1 coatings took place in February 2008. Cracking was 

observed over a 0.5 square foot area on the Sump B platform at elevation 695 feet of zone A.

Flaking was also observed on a hanger support at elevation 695 feet of zone B that covered one 

square foot of area.

The results of these inspections and the discovery of coating degradation were entered into the 

corrective actions program. The degraded coatings were either removed or evaluated to ensure 

that the amount of unqualified and degraded qualified coatings that are left inside containment 

were less than the calculated limit.

The staff confirmed that the OE program element satisfies the criterion defined in the GALL 

Report and SRP-LR Section A.1.2.3.10. The staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A2.41, the applicant provided the UFSAR supplement for 

the Protective Coating Monitoring and Maintenance Program.

Based on this review, the staff finds that the UFSAR supplement summary in LRA 

Section A2.41 provides an acceptable description of the applicant’s Protective Coating 

Monitoring and Maintenance Program because it is consistent with the UFSAR supplement 

summary description recommended in the SRP-LR for a Protective Coating Monitoring and 

Maintenance Program

The staff determines that the information in the UFSAR 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 Protective Coating Monitoring 

and Maintenance Program, the staff finds all program elements consistent with the GALL 

Report. The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.0.3.2 AMPs Consistent with the GALL Report with Exceptions or Enhancements 

In LRA Appendix B, the applicant stated that the following AMPs are, or will be, consistent with 

the GALL Report, with exceptions or enhancements[1]:

• Bolting Integrity Program

• Closed-Cycle Cooling Water System Program

• Compressed Air Monitoring Program

• Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program

• External Surfaces Monitoring Program

• Fire Protection Program

• Fire Water System Program

• Flux Thimble Tube Inspection Program

• Fuel Oil Chemistry Program

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program

• Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of 

Pressurized Water Reactors Program

• Reactor Head Closure Studs Program

• Reactor Vessel Surveillance Program

• RG 1.127 Inspection of Water Control Structures Associated with Nuclear Power Plants

Program

• Selective Leaching of Materials Program

• Steam Generator Tube Integrity Program

• Structures Monitoring Program

• Water Chemistry Control Program

• Metal Fatigue of Reactor Coolant Pressure Boundary Program

[1]: In a letter dated March 12, 2009, the applicant amended its Flow-Accelerated Corrosion Program by 

adding an exception. Thus, this program is changed to one that is consistent with the GALL Report with 

an exception.
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For AMPs that the applicant claimed are consistent with the GALL Report, with exception(s) 

and/or enhancement(s), the staff performed an audit and review to confirm that those attributes 

or features of the program, for which the applicant claimed consistency with the GALL Report, 

were indeed consistent. The staff also reviewed the exception(s) and/or enhancement(s) to the 

GALL Report to determine whether they were acceptable and adequate. The results of the 

staff’s audits and reviews are documented in the following sections.

3.0.3.2.1 Bolting Integrity

Summary of Technical Information in the Application. LRA Section B2.1.6 describes the existing 

Bolting Integrity Program as consistent, with enhancement and exception, with GALL AMP 

XI.M18, “Bolting Integrity.” The Bolting Integrity Program includes periodic inspection of closure 

and structural bolting for indication of cracking, loss of preload, and loss of material due to 

corrosion. This program manages aging effects for bolting of mechanical components within the 

scope of license renewal. The applicant stated that PINGP credits the ISI program, IWE 

Program, IWF Program, Buried Piping and Tanks Inspection Program, External Surfaces 

Monitoring Program, RG 1.127 Inspection of Water-Control Structures Associated with Nuclear 

Power Plants Program, and Structures Monitoring Program with conducting the inspections of 

bolting within the scope of the Bolting Integrity Program. Furthermore, the applicant also stated 

that PINGP takes exception to the use of volumetric examination in high strength bolting.

Instead, the applicant proposes the use of volumetric examination only when prescribed by the 

plant corrective action program. 

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the enhancement and exception to 

determine whether the AMP, with the enhancement and exceptions is adequate to manage the 

aging effects for which the LRA credits it. 

In the PINGP LRA, the applicant stated that the PINGP AMP B2.1.6 is an existing program that 

is consistent with GALL AMP XI.M18, “Bolting Integrity” with exception and an enhancement.

The exception affects the “parameters monitored or inspected,” and the “detection of aging 

effects” program elements. The enhancement affects the same program elements

During its audit and review, the staff reviewed the applicant’s on-site documentation supporting 

the applicant’s conclusion that the program elements are consistent with the elements in the 

GALL report. The staff interviewed the applicant’s technical staff and reviewed on-site 

documents.

In comparing the program elements in the applicant’s program to the elements in GALL AMP 

XI.M18, the staff found that the GALL Report “monitoring and trending” program element 

recommended leak rates to be monitored on a particularly defined schedule was not properly 

documented in the applicant’s bolting integrity program. The staff found that this GALL Report 

recommendation was not specifically addressed, and should possibly be identified as an 

exception if it is indeed not met. Therefore, by letter dated November 5, 2008, the staff issued 

RAI B.2.1.6-1 requesting additional information on the applicant’s leak rate monitoring schedule.
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By letter dated December 5, 2008, the applicant responded to RAI B.2.1.6-1 by stating that it 

agrees with the staff’s position that the leak rate monitoring issue should be identified as an 

exception to the GALL Report “monitoring and trending” program element. The applicant 

submitted this exception crediting its current corrective action program and leak detection 

process for meeting the recommendations of the GALL Report “monitoring and trending” 

program element. Furthermore, the applicant states that each new Corrective Action Program 

Action Request that affects plant equipment is reviewed and assessed by a Senior Reactor 

Operator. Once a leak is identified, the issue is documented in the corrective action program 

and frequency of followup inspections is assigned based on the evaluation of the problem. The 

applicant further stated that, for any leak, an evaluation is completed to determine the actions 

required based on the severity of the leak and the potential to impact normal operations and 

safety. Furthermore, if the leak rate changes, further evaluation is performed to determine the 

actions required based on factors such as leak stability, leak reduction, and containment of 

leakage. Based on the justification provided, the staff found the applicant’s response and 

exception to be acceptable.

Additionally, the applicant stated in PINGP AMP B2.1.6 that its Bolting Integrity Program follows 

the guidance and standards outlined in NUREG-1339 “Resolution of Generic Safety Issue 29: 

Bolting Degradation or Failure in Nuclear Power Plants," EPRI NP-5769 “Degradation and 

Failure of Bolting in Nuclear Power Plants," EPRI TR-104213 “Bolted Joint Maintenance & 

Application Guide," EPRI TR-111472 “Assembling Bolted Connections Using Spiral-Wound 

Gaskets," and EPRI NP-5067 Volume 1 and 2 “Good Bolting Practices." However, GALL AMP 

XI.M18 identifies only NUREG-1339, EPRI NP-5769, and EPRI TR-104213 as guidance relied 

upon for the Bolting Integrity Program. The applicant did not include an enhancement or 

exception related to the use of these guidance documents. The use of guidance and standards 

not endorsed by the GALL program brings into question the adequacy of the standards that

were applied, as well as possible differences or contradictions between the GALL endorsed and 

non-endorsed guidance documents. Therefore, by letter dated November 5, 2008, the staff 

issued RAI B2.1.6-2 requesting additional information on the differences and use of these 

guidance documents.

By letter dated December 5, 2008, the applicant responded to RAI B2.1.6-2 by stating that 

although the AMP B2.1.6 follows the guidelines and recommendations of EPRI NP-5067 and 

EPRI TR-111472, in addition to EPRI NP-5769, EPRI TR-104213 and NUREG-1339, the Bolting 

Integrity Program still meets the intent of the GALL Report recommendations. The applicant 

referenced a previous NRC determination of the interchangeability of EPRI NP-5067, which was 

detailed in a point-by-point comparison of the two sets of documents dated April 1, 2005 

(ML051020128). This comparison was previously accepted by the NRC, and found to 

adequately address the bolting guidelines in the GALL Report. Additionally, the applicant stated 

that EPRI TR-111472, “Assembling Bolted Connections Using Spiral-Wound Gaskets” is a 

training module that is based on EPRI NP-5067 and EPRI TR-104213, and consolidated into a 

more usable form for plant maintenance and training. The staff noted that the comparison of the 

reference documents was adequate, and the documents still meet the intent of the GALL Report 

recommendations. However, the applicant stated that the use of these documents does not 

represent an exception to the GALL Report. The staff disagrees with this assessment, and 

discussed the issue with the applicant in a teleconference dated January 22, 2009. The 

applicant supplemented their response to RAI B2.1.6-2 by letter dated February 6, 2009 by 

submitting the use of EPRI-5067 and EPRI 111472 as an exception to GALL program elements 
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“scope of program," “preventive actions” and “corrective actions." Based on the justification 

provided, the staff finds the applicant’s response to be acceptable.

The staff also noted that the applicant plans to use the External Surfaces Monitoring Program, 

Buried Piping and Tanks Inspection Program, Structures Monitoring Program, and RG 1.127 

Inspection of Water Control Structures Associated with Nuclear Power Plants Program as other 

AMPs that implement aspects of the bolting integrity program. However, the staff found that 

these supplemental programs include inconsistent statements in their program basis documents 

regarding their management of bolting. The discrepancies indicate a possible misunderstanding 

of the intent of the Bolting Integrity Program. As a result, it is not clear how, or if, these 

supplemental programs implement the specifications set in the Bolting Integrity Program.

Therefore, by letter dated November 5, 2008, the staff issued RAI B.2.1.6-4 to request 

additional information on the inspection requirements included in the supplemental AMPs, which

will meet the recommendations of the Bolting Integrity Program.

By letter dated December 5, 2008, the applicant responded to RAI B.2.1.6-4 by stating that they 

concur with the staff’s position that the requirements for bolting inspection originate in the 

Bolting Integrity Program. The applicant clarified that the AMPs supplementing the Bolting 

Integrity Program will include the specific inspection requirements, which are outlined in the 

Bolting Integrity Program to ensure consistent implementation. Furthermore, the applicant 

clarified that the statements made in their LRA are not meant to suggest that the AMPs 

supplementing the Bolting Integrity Program supersede or contradict the Bolting Integrity 

Program. Additionally, the applicant responded to a specific example identified by the staff, 

wherein it was not clear whether a program identified as supplementing the Bolting Integrity 

Program included bolting in its aging management by updating the External Surfaces Monitoring 

Program to include a specific reference to bolting as a component that is managed. Based on 

the clarification provided, the staff finds the applicant’s response to be acceptable.

Exception. LRA Section B2.1.6 states an exception to the following GALL Report program 

elements: parameters monitored or inspected, and detection of aging effects. Specifically, the 

exception stated the following:

High strength bolting used in steam generator hold-down supports, reactor 

coolant pump supports, and other structural applications is periodically examined 

with visual techniques. Performing visual inspections of high strength bolts in lieu 

of a volumetric examination is an exception to the discussion provided in GALL

AMP XI.M18. For stress corrosion cracking to occur in a susceptible high 

strength bolting material, a sustained high tensile stress and a corrosive 

environment must be present. Visual examinations of structural assemblies will 

detect corrosion or conditions indicative of a corrosive environment that could 

lead to stress corrosion cracking in potentially susceptible high strength bolting, 

and will cause appropriate corrective action to be taken under the Corrective 

Action Program when necessary. Corrective action may include volumetric 

examination of affected bolts, hammer testing, or other actions appropriate for 

the condition. Therefore, visual examination, as described, will effectively 

manage the aging of installed high strength bolting.
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The staff agrees with the applicant’s assertion that a sustained high tensile stress and a 

corrosive environment must be present in order to initiate SCC, and is discussed in EPRI NP5067. The staff notes that this is identified in the GALL Report “detection of aging effects” 

program element, and allows the recommendation to be waived with sufficient plant-specific

justification. The applicant states that the plant’s Corrective Action Program will trigger proper 

corrective actions based on the results of visual examinations for conditions indicative of a 

corrosive environment. The applicant also states that if a corrosive environment is found 

through visual examinations, followup testing may include volumetric examination, hammer 

testing, or other actions appropriate for the condition. The staff finds that the proposed 

exception meets the intent of the GALL Report recommendations with a plant-specific corrective 

action program, which will identify proper followup actions if a nonconforming condition is 

identified. On the basis of its review as described above, the staff finds that this exception is 

acceptable.

Enhancement. LRA Section B2.1.6 states an enhancement to the GALL Report program 

elements: parameters monitored or inspected, and detection of aging effects. Specifically, the 

enhancement stated the following:

Procedures for the conduct of inspections in the External Surfaces Monitoring 

Program, Structures Monitoring Program, Buried Piping and Tanks Inspection 

Program, and the RG 1.127 Inspection of Water-Control Structures Associated 

with Nuclear Power Plants Program will be enhanced to include guidance for 

visual inspections of installed bolting.

The staff noted that the enhancement would affect multiple different AMPs, did not include 

details on what guidance would be enhanced, and specifically what would be included in those 

enhancements. The staff noted that the lack of detail in this enhancement brings into question 

whether the changes will address the specifications recommended by the Bolting Integrity 

Program. Therefore, by letter dated November 5, 2008, the staff issued RAI B2.1.6-3 requesting 

additional information on the details of the enhancement described. 

The applicant responded to RAI B2.1.6-3 by letter dated December 5, 2008, stating that the 

AMPs listed in the enhancement will be enhanced to include guidance through the 

implementation of procedural guidelines, which meet the intent of the GALL Report 

recommendations. The applicant further clarified the guidelines to be added by stating that 

procedural guidance will be included to monitor the effects of aging on the intended function of 

closure and structural bolting, and will specifically define the conditions indicative of potential 

degradation such as evidence of leakage, loosening, corrosion, or conditions that could lead to 

SCC. Based on the clarification provided, the staff finds that the applicant’s response to this RAI 

to be acceptable since the enhancements described will meet the GALL Report 

recommendations when implemented.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.6. The 

applicant stated that “the Bolting Integrity Program incorporates both plant and industry 

experience on bolting issues.” To verify the accuracy of this statement, the staff reviewed a 

sample of CRs, and interviewed the applicant’s technical staff to confirm that the plant-specific 

OE did not reveal any degradation not bounded by industry experience. A CR indicated that in 

2005, improper thread engagement was discovered on the containment spray pump. The staff 
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found that proper corrective actions were taken to address the issue as well as proper followup 

inspections on the pump. This report and others like it helped to confirm the applicant’s 

statement above, and helped to demonstrate that proper corrective actions are taken to address 

bolting issues.

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 

element acceptable.

UFSAR Supplement. In LRA Section A.2.6, the applicant provided the UFSAR Supplement for 

the Bolting Integrity Program. The staff reviewed this section and finds it acceptable because it 

is consistent with the corresponding program description in SRP-LR Table 3.1-2.

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

In Commitment No. 4, the applicant committed to implement the enhancement described above 

to this existing program before entering the period of extended operation.

Conclusion. The staff has reviewed the information provided in Section B2.1.6 of the LRA 

Appendix B and additional information provided by the applicant by letters dated December 5, 

2008, and February 6, 2009. On the basis of its review as discussed above, the staff concludes 

that the applicant has demonstrated that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the GALL Report. In addition, the 

staff reviewed the exception and the associated justification, and determined that the AMP, with 

the exception, is adequate to manage the aging effects for which it is credited. In addition, the 

staff has reviewed the enhancement and confirmed that the implementation of the enhancement 

prior to the PEO would result in the existing AMP being consistent with the GALL AMP XI.M18.

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 UFSAR supplement for this AMP and concluded that it 

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.2 Closed-Cycle Cooling Water System 

Summary of Technical Information in the Application. LRA Section B2.1.9 describes the existing 

Closed-Cycle Cooling Water System Program as consistent, with exceptions and enhancement, 

with GALL AMP XI.M21, “Closed-Cycle Cooling Water System.” The applicant stated that the 

Closed-Cycle Cooling Water System Program is both a preventive and condition monitoring 

program that is based on EPRI “Closed-Cycle Cooling Water Chemistry Guideline,” TR-107396, 

Revision 1. The program includes preventive measures to minimize corrosion, heat transfer 

degradation, and Stress Corrosion Cracking (SCC); and testing and inspection to monitor the 

effects of corrosion, heat transfer degradation, and SCC on the intended functions of the 

components. The applicant stated that preventive measures consist of maintaining the system 

corrosion inhibitor concentrations within specified limits by periodic testing; that testing is 

performed to verify key chemistry parameters and to measure impurities, conductivity and 

microbiological growth; that inspections are performed to identify corrosion, fouling and SCC 
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that may be present; and that cleaning and inspection of heat exchangers are performed 

periodically along with pump and heat exchanger performance and functional testing. 

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the exceptions and enhancement to 

determine whether the AMP, with the exceptions and enhancement, is adequate to manage the 

aging effects for which the LRA credits it.

The staff reviewed the applicant’s program basis document, on-site procedures, corrective 

actions reports, and other plant documents that were included in the applicant’s license renewal 

program basis document binder for the Closed-Cycle Cooling Water System Program and that 

contained information supporting the applicant’s evaluation of this AMP.

The staff noted that the Closed-Cycle Cooling Water System Program is credited with managing 

the aging effects of loss of material due to general, pitting, crevice, galvanic, and 

microbiologically-influenced corrosion (MIC). The staff noted that the AMP relies on use of 

appropriate materials, corrosion inhibitors, and closed-cycle cooling water chemistry to protect 

the internal metal surfaces of components exposed to closed-cycle cooling water. The staff 

noted that performance adequacy of systems and components in continuous operation are

verified by monitoring and trending of system and component operating parameters and by 

periodic testing of those components not normally in operation. The staff noted that acceptance 

criteria and tolerances are based on system and component design parameters and functions, 

and that corrosion inhibitor concentrations are maintained within limits by periodic testing at 

specified frequencies. The staff finds these features of the applicant’s Closed-Cycle Cooling 

Water System program consistent with recommendations in the GALL Report.

The staff compared program elements in the applicant’s program to those in GALL AMP XI.M21 

and found that the program elements in the AMP that the applicant claims to be consistent with 

the GALL Report are consistent with the corresponding program element criteria recommended 

in GALL AMP XI.M21. Except for the enhancement and exceptions described in the LRA by the 

applicant, the staff did not identify any differences between recommendations in the GALL 

Report and the applicant’s consistency claims.

Exception 1. LRA Section B2.1.9 states an exception to the “preventive actions” program 

element. The exception is that guidance provided in EPRI TR-107396, Revision 1 (1007820), 

“Closed Cooling Water Chemistry Guideline,” April 2004, is used in lieu of recommendations in 

EPRI TR-107396, Revision 0, “Closed Cooling Water Chemistry Guideline,” October 1997, 

which is the version of the EPRI guidelines recommended in the GALL Report. 

Because the GALL Report refers to EPRI TR-107396, Revision 0, and does not include a 

statement about use of later revisions of this guidance document, the applicant identified use of 

EPRI TR-107396, Revision 1, as an exception to the GALL Report. During its audit, the staff 

noted in the license renewal AMP basis document for the Closed-Cycle Cooling Water System 

Program the applicant’s statement that Revision 1 is the most recent revision of the EPRI 

guidance document and that it provides more prescriptive guidance than Revision 0 based on 

the latest industry operating experience (OE).
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The staff noted that although GALL AMP XI.M21 lists EPRI TR-107396, Revision 0, among its 

references, the GALL Report does not limit an applicant to using only that version of the EPRI 

Closed Cooling Water Chemistry Guidelines as a basis for its AMP. Because the GALL Report 

does not restrict use of more recent version of the EPRI guidelines, the staff finds the 

applicant’s use of EPRI TR-107396, Revision 1, in lieu of Revision 0, to be acceptable. On this 

basis, the staff finds Exception 1 to the “preventive action” program element to be acceptable.

Exception 2. LRA Section B2.1.9 states an exception to the “parameters monitored/inspected” 

program element. The exception is that some of the pump and heat exchanger performance 

parameters recommended by the GALL Report are not used for monitoring specific pumps or 

smaller converters serviced by the closed-cycle cooling water systems.

In a letter dated November 5, 2008, the staff issued RAI AMP-B2.1.9-1 asking the applicant to 

provide a more detailed description of this exception, stating what pumps and heat exchangers 

(converters) are affected by this exception and what performance parameters are monitored.

The applicant responded to RAI AMP-B2.1.9-1 in a letter dated December 5, 2008. In that letter, 

the applicant provided a detailed list of closed cooling water subsystems and equipment 

affected by the exception. These include chiller loops and hot water converter loops for various 

buildings and rooms and the diesel generator jacket water cooler loops. For these subsystem 

loops, where the installed instrumentation does not include measurements recommended in the 

GALL Report, the applicant credited measurement of alternative performance parameters where 

alternative installed instrumentation is available, or credited additional chemistry parameter 

measurements and total metal analysis (iron and copper) using in-house testing or outside 

laboratory testing on quarterly or yearly frequency. The applicant also stated that performance 

monitoring of the diesel generator water jacket cooler loops is consistent with commitments 

made in response to NRC Generic Letter 89-13, “Service Water System Problems Affecting 

Safety Related Components.”

In a letter dated February 6, 2009, the applicant modified its original response. The applicant 

noted that their original response had stated that no performance parameters are monitored for 

three of the closed-cooling water loops: 1) the cold lab chiller loop, 2) the computer room chiller 

loop, and 3) the hot lab chiller loop. The applicant stated that since these loops are not subject 

to any periodic performance testing, it had determined that this should also be identified as an 

exception to the “detection of aging effects” program element. The applicant revised LRA 

Section B2.1.9, to state an exception, to the “detection of aging effects” program element. This 

exception reads as follows:

“No periodic performance testing is conducted on the cold lab chiller loop, 

computer room chiller loop, or hot lab chiller loop as recommended by NUREG1801. Periodic sampling and chemistry controls are adequate to manage these 

closed-cycle cooling water systems.”

The staff noted that the applicant uses installed performance monitoring instrumentation and 

periodic chemical testing as part of its normal process for monitoring of the closed-cycle cooling 

water system. The staff also noted that where existing instrumentation is available to monitor 

parameters recommended in the GALL Report, the applicant appropriately credits the use of the 

available instrumentation. For each of the closed-cycle cooling water loops where the applicant 
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stated that installed instrumentation is available, but the available instrumentation does not 

measure the specific performance parameters recommended in the GALL Report, the applicant 

also credited periodic monitoring of closed-cycle cooling water chemistry parameters and total 

metallic species (iron and copper) to provide indications of system or component aging. The 

staff finds monitoring of alternative performance parameters, along with total metallic species, to 

be acceptable because the alternative monitoring also provides indications of aging effects in 

components and systems exposed to closed-cycle cooling water and is consistent with the 

SRP-LR, Section A.1.2.3.3 recommendation that the parameters to be monitored or inspected 

should be identified and linked to the degradation of the particular structure and component 

intended function.

For the cold lab chiller loop, the computer room chiller loop, and the hot lab chiller loop where 

the applicant stated that no performance parameters are monitored, the staff noted that the 

applicant credited only annual sampling of chemistry parameters and total metals (iron and 

copper) with detecting the effects of aging. In a telephone call with the applicant dated 

February 10, 2009, the staff stated that annual sampling of chemistry parameters and total 

metals is not sufficient to determine whether aging is occurring and asked the applicant to 

further justify the proposed AMPs for the cold lab chiller loop, the computer room chiller loop, 

and the hot lab chiller loop.

In a letter dated February 26, 2009, the applicant clarified that visual inspections will be 

performed for the cold lab chiller loop, the computer room chiller loop, and the hot lab chiller 

loop. In addition, the applicant revised the exception to the “detection of aging effects” program 

element to read as follows:

No periodic performance testing is conducted on the cold lab chiller loop, 

computer room chiller loop, or hot lab chiller loop as recommended by NUREG1801. Periodic visual inspections will be performed on these systems to identify 

the presence of aging effects and to confirm the effectiveness of chemistry 

controls. The coolant environment in these chiller loops is managed by periodic 

sampling and chemistry control. Chemical controls and visual inspections are 

adequate to manage aging effects in these closed-cycle cooling water systems.

The staff noted that in its revised response, the applicant states that periodic visual inspections 

will be performed in lieu of performance monitoring for the cold lab chiller loop, computer room 

chiller loop, and hot lab chiller loop, which do not have installed instrumentation to provide 

performance monitoring. The staff finds use of periodic visual inspections acceptable because 

visual inspections are able to detect whether loss of material due to corrosion is occurring and 

whether chemistry control of the closed-cycle cooling water is adequate to prevent or eliminate 

this aging effect.

Based on its review of the applicant’s response to RAI AMP-B2.1.9-1, and the applicant’s 

additional clarifications of that response, the staff determined that the applicant’s use of 

available performance monitoring instrumentation and additional periodic chemical sampling, 

plus periodic inspections where performance monitoring instrumentation is not installed, is 

adequate to provide indications of equipment and component degradation that might be caused 

by aging effects the applicant performs supplement performance monitoring for those closecycle cooling water systems on which instrumentation has been installed and because the 
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applicant performs sampling and testing of total metal ions in these systems. On this basis, the 

staff finds the issues in RAI AMP-B2.1.9-1 to be resolved and Exception 2 to the “parameters 

monitored/inspected” program element to be acceptable.

Enhancement 1. LRA Section B2.1.9 states an enhancement to the “monitoring and trending” 

program element. The applicant stated that the program will be enhanced to include an internal 

visual examination of accessible surfaces of components serviced by closed-cycle cooling water 

when the systems or components are opened during scheduled maintenance or surveillance 

activities.

During review of AMR results, the staff noted that the applicant credited the Closed-Cycle 

Cooling Water System Program with managing the aging effect of cracking in steel components 

exposed to closed cooling water (CCW). In a letter dated December 18, 2008, the staff issued 

RAI 3.3.2-13-01, which is discussed further in SER Section 3.3.2.3.13, asking the applicant to 

clarify how cracking in steel components would be detected by the Closed-Cycle Cooling Water 

System Program. In a response dated January 20, 2009, the applicant stated that inspections 

for cracking will be performed by visual examination with a magnified resolution (i.e. enhanced 

visual) as described in 10 CFR 50.55a(b)(2)(xxi)(A) or with ultrasonic methods. The applicant 

also revised Enhancement 1 to read as follows:

The program will be enhanced to include periodic inspection of accessible 

surfaces of components serviced by closed-cycle cooling water when the system 

or components are opened during scheduled maintenance or surveillance 

activities. Inspections are performed to identify the presence of aging effects and 

to confirm the effectiveness of the chemistry controls. Visual inspection of 

component internals will be used to detect loss of material and heat transfer 

degradation. Enhanced visual or volumetric examination techniques will be used 

to detect cracking.

In its letter dated April 13. 2009, the applicant revised its License Renewal Commitment List, 

Commitment No. 6, to include this revised enhancement as described above, with 

implementation to occur prior to the period of extended operation.

The GALL Report references EPRI TR-107396 as a basis for the Closed-Cycle Cooling Water 

System Program. EPRI-TR-107396, Revision1, Section 8.2, states that one of the most effective 

methods of determining the extent of fouling in closed cooling water components is through 

visual inspection of opened system components and that this can be done any time a system 

component is taken out of service for scheduled maintenance. The staff noted that the 

applicant’s proposed enhancement adds a procedural provision in maintenance and 

surveillance instructions to perform opportunistic visual examination of accessible surfaces 

whenever systems or components serviced by the closed-cooling water system are opened 

during scheduled maintenance or surveillance activities. 

In its review of on-site documentation for the applicant’s Closed-Cycle Cooling Water System 

Program, the staff noted that the applicant performs periodic visual inspections using corrosion 

coupons, which is consistent with the recommendations in EPRI-TR-107396, Revision 1, 

Section 8.8.1. The staff further noted that the opportunistic visual examinations are performed in 

addition to the inspection of corrosion coupons and finds that the additional visual examinations 
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provide increased assurance that aging effects will be detected before they can cause loss of 

component or system intended functions. In its letter of January 20, 2009, the applicant stated 

that enhanced visual or volumetric examination techniques will be used to inspect for cracking. 

The staff noted that the new procedural provision provides increased visual examinations 

consistent with the EPRI guidelines referenced in GALL AMP XI.M21. These examinations 

increase confidence that indications of fouling or loss of material due to corrosion are 

discovered so that corrective actions can be taken before a component's intended functions are 

adversely affected. Furthermore, enhanced visual or ultrasonic techniques provide inspection 

methodologies that are capable of detecting the aging effect of cracking, which also is managed 

by this AMP. Because the enhancement provides procedural changes that are consistent with 

recommendations in the GALL Report and is included in Commitment No. 6 of the applicant’s 

License Renewal Commitment list, the staff finds the proposed enhancement to the applicant’s 

Closed-Cycle Cooling Water System Program to be acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.9. The 

applicant stated that a review of OE for the Closed-Cycle Cooling Water System Program 

identified no adverse trends or issues with program performance. The applicant stated that 

conditions such as corrosion, fouling, and out-of-range chemistry parameters have been 

identified and corrected prior to causing significant impact to safe operation or loss of intended 

functions and that adequate corrective actions were taken to prevent recurrence.

The staff reviewed the OE discussion that was provided in the applicant’s license renewal 

program basis document binder for the Closed-Cycle Cooling Water System Program. The staff 

confirmed that the applicant’s review of OE included evaluation of both industry and plantspecific events that have occurred since issuance of the GALL Report, Revision 1. The staff 

reviewed additional selected CRs related to the applicant’s Closed-Cycle Cooling Water System 

Program and interviewed the applicant’s subject matter experts for the Closed-Cycle Cooling 

Water System Program. CRs reviewed by the staff included ones where the applicant found 

indications of corrosion, out-of-specification-chemistry conditions, and leaking components in 

the closed-cycle cooling water system. For all CRs reviewed, the staff noted that the applicant 

had performed adequate evaluations to determine a cause for the event and had taken 

corrective action adequate to repair or replace components or to restore operation within 

specification. Based on its review of the plant-specific OE, the staff finds that the applicant’s 

program has demonstrated its capability to monitor, trend and control closed-cycle cooling water 

chemistry parameters consistent with recommendations of the EPRI guidelines referenced in 

the GALL Report, and to implement corrective actions adequate to prevent loss of intended 

functions for components and systems affected by the Closed-Cycle Cooling Water System 

Program.

Based on this review, the staff finds (1) that the OE for this AMP demonstrates that the 

applicant’s Closed-Cycle Cooling Water System Program is achieving its objective of mitigating 

aging effects of cracking, loss of material, or reduction of heat transfer due to fouling for 

materials exposed to treated water in the closed-cycle cooling water system, and (2) that the 

applicant is taking appropriate corrective actions through implementation of this program.

The staff confirmed that the OE 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 element acceptable.
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UFSAR Supplement. In LRA Section A2.9, the applicant provided the UFSAR supplement for 

the Closed-Cycle Cooling Water System Program. The staff verified that the UFSAR

supplement summary for the Closed-Cycle Cooling Water System Program conforms to the 

staff’s recommended UFSAR supplement for this type of program as described in the SRP-LR.

In its letter dated April 13, 2009, the applicant provided a list of license renewal commitments. 

The staff verified that the applicant has included the program enhancements identified in the 

LRA for the Closed-Cycle Cooling Water System Program in Commitment No. 6 of the final 

License Renewal Commitment List. The staff also verified that the applicant’s Commitment No. 

6 includes a statement that periodic visual inspections of the cold lab chiller loop, computer 

room chiller loop, or hot lab chiller loop will be performed to identify the presence of aging 

effects and to confirm the effectiveness of chemistry controls. In addition, the Closed-Cycle 

Cooling Water System Program will be enhanced to include periodic inspection of accessible 

surfaces of components serviced by closed cycle cooling water when the systems or 

components are opened during scheduled maintenance or surveillance activities.

The staff finds that the UFSAR supplement summary in LRA Section A2.9 provides an 

acceptable description of the applicant’s Closed-Cycle Cooling Water System Program because 

it is consistent with the UFSAR supplement summary description recommended in the SRP-LR 

for a Closed-Cycle Cooling Water System program. The applicant has appropriately included all 

program enhancements in Commitment No. 6 of the License Renewal Commitment list, which is 

linked with UFSAR supplement Section A.2.9 and scheduled for implementation prior to the 

period of extended operation.

The staff determined that the information in the UFSAR 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 Closed-Cycle Cooling Water System 

Program and the applicant’s response to RAI AMP-B2.1.9-1, the staff determines that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. The staff also reviewed the exceptions and their justifications and determines that 

the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. In 

addition, the staff reviewed the enhancement, as modified by the applicant’s response to RAI 

3.3.2-13-01 and confirmed that its implementation through Commitment No. 6 prior to the period 

of extended operation makes the existing AMP consistent with the GALL AMP to which it was 

compared, with acceptable exceptions. The staff concludes that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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 Compressed Air Monitoring 

Summary of Technical Information in the Application. LRA Section B2.1.10 describes the 

Compressed Air Monitoring Program as an existing program that is consistent with GALL AMP

XI.M24, “Compressed Air Monitoring,” with enhancements and an exception. The applicant 
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stated that this program conducts periodic air quality sampling, inspections, component 

functional testing, and leakage testing. Additionally, the applicant further stated that preventive 

maintenance is performed at regular intervals to assure system components continue to operate 

reliably, thereby assuring that quality air is supplied to plant equipment.

Staff Evaluation. During its audit the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff reviewed the exception and the enhancements to determine whether 

the applicant’s AMP, with the exception and the enhancements, is adequate to manage the 

aging effects for which the LRA credits it. In comparing the program elements in the applicant’s

program to those in GALL AMP XI.M24, Compressed Air Monitoring, the staff confirmed that the 

program elements in the applicant’s AMP are consistent with the GALL Report's AMP XI.M24

corresponding program element criteria, except for the exception and enhancements. 

Exception. The applicant has taken an exception to the “preventive actions” and “detection of 

aging effects” program elements as follows:

The PINGP Compressed Air Monitoring Program does not explicitly incorporate the 

performance testing guidelines provided in EPRI NP-7079, EPRI TR-108147, and

ASME OM-S/G-1998, Part 17, that are listed in NUREG-1801. The PINGP Station 

and Instrument Air System is an older installation, which was not designed and 

installed with the instrumentation and features (i.e., in-line dewpoint indication with 

alarm) necessary to conduct the specified performance testing. Instead, preventive 

maintenance activities are conducted on Station and Instrument Air System 

components, based upon manufacturer's recommendations and other EPRI 

guidance. These routine maintenance activities in conjunction with system 

inspections and system alarms provide for sufficient inspection and monitoring to 

ensure the timely detection of aging effects such that the Station and Instrument 

Air System is capable of performing its intended function.

The staff reviewed ASME OM-S/G-1998, Part 17, “Performance Testing of Instrument Air 

Systems Information Notice Light-Water Reactor Power Plants," and ISA-S7.0.1-1996, “Quality 

Standard for Instrument Air,” which are referenced in GALL AMP XI.M24. The staff noted that 

PINGP is an older plant and does not have the necessary design features for an in-line 

dewpoint indication with alarm. The staff noted that ISA-S7.0.1-1996, in Section 5.1 states that a 

monitored alarm for pressure dew-point is preferred; however, if a monitored alarm is 

unavailable, per shift monitoring is recommended. The staff reviewed the applicant’s program 

basis document and implementing procedures and noted that the PINGP Station and Instrument 

Air System receivers, dryers, and moisture separators are checked for moisture several times 

daily during plant rounds. The staff also noted that the preventive maintenance program for the 

air compressors, dryers, and filters is based upon manufacturer’s recommendations. Based on 

ISA-S7.0.01, the staff noted that pressure dewpoints are established to protect instrument air 

systems from the presence of moisture. By performing frequent moisture checks, the applicant 

is ensuring that moisture is not present in the compressed air system; thereby ensuring that the 

program is consistent with the “preventive actions” program element of GALL AMP XI.M24. 

Based on this review, the staff finds this exception acceptable because the applicant performs 

moisture checks several times daily and performs periodic inspections as recommended by the 

manufacturer to ensure that the station and instrument air system is capable of performing its 

intended function.
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Enhancement 1. In LRA Section B2.1.10, the applicant included an enhancement to the 

“preventive actions” and “acceptance criteria” program elements to state that station and 

instrument air system air quality will be monitored and maintained in accordance with the 

instrument air quality guidance provided in ISA S7.0.01-1996; and particulate testing will be 

revised to use a particle size methodology as specified in ISA S7.0.01. 

The staff reviewed the applicant’s program basis document and noted that the applicant is using 

ISA S7.3 acceptance criteria. The acceptance criteria of ISA S7.3 states that in no case shall 

the dewpoint exceed 35o F, and the maximum particle size in the air stream shall not exceed 3 

micrometers. The acceptance criteria of ISA S7.0.01 states that in no case shall dewpoint 

exceed 39 o F, and a maximum 40-micrometer particle size in the instrument air system is 

acceptable. The staff finds that this enhancement to use the guidance of ISA S7.0.01 will make 

the Compressed Air Monitoring Program consistent with GALL AMP XI.M24, “preventive 

actions” program element, which recommends guidelines based on ISA-S7.0.01-1996. The staff 

also verified that the applicant has included Commitment No. 7 in its commitment list to enhance 

the program to include S7.0.01 criteria prior to the period of extended operation. On the basis 

that the enhancement, when implemented, will make the Compressed Air Monitoring Program 

consistent with the GALL Report, the staff finds the enhancement acceptable. 

Enhancement 2. In its letter dated February 6, 2009, in response to the NRC Region III 

inspection, the applicant included an enhancement to “preventive actions” and “detection of 

aging effects” program elements to state that the program will be enhanced to include on-line 

dewpoint monitoring (Commitment No. 7).

The applicant stated that the PINGP station and instrument air dryers are equipped with colorchange moisture indicators, which provide a constant visual indication that dry gas is being 

supplied to the dryer outlet. However, the PINGP Compressed Air Monitoring Program did not 

credit the use of the moisture indicators as a means of on-line dewpoint monitoring. As a result, 

the applicant determined that on-line dewpoint monitoring should be explicitly addressed as an 

enhancement to the existing program.

The staff finds that this enhancement to include on-line dewpoint monitoring will make the 

Compressed Air Monitoring Program consistent with GALL AMP XI.M24, “preventive actions” 

program element, which recommends the system air quality is monitored and maintained to 

ensure that the system and components meet specified operability requirements. The staff also 

verified that the applicant has revised Commitment No. 7 in its commitment list to enhance the 

program to include on-line dewpoint monitoring prior to the period of extended operation. On the 

basis that the enhancement, when implemented, will make the Compressed Air Monitoring 

Program consistent with the GALL Report, the staff finds the enhancement acceptable. 

Based on its review of the exception and the enhancements, the staff finds the applicant’s 

Compressed Air Monitoring program acceptable because it conforms to the recommended 

GALL AMP XI.M24, Compressed Air Monitoring, with enhancements.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.10 and 

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 also confirmed that 
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applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 

and are evaluated in the GALL Report. 

The staff reviewed CRs as part of the OE review during the audit and found that the applicant 

had identified that station air compressor jacket cooling outlet temperature was higher than

normal. The staff noted that the applicant determined that the control valve orientation was not 

proper, and took corrective action to properly orient the valve and made changes to the piping 

configuration to address the issue. In another CR, the staff noted that the applicant had 

identified that an air dryer inlet control valve was stuck. The applicant determined that these 

control valves had aged significantly and took corrective action to replace these valves. The 

staff noted that as part of its generic issue resolution, the applicant determined that the air 

dryers were also very old, and took the corrective action to replace the dryers. 

Furthermore, the staff confirmed that the applicant had addressed OE identified after the 

issuance of the GALL Report. The staff finds that the applicant’s Compressed Air Monitoring 

Program, with the corrective actions discussed in the LRA, has been effective in identifying, 

monitoring, and correcting the effects of age-related degradation in station and instrument air 

system.

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.10, the applicant provided the UFSAR supplement for 

the Compressed Air Monitoring Program. The staff verified that the UFSAR supplement 

summary description for the Compressed Air Monitoring Program was in conformance with the 

staff’s recommended UFSAR supplement for the Compressed Air Monitoring Program provided 

in Table 3.3-2 of the SRP-LR.

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant included Commitment No. 7 in the final license renewal 

commitment list, the program enhancements identified in the LRA and its letter dated 

April 13, 2009 for the applicant’s Compressed Air Monitoring Program. 

Based on this review, the staff finds that UFSAR supplement Section A2.10 provides an 

acceptable UFSAR supplement summary description of the applicant’s Compressed Air 

Monitoring Program because it is consistent with the UFSAR supplement summary description 

in the SRP-LR for the Compressed Air Monitoring Program. The staff determines that the 

information in the UFSAR 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 and the applicant’s response to NRC Region III inspection, the staff confirmed the 

applicant’s claim of consistency with the GALL Report. The staff also reviewed the 

enhancements and confirmed that their implementation through Commitment No. 7 prior to the 

period of extended operation will make the existing AMP consistent with the GALL AMP to 

which it was compared. 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 
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aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR 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 Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements 

Summary of Technical Information in the Application. LRA Section B2.1.11 describes the

Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program as a new program that will be consistent, with exceptions, to GALL AMP 

XI.E6, “Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.” The applicant states that the program conducts a one-time test of a 

representative sample of electrical cable connections (metallic portions) to confirm the absence 

of aging effects (loose connections). Cable connections terminating within an active or passive 

device/enclosure from external sources are within the scope of this program. However, the 

applicant states that cable/wiring connections terminating within an active or passive 

device/enclosure from internal sources are not within the scope of this program. The applicant 

also states that the program manages the aging effects of loose connections and electrical 

failure from the following aging stressors: thermal cycling, ohmic heating, electrical transients, 

vibration, chemical contamination, corrosion and oxidation. The representative sample includes 

connections of various voltage applications (medium and low voltage), circuit loadings, and 

locations (high temperature, high humidity, vibration, etc.). The technical basis for the sample 

selections will be documented. The applicant further stated that the exceptions are consistent 

with the proposed Interim Staff Guidance LR-ISG-2007-02, noticed for public comment in the 

Federal Register on September 6, 2007 (72 FR 51256).

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the exceptions to determine whether the 

AMP, with exceptions, is adequate to manage the aging effects for which the LRA credits it.

Based on its review, the staff finds that the applicant’s Electrical Cable Connections Not Subject

to 10 CFR 50.49 Environmental Qualification Requirements Program consistent with the 

program elements of GALL AMP XI.E6.

The staff’s review of exceptions is discussed below.

Exception 1. LRA Section B2.1.11 states an exception to the Scope of Program, Parameters 

Monitored/Inspected, Detection of Aging Effects, and Monitoring and Trending program 

elements. The applicant stated that the Electrical Cable Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements Program is consistent with the GALL Report as 

it is modified by the proposed LR-ISG-2007-02. The applicant also stated that the GALL Report

describes an AMP for electrical cable connections and a revision to this program is being 

developed via the Interim Staff Guidance (ISG) process. The applicant further stated that a 

revised program was published for public comment on September 6, 2007, in Federal Register 

Notice 72 FR 51256 “Proposed License Renewal Interim Staff Guidance LR-ISG-2007-02: 

Changes to Generic Aging Lessons Learned (GALL) Report Aging Management Program 
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(AMP) XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements" Solicitation of Public Comment.”

The staff issued draft LR-ISG-2007-02 on September 6, 2007, for public comments. In this ISG, 

the staff clarifies and recommends a one-time inspection to ensure that either aging of metallic 

cable connections is not occurring or an existing maintenance program is effective. Upon 

receiving public comments, the staff will evaluate comments and make a determination to 

incorporate comments, as appropriate. Once the NRC staff completes the LR-ISG, it will issue 

the LR-ISG for industry use. The staff will incorporate the approved LR-ISG into the next 

revision of the license renewal guidance document. Until then, the staff will compare the 

elements of applicant’s Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements Program against those currently in the GALL AMP 

XI.E6. Any deviation from the GALL AMP XI.E6 will require the applicant’s description for each 

exception and element affected. The staff noted that the applicant did not specifically identify 

each exception and program element associated with the exceptions. In a teleconference on 

January 23, 2009, the staff requested the applicant to provide a description of the exceptions to 

GALL XI.E6 and the program elements associated with these exceptions which the applicant 

agreed to provide in followup RAI B2.1.11,.

In a letter dated February 6, 2009, the applicant responded that the differences resulted in the 

PINGP Electrical Cable Connections Not Subject to 50.49 Environmental Qualification 

Requirements Program having exceptions to four elements of the GALL Report program. The 

specific exceptions are summarized below.

Program Element 1, Scope of Program. GALL Report, XI.E6 Element 1, states:

"Connections associated with cables in scope of license renewal are part of this program, 

regardless of their association with active or passive components."

The PINGP program states:

...Program is a one-time inspection program that tests a representative sample 

of cable connections based upon factors such as application (medium and low 

voltage), connection type, circuit loading, and location (high temperature, high 

humidity, vibration, etc.). Cable connections terminating within an active or 

passive device/assembly from external sources are within the scope of this 

program. Cable/wiring connections terminating within an active assembly from 

internal sources are not within the scope of this program.
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The exceptions to GALL AMP XI.E6 Element 1, are a result of:

(1) The proposed LR-ISG-2007-02 provides for a one-time inspection/test program, while 

the GALL AMP XI.E6 program specifies periodic testing.

(2) The proposed LR-ISG-2007-02 excludes high-voltage applications (states only medium 

and low voltage applications), while the GALL AMP XI.E6 program includes high, 

medium, and low voltage applications.

(3) The proposed LR-ISG-2007-02 excludes internal wiring/cable connections within active 

assemblies, while the GALL AMP XI.E6 program does not differentiate between internal 

wiring connections within an active assembly and external cable connections to active or 

passive assemblies.

Program Element 3, Parameters Monitored/Inspected. GALL AMP XI.E6 Element 3, states the 

following:

This program will focus on the metallic parts of the connection. The monitoring 

includes loosening of bolted connections due to thermal cycling, ohmic heating, 

electrical transients, vibration, chemical contamination, corrosion, and oxidation.

A representative sample of electrical cable connections is tested. The following 

factors are to be considered for sampling: application (high, medium and low 

voltage), circuit loading, and location (high temperature, high humidity, vibration, 

etc.). The technical basis for the sample selected is to be documented.

The PINGP Program states the following:

... Program will focus on the metallic parts of cable connections. The one-time 

inspection will test a representative sample of electrical connections having 

different voltage applications (medium and low voltage) and locations (high 

temperature, high humidity, vibration, etc.), and will demonstrate that the 

loosening of bolted connections due to thermal cycling, ohmic heating, electrical 

transients, vibration, chemical contamination, corrosion, and oxidation does not 

occur, and would not require a periodic AMP to prevent electrical connection 

failures during the period of extended operation. Cable connections terminating 

within an active or passive device/assembly from external sources are within the 

scope of this program. Cable/wiring connections terminating within an active 

assembly from internal sources are not within the scope of this program. The 

technical basis for the sample selected will be documented.

The exceptions to GALL AMP XI.E6 Element 3, are a result of the following:

• The proposed LR-ISG-2007-02 excludes high-voltage applications (states only medium 

and low voltage applications), while the NUREG-1801, XI.E6 program includes high, 

medium, and low voltage applications.

• The proposed LR-ISG-2007-02 excludes internal wiring/cable connections within active 

assemblies, while the NUREG-1801, XI.E6 program does not differentiate between 
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internal wiring connections within an active assembly and external cable connections to 

active or passive assemblies.

Program Element 4, Detection of Aging Effects. NUREG-1801, XI.E6 Element 4, states:

Electrical connections within the scope of license renewal will be tested at least 

once every 10 years. Testing may include thermography, contact resistance 

testing, or other appropriate testing methods. This is an adequate period to 

preclude failures of the electrical connections since experience has shown that 

aging degradation is a slow process. A 10-year testing interval will provide two 

data points during a 20-year period, which can be used to characterize the 

degradation rate. The first tests for license renewal are to be completed before 

the period of extended operation.

The PINGP Program states the following:

... Program is a one-time inspection program that tests a representative sample 

of electrical connections within the scope of license renewal and subject to AMR.

Cable connections terminating within an active or passive device/assembly from 

external sources are within the scope of this program. Cable/wiring connections 

terminating within an active assembly from internal sources are not within the 

scope of this program.

Factors considered for sample selection will be application (medium and low 

voltage) ...

The exceptions to NUREG-1801, XI.E6 Element 4, are a result of the following:

• The proposed LR-ISG-2007-02 provides for a one-time inspection/test program, while 

the NUREG-1801, XI.E6 program specifies periodic testing.

• The proposed LR-ISG-2007-02 excludes high-voltage applications (states only medium 

and low voltage applications), while the NUREG-1801, XI.E6 program includes high, 

medium, and low voltage applications.

• The proposed LR-ISG-2007-02 excludes internal wiring/cable connections within active 

assemblies, while the NUREG-1801, XI.E6 program does not differentiate between 

internal wiring connections within an active assembly and external cable connections to 

active or passive assemblies.

Program Element 5, Monitoring and Trending. NUREG-1801, XI.E6 Element 5, states the 

following:

“Trending actions are not included as part of this program because the ability to trend 

test results is dependent on the specific type of test chosen. However, test results that 

are trendable provide additional information on the rate of degradation.”
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The PINGP Program states the following:

“The Electrical Cable Connections Not Subject to 10CFR50.49 Environmental 

Qualification Requirements Program is a one-time inspection program, and 

trending actions are not included.”

The exception to NUREG-1801, XI.E6 Element 5, is related to the frequency of testing. The 

GALL Report recommends periodic testing. However, proposed LR-ISG-2007-02 provides for a 

one-time inspection/test program.

During the review of the staff’s followup question, the applicant determined that LRA Sections 

A2.1 and B2.1.11 should be changed to use terms that conform to the terminology used in the 

proposed LR-ISG-2007-02. Accordingly, the applicant made changes to LRA Section A2.11 on 

Page A-6, the second and third sentences are revised to read as follows:

Cable connections terminating within an active or passive device/assembly from 

external sources are within the scope of this program. Cable/wiring connections 

terminating within an active assembly from internal sources are not within the 

scope of this program.

In LRA Section B2.1.11 on Page B-31, Program Description, the second and third sentences of 

the first paragraph are revised to read as follows:

Cable connections terminating within an active or passive device/assembly from 

external sources are within the scope of this program. Cable/wiring connections 

terminating within an active assembly from internal sources are not within the 

scope of this program.

Based on its review, the staff finds the applicant’s response dated February 6, 2009, to the RAI 

B2.1.11 followup question acceptable. The exception to the “scope of program” program 

element is acceptable because it is consistent with what is proposed in the final revision of LRISG-2007-02. The staff noted that the connection to an internal wiring is considered as a part of 

the active assembly therefore does not require an AMR. The exclusion of high-voltage

connections (>35 kV) in the “scope of program” program element is acceptable because highvoltage connections are addressed elsewhere in the SER under switchyard connections. The 

staff also finds the exception to the “parameters monitored or inspected,” program element 

acceptable because the exception is consistent with the staff’s clarifications provided in LR-ISG2007-02. The sample of connections considered does not include the high-voltage application 

and low circuit loading because the aging effect of loosening of cable connections due to 

thermal cycling is insignificant for low load circuits because of low currents. The staff noted that 

high-voltage connections are addressed elsewhere in the SER under switchyard connections. In 

addition, the staff finds the exception to the “detection of aging effects” program element 

acceptable because this is a one-time inspection on a sampling basis instead of periodic 

inspections as currently recommended in GALL AMP XI.E6.

In reviewing OE to address industry comments about GALL AMP XI.E6, the staff finds that few 

OEs related to failed connections are due to human errors or maintenance practices. The staff 

noted that the OE cannot support a periodic inspection as currently recommended in GALL 
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AMP XI.E6. However, because there have been limited number of age-related failures of cable 

connections, a one-time inspection of the metallic portion of electrical cable connections is 

warranted. On this basis, the staff issued LR-ISG-2007-02 to provide clarification and 

recommend a one-time inspection on a representative sampling basis to ensure that either 

aging of metallic cable connections is not occurring or existing preventive maintenance is 

effective such that a periodic inspection is not needed.

The staff also finds that the proposed amendments in LRA Sections A2.11 and B2.1.11 

acceptable because the applicant provided clarification of the scope of cable connections to be 

included in Electrical Cable Connections not Subject to 10 CFR 50.49 Environmental 

Qualification Requirements Program. These clarifications are consistent with those in the staff’s 

LR-ISG-2007-02. The staff’s concern described in the RAI B2.1.11 followup question is 

resolved.

Based on its review, the staff finds that the AMP, with the exceptions, is adequate to manage

the aging effect for which it is credited.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.11. The 

applicant states that a review of PINGP OE identified one significant connection failure that 

resulted in a fire. The cause of this failure was determined to be from either improper resilvering of the bus contacts, improper connection during maintenance activities, and/or a 

manufacturers' design flaw (tulip connection) where connection pieces may break (unnoticed) 

during reconnection activities. None of the failure causes were age-related, but the detrimental 

effects of the improper connection heightened the awareness and importance of having sound 

electrical connections (regardless of the cause of loose connections), and resulted in an 

expansion of the number of electrical connections periodically inspected under the PINGP 

Thermography Program. The applicant also stated that the Corrective Action Program 

evaluation also investigated similar connections in detail, and found no similar loose 

connections that would lead to circuit failure or fire. A procedure change was made to include an 

acceptable and consistent contact re-silvering process.

The staff reviewed the OE provided in the LRA and basis documents available during the audits.

Based on the review of the applicant-identified OE, the staff has confirmed that the applicant 

has taken appropriate correction actions to address the cable connection issue. Therefore, the 

staff determines that the applicant has adequately addressed this element. The staff confirmed 

that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.11, the applicant provided the UFSAR supplement for 

the AMP Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program. The staff reviewed this section and determines that the information in 

UFSAR supplement is an adequate summary description of the program, as required by 10 

CFR 54.21(d).

The applicant committed to implement this AMP prior to the period of extended operation and 

identified it as LRA Commitment No. 8.
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Conclusion. On the basis of its audit and reviews of the applicant's Electrical Cable Connections 

Not Subject to 10 CFR 50.49 Environmental Qualification Requirement 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 determined that 

the AMP, with the exceptions, is adequate to manage the aging effects for which it is credited. 

The staff concludes that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed 

the UFSAR 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 External Surfaces Monitoring

Summary of Technical Information in the Application. LRA Section B2.1.14 describes the 

applicant’s existing External Surfaces Monitoring Program as consistent, with enhancements, 

with GALL AMP XI.M36, “External Surfaces Monitoring." The applicant stated that this program 

is credited to manage loss of material, cracking, change in material properties, and heat transfer 

degradation for applicable metallic and non-metallic components. The applicant further stated 

that this program will utilize periodic visual inspections during system walkdowns and 

inspections for the accessible external surfaces for components that are within the scope of this 

program. The applicant stated that this program will be credited for managing degradation of 

internal surfaces for those situations where the external surfaces condition is representative of 

the conditions on the internal surface, consistent with the recommendations provided in GALL 

AMP XI.M36.

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the enhancements to determine whether 

the AMP, with the enhancements, is adequate to manage the aging effects for which the LRA 

credits it. The staff’s summary of its on-site review of AMP B2.1.14 is documented in staff’s 

Audit Summary Report Section for this AMP. The applicant claims that the AMP B2.1.21 is 

consistent with GALL AMP XI.M36, “External Surfaces Monitoring," with enhancements

In comparing the seven program elements in the applicant’s program to those in 

GALL AMP XI.M36, the staff noted that the program elements in which the applicant’s AMP 

claimed to be consistent with GALL were consistent with the corresponding program element 

criteria recommended in the program elements of GALL AMP XI.M36 with the exception of 

those portions of the program elements that related to the enhancements and additional areas 

in which the staff determined there was a need for additional information and clarification for 

which a RAI was issued.

Enhancement 1. In LRA Section B2.1.14, the applicant stated that the program element, scope 

of program, for the External Surfaces Monitoring Program will be enhanced prior to the period of 

extended operation. The applicant’s enhancement to the scope of program states that:

The scope of program will be expanded as necessary to include all metallic and 

non-metallic components within the scope of License Renewal that require aging 

management in accordance with this program.
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The staff noted that the scope of GALL AMP XI.M36, “External Surfaces Monitoring,” is 

applicable only to the management of loss of material in components that are fabricated from 

steel materials or to degradation of their external liners or coatings, if the designs include these 

features. However, the staff noted that the applicant is proposing to expand the scope of this 

program to include several other metallic and non-metallic components. Therefore, by letter 

dated November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant to do:

(a) provide an appropriate program to manage non-metallic components and their 

associated aging effects;

(b) justify why the aging effect of heat transfer degradation due to fouling as it 

applies to the additional metallic components added to the scope of this program 

is not considered an enhancement to this program element; and

(c) justify how this program will adequately manage the aging effects of loss of 

material and heat transfer degradation as it applies to the additional metallic 

components added to the scope of this program

The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008. In its response to 

(a) of RAI B2.1.14-1, the applicant stated that the aging effects in non-metallic materials can be 

detected by a visual inspection evidence of surface discontinuities that include cracking, 

crazing, peeling, blistering, chalking, flaking, physical distortion, discoloration, loss of material 

from wear, and signs of leakage. The applicant further stated that a physical manipulation of 

non-metallic components will supplement the visual examination in order to verify aging effects 

such as hardening, embrittlement, or gross softening are not occurring. The staff noted that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration.

During its review of the applicant’s response the staff noted that the applicant did not amend 

Commitment No. 11 to indicate that a physical manipulation will supplement a visual inspection 

when appropriate. During a teleconference on January 22, 2009, the applicant stated that it will 

amend Commitment No. 11 to indicate physical manipulation will supplement the visual 

inspection when appropriate. By letter dated February 6, 2009, the applicant amended 

Commitment No. 11 to indicate physical manipulation will supplement a visual inspection when 

appropriate. On the basis of its review, the staff finds the applicant’s response acceptable 

because (1) the applicant will supplement the visual inspection for non-metallic components with 

a physical manipulation, when appropriate, which is capable of detecting age-related 

degradation for non-metallic components as described above and (2) the applicant amended its 

Commitment No. 11 to specifically indicate that a physical manipulation of non-metallic 

components will supplement the visual examination, when appropriate.

The applicant stated in its response to (b) of B2.1.14-1 that this program is only credited for the 

management of heat transfer degradation due to fouling of the external surfaces of cooling coils 

that are exposed to an external air environment (plant indoor air or primary containment air).

The staff noted that the visual examinations performed as part of this program will be capable of 

identifying corrosion, discoloration and accumulation of dirt/debris, which is consistent with the 
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intention of GALL AMP XI.M36. The staff noted that indications of corrosion, discoloration and 

accumulation of dirt/debris are indicative of fouling on the cooling coil external surface and has 

the potential to lead to heat transfer degradation. The staff noted that because the program will 

be capable of identifying corrosion, discoloration and accumulation of dirt/debris that are 

indicative of heat transfer degradation due to fouling that the addition of this aging effect to the 

scope of the program is not considered an enhancement. On the basis of its review the staff 

finds the applicant’s response and this augmentation to be acceptable because the applicant’s 

program consists of visual examinations, consistent with GALL AMP XI.M36, which are capable 

of detecting fouling (buildup from whatever source) which may potentially degrade the heat 

transfer capability of the cooling coil surface to the external air environment.

The applicant stated in its response to (c) of RAI B2.1.14-1 that a visual inspection that is 

performed during activities of this program will be capable of identifying loss of material and 

heat transfer degradation for metallic components (aluminum, copper alloy, copper-nickel, 

chrome-molybdenum alloy, carbon steel with stainless steel clad) other than steel. The applicant 

further stated that the visual inspection performed during activities of this program will monitor 

parameters such as corrosion wastage, oxidation, discoloration, cracking, coating degradation, 

accumulation of dirt/debris, evidence of leakage, surface discontinuities and pitting. The staff 

noted that metallic components other than steel would exhibit indications of loss of material on 

the surface similar to steel and a visual inspection will be capable of detecting age-related

degradation. The staff further noted that the these visual inspections will be performed by the 

applicant’s staff that are qualified to perform the activities of the visual inspection in accordance 

with site controlled procedures and processes at least once per refueling cycle. Furthermore, 

deficiencies, problems and concerns are documented and corrective actions are taken as 

appropriate, which is consistent with the program elements, (1) detection of aging effects and 

(2) monitoring and trending, of GALL AMP XI.M36. On the basis of its review, the staff finds that 

the applicant’s basis for aging management, as amended in the RAI response, to be acceptable 

because: (1) the applicant will be performing visual inspections that are capable of detecting 

loss of material in metallic components as they display indications of degradation similar to 

steel, for which GALL AMP XI.M36 was intended and (2) these visual inspections will be 

performed at least once per refueling cycle by the applicant’s staff that has been qualified in 

accordance with site controlled procedures and processes, which is consistent with GALL AMP 

XI.M36.

The staff verified that the applicant has incorporated this enhancement of the AMP in 

LRA Commitment No. 11, which was placed on UFSAR Supplement for the LRA in a letter 

dated April 13, 2009. 

On the basis of its review, the staff finds the applicant’s response to RAI B2.1.14-1, and 

enhancement of the program in Commitment No. 11 to be acceptable in its entirety, and 

therefore the applicant’s enhancement acceptable. 

Enhancement 2. In LRA Section B2.1.14 the applicant states that the program element, scope 

of program, for the External Surfaces Monitoring Program must be enhanced in order to be 

consistent with GALL XI.M36 “External Surfaces Monitoring." The applicant’s enhancement to 

the scope of program states that:
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The program will be enhanced to ensure that surfaces that are inaccessible or 

not readily visible during plant operations will be inspected during refueling 

outages.

The program will be enhanced to ensure that surfaces that are inaccessible or 

not readily visible during both plant operations and refueling outages will be 

inspected at intervals that provide reasonable assurance that aging effects are 

managed such that applicable components will perform their intended functions 

during the period of extended operation.

The staff reviewed the applicant’s enhancement and compared it to the recommendations 

provided in GALL AMP XI.M36. The staff noted that the applicant’s proposed enhancements are 

consistent with the recommendations provided in the GALL AMP XI.M36. On the basis of its 

review, the staff finds the applicant’s enhancement to be acceptable because when the 

applicant’s program is enhanced as described above prior to the period of extended operating, 

this program will be consistent with the recommendations provided in the program element, 

“scope of program” element in GALL AMP XI.M36.

The staff verified that the applicant has incorporated this enhancement of the AMP in 

LRA Commitment No. 11, which was placed on UFSAR Supplement for the LRA in a letter 

dated April 13, 2009. On the basis of its review, the staff finds the applicant’s response to RAI 

B2.1.14-1, and enhancement of the program in Commitment No. 11 to be acceptable in its 

entirety, and, therefore, the applicant’s enhancement acceptable. 

Enhancement 3. By letter dated February 6, 2009 the applicant amended its LRA to include an 

additional enhancement to its program. The applicant’s enhancement to the program element, 

detection of aging effects program element states that the program will apply physical 

manipulation techniques, in addition to visual inspection, to detect aging effects in elastomers 

and plastics.

The staff noted that the physical manipulation will supplement and aid the visual inspection in 

detecting age-related degradation because changes in material properties, such as hardening 

and loss of strength, can be detected during manipulation of elastomers and plastics, when 

appropriate, by the relative inflexibility of the component, or by the failure of the component to 

return to its previous shape or configuration.

On the basis of its review, the staff finds the applicant’s enhancement acceptable because the 

applicant will supplement the visual inspection for elastomer and plastic components with a 

physical manipulation, when appropriate, which is capable of detecting age-related degradation 

for non-metallic components as described above.

The staff verified that the applicant has incorporated this enhancement of the AMP in 

LRA Commitment No. 11, which was placed on UFSAR Supplement for the LRA in a letter 

dated April 13, 2009.

Enhancement 4. By letter dated February 6, 2009, the applicant amended its LRA to include an 

additional enhancement to its program. The applicant’s enhancement to the acceptance criteria 

program element states that:
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The program will include acceptance criteria (e.g. threshold values for identified 

aging effects) to ensure that the need for corrective actions will be identified 

before loss of intended functions.

The program element, acceptance criteria, of GALL AMP XI.M36 recommends that for each 

component/aging effect combination, the acceptance criteria are defined to ensure that the need 

for corrective actions will be identified before loss of intended functions. The staff reviewed the 

applicant’s program basis documents and this enhancement and finds that the implementation 

of this enhancement will make the applicant’s program consistent with the GALL AMP XI.M36.

The staff verified that the applicant has incorporated this enhancement of the AMP in LRA 

Commitment No. 11, which was placed on UFSAR Supplement for the LRA in a letter dated 

April 13, 2009.

Enhancement 5. By letter dated February 6, 2009, the applicant amended its LRA to include an 

additional enhancement to its program. The applicant’s enhancement to the administrative 

controls program element states that:

The program will ensure that program documentation such as walkdown records, 

inspection results, and other records of monitoring and trending activities are 

auditable and retrievable.

The program element, administrative controls, of GALL AMP XI.M36 and 10 CFR Part 50, 

Appendix B, provides the acceptable recommendations for this program element. The staff 

reviewed the applicant’s program basis documents and this enhancement and finds that the 

implementation of this enhancement will make the applicant’s program consistent with the GALL 

AMP XI.M36 and 10 CFR Part 50, Appendix B, such that system walkdown records, inspection 

results and other records associated with this program were retrievable and auditable.

On the basis of its review of the applicant’s program, together with review of the enhancements 

and RAI B.2.14-1 as described above, the staff finds the External Surfaces Monitoring Program 

consistent with the program elements of GALL AMP XI.M36 with acceptable enhancements, 

and therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.14 and 

the applicant’s CRs during the on-site audit and interviewed the applicant’s technical staff to 

confirm that the plant-specific OE did not reveal any degradation not bounded by industry 

experience. During its review of the applicant’s OE the staff noted that the applicant identified 

the fan coil unit (FCU) supply/return flanges were corroded in May 2005. The applicant identified 

the corrosion and then performed an evaluation to either replace or resurface the flange. The 

applicant later found several other flanges with similar conditions of degradation. The applicant 

further stated that based on the evaluation it performed these flanges that corroded were 

subsequently repaired/resurfaced by machining. The staff noted that the applicant had taken 

appropriate corrective actions to resurface the affected areas by machining after discovery of 

the degradation of the FCU supply/return flanges.
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During its review of the applicant’s OE the staff noted that in September 2007 the applicant 

discovered there was a boric acid leak on valve CV-31213. It was later determined by the 

applicant that the boric acid was located on stainless steel materials, which is resistant to boric 

acid corrosion. The applicant subsequently repaired the leak and cleaned any of the residual dry 

boric acid from the stainless steel surface. The staff noted that the applicant was capable of 

identifying the leakage and then initiated corrective actions to repair the source of the leak and 

clean any remaining boric acid on the surface of the valve.

The applicant also noted that during a surveillance test (diesel generator monthly slow start) on 

October 2006 that there was a leak at the 2EG-9-16 valve. The applicant’s evaluation noted that 

this type of leak may put them in an unplanned limiting condition for operation. The applicant 

initiated corrective actions to have the leak repaired by the “Fix It Now” team in November 2006.

The staff noted in this situation the applicant was capable of identifying leakage and then 

initiating corrective actions to have the leak from the valve repaired.

The staff reviewed the OE provided in the LRA and interviewed the applicant’s technical

personnel regarding the generic and plant-specific OE that is applicable to this AMP. The staff 

confirmed that the applicant had taken appropriate corrective actions for the OE that are 

applicable to the External Surfaces Monitoring Program. The staff also noted that there was not 

any aging effects or age-related degradation that could not be detected with the AMP's 

inspection and physical manipulation methods or that are not bounded by the ability of the AMP 

to detect the aging effects. The staff confirmed that the “operating experience” program element 

satisfies the criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.10; therefore, 

the staff finds this program element acceptable.

UFSAR Supplement. In LRA Section A2.14, the applicant provided the UFSAR supplement for 

the External Surfaces Monitoring Program. The staff reviewed the supplement and verified that, 

in LRA Commitment No. 11 of the License Renewal Commitments in a letter dated April 13,

2009, the applicant committed to implementing this program and its enhancements prior to the 

period of extended operation as described in LRA Section B2.1.14. The staff finds the UFSAR

supplement for this AMP acceptable because it is consistent with the corresponding description 

in SRP-LR Table 3.3-2 and because the summary description includes the bases for 

determining that aging effects will be managed, as committed to in LRA Commitment No. 11.

The staff determines that the information in the UFSAR 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 that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancements and confirmed that their implementation through Commitment No. 11 prior to the 

period of extended operation would make the existing AMP consistent with the GALL AMP to 

which it was compared. The staff concludes that the applicant has demonstrated that effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff 

also reviewed the UFSAR 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 Fire Protection Program

Summary of Technical Information in the Application. LRA Section B2.1.15 describes the Fire 

Protection Program as an existing program that is consistent with an exception and 

enhancements with GALL AMP XI.M26, “Fire Protection.” The applicant stated that the Fire 

Protection Program is a condition monitoring program that consists of fire barrier inspection 

activities, diesel-driven fire pump inspection activities and halon/carbon dioxide (CO2) fire 

suppression system inspection activities. The applicant also stated that Fire Protection Program 

activities include inspection activities include (1) periodic visual inspection of fire barrier 

penetration seals, fire barrier walls, ceilings, and floors, and periodic inspection and functional 

testing of all fire-rated doors that perform a fire barrier function to ensure that their operability 

and intended functions are maintained; (2) periodic diesel-driven fire pump performance testing 

to ensure that the fuel supply line can perform its intended function; and (3) periodic inspection 

and functional testing of the halon/CO2 fire suppression system to manage the aging effects and 

degradation that may affect the intended function and performance of the system.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff’s summary of its on-site review of AMP B2.1.15, Fire Protection 

Program, is documented in staff’s Audit Summary Report Section for this AMP.

The staff reviewed the exception and enhancements to determine whether the AMP, with the 

exception and enhancements, is adequate to manage the aging effects for which the LRA 

credits it. In comparing the elements in the applicant’s program to those in GALL AMP XI.M26, 

the staff noted that the program elements in the applicant’s AMP claimed to be consistent with 

GALL were consistent with the corresponding program element criteria recommended in the 

program elements of GALL AMP XI.M26, with the exception of two program element aspects.

These program element aspects are identified below and the staff determined there was a need 

for additional clarification. The staff also confirmed that the plant program contains all of the 

elements of the referenced GALL program. On-site interviews were also held to confirm these 

results.

The Fire Protection Program basis document states that the diesel-driven fire pump inspection 

activities require that the pump be periodically performance tested. PINGP credits the Fire 

Protection Program to manage cracking in the fuel oil lines. The staff issued RAI B2.1.15-1 by 

letter dated November 5, 2008, requesting the applicant to explain how the periodic 

performance test will manage the aging effect of cracking in the fuel oil lines.

In its letter dated December 5, 2008, in response to RAI B2.1.15-1, the applicant stated that as 

recommended in GALL AMP XI.M26, "Fire Protection," program element 4, periodic 

performance tests of the diesel-driven fire pump are conducted to ensure fuel supply line 

performance. The applicant also stated that the fuel oil supply line intended function is 

confirmed by starting and running the diesel-driven fire pump for 30 minutes every week and 

that the periodic pump performance test provides an indirect means of verifying the absence of 

fuel line cracking by confirming satisfactory pump performance. 

The staff finds the applicant response acceptable because the diesel-driven fire pump is under 

observation during the performance tests such as flow and discharge tests, and sequential 
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starting capability tests and any age-related degradation such as leakages will be documented 

and evaluated. The staff finds this response consistent with GALL AMP XI.M26 

recommendations that the pump be periodically performance tested to ensure that the fuel 

supply line can perform its intended function. Thus, RAI B2.1.15-1 is resolved.

The GALL AMP XI.M26's “acceptance criteria” program element recommends that no corrosion 

is acceptable in the fuel supply line for the diesel-driven fire pump. Acceptance criteria element 

under Section 5.6 of the program basis document states that the diesel-driven fire pump is flow 

tested to ensure there is no indication of internal fuel supply line corrosion. The staff issued RAI 

B2.1.15-2 by letter dated November 5, 2008, requesting the applicant to explain how the flow 

test will ensure there is no corrosion.

The staff finds the applicant response acceptable because the diesel-driven fire pump is under 

observation during the performance tests such as flow and discharge tests, and sequential 

starting capability tests and any age-related degradation such as corrosion would impact flow, 

and will be documented and evaluated. The staff finds this response consistent with GALL AMP 

XI.M26 recommendations that the pump be periodically performance tested to ensure that the 

fuel supply line can perform its intended function. Thus, RAI B2.1.15-2 is resolved.

Exception. The applicant has taken an exception to the “parameters monitored/inspected” 

program element stating that:

The Relay/Cable Spreading Room and Computer Room CO2 System is 

functionally tested and visually inspected every 18 months instead of every six 

months as recommended in NUREG-1801, XI.M26. The surveillance interval is 

specified in the NRC-approved fire protection program, which is an element of 

the plant's licensing basis, and is historically traceable to the plant Technical 

Specifications. Functional testing and visual inspections performed every 18 

months are sufficient to identify material conditions that may affect the 

performance of the system.

The halon system smoke detectors in the computer room and the Old 

Administration Building vault are functionally tested every 3 and 5 years 

respectively, instead of every six months as recommended in NUREG-1801, 

XI.M26. Functional testing the smoke detectors in the computer room and vault 

every 3 and 5 years respectively, will be sufficient to identify degradation that 

may affect the performance of the systems.

The applicant stated that the frequencies of Relay/Cable Spreading Room and Computer Room 

CO2 System are based on the CLB at PINGP. The staff reviewed the applicant’s program basis 

document and determined that the applicant’s current licensing bases are captured in Document 

F5, Appendix K, Fire Protection System Operability Requirements. The staff noted that 

Document F5, Appendix K, Section 8.7.2 states that the system is verified operable by 

performing a system functional test every 18 months, and Section 8.7.1 states that CO2 storage 

tank level and pressure are verified every week. The staff also reviewed the applicant’s OE

report and did not find any age-related degradation in the halon and CO2 systems. On the basis 

of its review and that the applicant is (1) performing functional tests in accordance with its CLB, 

which would identify if the smoke detectors are performing their intended function, (2) 
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performing weekly visual inspection of CO2 system storage tank level and pressure check, 

which would identify any age-related degradation, and (3) based on the plant-specific OE that 

did not find any age-related degradation in the halon system, the staff finds that these inspection 

and testing frequencies are adequate to ensure the Relay/Cable Spreading Room and 

Computer Room CO2 system maintains its function. Therefore, the staff finds the exception 

acceptable. 

In the case of the halon system smoke detectors, the staff issued RAI B2.1.15-3 by letter dated 

November 5, 2008, requesting the applicant to provide a basis for using a different frequency 

than the GALL Report recommended frequency of testing once every six months. 

In its letter dated December 5, 2008, in response to RAI B2.1.15-3, the applicant stated that:

The three halon fire suppression systems at PINGP afford protection to the 

service building computer room, guardhouse, and the old administration building 

records vault. As defined in the PINGP fire hazards analysis, a fire in these plant 

areas would have no effect on the safe shutdown capability of the plant. In the 

case of a service building computer room fire, an old administration building 

records vault fire, or a guardhouse fire, all Unit 1 and Unit 2 safe shutdown 

functions would remain available from the Control Room. Additionally, no process 

monitoring instrumentation in the Control Room would be affected by fires in 

these areas. As described in PINGP UFSAR Section 10.3.1.3.1, the performance 

description and operability requirements of the fire detection and fire protection 

systems are described in and governed by the PINGP Operations Manual. There 

are no specific operability or surveillance requirements defined for the three 

halon suppression systems in the Operations Manual.

The three halon fire suppression systems are visually inspected every six months 

to ensure adequate halon availability by verifying the level of each halon cylinder. 

In addition, the smoke detectors in the service building computer room are 

functionally tested every three years. The smoke detectors in the guardhouse 

and the old administration building records vault are functionally tested every five 

years. The enhancement in the PINGP LRA, Appendix B2.1.15, that states that 

the Fire Protection Program will be enhanced to require functional testing of the 

halon system smoke detectors in the guardhouse every 5 years, is in error. 

PINGP has determined that the halon system smoke detectors in the guardhouse 

are already being functionally tested every 5 years, and this enhancement is 

unnecessary. 

The applicant also determined that the exception discussed in LRA Section B2.1.15 related to 

halon testing required revision. Accordingly, the applicant revised the exception.

In LRA Section B2.1.15 on Page B-39, under Exceptions to the GALL Report, the second 

paragraph under Parameters Monitored/Inspected is revised in its entirety to read as 

follows: 

The halon system smoke detectors in the service building computer room are 

functionally tested every 3 years and those in the old administration building 
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records vault and guardhouse are functionally tested every 5 years, instead of 

every six months as recommended in NUREG-1801, XI.M26. Functional testing 

of the smoke detectors in the computer room every 3 years and those in the vault 

and guardhouse every 5 years will be sufficient to identify degradation that may 

affect the performance of the systems.

The applicant further stated that:

A review of PINGP OE identified no adverse trends or issues with the halon 

smoke detectors. The halon smoke detector functional testing frequencies of 

three and five years in lieu of every six months as recommended by NUREG1801, is based on the maintenance history for each of the three systems. 

Agreement on these functional testing frequencies has been reached with the 

PINGP insurance underwriter, Nuclear Electric Insurance Limited (NEIL).

Functional testing of the halon smoke detectors in the service building computer 

room every three years, and testing of those in the guardhouse and the old 

administration building records vault every five years, will be sufficient to identify 

degradation that may affect the performance of the systems. The halon systems 

will also be inspected periodically at a frequency of at least once per refueling 

cycle by the External Surfaces Monitoring Program for corrosion and mechanical 

damage.

The staff reviewed the applicant's response and noted that the halon smoke detectors are 

located in areas where a fire would not have any effect on the safe shutdown capability of the 

plant. The staff reviewed the applicant’s program basis document and determined that the 

applicant’s current licensing bases are captured in Document F5, Appendix K, Fire Protection 

System Operability Requirements. The staff reviewed the Fire Protection System Operability 

Requirements and noted that there are no specific operability or surveillance requirements 

defined for the three halon suppression systems in the Operations Manual. The staff verified 

that three halon suppression systems are inspected every six months, which is in accordance 

with GALL AMP XI.M-26 recommendations. 

The staff reviewed the plant's OE and noted that there was no age-related degradation 

identified for the halon and carbon dioxide systems. The staff also reviewed the revision to the 

second paragraph of the exception and finds that it provides more clarity to the different 

frequencies used for the three smoke detectors. 

On the basis that the applicant is performing visual inspections once every six months 

consistent with GALL AMP XI.M26 recommendation, periodic external surface inspections every 

refueling cycle and based on the plant OE that did not identify any age-related degradation, the 

staff finds that the three-year and five-year testing intervals are adequate to ensure the system 

maintains its function and finds the exception acceptable.

Enhancement 1. In LRA Section B2.1.15, the applicant included an enhancement in the 

“parameters monitored/inspected” program element to require functional testing of the halon 

system smoke detectors in the guardhouse every five years.
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However, in its response to RAI B2.1.15-3, the applicant stated that halon system smoke 

detectors in the guardhouse are already being functionally tested every five years, and this 

enhancement is unnecessary. The applicant revised the LRA and deleted the enhancement. 

The applicant also revised the Commitment List to delete this enhancement from Commitment 

No. 12.

On the basis that the applicant is already performing functional tests of halon smoke detectors 

in the guardhouse every five years, the staff finds the enhancement is not necessary and 

therefore finds the deletion of the enhancement to be acceptable.

Enhancement 2. In LRA Section B2.1.15, the applicant included an enhancement in the 

“detection of aging effects” program element to require periodic visual inspection of the fire 

barrier walls, ceilings, and floors to be performed during walkdowns at least once every 

refueling cycle.

The staff verified that the applicant has included Commitment No. 12 in the commitment list to 

enhance the program to require periodic visual inspection of the fire barrier walls, ceilings, and 

floors to be performed during walkdowns at least once every refueling cycle. This enhancement, 

when implemented, will make the Fire Protection Program consistent with the GALL AMP 

XI.M26, which recommends that visual inspection of fire barriers once every refueling cycle 

ensures timely detection of aging effects. Based on this review, the staff finds the enhancement 

acceptable.

Based on its review of the exception and enhancements, and resolution of the RAI as described 

above, the staff finds the Fire Protection Program consistent with program elements of GALL 

AMP XI.M26, with acceptable exception, and therefore acceptable.

Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.15 and 

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 also confirmed that 

applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 

and are evaluated in the GALL Report. 

The staff also reviewed the applicant’s “operating experience” discussion that was provided in 

the applicant’s license renewal basis document for the Fire Protection Program. The staff 

reviewed a sample of CRs and confirmed that the applicant had identified age-related

degradation in penetration seals, and in the diesel-driven fire pump strainer. The applicant 

repaired the penetration seals and determined that the strainer failure was due to an active 

failure of the strainer motor isolation, which required replacement of the overload heaters and to 

reset them. 

In LRA Section B2.1.15, the applicant stated that a review of OE for the Fire Protection Program 

identified no adverse trends or issues with program performance. The applicant identified a fire 

door closure issue that was determined to be a generic issue. The applicant stated that 

modifications were made to fire doors to prevent the recurrence of the doors not closing 

properly due to inadequate clearances or improper adjustments.
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Furthermore, the staff confirmed that the applicant has addressed OE identified after the 

issuance of the GALL Report. The staff finds that the applicant’s Fire Protection program, with 

the corrective actions discussed in the LRA, has been effective in identifying, monitoring, and 

correcting the effects of age-related degradation in fire protection system components and 

structures.

The staff confirmed that the OE 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 element acceptable. 

UFSAR Supplement. In LRA Section A2.15, the applicant provided the UFSAR supplement for 

the Fire Protection program. The staff verified that the UFSAR supplement summary description 

for the Fire Protection Program was in conformance with the staff’s recommended UFSAR

supplement for these types of programs provided in Table 3.4-2 of the SRP-LR. 

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant has included in the final License Renewal Commitment List, 

Commitment No. 12, the program enhancement identified in the LRA for the applicant’s Fire 

Protection Program.

Based on this review, the staff determines that UFSAR supplement Section A2.15 provides an 

acceptable UFSAR supplement summary description of the applicant’s Fire Protection program 

because it is consistent with those UFSAR supplement summary description in the SRP-LR for 

the Fire Protection Program.

The staff determines that the information in the UFSAR 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 and 

the applicant’s response to the staff’s RAI, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff also reviewed the enhancement and confirmed that 

its implementation through Commitment No. 12 prior to the period of extended operation will 

make the existing AMP consistent with the GALL AMP to which it was compared. 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 

concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR 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 Fire Water System 

Summary of Technical Information in the Application. LRA Section B2.1.16 describes the Fire 

Water System Program as an existing program that is consistent with enhancements with GALL 

AMP XI.M27, “Fire Water System.” The applicant stated that this program manages loss of 

material due to corrosion, MIC and fouling of the water-based fire protection system and

associated components by periodic flushing, flow testing and wall thickness evaluations. The 

applicant further stated that inspection and testing are performed in accordance with applicable 
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National Fire Protection Association (NFPA) codes and standards, and NRC commitments. The 

applicant also stated that internal portions of the fire water system are visually inspected when 

disassembled for maintenance.

Staff Evaluation. During its audit the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff’s summary of its on-site review of AMP B2.1.16, Fire Water System 

Program, is documented in staff’s Audit Summary Report Section for this AMP. 

The staff reviewed the enhancements to determine whether the AMP, with the enhancements, 

is adequate to manage the aging effects for which the LRA credits it. In comparing the elements 

in the applicant’s program to those in GALL AMP XI.M27, the staff noted that the program 

elements in the applicant’s AMP claimed to be consistent with the GALL Report were consistent 

with the corresponding program element criteria recommended in the program elements of 

GALL AMP XI.M27. The staff also confirmed that the plant program contains all of the elements 

of the referenced GALL AMP. On-site interviews were also held to confirm these results.

Enhancement 1. In LRA Section B2.1.16, the applicant included an enhancement in the 

“detection of aging effects” program element to include eight additional yard fire hydrants in the 

scope of the annual visual inspection and flushing activities.

The staff reviewed the applicant’s program basis document and determined that these eight 

additional fire hydrants are identified as additions to the program. The staff verified that the 

applicant has included Commitment No. 13 in the commitment list to enhance the program to 

include these eight additional yard fire hydrants in the scope of the annual visual inspection and 

flushing activities. This enhancement, when implemented, will make the Fire Water System 

Program consistent with the GALL AMP XI.M27, “detection of aging effects” program element, 

which recommends visual inspections of yard fire hydrants be performed annually to ensure 

timely detection of signs of degradation, such as corrosion. Based on this review, the staff finds 

the enhancement acceptable. 

Enhancement 2. In LRA Section B2.1.16, the applicant included an enhancement in the 

“detection of aging effects” program element to replace sprinkler heads that have been in place 

for 50 years or a representative sample of sprinkler heads will be tested using the guidance of 

NFPA 25, “Inspection, Testing and Maintenance of Water-Based Fire Protection Systems” 

(2002 Edition, Section 5.3.1.1.1). The applicant further stated that sample testing, if performed, 

will continue at a 10-year interval following the initial testing.

The staff verified that the applicant has included Commitment No. 13 in the Commitment list to 

enhance the program to require that sprinkler heads that have been in place for 50 years be 

replaced or a representative sample be tested. This enhancement, when implemented, will 

make the Fire Water System Program consistent with the GALL AMP XI.M27, which 

recommends testing or replacement of sprinkler heads in service for 50 years. Based on this 

review, the staff finds the enhancement acceptable. 

Based on its review of the enhancements as described above, the staff finds the Fire Water 

System Program consistent with program elements of GALL AMP XI.M27, and therefore 

acceptable.
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Operating Experience. The staff reviewed the OE provided in LRA Section B2.1.16 and 

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 also confirmed that 

applicable aging effects and industry and plant-specific OE have been reviewed by the applicant 

and are evaluated in the GALL Report. Furthermore, the staff confirmed that the applicant has 

addressed OE identified after the issuance of the GALL Report. 

The staff also reviewed the OE provided in the program basis document. During performance of 

a surveillance test on fire hydrants, the applicant found a fire hydrant leaking from a corroded 

barrel. The applicant replaced the fire hydrants. During performance of wall thickness 

measurements on the fire water header, the applicant found a section of pipe below minimum 

wall thickness. The applicant determined the cause to be loss of material due to MIC in a 

stagnant portion of the pipe. The applicant performed wall thickness measurements in other fire 

water headers in stagnant portions of pipe and did not find other areas of similar degradation 

and determined it was not a generic issue. The applicant replaced the degraded section of pipe 

with like material. 

Furthermore, the staff confirmed that the applicant has addressed OE identified after the 

issuance of the GALL Report. The staff finds that the applicant’s Fire Water System Program, 

with the corrective actions discussed in the LRA and the program basis document, has been 

effective in identifying, monitoring, and correcting the effects of age-related degradation in fire 

water system components and structures.

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.16, the applicant provided the UFSAR supplement for 

the Fire Water System Program. The staff verified that the UFSAR supplement summary 

description for the Fire Water System Program was in conformance with the staff’s 

recommended UFSAR supplement for the Fire Water System program provided in Table 3.3-2 

of the SRP-LR.

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant has included in the final license renewal commitment list, 

Commitment No. 13, the program enhancements identified in the LRA for the applicant’s Fire 

Water System Program.

Based on this review, the staff finds that UFSAR supplement Section A.2.16 provides an 

acceptable UFSAR supplement summary description of the applicant’s Fire Water System 

Program because it is consistent with those UFSAR supplement summary description in the 

SRP-LR for the Fire Water System Program. 

The staff determines that the information in the UFSAR 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 Fire Water System Program, the staff 

finds those program elements for which the applicant claimed consistency with the GALL Report 

are consistent. In addition, the staff reviewed the enhancements and confirmed that their 
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implementation through Commitment No. 13 prior to the period of extended operation will make 

the existing AMP consistent with the GALL AMP to which it was compared. The staff concludes 

that the applicant has demonstrated that the effects of aging 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 UFSAR

supplement, for this AMP and concludes that it provides an adequate summary description of 

the program, as required by 10 CFR 54.21(d).

3.0.3.2.8 Flux Thimble Tube Inspection 

Summary of Technical Information in the Application. LRA Section B2.1.18 describes the 

applicant’s existing Flux Thimble Tube Inspection Program as consistent, with enhancements, 

with GALL AMP XI.M37, “Flux Thimble Tube Inspection.” The applicant stated that the Flux 

Thimble Tube Inspection Program is a condition monitoring program that manages loss of 

material due to wear for in-core instrument thimble tubes. The program requires periodic ECT of 

thimble tubes for thinning of the flux thimble tube wall due to flow-induced fretting and provides 

for evaluation and trending of inspection results and implementation of corrective actions. The 

applicant also stated that this program implements the commitments made in the applicant’s 

response to NRC Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors.”

Staff Evaluation. During the audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the applicant’s existing program and the 

proposed enhancements to determine whether the AMP, with the enhancements, is adequate to 

manage the aging effects for which the LRA credits it.

The staff reviewed the applicant’s program basis document, on-site procedures, corrective 

action reports, and other plant documents that were included in the applicant’s license renewal 

program basis document binder for the Flux Thimble Tube Inspection Program and that 

contained relevant information supporting the applicant’s evaluation of this AMP.

The staff noted that the applicant’s Flux Thimble Tube Inspection Program manages the aging 

effect of loss of material due to wear for in-core instrument thimble tubes. The flux thimble tubes 

provide a travel path for insertion of the incore neutron flux monitoring system detectors and 

form part of the reactor coolant pressure boundary. As discussed in NRC Information Notice 87-

44, Supplement 1, “Thimble Tube Thinning in Westinghouse Reactors,” dated March 28, 1988, 

flux thimble tubes have experienced loss of material (wall thinning) due to wear caused by flowinduced vibrations, and flux thimble tube wear has generally been detected at locations 

associated with geometric discontinuities or areas of change along the flux thimble tube’s axial 

length, such as areas near the lower core plate, the core support forging, the lower tie plate, the 

upper tie plate, and the vessel penetration. 

The staff also noted that the applicant’s Flux Thimble Tube Inspection Program conducts 

inspections to monitor for wall thinning of the flux thimble tubes and that the program includes 

provisions for repositioning or capping flux thimble tubes that do not meet acceptable criteria to 

ensure that the integrity of the reactor coolant pressure boundary is maintained. The staff noted 

that when wear becomes excessive, corrective actions are taken to axially reposition the flux 

thimble tube so that the worn area is moved away from the geometric discontinuity if wall 

thickness remains acceptable, to remove the flux thimble tube from service and cap the tube so 
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as to prevent degradation of the reactor coolant pressure boundary, or to replace the flux 

thimble tube. The staff finds these features of the applicant’s Flux Thimble Tube Inspection 

Program to be acceptable because they are consistent with recommendations for “correction 

actions” in GALL AMP XI.M37, Flux-Thimble Tube Inspection.

The staff further noted that the applicant’s Flux Thimble Tube Inspection Program encompasses 

all of the flux thimble tubes that form part of the reactor coolant system pressure boundary. The 

staff also noted that the applicant’s program calls for the applicant to inspect all flux thimble 

tubes that are currently inservice (non-capped) using ECT methodology at each refueling 

outage in order to detect any wall thinning in the flux thimble tubes, and to establish a thimble 

tube wear projection based on a comparison of the newly recorded wall thickness data with that 

obtained from prior examinations of the thimble tubes. The staff also noted that any significant 

changes in the percentage of tube wall loss are compared against acceptance criteria, and 

affected flux thimble tubes are evaluated for repositioning, capping or replacement. The staff 

noted that flux thimble tubes that do not meet the acceptance criteria are repositioned, capped 

or replaced to ensure that the integrity of the reactor coolant pressure boundary is maintained. 

The staff finds these features of the applicant’s Flux Thimble Tube Inspection Program to be 

consistent with “detection of aging effects,” “monitoring and trending,” and “corrective actions” 

program element recommendations in the GALL AMP XI.M37.

In a letter dated November 5, 2008, the staff issued RAI AMP-B2.1.18-1 asking the applicant to 

provide additional information with regard to its “acceptance criteria” program element, stating 

current acceptance criteria values and basis, and clarifying whether wear rate projections are 

based on plant-specific or generic wear data.

The applicant responded to the RAI in a letter dated December 5, 2008. In its response the 

applicant stated that any flux thimble tube measuring greater than or equal to 80 percent 

through wall loss is required to be capped, and any flux thimble tube measuring greater than or 

equal to 60 percent through wall loss is repositioned, or capped if the trend is approaching the 

capping criteria. The applicant stated that the values of 80 percent for capping and 60 percent 

for repositioning are conservative relative to values documented in Proprietary WCAP-12866, 

“Bottom Mounted Instrumentation Flux Thimble Tube Wear,” which documented that flux 

thimble tubes retain functional and structural integrity up to 85 percent wall loss. The applicant 

also stated that all flux thimble tubes are inspected at every refueling outage and that this 

inspection frequency has been in place since 1987. The applicant further stated that unitspecific wear rate data is used for flux thimble tube wear projections.

The staff noted that the applicant’s acceptance criteria of 80 percent through wall loss for 

capping and 60 percent through wall loss for repositioning of flux thimble tubes includes 

allowances for factors such as instrument uncertainty, uncertainties in wear scar geometry and 

other potential uncertainties as recommended in GALL AMP XI.M37. The staff finds these 

acceptance criteria to be acceptable because they have been established based on actual 

thimble tube burst test data that has been compiled by the industry and referenced in 

Proprietary WCAP-12866 and because the applicant’s 80 percent acceptable wall loss 

acceptance criterion account for eddy current instrument uncertainty is consistent with the 

“acceptance criteria” program element in GALL AMP XI.M37. The staff also finds that the 

applicant’s uses of unit-specific wear rate projection is consistent with recommendations of the 
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GALL Report. On this basis, the staff finds the applicant’s response resolved all issues in RAI 

AMP-B2.1.18-1 and are acceptable.

The staff compared program elements in the applicant’s program to those in GALL AMP XI.M37 

and found that the program elements in the AMP that the applicant claims to be consistent with 

the GALL Report are consistent with the corresponding program element criteria recommended 

in GALL AMP XI.M37. Except for the enhancements described in the LRA by the applicant and 

discussed below, the staff did not identify any differences between recommendations in the 

GALL Report and the applicant’s consistency claims.

Enhancement 1. LRA Section B2.1.18 states an enhancement to the “monitoring and trending” 

program element. The applicant stated that the program will be enhanced to require that the 

interval between inspections be established such that no flux thimble tube is predicted to incur 

wear that exceeds the established acceptance criteria before the next inspection.

During the on-site audit of this program, the staff noted that the applicant’s current process 

already requires flux thimble tube inspections such that no flux thimble tube is predicted to 

exceed criteria before the next inspection. Subsequently the staff asked the applicant to clarify 

the intention of Enhancement 1. In its clarification, the applicant stated that the enhancement is 

a procedure change to formally incorporate existing practices into appropriate implementing 

procedures. The staff confirmed that the applicant has incorporated this enhancement of the 

program in LRA Commitment No. 14, which was placed on the UFSAR Supplement in the 

applicant’s letter of April 13, 2009.

The staff finds Enhancement 1 to be acceptable because it formally incorporates existing 

practices into appropriate required implementing procedures that are consistent with 

recommendations in the GALL Report.

Enhancement 2. LRA Section B2.1.18 states a second enhancement to the “monitoring and 

trending” program element. The applicant stated that the program will require that re-baselining 

of the examination frequency be justified using plant-specific wear rate data unless prior plantspecific NRC acceptance for the re-baselining was received. If design changes are made to use 

more wear-resistant thimble tube materials, sufficient inspections will be conducted at an 

adequate inspection frequency for the new materials.

During the on-site audit of this program, the staff noted that the applicant’s current process 

already requires baselining of the flux thimble tube examination frequency based on plantspecific data and that flux thimble tube wear rates and wear rate predictions are updated at 

each outage based on newly acquired plant-specific data. Subsequently the staff asked the 

applicant to clarify the intention of Enhancement 2. In its clarification, the applicant stated that 

the enhancement is a procedure change to formally incorporate existing practices into 

appropriate implementing procedures. The staff confirmed that the applicant has incorporated 

this enhancement of the program in LRA Commitment No. 14 that was placed on the UFSAR

Supplement in the applicant’s letter of April 13, 2009.

The staff finds Enhancement 2 to be acceptable because it formally incorporates existing 

practices into appropriate required implementing procedures that are consistent with 

recommendations in the GALL Report.
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Enhancement 3. LRA Section B2.1.18 states an enhancement to the “corrective actions” 

program element. The applicant stated that the program will require that flux thimble tubes that 

cannot be inspected must be removed from service.

During the on-site audit, the staff asked the applicant whether there currently are any flux 

thimble tubes that cannot be inspected and whether those flux thimble tubes currently are 

capped and removed from service. The applicant responded that they have been unable to 

perform inspection of one thimble tube in Unit 2 using its current ECT methodology and that 

thimble tube has been capped and removed from service.

Subsequently the staff asked the applicant to clarify the intention of Enhancement 3. In its 

clarification, the applicant stated that the enhancement is a procedure change to formally 

incorporate existing practices into appropriate implementing procedures.

Based on the applicant’s response and current treatment of flux thimble tubes that cannot be 

inspected, the staff finds Enhancement 3 to be acceptable, because it formally incorporates 

existing practices into appropriate required implementing procedures that are consistent with 

recommendations in the GALL Report.

The staff finds the applicant’s Enhancements 1, 2, and 3 to be acceptable because the 

enhancements formally incorporate existing practices into appropriate required procedures that 

are consistent with the program element recommendations in GALL AMP XI.M37, “Flux Thimble 

Tube Inspection,” and because the applicant has incorporated these commitments into 

Commitment No. 14 of the UFSAR Supplement for the LRA, which was submitted in the 

applicant’s letter of April 13. 2009. The staff finds that the applicant’s Flux Thimble Tube 

Inspection Program, when enhanced, is consistent with GALL AMP XI.M37 and is therefore 

acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.18. The 

applicant stated that a review of OE for the Flux Thimble Tube Inspection Program identified no 

adverse trends or issues with program performance. The applicant stated that no thimble tubes 

have had a through wall leak and that one thimble tube in Unit 2 currently is capped. The 

applicant also stated that in 2002 a thimble tube in Unit 1 exhibited a significant increase in new 

wear and was capped to reduce the risk of leaking; however, the wear rate later stabilized, and 

the thimble tube was subsequently uncapped. The applicant further stated that thimble tubes 

have been replaced in both Unit 1 and Unit 2 because of difficulty in the movement of the incore 

neutron detectors, but that the replacements were not due to age-related wear.

The staff reviewed the OE discussion that was provided in the applicant’s license renewal 

program basis document binder for the Flux Thimble Tube Inspection Program. The staff 

confirmed that the applicant’s review of OE included evaluation of both industry and plantspecific events that have occurred since issuance of the GALL Report, Revision 1. The staff 

reviewed completed inspection procedures and selected corrective action reports related to the 

applicant’s Flux Thimble Tube Inspection Program and interviewed the applicant’s technical 

staff to confirm that the plant-specific OE did not reveal any degradation not bounded by 

industry experience.
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Based on this review, the staff finds (1) that the OE for this AMP demonstrates that the 

applicant’s Flux Thimble Tube Inspection Program is achieving its objective of monitoring for 

thinning of the flux thimble tube wall using ECT methodology consistent with the 

recommendations in NRC Bulletin 88-09, and (2) that the applicant is taking appropriate 

corrective actions through implementation of this 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 

element acceptable.

UFSAR Supplement. In LRA Section A2.18 the applicant provided the UFSAR supplement for 

the Flux Thimble Tube Inspection Program. The staff verified that the UFSAR supplement 

summary for the Flux Thimble Tube Inspection Program conforms to the staff’s recommended 

UFSAR supplement for this type of program as described in the SRP-LR.

In its letter dated April 13, 2009, the applicant provided a list of License Renewal Commitments. 

The staff verified that the applicant has included the program enhancements for the Flux 

Thimble Tube Inspection Program in Commitment No. 14 of this letter.

Based on this review, the staff finds that the UFSAR supplement summary in LRA Section 

A2.18 provides an acceptable description of the applicant’s Flux Thimble Tube Inspection 

Program because it is consistent with the UFSAR supplement summary description in the SRPLR for the Flux Thimble Tube Inspection Program and because the enhancements for this AMP 

have appropriately been placed onto the UFSAR Supplement for the application.

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s Flux Thimble Tube Inspection 

Program and the applicant’s response to RAI AMP-B2.18-1, the staff finds that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent. In 

addition, the staff reviewed the enhancements and confirms that their implementation through 

Commitment No. 14, prior to the period of extended operation, makes the existing AMP 

consistent with the GALL AMP to which it was compared. The staff concludes that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.2.9 Fuel Oil Chemistry 

Summary of Technical Information in the Application. LRA Section B2.1.19 describes the 

applicant’s existing Fuel Oil Chemistry Program as consistent, with exceptions and 

enhancements. The Fuel Oil Chemistry Program manages the aging effects of loss of material 

and cracking on internal surfaces of the diesel fuel oil system piping, piping components and 

tanks by minimizing the potential for a corrosive environment, and by verifying that the actions 

taken to mitigate corrosion are effective. The program includes testing to detect unacceptable 
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level of water, sediment and particulate contamination inspection of fuel oil tanks, and one-time 

ultrasonic inspections of selected tank bottom and piping locations.

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the exceptions and enhancements to 

determine whether the AMP, with the exceptions and enhancements, is adequate to manage 

the aging effects for which the LRA credits it.

LRA Section B2.1.19 provides the program description, statement of consistency with the GALL 

Report, OE, and the conclusion that the PINGP Fuel Oil Chemistry AMP after implementation of 

enhancements will provide reasonable assurance that loss of material will be adequately 

managed through the period of extended operation. The applicant stated that the Fuel Oil 

Chemistry Program is consistent with the 10 elements of GALL AMP XI.M30, “Fuel Oil 

Chemistry," after implementing two program enhancements, with two exceptions.

LRA Section B2.1.19, "Fuel Oil Chemistry Program," identifies two exceptions to the program 

elements in GALL AMP XI.M30, “Fuel Oil Chemistry.” The acceptability of these exceptions is 

evaluated as follows.

Exception 1. In Exception No. 1, the applicant took an exception to the recommendation in the 

“preventive actions” program element in GALL AMP XI.M30 to perform periodic sampling, 

draining, and cleaning of diesel fuel oil tanks and to add corrosion inhibitors and/or biocide 

agents to the diesel fuel oil inventories. The applicant stated in LRA B2.1.19 that preventive 

actions such as periodic fuel oil sampling, and draining and cleaning of all fuel oil tanks are not 

performed, and additives are not added to fuel oil.

The staff noted that there are, in fact, three exceptions to GALL AMP XI.30 "monitoring and 

trending" and “preventive actions” element as follows:

(1) Periodic fuel oil sampling of specific fuel oil tanks (day tanks and leakage 

collection tanks) will not be performed. The staff noted that the applicant relies on 

the high turnover of fuel in these tanks to preclude the need for periodic sampling 

because the tanks that supply fuel oil to these tanks, are sampled on a periodic 

basis. However, MIC could be active in these tanks because the source of the oil 

is not monitored for biological activity. The staff noted that the applicant relies on 

OE of the supply tanks, where no general, pitting and crevice corrosion and MIC 

has not been observed, to justify not sampling all fuel oil tanks. The staff does 

not consider OE alone justification for not sampling the oil of these tanks 

particularly because these tanks will not receive visual inspection or UT 

examination of tank bottoms. Additional actions and/or evaluations are necessary 

to justify not sampling the oil of these tanks. 

(2) GALL AMP XI.M30 recommends, in the “detection of aging effects” element, 

periodic cleaning and visual examination of fuel oil tanks. GALL AMP XI.M30 

also recommends ultrasonic thickness measurement for locations where 

contaminants can accumulate such as tank bottoms in the “detection of aging” 

element to ensure significant degradation is not occurring. In its review of LRA 

B2.1.19 and the associated basis document, the staff noted that the applicant’s 
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basis document did not clearly identify whether a particular diesel fuel oil tank 

would be subjected to UT of its tank bottom if the tank was not subject to a 

cleaning and a visual examination of the exposed, cleaned tank surfaces. The 

staff also noted that the basis document did not clearly identify what extent of UT 

examination would be in regard to the grid size for the examinations. By letter 

dated December 5, 2008, the staff issued RAI B2.1.19-3 asking the applicant to 

provide the results of all diesel fuel tank cleaning and inspection, to identify which 

fuel tanks will be subjected to ultrasonic testing (UT) of the tank bottom and the 

extent of UT of tank bottoms, and provide a list of specific fuel tanks (if any) that 

will not be subjected to periodic cleaning and visual inspection or UT. In addition, 

the staff asked the applicant to provide a justification for not verifying that loss of 

material is occurring in fuel tanks that are not subjected to cleaning and visual 

inspection or UT.

(3) By letter dated December 18, 2008, the applicant responded to RAI B2.1.19-3 

stating that PINGP fuel oil tanks have been subjected to cleaning and visual 

inspection on tank interiors and UT examination of tank bottoms with no 

corrosion identified. The applicant further stated that as a part of the One-Time 

Inspection Program, prior to the period of extended operation, one vaulted fuel oil 

storage tank bottom for the Unit 2 emergency diesel generators will be subjected 

to external UT. The staff noted that these tanks have not been subjected to 

internal cleaning and visual inspection. The applicant stated that one of the Unit 

1 emergency diesel generator underground storage tanks and the diesel-driven 

cooling water pump fuel storage tank will be subject to cleaning, interior visual 

inspection, and internal UT of the tank bottoms. The applicant stated that results 

of future inspections will be compared with previous results and any evidence of 

corrosion will be enter into the Corrective Action Program to identify actions 

including additional tank inspections. 

Based on the information supplied by the applicant related to exceptions to the GALL 

AMP XI.M30 and responses to RAIs, the staff finds that not verifying all tank bottom thicknesses 

(i.e. day tanks and leakage collection tanks) unacceptable because these tanks are 1) not 

subject to periodic sampling, 2) not cleaned and subjected to visual examinations and 3) not 

subjected to a UT of the tank bottoms to verify that corrosion induced loss of materials is not 

occurring in the tanks. Absence of an aging effect to date does not justify not performing 

sampling, cleaning and inspection of these tanks for wall thinning. The purity of diesel fuel 

inventories added to the tanks may vary from batch to batch. The staff considered this an issue 

because tanks selected for the one-time inspection at each unit would not necessarily be 

indicative of the fuel oil conditions in the remaining un-inspected fuel oil tanks for the units. 

During a conference call on March 30, 2009 between the staff and the applicant, the staff 

expressed concern that loss of material could be occurring in tanks (i. e. day tanks and leakage 

collection tanks) that do not receive any monitoring, preventive, or confirmatory actions and 

therefore, degradation would not be detected. 

In a letter dated April 6, 2009 the applicant stated that one-time inspections using ultrasonic 

thickness measurements will be performed on selected day tanks and clean fuel oil leakage 

collection tanks prior to the period of extended operation as part of the One-Time Inspection 

Program where specific locations to be selected include: an external UT on select bottom 
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locations on four of the seven diesel fuel oil day tanks, and an external UT on select bottom 

locations of one of the two D1/D2 clean fuel oil leakage collection tanks.

The staff finds that one-time UT inspection of diesel fuel oil day tanks and clean fuel oil leakage 

collection tanks sufficient to detect loss of material of tank bottoms because any wall thinning in 

these tanks would trigger additional actions such as expansion of tank bottom inspections, tank 

repair/replacement, tank cleaning, increased monitoring as determined through the applicant’s 

corrective action program. Therefore, the staff finds that not monitoring fuel oil day tanks and 

fuel oil leakage collection tanks for particulate, sediment and biological activity and not cleaning 

and internally inspecting these tanks acceptable because degradation of tank bottoms resulting 

from contaminated fuel oil will be detected and corrective actions will be implemented.

The staff reviewed the exception that periodic draining and cleaning of specific fuel oil tanks 

(day tanks, and leakage collection tanks) are not performed and will not be performed. The staff 

noted that the applicant relies on the lack of degradation of other fuel oil tanks and fuel oil 

quality trends as justification for not periodically draining and cleaning these tanks. The staff 

does not consider OE alone justification for not draining and cleaning these tanks.

The staff reviewed the exception that biocides and/or corrosion inhibitors will not be added to 

fuel oil. The staff noted that the applicant relies on the lack of degradation and fuel oil quality 

trends as justification for not using biocides and corrosion inhibitors. The staff does not consider 

OE alone justification for not using biocides or corrosion inhibitors particularly for those tanks 

that will not receive periodic cleaning and interior visual inspection or UT examination of tank 

bottoms. Additional actions and/or evaluations are necessary to justify not using biocides 

and/or corrosion inhibitors. 

GALL AMP XI.M30 recommends in the “monitoring and trending” element to monitor and trend 

biological activity at least quarterly. In its review of LRA B2.1.19 and the associated basis 

document, the staff noted that the applicant does not state whether fuel oil is tested for 

biological activity. By letter dated December 5, 2008, the staff issued RAI B2.1.19-2 asking the 

applicant if microbiological activity is monitored in fuel oil and if so, identify the frequency of 

monitoring for microbiological activity. If not, why is lack of monitoring for biological activity not 

identified as an exception to GALL AMP XI.M30?

By letter dated December 18, 2008, the applicant responded to RAI B2.1.19-2 stating that 

PINGP does not monitor fuel oil for biological activity, as recommended by NUREG-1801, 

Program XI.M30, Element 5, Monitoring and Trending because 1) no indications of biological 

activities have been observed such as cloudiness, sludge, or other conditions that would 

indicate significant or any fuel degradation 2) fuel oil quality parameters, including water and 

sediment percentage, are routinely within acceptance limits with no adverse trends, 3) internal 

visual inspections of storage tank surfaces have identified no significant corrosion, and 4)

ultrasonic testing of one tank indicated no wall thinning. 

The applicant stated that the lack of monitoring for biological activity will be identified as an 

exception to GALL AMP XI.M30, Fuel Oil Chemistry and will amend Appendix B2.1.19, Fuel Oil 

Chemistry Program to identify the lack of monitoring fuel oil for biological activity as an 

exception as follows:
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Fuel oil is not periodically monitored for biological activity. Fuel oil quality 

parameters, including water and sediment percentage, are routinely within 

acceptance limits at the various monitored locations and no adverse trends have 

been identified. The internal visual inspections of storage tank surfaces that have 

been completed have identified no significant corrosion, pitting or areas requiring 

repair due to aging effects, and no indications of unacceptable fuel oil chemistry 

control. Plant OE has not identified any problems involving water in the diesel 

fuel oil, particulate contamination, or biological fouling.

The staff noted that water, sediment, and particulate contamination of fuel oil could promote 

biological activity that causes loss of material due to MIC. The staff noted that monitoring and 

maintaining contamination (water and particulate) below acceptable levels in fuel oil systems 

and periodic cleaning of tanks are effective methods to mitigate biological activity because these 

contaminants promote biological activity and that these contaminants are effectively controlled 

through the applicant’s Fuel Oil Chemistry program. The staff does not consider OE alone, such 

as lack of observing corrosion or routine acceptable fuel oil contamination levels, justification for 

not monitoring fuel oil for biological activity particularly for those tanks that will not receive 

periodic cleaning and interior visual inspection or UT examination of tank bottoms. The staff 

noted that additional actions and/or evaluations are necessary to justify not monitoring fuel oil 

for biological activity. In response to a telephone conference on 2/10/09 between the staff and 

the applicant, the applicant stated in a letter dated February 26, 2009, that the Fuel Oil 

Chemistry Program, B2.1.19 uses ASTM D 6217 to assess the mass quantity of particulate 

contamination present in fuel oil by filtration using a conservative filter pore size of 0.8 μm. The 

applicant further stated that biological activity would produce sludge and other by-products of 

metabolism, the test results for water and sediment (reported in volume percent) and particulate 

contamination (reported in mass per volume of fuel filtered) would identify the presence of 

biological activity in the fuel oil because test results would exhibit an increase if biological 

activity were present. The staff confirms that biological activity will be detected using a ASTM D 

6217 using a filter pore size of 0.8 μm and finds that this is an acceptable alternative to direct 

monitoring for biological activity. 

Exception 2. The applicant stated in LRA B2.1.19 that particulate contamination testing of fuel 

oil will be performed annually and not quarterly as recommended in the GALL AMP XI.30 

“monitoring and trending” element, because annual testing is sufficiently frequent to verify that 

particulates are not forming, and the absence of previous particulate contamination during 

routine historical sampling and analysis justifies a relaxed sampling frequency. The staff 

considers that operating history alone is not justification for relaxing sampling frequency. By 

letter dated December 5, 2008, the staff issued RAI B2.1.19-1 asking the applicant to provide 

additional justification for relaxation of sampling frequency. 

By letter dated December 18, 2008, the applicant responded to RAI B2.1.19-1 stating that 

historical sampling and analysis provides OE that shows particulate contamination of fuel has 

not been a problem. However, the staff noted that testing of fuel oil for particulate contamination 

at PINGP has not been performed on a regular sampling frequency and testing of fuel oil for 

particulate contamination is an enhancement to the applicant’s Fuel Oil Chemistry (B2.1.19), 

which has yet to be implemented. As such, the staff noted that sufficient particulate 

contamination data are not available to evaluate a trend of particulate contamination such that 

sampling frequency could be reduced. During a conference call on March 30, 2009 between the 
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staff and the applicant, the staff requested further information that justifies relaxation of the 

GALL AMP XI.M30 recommendation for quarterly sampling of fuel oil for particulate. In a letter 

dated April 6, 2009 the applicant stated that when fuel oil analysis limits are not met, such as for 

sediment content or particulate contamination, the condition is entered into the Corrective Action 

Program for evaluation and assignment of corrective actions where actions may include 

replacement of diesel fuel oil, more frequent sampling, use of fuel oil additives such as biocides, 

or tank draining, cleaning and inspection, depending on the significance of the issue and 

required actions to correct the condition. The staff finds that changes in sediment or particulate 

values will trigger corrective actions, which could include increased frequency of fuel oil 

particulate sampling if deemed necessary. The staff finds this exception to the GALL AMP 

XI.M30 acceptable because, unacceptable values of sediment (indicating possible high 

particulate content) and/or particulate content will initiate corrective action. 

LRA Section B2.1.19, Fuel Oil Chemistry Program, identifies enhancements to the program.

The applicant committed to the program enhancements.

Enhancement 1. The applicant stated that the “monitoring and trending” element will be 

enhanced to provide particulate contamination testing of fuel oil in the eleven fuel oil storage 

tanks in accordance with ASTM D 6217 on an annual basis. GALL AMP XI.M30 recommends 

the methods of ASTM D 6217 to determine particulate contamination levels in fuel oil.

Implementation of ASTM D 6217 into the applicant’s Fuel Oil Chemistry Program will provide 

further assurance of fuel oil purity through the period of extended operation. This is acceptable 

because the implementation in accordance to ASTM D-6217 is consistent with GALL AMP 

XI.M30 with the exception of using a yearly sampling basis, as discussed, evaluated and 

accepted in the staff's evaluation of Exception 2 to this AMP.

Enhancement 2. The applicant stated that the “monitoring and trending” element will be 

enhanced to implement one-time ultrasonic thickness measurements that will be performed at 

selected tank bottom and piping locations prior to the period of extended operation. GALL AMP 

XI.M30 recommends UT inspections of tank bottoms to verify loss of material is not occurring.

Implementation of UT will provide further assurance that loss material is not occurring in fuel oil 

tanks and piping.

The staff finds that these enhancements will, when implemented, provide changes to the 

applicant’s Fuel Oil Chemistry Program such that it will conform more closely to GALL AMP 

XI.M30. As such, the staff finds that these enhancements will contribute to reasonable 

assurance that loss of material is not progressing through the period of extended operation.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.19. The 

applicant stated in LRA B2.1.19 that the Fuel Oil Chemistry Program has been effective in 

monitoring and controlling diesel fuel oil chemistry to mitigate aging effects based on OE. The 

applicant identified that:

• fuel oil quality parameters, including water and sediment percentage, being routinely 

within acceptance limits;

• new fuel oil, that did not meet quality standards, was not placed in service;
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• the internal visual inspections of storage tank surfaces that have been performed 

identified no significant corrosion; and

• ultrasonic testing of one tank was performed in 1995 where no wall thinning due to

corrosion was detected. 

The staff noted that no excessive fuel oil contamination has been discovered during routine fuel 

oil sampling activities and that fuel oil contamination was effectively addressed through the 

applicant’s Corrective Action Program. The staff also noted that visual and UT inspections of 

fuel oil tanks performed by the applicant confirm the effectiveness of the “preventive action” and 

“parameters monitored/inspected” elements of the Fuel Oil Chemistry Program, B2.1.19.

The staff confirmed, based on its review of PINGP OE reports, that the plant-specific OE did not 

reveal any degradation not bounded by the ability of visual and UT inspection to detect it and 

not bounded by industry experience.

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.19, the applicant provided the UFSAR Supplement 

for the Fuel Oil Chemistry Program. The staff verified that provisions of the UFSAR Supplement 

are in accordance with SRP-LR, Table 3.3-2, Fuel Oil Chemistry after enhancements to the 

program are implemented as identified in the LRA. The staff verified Commitment No. 15 of the 

License Renewal Commitments that the applicant committed to the existing Fuel Oil Chemistry 

Program with enhancements before the period of extended operation and continued through the 

period of extended operation.

The staff determined that the information in the UFSAR Supplement is an adequate summary 

description of the program as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant's Fuel Oil Chemistry Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. In addition, the staff reviewed the exceptions and their 

justifications and determined that the AMP, with exceptions, is adequate to manage the aging

effects. In addition, the staff reviewed the enhancements and confirmed that their 

implementation prior to the period of extended operation would make the existing AMP 

consistent with the GALL Report to which it was compared. The staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.2.10 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems 

Summary of Technical Information in the Application. LRA Section B2.1.23 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 
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Systems Program as consistent, with enhancements with GALL AMP XI.M23, “Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The program 

utilizes periodic visual inspections to manage aging effects for structural components of cranes 

and hoists including the bridge, trolley, rail system, structural bolting, and lifting devices in 

accordance with the provisions of NUREG-0612, “Control of Heavy Loads at Nuclear Power 

Plants."

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the enhancements to determine whether 

the AMP, with the enhancements, is adequate to manage the aging effects for which the LRA 

credits it. Additionally, the staff interviewed the applicant’s technical staff and reviewed on-site 

documents. 

The enhancements include guidance requiring components and structures subject to inspection 

to be clearly identified, and additional clarification of inspection procedures to include corrosion 

and wear where it is currently left out. 

Through its onsite review and discussions with the applicant, the staff learned that the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program is implemented through station procedures that are based on NRC approved 

guidance. Inspections are visual in nature, and are conducted on a routine basis for 

degradation.

Additionally, the staff found that the acceptance criteria program element included reference to 

the use of EOCI-61 as guidance for design of the containment polar cranes and turbine cranes.

According to GALL Report recommendations, use of the specification that was applicable at the 

time the crane was manufactured is acceptable. The staff reviewed both the EOCI-61 

specifications, and the CMAA-70 specifications as recommended in the GALL Report, as well 

as the licensee’s point-by-point comparison of the two specifications. The point by point 

comparison was previously submitted to and accepted by the NRC in 1982.

Enhancement 1. LRA Section B2.1.23 states an enhancement to the GALL Report “scope of 

program,” program element to include guidance in licensee procedures to clearly identify the 

components and structures subject to inspection. The staff finds this enhancement acceptable 

because when implemented, the Inspection of Overhead Heavy Load and Light Load (Related 

to Refueling) Handling Systems Program will be consistent with the GALL AMP XI.M23 and will 

add assurance of adequate management of aging effects.

Enhancement 2. LRA Section B2.1.23 states an enhancement to the GALL Report “parameters 

monitored/inspected,” program element to include guidance in licensee procedures to require 

inspection of crane components for corrosion and wear where it is currently omitted. The staff 

finds this enhancement acceptable because when implemented, the Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be consistent 

with the GALL AMP XI.M23 and will add assurance of adequate management of aging effects.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.23. The 

applicant stated that the OE review showed that examples of paint damage and corrosion in 

load handling systems had been identified and corrected prior to loss of intended functions. The
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staff also reviewed the OE reports, including a sample of CRs, and interviewed the applicant’s 

technical staff to confirm that the plant-specific OE did not reveal any degradation not bounded 

by industry experience. A CR indicated that in 2003, a crack was discovered in the turbine 

building crane girder. An NDE was completed to verify the crack and the staff found that proper 

corrective actions were taken to address the issue.

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 

element acceptable.

UFSAR Supplement. In LRA section A.2.23, the applicant provided the UFSAR Supplement for 

the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program. The staff reviewed this section and finds it acceptable because it is 

consistent with the corresponding program description in SRP-LR Table 3.3-2. 

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d). 

The applicant committed (Commitment No. 19) to implement this program prior to the period of 

extended operation.

Conclusion. On the basis of its audit and review of the applicant's Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program the staff 

determined that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the GALL Report. The staff also reviewed the enhancements 

and confirmed that their implementation before the period of extended operation will result in the 

existing AMP being consistent with the GALL AMP to which it was credited. The staff concludes 

that the applicant demonstrated that the effects of aging will be adequately managed so that 

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 UFSAR supplement 

for this AMP and concluded that it adequately describes the program, as required by 10 CFR 

54.21 (d).

3.0.3.2.11 Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors 

Summary of Technical Information in the Application. LRA Section B2.1.28 describes the 

applicant’s existing Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel 

Closure Heads of Pressurized Water Reactors Program. The applicant stated that the NickelAlloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized 

Water Reactors Program (Nickel-Alloy Vessel Head Penetration Nozzle Program) is a condition 

monitoring program that implements the requirements of the NRC's First Revised Order 

EA-03-009, “Issue of Order Establishing Interim Inspection Requirements for Reactor Pressure 

Vessel Heads at Pressurized Water Reactors,” dated February 20, 2004 (Order). This program 

manages the aging effects of cracking due to PWSCC of the nickel-alloy vessel head 

penetration nozzles welded to the upper reactor vessel head. 
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In addition, the program monitors the upper reactor vessel head surface and the region above 

the reactor vessel head for boric acid leakage. The upper reactor vessel heads for both Units 1 

and 2 have been replaced. The new heads now incorporate Nickel-Alloy 690 (SB167) for each 

of the reactor head penetration nozzles instead of the Nickel-Alloy 600 utilized in the previous 

heads. 

Staff Evaluation. During its audit, the staff confirmed the applicant=s claim of consistency with 

the GALL Report. The staff reviewed enhancements to determine whether the AMP, with the 

enhancements, is adequate to manage the aging effects for which the LRA credits it.

The staff noted that where the applicant claimed the Nickel-Alloy Penetration Nozzles Welded to 

the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program to be 

consistent with elements of the GALL AMP XI.M11A, the Nickel-Alloy Penetration Nozzles 

Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program 

elements are consistent with the GALL AMP XI.M11A after the enhancements are implemented.

LRA Section B2.1.28, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel 

Closure Heads of Pressurized Water Reactors Program, identifies four enhancements to the 

program, as follows:

(1) on the “detection of aging effects” program element - the program will be enhanced to 

require that any deviations from implementing the appropriate required inspection 

methods of the NRC First Revised Order EA-03-009, will be submitted for NRC review 

and approval;

(2) on the “monitoring and trending” program element - the program will be enhanced to 

require that any deviations from implementing the required inspection frequencies will be 

submitted for NRC review and approval;

(3) on the “acceptance criteria” program element – the program will be enhanced to require 

that relevant flaw indications detected as a result of implementing the augmented 

inspections of the upper reactor vessel closure head penetration nozzles will be 

evaluated in accordance with the criteria approved by the NRC; and

(4) on the “corrective actions” program element - the program will be enhanced to require 

that, if leakage or evidence of cracking in the upper reactor vessel closure head 

penetration nozzles is detected while the nozzles are ranked in the “Low,” “Moderate,” or 

“Replaced” susceptibility category, the nozzles are to be immediately reclassified to the 

“High” susceptibility category and the required augmented inspections for the “High” 

susceptibility category are to be implemented during the same outage the leakage or 

cracking is detected.

The staff finds that these enhancements will provide changes to the applicant’s Nickel-Alloy 

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water 

Reactors Program such that it will conform to GALL AMP XI.M11A. As such, the staff finds that 

these enhancements will contribute to reasonable assurance that cracking due to PWSCC will 

be managed such that the vessel head penetrations will perform their intended functions 

through the period of extended operation.
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The staff noted that, in its final SOC on the updates of 10 CFR 50.55a, “codes and standards” 

(refer to Federal Register [FR] Volume 73, No. 176, pages 52730 – 52750), the staff mandated 

new augmented inspection requirements for upper reactor vessel closure head (RVCH) 

penetration nozzles that are made from nickel-alloy materials or that are structurally welded to 

the upper RVCH using bimetallic (i.e., nickel-alloy) weld filler metals. For these components, the 

updated rule imposed: (1) new augmented non-visual inspection methods for the components in 

accordance with the methods and criteria in ASME Code Case N-729-1, as defined, referenced 

and subject to the limitations in 10 CFR 50.55a(g)(6)(ii)(D), and (2) new augmented bare metal 

visual examinations requirements in accordance with the methods and criteria in ASME Code 

Case N-722, as defined, referenced and subject to the limitations in 10 CFR 50.55a(g)(6)(ii)(E).

The referenced SOC makes the following statement with respect to PWR applicants whose

LRAs include AMPs corresponding to GALL AMP XI.M-11A and whose LRAs are currently 

under review:

For new or current license renewal applicants, they may reference conformance 

GALL AMP XI.M11A and compliance with the augmented inspection requirements 

in paragraphs 10 CFR 50.55a(g)(6)(ii)(D) and (E) without the need for taking an 

exception to the program elements in GALL AMP XI.M11A.

The program description in GALL AMP XI.M11-A states:

This program is established to ensure that augmented inservice inspections (ISI) of 

all nickel-alloy vessel head penetration (VHP) nozzles welded to the upper reactor 

vessel (RV) head of a PWR-designed light-water reactor will continue to be 

performed as mandated by the interim requirements in Order EA-03-009, “Issuance 

of Order Establishing Interim Inspection Requirements for Reactor Pressure Vessel 

Heads at Pressurized Water Reactors (PWRs),” as amended by the First Revision 

of the Order, or by any subsequent NRC requirements that may be established to 

supersede the requirements of Order EA-03-009.

Thus, the staff’s program in GALL AMP XI.M11-A accounted for the fact that the augmented 

inspection requirements that were established in NRC Order EA-03-009 and amended in First 

Revised Order EA-03-009 would eventually be superseded by augmented inspection 

requirements for these components in either 10 CFR 50.55a or in the ASME Code Section XI.

The SOC in FR Volume 73, No. 176, pages 52730 – 52750, confirms that the finalized 

augmented inspection requirements have been mandated in accordance with 10 CFR 50.55a 

(g)(6)(ii)(D) - (E) and in the ASME Code cases referenced in these regulatory paragraphs. Thus 

based on this clarification and the regulatory basis in SOC in FR Volume 73, No. 176 (pages 

52730 – 52750), the applicant may update the program elements for its Nickel-Alloy Penetration 

Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors 

Program to reflect the new augmented inspection requirements for these components without 

having to take an exception to GALL AMP XI.M11-A. 

The applicant’s program includes LRA Commitment No. 22, which calls for the applicant to 

implement its Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure 

Heads of Pressurized Water Reactors Program during the period of extended operation but 

does not include the new mandated requirements of 10 CFR 50.55a(g)(6)(ii)(D) -(E). However, 

the staff noted that the applicant committed in Commitment No. 1 to submit amendments to the 
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PINGP LRA including UFSAR supplements pursuant to10 CFR 54.21(b), which requires that 

each year following submittal of the LRA and at least three months before scheduled completion 

of the NRC review, an amendment to the renewal application must be submitted that identifies 

any change to the CLB of the facility that materially affects the contents of the LRA, including 

the FSAR supplement. Based on the applicant’s Commitment No. 1, the staff finds the applicant 

will implement the new mandated augmented inspection requirements in 10 CFR 

50.55a(g)(6)(ii)(D) - (E).

The staff’s cover letter for First Revised Order EA-03-009, dated February 20, 2004, states the 

requirements of the Order are in effect until that time when the requirements of the Order will be 

reflected in an appropriate update of 10 CFR 50.55a. The augmented inspection requirements 

for upper RVCH penetration nozzles and their welds, as provided in 10 CFR 50.55a(g)(6)(ii)(D) -

(E), are the appropriate augmented inspection requirements that supersede the requirements in 

First Revised Order EA-03-009. When implemented, the required update of the Nickel-Alloy 

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water 

Reactors Program to include these augmented inspection requirements will eliminate the need 

for the enhancements of the program under LRA Commitment No. 22 because the augmented 

inspection requirements in 10 CFR 50.55a(g)(6)(ii)(D) and (E) for these components supersede 

the requirements in First Revised Order EA-03-009 for these components and because the 

NRC has now established appropriate regulations in 10 CFR 50.55a to ensure the non-visual 

NDEs will now be performed on upper RVCH penetration nozzles and their associated nozzleto-vessel Class 1 pressure boundary welds and that bare metal visual examinations will now be 

performed on the upper RVCH, and in most importantly at upper reactor closure head to 

penetration nozzle junctions.

Operating Experience Review. The applicant stated that OE for the Nickel-Alloy Vessel Head 

Penetration Nozzle Program identified no adverse trends or issues with program performance.

A few minor non-relevant leaks from valves were identified and corrected prior to causing any 

significant impact to safe operation or loss of intended functions. Adequate corrective actions 

were taken to prevent recurrence.

Operating experience on cracking of upper RVCH penetration nozzles is adequately addressed 

in NRC Order EA-03-009 and in First Revised Order EA-03-009. The requirements in the orders 

(prior to the time that they were superseded by the updated augmented requirements for these 

components in 10 CFR 50.55a(g)(6)(ii)(D) and (E)) were imposed to address the generic OE for 

upper RVCH penetration nozzles that are fabricated from nickel-alloy base metals or that are 

welded to the upper RVCHs using nickel-alloy weld materials. The orders established that 

replacement of the upper RVCHs is a viable corrective action activity to address the generic OE

for these components.

The staff audited the applicant’s OE reports and interviewed the applicant’s technical staff. The 

staff noted that the documentation provided by the applicant during the onsite review support 

the applicant’s statements regarding OE and confirmed that the plant-specific OE did not reveal 

any degradation not bounded by industry experience.

The staff noted that the applicant did not identify any leakage of the borated reactor coolant due 

to cracking in the upper RVCH penetration nozzles or their nickel-alloy nozzle-to-RVCH 

J-groove welds. The staff also noted that the applicant replaced both RVCHs with RVCHs that 
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have Alloy 690 nickel-alloy penetration nozzles and Alloy 52/152 nickel-alloy nozzle-to-RVCH 

welds. Thus, the staff concludes that the applicant has addressed the generic OE for its upper 

RVCH penetration nozzles because the applicant has replaced the upper RVCHs for the PINGP 

units and because the applicant will now follow the current augmented inspection requirements 

for the replacement upper RVCHs and penetration nozzles, as mandated in 10 CFR 50.55a 

(g)(6)(ii)(D) - (E) and in the ASME code cases as referenced in and subject to the limitations of 

these regulatory paragraphs.

Thus, based on this review, the staff confirmed that the OE 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 element acceptable.

UFSAR Supplement Review. The applicant provided its UFSAR Supplement for the Nickel-Alloy 

Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water 

Reactors Program in PINGP LRA, Appendix A, Section A2.28. The staff verified that provisions 

of the UFSAR Supplement are in accordance with SRP-LR (NUREG-1800, Revision 1), Table

3.1-2, Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of 

Pressurized Water Reactors Program. 

The staff verified that in Commitment No. 22, the applicant committed to the existing NickelAlloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized 

Water Reactors Program with enhancements through the period of extended operation.

However, new augmented inspection requirements for the upper RVCH penetration nozzles that 

are mandated in 10 CFR 50.55a (g)(6)(ii)(D) - (E) and in the ASME Code Cases N-722 and 

N-729 which are referenced in and subject to the limitations of these regulatory paragraphs.

The staff noted that in the applicant’s Commitment No. 1, the applicant submitted changes to 

the LRA that are needed based on changes to the CLB that affect the contents of the LRA, 

including UFSAR Supplements summary sections for the LRA. Thus, the staff also noted that 

the scope of the commitment includes the need to update the program elements of the NickelAlloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of Pressurized 

Water Reactors Program, as implemented through the implementation of the applicant’s, ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program in order to 

incorporate the new augmented inspection requirements for upper reactor vessel closure head 

penetration nozzles that were mandated in 10 CFR 50.55a(g)(6)(ii)(D) - (E). The staff finds this 

to be acceptable because it is in compliance with the requirements 10 CFR 54.21(b) and 

because the applicant has amended the program elements for this AMP as provided by letter 

dated April 13, 2009, to incorporate these new augmented inspection requirements for nickelalloy components.

Based on this review, the staff finds that the applicant’s UFSAR Supplement for this AMP is 

acceptable because it is in conformance with the recommended UFSAR Supplement summary 

description for these types of programs in Table 3.1-2 of the SRP-LR and because the applicant 

will update the UFSAR Supplement following the augmented inspection requirements for these 

components in 10 CFR 50.55a (g)(6)(ii)(D) - (E) and in the ASME code cases that are 

referenced in and subject to the limitations of these regulatory paragraphs. 
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The staff finds that the UFSAR Supplement for the Nickel-Alloy Penetration Nozzles Welded to 

the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program 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 Nickel-Alloy Penetration Nozzles 

Welded to the Upper Reactor Vessel Closure Heads of Pressurized Water Reactors Program, 

the staff finds 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 function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement 

for this AMP and concludes that it provides an adequate summary description of the program, 

as required by 10 CFR 54.21(d).

3.0.3.2.12 Reactor Head Closure Studs 

Summary of Technical Information in the Application. LRA Section B2.1.33 describes the 

Reactor Head Closure Studs program as consistent, with an enhancement to the GALL AMP 

XI.M3, “Reactor Head Closure Studs.” The program manages the effects of aging for reactor 

head closure studs and stud components through the implementation of plant procedures 

following the examination and inspection requirements of ASME Section XI Table, IWB-2500-1, 

and the guidance provided in NRC Regulatory Guide 1.65, “Materials and Inspection for Reactor 

Vessel Closure Studs.” AERM include cracking due to SCC, and loss of material due to wear.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. 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 reviewed the applicant’s on-site documentation supporting the applicant’s 

conclusion that the program elements are consistent with the elements in the GALL AMP and 

compared the elements in the applicant’s program with the GALL AMP XI.M3 program 

elements. 

The staff compared the elements in the applicant’s program with the GALL Report program 

elements. The applicant confirmed that it conforms to the requirements of the ASME Code, 

Section XI, Subsection IWB 1998 edition including the 1998, 1999, and 2000 Addenda for the 

current ISI interval, and not the 2001 edition as recommended by GALL Report. The staff noted 

that the applicant discusses its use of this ASME Code Section XI edition in LRA AMP B2.1.3, 

ASME Section XI Inservice Inspection, Subsection IWB, IWC, and IWD Program. The staff 

evaluates AMP B2.1.3 in SER Section 3.0.3.1.3. 

Enhancement 1. LRA Section B2.1.33 states an enhancement to the GALL Report “corrective 

actions,” program elements to include controls to be implemented prior to August 9, 2013, for 

Unit 1, and October 29, 2014, for Unit 2 which “ensure that future procurement of reactor head 

closure studs will be in accordance with the material and inspection guidance provided in NRC 

Regulatory Guide 1.65.” The staff confirmed with the applicant that current reactor head closure 

studs are already in accordance with NRC RG 1.65, and the applicant further explained that 

though they are aware of, and currently conform to the specifications in NRC RG 1.65, no 

controls currently exist at PINGP that would prevent non-conformance. The staff finds this 

enhancement acceptable because when implemented, the Reactor Head Closure Studs 
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Program will be consistent with GALL AMP XI.M3 and will add assurance of adequate 

management of corrective actions.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.33. The 

applicant stated that the program is effective in the management of age-related degradation 

associated with reactor head closure studs, as well as the detection of closure bolting leakage 

associated with reactor head closure studs. The staff reviewed the OE reports to confirm that 

the plant identified indications could not be detected or managed through implementation of this 

AMP’s program elements. The staff noted that the applicant had indicated that two relevant 

indications have been recorded on the reactor head closure studs at the PINGP site. The staff 

verified that the recordable indications in the stud’s conditions were minor in severity, not age 

related and were corrected through its corrective action program. PINGP did not identify any 

adverse trend in program performance. PINGP also reviews industry OE and completes 

periodic self assessments to evaluate its own program effectiveness. 

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 

element acceptable.

UFSAR Supplement. In LRA section A.2.33, the applicant provided the UFSAR Supplement for 

the Reactor Head Closure Studs Program. The staff reviewed this section and finds it 

acceptable because it is consistent with the corresponding program description in SRP-LR 

Table 3.1-2.

The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

The staff verified that, in LRA Commitment No. 26, the applicant committed to implementing the 

enhancements to the program as described in LRA Section B2.1.33 prior to the period of 

extended operation. 

Conclusion. On the basis of its review of the applicant’s Reactor Head Closure Studs Program 

as discussed above, the staff determined that those program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the GALL Report. The staff has 

reviewed the information provided in Section B2.1.33 of the LRA Appendix B. In addition, the 

staff reviewed the enhancement and its associated justifications and determined that the AMP, 

with the enhancement, is adequate to manage the aging effects for which it is credited and 

confirmed that its implementation before the period of extended operation will result in the 

existing AMP being consistent with the GALL AMP to which it was credited. The staff concluded 

that the applicant has demonstrated that effects of aging on the reactor head closure studs and 

nuts constructed from materials with a maximum tensile strength limited to less than 170 ksi 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 UFSAR supplement for this AMP and 

concluded that it adequately describes the program, as required by 10 CFR 54.21(d).
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3.0.3.2.13 Reactor Vessel Surveillance Program

In Appendix B of the LRA, the applicant indicated that it will implement AMP B2.1.34, “Reactor 

Vessel Surveillance Program,” for monitoring neutron embrittlement of the reactor vessel (RV) 

beltline materials at the PINGP, Units 1 and 2. This AMP is consistent with the GALL Report 

with enhancements. The staff reviewed the attributes of the applicable enhancements and the 

results of the review are documented in the following sections.

Summary of Technical Information in the Application. LRA Section B2.1.34 describes the 

existing RV Surveillance Program (RVSP) as consistent, with enhancements, with GALL AMP 

XI.M31, “RV Surveillance.” The applicant’s RVSP manages the reduction of fracture toughness 

of the RV beltline materials due to neutron embrittlement to fulfill the intent and scope of Title 10 

of the Code of Federal Regulations (10 CFR) Part 50, Appendix H, “Reactor Vessel Material 

Surveillance Program Requirements.” The program ensures compliance with the requirements 

that are specified in 10 CFR 50.60 for fracture prevention and 10 CFR 50.61 for Pressurized 

Thermal Shock (PTS). The applicant’s RVSP includes radiation analysis, mechanical testing of 

the surveillance capsules, development of pressure-temperature (P-T) operating limits, and 

determination of low-temperature overpressure protection. The applicant stated that consistent 

with plant technical specifications, the P-T limits report, and 10 CFR 50.60 and 10 CFR Part 50, 

Appendix H, the RVSP will update the operating P-T limits and will manage surveillance capsule 

withdrawal schedules.

The applicant stated that it included enhancements to the GALL AMP XI.M31 for the extended 

period of operation in which the following requirements will be added to its RVSP:

(1) all withdrawn and tested surveillance capsules, not discarded as of August 31, 2000, are 

placed in storage for possible future re-constitution and use, and

(2) if spare capsules are withdrawn, the untested capsules are placed in storage and 

maintained for future insertion.

The program manages the steps taken (e.g., the review and updating of 60-year fluence 

projections to support the preparation of new P-T limit curves and pressurized thermal shock 

reference temperature calculations) for altered RV exposure conditions.

Staff Evaluation. The staff reviewed the applicant’s proposed enhancements to the GALL 

Report requirements to determine whether the AMP, with the enhancements, remains adequate 

to manage the aging effects for which it is credited. The RVSP, which is designed and 

implemented in accordance with 10 CFR Part 50, Appendix H, uses testing of the RV 

surveillance capsule test specimens as the basis for monitoring for neutron irradiation-induced 

embrittlement in base metals (plate or forgings) and welds that are located in the beltline region 

of the low alloy steel RV. 

Units 1 and 2 RVSP consists of six surveillance capsules for each unit and each capsule 

contains mechanical test specimens, Charpy V-Notch specimens, neutron dosimetry, and 

thermal monitors. Fracture toughness of beltline materials is indirectly monitored through 

measurement of the impact energy of Charpy V-Notch specimens. The applicant has tested four 

of the six surveillance capsules in each unit to date, and the latest capsules of PINGP, Units 1 
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and 2 were tested at projected fluence values, which are less than 60 year fluence. Section 6.0 

of AMP XI.M31 in NUREG-1801, “Generic Aging Lessons Learned Report,” Volume 2, Revision 

1, states that if an applicant has a surveillance program that consists of capsules with a 

projected fluence exceeding the 60 year fluence at the end of 40 years, the applicant withdraws

one capsule at an outage in which the capsule receives a neutron fluence equivalent to the 60 

year fluence and tests the capsule in accordance with the requirements of ASTM E 185. To 

ensure that the applicant complies with the aforementioned GALL Report requirement, in RAI 

B2.1.34 (A), by letter dated November 4, 2008, the staff requested that the applicant confirm 

whether one of the two remaining capsules in each unit will be tested during the extended 

period of operation. Furthermore, the staff requested that the applicant provide the following 

relevant information regarding the testing of the capsules in Units 1 and 2.

(1) Applicant’s plan to test an additional surveillance capsule from each unit,

(2) the projected refueling outages of withdrawal for each unit, and 

(3) projected neutron fluence value for each capsule at the time of withdrawal.

In response to the staff’s RAI, in a letter dated November 12, 2008, the applicant stated that one 

of the two remaining capsules in each unit will be withdrawn after the capsules have received a 

neutron fluence equivalent to the 54 effective full power years (EFPY). The applicant did provide 

the projected maximum RV fluence values that represent the fluence values for 54 EFPY at the 

time of withdrawal of the surveillance capsules from Units 1 and 2. The Unit 1 surveillance 

capsule is planned for withdrawal during the re-fueling outage 1R27 which is expected to occur 

in 2011, and the Unit 2 surveillance capsule is planned for withdrawal during the re-fueling 

outage 2R27 which is expected to occur in 2012. The staff finds the applicant’s response 

acceptable because it complies with the GALL Report requirement and it provides adequate 

assurance that the applicant intends to monitor the neutron embrittlement of the RV during the 

extended period of operation.

In RAI B.2.1.34 (B), in a letter dated November 4, 2008, the staff requested that the applicant 

confirm that the withdrawal schedule of the capsules to be used for future tests during the 

extended period of operation is consistent with the requirements specified in paragraph 7.6.2 of 

the American Society of Testing Materials (ASTM) E 185, 1982 Edition, “Conducting 

Surveillance Tests for Light-Water Cooled Nuclear Power Reactor Vessels.”

In response to the staff’s RAI B.2.1.34 (B), in a letter dated November 12, 2008, the applicant 

confirmed that consistent with the requirements specified in ASTM E 185, 1982 Edition, it will 

withdraw the surveillance capsules from Units 1 and 2 when their exposure exceeds the peak 

neutron fluence value at 54 EFPY but does not exceed twice this peak neutron fluence value.

The staff accepts this response as it is consistent with the requirements specified in ASTM E 

185, 1982 Edition.

In RAI B.2.1.34 (C), by letter dated November 4, 2008, the staff requested that the applicant 

confirm that untested surveillance capsules (standby capsules) will be stored for future use at 

Units 1 and 2. In response to the staff’s RAI B.2.1.34 (C), by a letter dated November 12, 2008, 

the applicant stated that consistent with its Commitment No. 27, it will add a requirement to 

AMP B2.1.34 indicating that the untested standby capsules will be placed in storage and 

maintained for future insertion at PINGP.
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The staff finds this response acceptable because future capsule testing will provide reasonable 

assurance that neutron irradiation-induced embrittlement in the RV beltline materials as a result 

of any change in projected neutron fluence can be monitored effectively during the extended 

period of operation. The staff determined that the aforementioned applicant’s response will be 

included in the staff’s safety evaluation as a part of a standard license condition. 

After reviewing the applicant’s response to the staff’s RAI B.2.1.34(A), (B) and (C), the staff 

concludes that its concern described in RAI B.2.1.34 is resolved.

The staff accepts the applicant’s RVSP based on the following reasons:

• the testing of the surveillance capsules in accordance with the proposed schedule 

provides reasonable assurance that the neutron-induced embrittlement in low alloy steel 

RV base metals and their associated welds will be adequately monitored during the 

extended period of operation and,

• the applicant’s RVSP complies with the requirements of the 10 CFR Part 50, 

Appendix H.

The staff confirmed that the applicant’s discussion of the OE program element satisfies the 

criteria defined in the GALL Report and in Section A.1.2.3.10 of the “Standard Review Plan for 

Review of License Renewal Applications for Nuclear Power Plants.” The staff finds this program 

element acceptable.

Operating Experience. The applicant stated that the RVSP has been effectively used to monitor 

the RV material aging effects due to neutron embrittlement. Based on the projected neutron 

fluence for the extended period of operation [i.e., 54 effective full power years (EFPY)], the 

applicant claimed that the RV beltline materials will maintain projected upper-shelf energy 

values exceeding the minimum required value of 50 ft-lb. The PTS reference temperatures for 

the beltline materials are projected to be below the screening criteria of 270 oF for longitudinal 

welds, plates and forgings and 300 oF for circumferential welds at 54 EFPY.

UFSAR Supplement. In LRA Section A.2.34, the applicant provided the UFSAR supplement for 

the RVSP. The staff reviewed this section and determined that the information in the 

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 RVSP, 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 enhancements and confirmed that their 

implementation prior to and/or during the period of extended operation would support the 

requirements of the GALL AMP. The staff concludes that the applicant has demonstrated that 

the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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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3.0.3.2.14 RG 1.127 Inspection of Water Control Structures Associated with Nuclear Power 

Plants 

Summary of Technical Information in the Application. LRA Section B2.1.35 describes the 

existing RG 1.127 Inspection of Water-Control Structures Inspection as consistent, with 

enhancements, with GALL AMP XI.S7, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants.” The applicant stated that the program manages aging effects in watercontrol SCs, including bolting, through periodic visual inspections and hydrographic surveys. 

The applicant also stated that the program considers the guidance in RG 1.127 and ACI 

349.3R-96 if it is necessary to evaluate degradation mechanisms and questionable concrete 

conditions.

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the enhancements in Commitment No. 28 

to determine whether the AMP, with the enhancements, is adequate to manage the aging 

effects for which it is credited by the LRA.

The staff interviewed the applicant’s technical staff and reviewed the associated bases 

documents for PINGP AMP B2.1.35 “RG 1.127 Water-Control Structures Inspection,” which 

provides an assessment of the AMP elements’ consistency with the GALL AMP XI.S7.

The staff also reviewed those portions of the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program for which the applicant claims consistency with 

the GALL AMP XI.S7.

Enhancement 1. LRA Section B2.1.35 states an enhancement to the “scope of program” 

element to add inspections of concrete and steel components that are below the water line at 

the Screenhouse and Intake Canal. The applicant also states that the scope will be enhanced to 

require inspections of the Approach Canal, Intake Canal, Emergency Cooling Water Intake, and 

Screenhouse immediately following extreme environmental conditions or natural phenomena 

including an earthquake, flood, tornado, severe thunderstorm, or high winds.

The staff reviewed the applicant’s RG 1.127 Water-Control Structures Inspection under the 

scope of program element. The staff noted that the program will be enhanced to ensure 

consistency with the scope identified in GALL AMP XI.S7, “RG 1.127, Inspection of WaterControl Structures Associated with Nuclear Power Plants." This AMP consists of PINGP 

activities that manage aging effects for components of the following systems and/or structures:

 • Approach Canal (APC);

 • Component Supports (HGR);

 • Emergency Cooling Water Intake (ECI);

 • Intake Canal (INC); and

 • Screenhouse (SCH)

The staff found this enhancement acceptable because enhancement to PINGP AMP B2.1.35, 

“RG 1.127 Water-Control Structures Inspection,” is consistent with the GALL AMP XI.S7 and 

provides additional assurance that the effects of aging will be adequately managed.
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Enhancement 2. LRA Section B2.1.35 states an enhancement to the “parameters monitored or 

inspected” program element to include an inspection of water-control concrete components that 

are below the water line for cavitation and erosion degradation. The applicant also states that 

the program will also be enhanced to visually inspect for damage such as cracking, settlement, 

movement, broken bolted and welded connections, buckling, and other degraded conditions 

following extreme environmental conditions or natural phenomena. 

The staff reviewed the applicant’s RG 1.127 Water-Control Structures Inspection Revision 1 

Section C.2 requirements, and their AERMs under the parameters monitored or inspected 

program elements. The staff noted that the program parameters to be inspected will be revised 

to include a visual inspection for cavitation and erosion damage of water-control concrete 

components that are below the water line. Enhanced parameters are consistent with those 

provided in NRC RG 1.127, Section C.2. The program will also be enhanced to visually inspect 

structural components for damage such as cracking, settlement, movement, broken

bolted and welded connections, buckling, and other degraded conditions immediately following 

extreme environmental conditions or natural phenomena including earthquake, flood, tornado, 

severe thunderstorm, or high winds. These parameters are consistent with those provided in 

NRC RG 1.127, Section C.2.

The staff found this enhancement acceptable because the enhancement to PINGP AMP 

B2.1.35, “RG 1.127 Water-Control Structures Inspection,” is consistent with the GALL AMP 

XI.S7 and provides additional assurance that the effects of aging will be adequately managed.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.35, 

Operation Experience Review Report (RG 1.127 Water-Control Structures Inspection‘s section), 

and interviewed the applicant’s technical staff to confirm that the plant-specific OE have been 

reviewed by the applicant. During its audit and review, the staff noticed some minor degradation 

of items such as gasket materials, grout and bolting. The applicant stated that in 1997, minor 

calcium deposits, concrete spalling and minor wall cracks were observed in the Screenhouse. 

The spalling was repaired and the calcium deposit and cracks were determined to be non-active 

and did not affect the structural integrity of any of the structures reviewed. The staff also noted 

that water-control structures are periodically inspected at least once every five years consistent 

with industry guidance provided in ACI 349.3R-96 and Section C.4 of NRC RG 1.127. The 

program contains provisions to increase the inspection frequency as one of many 

considerations when evaluating the cause of a degraded condition in accordance with the 

corrective action program. 

The staff also confirmed that the applicant has addressed OE identified after the issuance of the 

GALL Report. The staff finds that the applicant’s RG 1.127 Water-Control Structures Inspection 

Program, has been effective in identifying, monitoring, and correcting the aging effects on water 

control structures and that existing program OE revealed no degradation not bounded by 

industry experience. 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 element acceptable.

UFSAR Supplement. In LRA Section A2.35, the applicant provided the UFSAR supplement for 

the RG 1.127 Water-Control Structures Inspection. The staff reviewed this section and 
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determines that the information in the UFSAR supplement is an adequate summary description 

of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127 Water-Control 

Structures Inspection, 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 

enhancements and confirmed that their implementation through Commitment No. 28 prior to the 

period of extended operation would make the existing AMP consistent with the GALL AMP to 

which it was compared. The staff concludes that the applicant has demonstrated that the effects 

of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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 Selective Leaching of Materials Program

Summary of Technical Information in the Application. LRA Section B2.1.36 describes the new 

Selective Leaching of Materials Program as consistent, with an exception, with GALL AMP 

XI.M33, “Selective Leaching of Materials.” The applicant stated that the program performs a 

one-time visual inspection of selected components made of cast iron, copper alloys greater than 

15 percent zinc, and copper-nickel. The applicant also stated that the program requires a 

hardness measurement or other suitable detection technique. The applicant stated that through 

inspections of representative samples, the program will determine if selective leaching is 

occurring and, if found, whether the aging mechanism will affect the ability of the component to 

perform its intended function.

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the exception to determine whether the 

AMP, with the exception, is adequate to manage the aging effects for which the LRA credits it. 

In comparing the elements in the applicant’s program to those in GALL AMP XI.M33, the staff 

noted that the program elements in the applicant’s AMP claimed to be consistent with the GALL 

Report were consistent with the corresponding program element criteria recommended in the 

program elements of the GALL AMP XI.M33. The staff also confirmed that the plant program 

contains all of the elements of the referenced the GALL AMP. On-site interviews with the 

applicant’s staff were also held to confirm these results.

Exception 1. LRA Section B2.1.36 states an exception to the “scope of program,” “parameters 

monitored/inspected," and “detection of aging effects” program elements. The applicant stated 

that alternate detection techniques may be used instead of, or in addition to visual inspections 

and hardness testing. The applicant noted that visual inspection and hardness measurement 

may not be feasible due to component configuration and location. In addition, other available 

detection techniques such as mechanical scraping or chipping, and additional examination 

methods that become available may be shown to be as effective as visual inspection and 

hardness testing in detecting and assessing the extent of selective leaching.

The staff reviewed the exception, which involves the use of examinations other than Brinell 

hardness testing identified in the GALL Report, to identify the presence of selective leaching.
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The staff issued RAI B2.1.36-1 by letter dated November 5, 2008 and requested that the 

applicant provide additional information concerning alternative detection techniques and 

justification for the use of these techniques.

In its response dated December 5, 2008, the applicant stated that the inspections specified in 

the GALL Report may not be feasible due to component form, configuration, and location. The 

applicant explained graphitization, which results from dissolving iron in gray cast iron 

components, and how it can weaken components by creating graphite, voids, and rust. The 

applicant also explained dezincification, which results from dissolving zinc in a liquid solution, 

and how it can weaken copper alloys (>15% zinc). 

The applicant stated that a combination of visual inspections in conjunction with mechanical 

methods will result in the detection of selective leaching, if present. The applicant stated that it 

would perform followup inspections if these methods detect dezincification or graphitization. The 

applicant also stated that it would enter the identification of selective leaching into the Corrective 

Action Program for evaluation to determine acceptability of the affected components for further 

service, and assessment of required corrective actions.

The staff determined that the exception is justified, because (1) Brinell hardness testing may not

be feasible for most components due to form and configuration (i.e., heat exchanger tubes) and 

(2) other mechanical means, i.e., scraping or chipping, provide an equally valid method of 

identification. The staff determined that the commitment to perform follow-up inspections and 

entering identified selective leaching into the Corrective Action Programs provides assurance 

that potential selective leaching is identified and managed. The staff recognizes that the industry 

is evaluating additional examination methods that become available for detecting and assessing 

the extent of the selective leaching mechanism.

The staff determined that the proposed alternate inspection methods are valid alternatives for 

identifying material aging. In addition, the use of different inspection techniques increases the 

likelihood of identifying aging in the various components within the Selective Leaching of 

Materials Program. The staff finds this exception acceptable because the additional qualitative 

mechanistic techniques can detect selective leaching and are in addition to visual inspections as 

recommended by the GALL Report.

Based on its review of the exception and resolution of the RAI as described above, the staff 

finds the Selective Leaching of Materials Program consistent with the program elements of the 

GALL AMP XI.M33, with acceptable exception, and therefore acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.36. The 

applicant stated that the Selective Leaching of Materials Program is a new program and has no 

OE related to the program implementation. The applicant stated that its search of plant OE did 

not reveal any instances of selective leaching having been documented at PINGP in the past.

However, the applicant plans to use available plant and industry OE to establish sample size, 

inspection location, and inspection techniques.

During the audit, the staff interviewed the applicant’s technical staff concerning industry OE. The 

applicant was aware of the difficulty in performing Brinell hardness testing on certain 
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components and was knowledgeable of other detection techniques being evaluated by the 

industry.

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. In LRA Section A2.36, the applicant provided the UFSAR supplement for 

the Selective Leaching of Materials Program. The staff verified that the UFSAR supplement 

summary description for the Selective Leaching of Materials Program was in conformance with 

the staff’s recommended UFSAR supplement for these types of programs provided in Table 3.3-

2 of the SRP-LR.

In its letter dated April 13. 2009, the applicant provided a list of license renewal commitments. 

The staff verified that the applicant has included in the final license renewal commitment list, 

Commitment No. 29, that the Selective Leaching of Materials Program will be implemented prior 

to the period of extended operation.

Based on this review, the staff determines that UFSAR supplement Section A2.36 provides an 

acceptable UFSAR supplement summary description of the applicant’s Selective Leaching of 

Materials Program because it is consistent with those UFSAR supplement summary description 

in the SRP-LR for Selective Leaching of Materials Program. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program, as 

required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching of 

Materials Program, and the applicant’s response to the staff’s RAI, 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 determined 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 UFSAR 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 Steam Generator Tube Integrity 

Summary of Technical Information in the Application. LRA Section B2.1.37 describes the 

existing Steam Generator Tube Integrity Program as consistent, with one exception, with the 

GALL AMP XI.M19, “Steam Generator Tube Integrity.” The applicant stated that the AMP 

consists of activities that manage the aging effects of cracking, denting, ligament cracking, and 

loss of material for steam generator tubes, tube plugs, tube repairs, and various secondary side 

internal components. 

The applicant stated that the Steam Generator Tube Integrity Program is implemented in 

accordance with Technical Specifications Section 5.5.8 and applicable industry guidance to 

maintain the integrity of the program. The applicant stated that it follows the guidelines 

contained in the latest revision of EPRI TR-107569-V1R5, “PWR Steam Generator 
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Examinations and Guidelines,” which provide criteria for the qualification of personnel, specific 

techniques, and the associated acquisition and analysis of data, including procedures, probe 

selection, analysis protocols, and reporting criteria.

The applicant further stated that the Steam Generator Tube Integrity Program also incorporates 

the guidance of NEI 97-06, “Steam Generator Program Guidance,” for performance criteria, 

which pertain to structural integrity accident-induced leakage, and operational leakage. The 

program also includes guidance on assessment of degradation mechanisms, inspection, tube 

integrity assessment, maintenance, plugging, repair, and leakage monitoring, as well as 

procedures for monitoring and controlling secondary side and primary side water chemistry.

In response to Generic Letter 97-06, the applicant outlined the program, which is in place, to 

detect degradation of steam generator internals. The applicant stated that its Steam Generator 

Tube Integrity Program demonstrated that the steam generator internals were in compliance 

with the plant’s CLB.

Staff Evaluation. During its audit, the staff confirmed the applicant’s claim of consistency with 

the GALL Report. The staff reviewed the exception to determine whether the AMP, with the 

exception, is adequate to manage the aging effects for which the LRA credits it. The staff’s 

summary of its on-site review of AMP B2.1.37, Steam Generator Tube Integrity Program, is 

documented in staff’s Audit Summary Report Section for this AMP. 

During its audit, the staff verified that the applicant’s Steam Generator Tube Integrity Program 

elements for “scope of program,” “preventive actions,” “parameters monitored/inspected,” 

“detection of aging effects,” “monitoring and trending,” “acceptance criteria,” and “operating 

experience” were consistent with the corresponding program elements of the GALL AMP 

XI.M19. The staff’s review of the program elements for “corrective actions,” “administrative 

controls,” and “confirmatory controls” program elements of this AMP were reviewed as part of 

the staff’s review of the Quality Assurance Program for the LRA. On-site interviews were also 

held to confirm these results.

Exception. LRA Section B2.1.37 states an exception to the “scope of program” program element 

in that the applicant’s Steam Generator Tube Integrity Program references NEI 97-06, “Steam 

Generator Program Guidance,” Revision 2, whereas the GALL AMP XI.M19 references NEI 

97-06, Revision 1. In discussions with the staff, the applicant stated that NEI 97-06, Revision 2, 

incorporates the latest industry OE, which strengthens the intent of NEI 97-06 to establish a 

framework for structuring and enhancing existing steam generator tube inspection programs.

On October 3, 2005, the staff sent a letter to NEI concerning NEI 97-06, “Steam Generator 

Program Guidelines,” Revision 2. The staff stated that NEI 97-06, Revision 2, is consistent with 

Technical Specification Task Force Traveler (TSTF) 449, Revision 4, “Steam Generator Tube 

Integrity.” The staff approved TSTF 449, Revision 4, in May 2005 and published the Traveler in 

the Federal Register on May 6, 2005.

In the letter dated October 3, 2005, the staff stated the following:

As you know, TSF 449 and NEI 97-06 are performance based. As a result, we 

will continue to monitor steam generator performance at each plant consistent 
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with our review and oversight processes. If we identify any issues with NEI 97-06 

or the associated Electric Power Research Institute (EPRI) guidelines as a result 

of these activities, we will notify you or your staff so that you can evaluate the 

need to update your guidance documents.

The GALL AMP XI.M19 states that a licensee’s plant Technical Specifications, its response to 

GL 97-06, and its commitment to implement the steam generator degradation management 

program described in NEI 97-06 are adequate to manage the effects of aging on the steam 

generator tubes, plugs, sleeves, and tube supports.

The staff issued Revision 1 of the GALL Report in September 2005. In the program description,

the staff does not identify the revision number for NEI 97-06. However, the GALL AMP XI.M19 

reference section identifies NEI 97-06, Revision 1. The staff determined that NEI 97-06, 

Revision 2, was issued after the GALL Report, Revision 1, was issued. Consequently, NEI 97-

06, Revision 2, was not included in the GALL AMP XI.M19 reference section.

The staff determined that NEI 97-06, Revision 2, summarizes the changes from NEI 97-06, 

Revision 1, and incorporates additional industry OE. The staff finds that the use of NEI 97-06, 

Revision 2 is acceptable until notified by the NRC.

The staff has reviewed and approved TSTF 449, Revision 4. The staff determined that the 

applicant has amended its Technical Specifications in accordance with TSTF 449, Revision 4.

The staff found that the applicant has incorporated the guidance in NEI 97-06, Revision 2, which 

includes the latest industry OE. The staff has yet to identify any issues associated with NEI 

97-06, Revision 2. 

On the basis of its review, the staff concludes the use of NEI 97-06, Revision 2, is consistent 

with GALL AMP XI.M19, and finds the exception acceptable.

Based on its review of the exception, the staff finds the Steam Generator Tube Integrity 

Program consistent with program elements of the GALL AMP XI.M19, with acceptable 

exception, and therefore acceptable.

Operating Experience. The staff reviewed the OE described in LRA Section B2.1.37. The 

applicant stated that a review of OE related to the Steam Generator Tube Integrity Program 

indicates the program has been effective in ensuring the timely detection and correction of 

steam generator aging effects. The applicant also stated that the program utilizes OE to 

promote the identification and transfer of lessons learned from both internal and industry events 

so that the knowledge gained can be used to improve nuclear safety and operations.

In LRA Section B2.1.37, the applicant states that the AMP has evolved to include improvements 

in programmatic features. The applicant stated that it has evaluated the existing AMP against 

NEI 97-06, Revision 2, and, where necessary, revised and strengthened the program attributes 

to meet the intent of the guidance. The applicant stated that the industry has strengthened their 

Steam Generator Tube Integrity Programs with aggressive improvements in control of 

secondary side water chemistry and upgrades in secondary side equipment, thus essentially 

eliminating both wastage and denting.
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In LRA Section B2.1.37, the applicant stated that in accordance with NEI 97-06, Revision 2, it 

conducts condition monitoring assessments to confirm adequate tube integrity has been 

maintained, outage inspections to confirm that the performance criteria are being met, and 

operational assessments to confirm that adequate tube integrity will be maintained for the 

operating interval between inspections. The applicant stated that if the operational assessment 

does not bound the latest condition monitoring results, then corrective action will be initiated.

The staff reviewed and approved TSTF 449, Revision 4, “Steam Generator Tube Integrity,” in 

May 2005. As part of the program requirements, the applicant is required to provide the staff 

with information concerning condition monitoring assessments, outage inspections, and 

operational assessments after every refueling outage. The staff reviewed this information and 

determined that it is acceptable. The staff audited A/R No. 00888189, “Action Request Report;” 

L-HU-06-026, “Supplement to Application for Technical Specification Improvement Regarding 

Steam Generator Tube Integrity; and the applicant’s response to Generic Letter 97-06, “Steam 

Generator Internals Degradation,” and determined that the applicant has complied with the

Steam Generator Tube Integrity Program requirements.

The GALL Report states that implementation of the Steam Generator Tube Integrity Program 

provides reasonable assurance that steam generator tube integrity is maintained consistent with 

the plants’ licensing basis for the period of extended operation. Experience with the condition 

monitoring and operational assessments required for plants that have implemented the alternate 

repair criteria in NRC GL 95-05 has shown that the predictions of the operational assessments 

have generally been consistent with the results of the subsequent condition monitoring 

assessments.

The staff reviewed the applicant’s OE associated with the Steam Generator Tube Integrity 

Program. The staff audited OE and selected reports and letters. The staff interviewed the 

applicant’s technical staff to confirm that plant-specific OE did not reveal any degradation 

outside the bounds of industry experience. The staff noted that the applicant has operated its 

steam generators for over 30 years before replacement was required. The staff determined that 

the applicant’s steam generator tube inspection programs have been effective. 

On these bases, the staff concluded that the applicant’s Steam Generator Tube Integrity 

Program has been effective in managing steam generator tube integrity aging effects and that 

the program will be managed adequately so that the structure and component intended 

functions will be maintained during the period of extended operations.

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 

element acceptable.

UFSAR Supplement. In LRA Section A2.37, the applicant provided the UFSAR supplement for 

the Steam Generator Tube Integrity Program. The staff verified that the UFSAR supplement 

summary description for the Steam Generator Tube Integrity Program was in conformance with 

the staff’s recommended UFSAR supplement for these types of programs provided in Table 3.1-

2 of the SRP-LR.
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Based on this review, the staff determines that UFSAR supplement Section A2.37 provides an 

acceptable UFSAR supplement summary description of the applicant’s Steam Generator Tube 

Integrity Program because it is consistent with those UFSAR supplement summary description 

in the SRP-LR for Steam Generator Tube Integrity Program. The staff determines that the 

information in the UFSAR supplement is an adequate summary description of the program as 

required by 10 CFR54.21(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 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 UFSAR supplement for this AMP and concludes that it 

provides an adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.3.2.17 Structures Monitoring 

Summary of Technical Information in the Application. LRA Section B2.1.38 describes the 

existing Structures Monitoring Program as consistent, with enhancements, with the GALL AMP 

XI.S6, “Structures Monitoring Program.” In the LRA, the applicant stated that the program will 

manage aging effects such that loss of material, cracking, and increase in porosity and 

permeability, among others are detected by visual inspection prior to the loss of the structure’s 

or component’s intended function(s). The applicant also stated that the program incorporates 

inspection guidance based on recommendations contained in ACI 349.3R, “Evaluation of 

Existing Nuclear Safety-Related Concrete Structures.” 

Staff Evaluation. During its audit and review, the staff confirmed the applicant=s claim of 

consistency with the GALL Report. The staff reviewed the enhancements in Commitment No. 30 

to determine whether the AMP, with the enhancements, is adequate to manage the aging 

effects for which it is credited in the LRA. 

During its audit, the staff audited the applicant’s on-site documentation supporting the 

applicant’s conclusion that the program elements are consistent with the elements in the GALL 

Report. The staff interviewed the applicant’s technical staff and reviewed the documents related 

to the Structures Monitoring Program, including the license renewal program evaluation report in 

which the applicant assessed whether the program elements are consistent with the GALL AMP 

XI.S6. 

Enhancement 1. LRA Section B2.1.38 states an enhancement to the “scope of program” 

program element in that the Structures Monitoring Program will be enhanced to include 

additional structures, components, and component supports for inspections requiring aging 

management. 

The staff reviewed the applicant’s Structures Monitoring Program, and its AERMs under the 

scope of the Structures Monitoring Program. The staff noted that the Structures Monitoring 

Program satisfies the monitoring requirements for plant structures that are within the scope of 
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the NRC Maintenance Rule, 10 CFR 50.65. PINGP structures, components, and component 

supports to be included within the enhanced scope of the Structures Monitoring Program 

include the following:

 • Approach Canal;

 • Fuel Oil Transfer House;

 • Old Administration Building and Administration Building Addition;

 • Component supports for cable tray, conduit, cable, tubing tray, tubing, non-ASME 

vessels, exchangers, pumps, valves, piping, mirror insulation, non-ASME valves, 

cabinets, panels, racks, equipment enclosures, junction boxes, bus ducts, breakers, 

transformers, instruments, diesel equipment, housings for HVAC fans, louvers, and 

dampers, HVAC ducts, vibration isolation elements for diesel equipment, and 

miscellaneous electrical and mechanical equipment items;

 • Miscellaneous electrical equipment and instrumentation enclosures including cable tray, 

conduit, wireway, tube tray, cabinets, panels, racks, equipment enclosures, junction 

boxes, breaker housings, transformer housings, lighting fixtures, and metal bus

enclosure assemblies;

 • Miscellaneous mechanical equipment enclosures including housings for HVAC fans, 

louvers and dampers; 

 • SBO Yard Structures and components including SBO cable vault and bus duct 

enclosures;

 • Fire Protection System hydrant houses;

 • Caulking, sealant, and elastomer materials; and

 • Nonsafety-related masonry walls that support equipment relied upon to perform a 

function that demonstrates compliance with a regulated event(s) 

The staff found this enhancement acceptable because when the enhancement is implemented, 

PINGP AMP B2.1.38, “Structures Monitoring Program,” will be consistent with the GALL AMP 

XI.S6 and provide additional assurance that the effects of aging will be adequately managed. 

Enhancement 2. LRA Section B2.1.38 states an enhancement to the “parameters monitored or 

inspected” program element to include additional inspection parameters. 

The staff reviewed the applicant’s License Renewal AMP Basis Document - Structures 

Monitoring Program (LR-AMP-428) Revision 2, dated August 15, 2008 Table 8.1 “Managed 

Aging Effects” against the “parameters monitored or inspected” program element criterion in 

SRP-LR Section A.1.2.3.3 which essentially states that the parameters to be monitored or 

inspected should be identified and linked to the degradation of the particular structure and 

component intended function(s). The staff found that the program identifies 60 items as listed in 

Table 8.1 “Managed Aging Effects” to be monitored or inspected and linked them to the 

degradation of the particular SCs intended functions. 
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The staff found this enhancement acceptable because when the enhancement is implemented, 

PINGP AMP B2.1.38, “Structures Monitoring Program,” will be consistent with the GALL AMP 

XI.S6 and provide additional assurance that the effects of aging will be adequately managed. 

Enhancement 3. LRA Section B2.1.38 states an enhancement to the “detection of aging effects” 

program element of the Structures Monitoring Program in that the procedure will be enhanced to 

require an inspection frequency of once every five (5) years for the inspection of structures, 

supports, and structural components within the scope of this program. The applicant also stated 

that the frequency of inspections can be adjusted, if necessary, to allow for early detection and 

timely correction of negative trends. The applicant further stated that the program will be 

enhanced to require periodic sampling of groundwater and river water chemistries to ensure 

they remain non-aggressive during the period of extended operation. 

The staff reviewed the applicant’s License Renewal AMP Basis Document - Structures 

Monitoring Program and found the visual inspection frequency, the periodic sampling of 

groundwater, and river water chemistries will be once in every five years during the period of

extended operation. However, it was not clear to the staff where the groundwater test samples 

were/are taken related to the safety-related and important-to-safety embedded concrete 

foundations; and the technical basis for concluding that periodic sampling will ensure that 

safety-related and important-to-safety embedded concrete foundations will not be exposed to 

aggressive groundwater. Therefore, the staff issued RAI B2.1.38-1, dated November 5, 2008. In 

the letter dated December 5, 2008, the applicant responded that the water samples are taken 

from the plant’s two deep wells and from the Mississippi River adjacent to the Intake 

Screenhouse. The deep wells are located approximately 295 yards and 350 yards west of the 

safety-related and important-to-safety concrete foundations. The river water sampling location is 

the Mississippi River just east of the Intake Screenhouse, approximately 210 yards from the 

safety-related and important-to-safety concrete foundations. The applicant also stated that the 

test results from well and river water sampling points have continuously shown that pH, 

chlorides, and sulfates concentrations are within the threshold of the GALL Report (pH > 5.5, 

chlorides < 500ppm, and sulfates < 1500ppm). Test results include a preconstruction report in 

1965 and reports spanning a 22-year period (from 1984 to 2006) which indicate that the 

maximum sulfates and chlorides levels recorded are 119 ppm and 89.4 ppm respectively, and 

pH obtained over the same time period ranges from 7.6 to 8.5. Therefore, the applicant 

concluded that groundwater is not aggressive. The staff finds the location of the wells 

appropriate, and this enhancement is acceptable because when the enhancement is 

implemented, PINGP AMP B2.1.38, “Structures Monitoring Program,” will be consistent with 

GALL AMP XI.S6 and provide additional assurance that the effects of aging will be adequately 

managed. 

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.38 and 

the applicant’s Operation Experience Review Report, and interviewed the applicant’s technical 

staff to confirm that the plant-specific OE has been reviewed by the applicant and is evaluated 

in the GALL Report. During its audit, the staff conducted a field walkdown with the applicant’s 

technical staff to the fuel oil transfer house, screenhouse, turbine building, intake canal, 

approach canal, diesel generator building, administration building addition, SBO structures, and 

the yard. In general, the staff noticed some degradation. However, all of the observations are 

minor and acceptable per the applicant’s inspection procedures and within the guidance of the 

ACI 201.1R (Guide for Making a Condition Survey of Concrete in Service) and ACI 349-3R 
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(Evaluation of Existing Nuclear Safety-Related Concrete Structures) as recommended in the 

GALL Report). 

During its audit and review, the staff noticed that PINGP has identified the leakage of borated 

water (CAP 01064513) from the Unit 1 and Unit 2 refueling cavities and through the concrete 

backing the liners since 1998. Leakage was fairly consistent throughout the duration of the 

flooding of the refueling cavity pool (average 1 gallon per hour). However, the leakage path has 

not been specifically identified. Therefore, the staff requested the applicant to provide the results 

of any root cause analyses, as well as corrective and preventive actions taken to address or 

correct this issue in RAI B2.1.38-2, dated November 5, 2008. In a letter dated December 5, 

2008, the applicant stated that the condition was detected by the ASME Section XI, Subsection 

IWE Program while examining the Class MC pressure retaining vessel. Both programs took 

corrective action to address the leakage. The staff reviewed the applicant’s responses to the 

RAI B2.1.38-2. The staff found that:

 The leakage inside containment was first documented in 1998 during the Unit 2 

refueling outage with water observed entering sump B from cracks in the grout around 

the RHR suction penetration sleeves at elevation 694 feet10 inches. This area is 

grouted from the floor of the sump to the ceiling of the sump back to the containment 

vessel wall.

 The chemical analysis of the fluid determined it to be similar to refueling water with a 

boron concentration of 2700 ppm, chloride concentration of 7 ppm, sulfate 

concentration of 0.2 ppm, and pH of 7.8. The boron content of the refueling pool water 

was measured at 2700 ppm with a pH of 5.2. (The increase in pH from the refueling 

cavity water to that found at the leaks was attributed to the acidity being neutralized by 

the carbonates and other minerals in the concrete.) 

 The grout at sump B was removed to inspect the containment vessel wall revealing no 

degradation of the containment vessel. 

 Other potential sources of leakage such as the Reactor Coolant (RC), Safety Injection 

(SI), and Residual Heat Removal (RH) systems were investigated and no other feasible 

source of leakage was identified. 

 During the Unit 2 outage in 2008, the plant performed over 150 ultrasonic (UT) 

thickness readings of the containment vessel from its exterior surface in the vicinity of 

the fuel transfer tube and at the sump B location. All readings were found to exceed the 

nominal vessel plate thicknesses of 1 1⁄2 inches and 3 1⁄2 inches.

The staff also found that the diagram on page four of Enclosure 3 to the letter dated December 

5, 2008, indicates that the potential leakage path follows the bottom of the containment liner. It 

appears to the staff that water could accumulate at the bottom of the liner and the area could 

remain wetted after refueling outages. Therefore, the staff did not agree with the applicant’s 

conclusion that the steel liner was not constantly wetted for long periods of time by the boric 

acid solution to cause any deterioration of the steel surface. The staff requested the applicant to 

explain in greater detail the increase in pH from the borated refueling water (pH 5.2) to the 

leakage found in sump B (pH 7.8), the chemical properties of the “white deposit” found on the 

concrete surfaces and the possibility of calcium hydroxide Ca(OH)2 leaching from the concrete, 

and why this leakage was omitted from the IWE Operating Experience discussion in the LRA. 
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The staff also requested an explanation of whether or not the liner and concrete remain wetted 

after refueling outages, and if so how this will be managed by the AMP in the period of extended 

operation. 

The applicant provided information related to this issue during a public meeting on March 2, 

2009. The applicant explained that a root cause evaluation determined that the leakage occurs 

at the reactor internals stand and the change fixture anchors, and that the applicant planned to 

permanently fix the leakage for both units during the upcoming outages (1R26 and 2R26). The 

applicant also explained that neither the containment vessel, nor the reinforcement should have 

experienced any significant corrosion. This conclusion was based, in part, on the assumed 

“buffering” effect of the concrete on the leakage, which would raise the pH of the leakage to a 

level that inhibits corrosion (i.e. greater than 12). The applicant also explained that the lack of 

evidence of washout or significant leaching of material from the concrete supported a 

conclusion that the leakage had not degraded the strength of the concrete.

The staff reviewed the information provided in the RAI response and during the public meeting 

and by letter dated March 31, 2009, the staff issued follow-up RAI B2.1.38 asking the applicant 

to discuss its plan for assessing the current condition of the steel containment vessel and to 

explain how the IWE program, or a plant specific program, will manage aging of the containment 

vessel. By letter dated April 6, 2009, the applicant responded to follow-up RAI B2.1.38. In the 

response, the applicant reiterated their proposed actions for permanently fixing the leakage 

during the upcoming outages (1R26 and 2R26) and for ensuring the adequacy of the 

containment vessel. The response included two new commitments. The applicant committed to 

remove concrete from a low point in containment (Sump C) to UT and visually inspect the 

containment vessel bottom head and to assess the condition of the concrete and rebar. This 

would be done during the first refueling outage following the repairs. The applicant also 

committed to perform visual inspections of the areas where refueling cavity leakage has been 

observed. The inspections would be conducted during the two consecutive refueling outages 

after the repairs were implemented (Commitments 41 & 42). Any degradation or continued 

leakage would be entered into the Corrective Action Program and evaluated for impact on 

structural integrity. The response also explained that a task had been entered into the site 

Corrective Action Program to collect and analyze deposits in areas showing signs of leakage.

While reviewing the April 6, 2009 response, the staff also conducted an audit on May 28, 2009, 

to review related on-site documentation. In response to the information reviewed while on-site, 

as well as the information provided in the April 6, 2009, response, the staff issued an additional 

follow-up RAI B2.1.38, by letter dated June 10, 2009. The additional RAI included nine parts 

and focused on clarifying information provided during the audit, including estimated upper 

bound corrosion projections and corrosion rates and the possible structural impacts of the 

projections. The staff also requested additional information on how the applicant concluded that 

the water between the containment vessel and the concrete would have a high pH value 

(greater than 12.5).

By letter dated June 24, 2009, the applicant responded to the follow-up RAI. The response 

explained the applicant’s estimates and assumptions, but did not clearly explain how the 

applicant would meet the design basis if the estimates were correct, or how the applicant was 

going to ensure that the estimated upper bound level of degradation had not occurred at the 

plant. To clarify these issues a conference call was held with the applicant on July 22, 2009. As 
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a result of the conference call, the applicant submitted a supplemental response by letter dated 

August 7, 2009. The following discussion summarizes the supplemental response and then 

addresses each of the nine points in the RAI dated June 10, 2009, including a summary of the 

staff’s request, the applicant’s response and the staff’s basis for finding the response 

acceptable. The discussion of the nine points is followed by an explanation of the staff’s 

assessment of issues regarding the reactor cavity leakage, and the basis for finding the 

Structures Monitoring Program and the ASME Section XI, Subsection IWE Program adequate to 

manage aging due to the refueling cavity leakage during the period of extended operation.

The response indicated that no containment wall thinning due to corrosion has been found at 

PINGP and recent UT measurements in known wetted areas have shown no corrosion. The 

response further stated that any future indications of degradation would be entered into the 

Corrective Action Program and evaluated in accordance with ASME Section XI, Subsection 

IWE. The response also included a new commitment and a revision to existing Commitment 41. 

Commitment 41 was revised to include petrographic examination of the concrete removed from 

Sump C, if the removal method provides pieces suitable for examination. Commitment 44 was 

added to include one concrete sample per Unit from a location known to have been wetted by 

borated water leakage. The samples will be taken during the first refueling outage following the 

repairs and will be tested for compression strength and subjected to petrographic examination. 

Any degradation identified from the samples will be entered into the Corrective Action Program. 

The applicant also stated that visual examination and vacuum box testing of the refueling cavity 

liner would be performed to look for any indications of grout washout behind the liner or weld 

failure in the liner seams. The inspections would occur during the repairs scheduled for the 

upcoming outages (1R26 and 2R26). The following discussion addresses each part of the 

June 10, 2009 RAI.

(A) The staff requested a schedule for performing a test to ensure that the water contacting 

the containment vessel would have a pH greater than 12.5. This test was recommended 

in a PINGP Report.

The applicant’s response described a simple laboratory test which involved adding 

chemicals representative of those in concrete to an open beaker of deionized water and 

then measuring the resulting pH. The test had already been conducted and the results 

were provided in the response.

The staff reviewed the test procedure and the results and concluded that the test was 

oversimplified and did not accurately represent the conditions present in the field. 

Therefore, the staff does not agree that the applicant conclusively demonstrated that the 

water in contact with the containment vessel and the reinforcement would have a pH 

greater than 12.5. However, based on the commitments to inspect the concrete, 

reinforcement, and vessel, as well as the fact that current operating experience does not 

indicate significant concrete or vessel degradation, the staff concludes that a more 

detailed test or measurement is unnecessary. The inspections will indicate the condition 

of the containment structures, regardless of the pH value of the leakage.

(B) The staff requested an explanation of why Sump C was the only location planned for 

concrete removal, when a PINGP report recommend removal at Sump C and at 

elevation 695’ near the transfer tube.
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The applicant’s response explained that they did not plan to remove concrete from the 

695’ elevation because it is not known whether or not that area is wetted by the leakage. 

Instead the applicant explained that they had previously removed grout along the vessel 

in the RHR suction sump (Sump B). This location is at a lower elevation and consistently 

shows wetting when refueling cavity leakage occurs. Visual and UT inspections of the 

vessel at Sump B showed no signs of degradation.

The staff reviewed the response and found that removal of concrete at the 695’ elevation 

was unnecessary. Since there is no guarantee that leaking water is contacting the vessel 

at the 695’ elevation, the location has a low potential for corrosion. Sumps B and C are 

more likely to experience corrosion due to the possibility of trapped water at Sump C, 

and repeated wetting and relatively close ambient oxygen at Sump B. Therefore, these 

locations are better candidates for vessel inspections and concrete does not need to be 

removed at the 695’ elevation.

(C) The staff requested an explanation of the upper bound containment loss estimate of 

0.25” over a 36 year period and how this loss would impact the stresses in the vessel.

The applicant’s response explained that the predicted 0.25” value assumes continuous 

wetting with aerated, concentrated boric acid over a 36 year period. However, it did not 

clearly explain how this estimate is related to the actual degradation, or how the design 

basis was being met if some or all of the estimated degradation had occurred. To 

address this, the applicant supplemented their response. The supplement explained that 

the 0.25” was a theoretical upper bound estimate that was not based on observed 

degradation at PINGP. The response further explained that currently there is no known 

containment wall thinning at PINGP. The applicant explained that if thinning is identified 

in the future, the issue will be entered into the Corrective Action Program and any 

required ASME Section XI, Subsection IWE actions would be performed and if 

necessary the resulting containment stresses would be analyzed.

The staff reviewed the response and concludes that the applicant has adequately 

addressed the corrosion estimate and the possible impacts on the containment. The 

absence of degradation at PINGP indicates that the 0.25” estimate is not representative 

of what is actually occurring in the field. In addition, the inspections committed to by the 

applicant provide assurance that degradation has either not occurred, or will be detected 

and addressed prior to the period of extended operation. Any degradation discovered in 

the future will be reviewed per the requirements of ASME Section XI, Subsection IWE, 

and the structural impact on the containment vessel will be evaluated.

(D) To account for concrete aggregate differences, the applicant assumed a concrete 

degradation rate twice that was used previously for Salem and Connecticut Yankee 

plants. The staff asked the applicant to explain whether or not any tests had been 

performed to confirm the assumption.

The applicant’s response explained that degradation in the concrete when exposed to 

boric acid is directly related to the amount of cement and soluble aggregate present in 

the concrete. The concrete at both the Salem and Connecticut Yankee plants did not 
3-146

contain soluble aggregates. The response further explained that PINGP concrete has 

about five percent soluble aggregate. Concrete normally contains 10 to 15 % cement for 

an average value of 12.5 % cement. Adding the five percent soluble aggregate at PINGP 

to the 12.5 % cement value generally present in concrete, including at Salem and 

Connecticut Yankee, results in an increase of soluble material from a base value of 12.5 

to PINGP specific value of 17.5 %. The response explained that published data indicates 

that an increase in soluble material from 12.5 to 17.5 % correlates to a weight loss 

increase of a factor of 1.49. Therefore, the applicant concluded that a degradation rate of 

twice that used for Salem and Connecticut Yankee was appropriate.

The staff reviewed the applicant’s response and concludes that the applicant’s approach 

for determining the degradation rate appears credible. However, regardless of the 

degradation rate, the applicant has committed to take concrete samples to inspect for 

signs of degradation (Commitment 44). Therefore, the staff agrees that additional tests 

to verify the concrete degradation rate are unnecessary. 

(E) The staff requested the applicant to explain how the formation of cracks in concrete due 

to borated water leakage would affect the shear capacity of concrete slabs and walls.

The applicant’s response explained that the shear strength of reinforced concrete 

depends on the strength provided by the concrete and the reinforcement. If a crack 

formed in the concrete along the shear plane, the reinforcement would have to carry the 

shear force. The applicant further stated that there is no indication that such a crack 

exists at PINGP. The observed leakage “seeps” from the cracks at an estimated rate of 

1 – 2 gallons per hour and no evidence of significant washout has been identified. In the 

supplemental response, the applicant added a new commitment to test concrete 

samples from areas known to be wetted by refueling cavity leakage.

The staff reviewed the response and concludes that the applicant has adequately 

addressed the possibility of reduced concrete capacity. The applicant has not identified 

any large concrete cracks or observed any indications of large cracks, such as material 

washout. In addition, the testing of concrete core samples will provide assurance that 

any concrete degradation will be detected and addressed prior to the period of extended 

operation.

(F) The staff requested the applicant explain how the possibility of corrosion of concrete 

reinforcement would be considered in determining the structural integrity of concrete 

walls and slabs.

The applicant’s response referenced tests performed for other plants and tests 

described in open literature which indicate that corrosion of reinforcement has been 

negligible, even when the borated water reaching the reinforcement is regularly 

refreshed. The response further explained that the most relevant tests referenced by the 

applicant lasted two years and resulted in no significant reinforcement degradation. The 

applicant estimated the exposure time of the reinforcement at PINGP over the last 36 

years to be approximately one year and therefore concluded that the corrosion and 

resulting effect on structural integrity would be insignificant. The applicant also 

committed to inspect all exposed reinforcement during concrete coring and the 
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excavation of Sump C, and enter any observed degradation into the Corrective Action 

Program. 

The staff reviewed the response and disagrees with the applicant’s estimate of 

reinforcement exposure time as one year. Reinforcement located near the bottom of the 

vessel may have been continuously exposed to borated water since refueling cavity 

leakage began. However, the reinforcement inspections committed to by the applicant 

will provide assurance that degradation has either not occurred, or will be detected and 

addressed prior to the period of extended operation. Therefore, the staff concludes that 

the applicant has adequately addressed the possibility of reinforcement corrosion.

(G) An applicant document estimated the upper bound loss of concrete depth behind the 

refueling cavity liner as 0.31 inches. The staff requested the applicant to address how 

this loss of concrete behind the liner would affect the load carrying capacity of the liner.

The applicant’s response explained that the liner is effectively a membrane backed by 

concrete which is generally four to five feet thick. Therefore, the impact on the capacity 

would be negligible. The response further stated that large areas of washout are 

unlikely, but if they did occur behind the liner, the liner would not be expected to fail due 

to the ductile nature of stainless steel. In the supplemental response, the applicant 

stated that visual inspections and vacuum box testing of the liner plate seams will be 

performed in the refueling cavity to look for depressions in the liner and for signs of 

washout due to the cavity leakage. These inspections will be performed during the next 

refueling outage for both Units.

The staff reviewed the response and finds that any loss of load carrying capacity of the 

concrete would be negligible since the concrete sections are four to five feet thick. The 

staff does not agree that the possible deformation of the liner would not be an issue due 

to the ductility of stainless steel; however, the visual inspections of the liner plate and 

vacuum box testing of the liner plate seams will provide assurance that any deformation 

will be detected and addressed prior to the period of extended operation.

(H) The applicant committed to inspecting areas where reactor cavity leakage has been 

observed in the two refueling outages after implementing the proposed fix. The staff 

requested the applicant to explain which AMP would be used to address these 

inspections.

The applicant’s response explained that the inspections are special inspections assigned 

within the Corrective Action Program, which will use the methodology, documentation 

and acceptance criteria of the Structures Monitoring Program. After the special 

inspections, general monitoring within containment will continue in accordance with the 

Structures Monitoring Program and the ASME Section XI, Subsection IWE Program.

The staff reviewed the response and finds it acceptable. The Structures Monitoring 

Program is the appropriate AMP for internal containment structures according to the 

GALL Report. Additionally, the GALL Report calls out the IWE AMP for inspections of 

the containment vessel and its integral attachments during the period of extended 

operation.
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(I) The staff requested the applicant provide the action plan and schedule for completing 

the five repair recommendations identified in the refueling cavity root cause evaluation.

The applicant’s response listed the five steps of the repair plan and explained that the 

intent of the plan is to permanently repair the refueling cavity leakage. The applicant 

further stated that the plan will be completed during the next refueling outage for each 

Unit. Step four of the repair plan was a recommendation to vacuum box or dye penetrant 

test the refueling cavity liner weld seams to ensure no leakage. The applicant performed 

testing of accessible seams in 1998 with no indications of cracking. The response 

explained that the exams during the next outage will confirm whether or not cracking of 

the welds has occurred since the last inspection. The supplemental response explained 

that approximately 100 linear feet of accessible floor and wall seams will be inspected, 

which will encompass the majority of the accessible floor seams of the lower refueling 

cavity near the reactor internals stands.

The staff reviewed the response and found it acceptable because it outlines a plan to 

stop the refueling cavity leakage, and verify the effectiveness of the repair, prior to the 

period of extended operation.

As discussed above, the staff reviewed the additional information provided in the letters dated 

June 24 and August 7, 2009. The staff had three issuesrelated to the refueling cavity leakage: 

(1) the leaking borated water may contact the containment vessel and remain in contact with the 

vessel between outages, (2) the leaking borated water may contact the concrete reinforcement 

and cause degradation, and (3) the leaking borated water may react with the concrete and 

cause degradation.

In response to the staff’s first issue of vessel degradation, the applicant has committed to 

removing concrete from Sump C and inspecting the containment vessel (Commitment 41). 

Sump C is a low point in containment which is likely to remain continuously wetted. This 

inspection will provide assurance that either the vessel has not experienced significant 

degradation, or any existing degradation will be documented and reviewed for structural impacts 

prior to the period of extended operation. The fact that in 2008, 150 UT measurements were 

taken of the containment vessel in the area of the expected leak path and grout was removed 

from Sump B to inspect the containment vessel, and neither inspection revealed signs of 

degradation, provides assurance that the implementation schedule of the containment vessel 

inspection commitments is adequate.

In response to the staff’s second issue, the possibility of concrete reinforcement degradation, 

the applicant has committed to inspect the exposed reinforcement during the excavation of 

Sump C. Any degradation will be entered into the Corrective Action Program and reviewed for 

its structural impact.

In response to the staff’s third issue, the possibility of concrete degradation, the applicant has 

committed to obtain concrete samples from locations known to have been wetted by borated 

water and to test them for compressive strength and perform a petrographic examination 

(Commitment 44). The applicant has also committed to performing petrographic examinations 

on any sample pieces removed from Sump C which are suitable for examination (Commitment 
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41). These tests will provide assurance that the borated water leakage has not caused 

significant degradation of the concrete. The petrographic examinations will also indicate the 

presence of any interaction between the borated water and the cementitious materials in the 

concrete that might lead to degradation. If any of the concrete tests or examinations indicates 

degradation, the results will be entered into the Corrective Action Program and reviewed for 

structural impacts prior to the period of extended operation. In addition, the observed white 

deposits, which could be signs of possible concrete interaction with the leakage, are minimal 

and only indicate a possibility of negligible concrete material loss. No indications of significant 

washout or dissolution of the concrete have been observed.

Based on the applicant’s existing repair plan and commitments, the staff concludes there is 

reasonable assurance the Structures Monitoring Program and the ASME Section XI, Subsection 

IWE Program will adequately manage the aging effects of the interior containment structures 

and the containment vessel during the period of extended operation.

On the basis of its review, including the information provided during the public meeting and RAI 

responses, as well as the new commitments, 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 element acceptable, and OI 3.0.3.2.17-1 is closed.

UFSAR Supplement. In LRA Section A2.38, the applicant provided the UFSAR supplement for 

the Structures Monitoring Program. The staff reviewed this section and determines that the 

information in the UFSAR 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, including review of the RAIs discussed above and the new Commitments 41, 42, and 

44, 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 

enhancements and confirmed that their implementation through Commitment 30 prior to the 

period of extended operation would make the existing AMP consistent with the GALL AMP to 

which it was compared. Based on the resolution of OI 3.0.3.2.17-1, the staff concludes that the 

applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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 Water Chemistry Control Program

Summary of Technical Information in the Application. LRA Section B2.1.40 describes the 

existing Water Chemistry Program as consistent, with exceptions and enhancement, with the 

GALL AMP XI.M2, “Water Chemistry.” The applicant stated that the Water Chemistry Program 

manages aging effects by controlling the internal environment of systems and components and 

that the Water Chemistry Program mitigates corrosion, SCC, and heat transfer degradation due 

to fouling in the primary, auxiliary (borated), and secondary water systems included within the 

scope of the program. The applicant further stated that the program manages aging effects by 

controlling concentrations of known detrimental chemical species below the levels known to 
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cause degradation. The applicant stated that the program includes specifications for chemical 

species, sampling and analysis frequencies, and corrective actions for control of water 

chemistry, and that the program conforms to both the EPRI “PWR Primary Water Chemistry 

Guidelines” and the EPRI “PWR Secondary Water Chemistry Guidelines.”

Staff Evaluation. During its audit and review, the staff confirmed the applicant’s claim of 

consistency with the GALL Report. The staff reviewed the exceptions and enhancement to 

determine whether the AMP, with the exceptions and enhancement is adequate to manage the 

aging effects for which the LRA credits it.

The staff reviewed the applicant’s program basis document, on-site procedures, corrective 

action reports, and other plant documents that were included in the applicant’s license renewal 

program basis document binder for the Water Chemistry Program and that contained 

information supporting the applicant’s evaluation of this AMP.

The staff noted that the applicant’s plant procedures require water chemistry control in 

accordance with EPRI 1002884, “PWR Primary Water Chemistry Guidelines,” Revision 5, and 

EPRI 1008224, “PWR Secondary Water Chemistry Guidelines, Revision 6, which are more 

recent revisions of the EPRI PWR water chemistry guidelines than referenced in the GALL 

Report. The primary water chemistry guidelines are applied to the reactor coolant (primary 

water) and auxiliary systems containing borated water that interface with the reactor coolant 

system. The secondary water chemistry guidelines are applied to water in the feedwater, 

condensate and steam generator blowdown systems. The applicant’s Water Chemistry Program 

mitigates aging effects by controlling the chemical environment of systems and components 

exposed to primary and secondary water sources. The program relies upon inspection activities 

of other programs to confirm effectiveness of aging effect mitigation. The staff found these 

features of the applicant’s Water Chemistry Program, including use of EPRI’s more recent water 

chemistry guidelines, to be consistent with recommendations in the GALL Report.

The staff noted that the applicant’s Water Chemistry Program includes specifications for 

chemical species, sampling and analysis frequencies, and acceptance limits. These 

requirements are contained in plant procedures and typically are identical to or more restrictive 

than the requirements in the EPRI guidelines, except as noted subsequently in this SER 

section. Corrective actions are required for chemistry conditions that do not meet acceptance 

conditions consistent with Action Levels and recommendations of the EPRI guidelines. The staff 

noted that the applicant uses both continuous in-process and periodic sampling techniques, and 

additional sampling and testing is performed when unexpected results are obtained. The staff 

finds these features of the applicant’s Water Chemistry Program to be consistent with 

recommendations in the GALL Report.

During the on-site review the staff noted that there are differences between the water chemistry 

diagnostic parameter measurements recommended in EPRI water chemistry guidelines 

referenced by the applicant and the water chemistry diagnostic parameter measurements as 

implemented by the applicant’s Water Chemistry Program. These differences were identified by 

the applicant in their license renewal program basis document, but they were not listed in the 

LRA as exceptions to the GALL Report’s recommendations. In a letter dated November 5, 2008, 

the staff issued RAI AMP B2.1.40-1 asking the applicant to explain why differences from the 

diagnostic parameter recommendations in the EPRI water chemistry guidelines are not 
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identified in the LRA as exceptions to the GALL Report and to justify that with these differences 

the Water Chemistry Program provides adequate aging management for affected components 

during the period of extended operation.

The applicant responded to RAI AMP-B2.1.40-1 in a letter dated December 5, 2008. In that 

letter the applicant referred to discussions of water chemistry control and diagnostic parameters 

contained in EPRI’s “PWR Primary Water Chemistry Guidelines” and “PWR Secondary Water 

Chemistry Guidelines.” Citing appropriate sections of the EPRI guidelines, the applicant stated 

that water chemistry parameters which require strict control due to material integrity 

considerations and which are needed to manage the effects of aging, are classified as control 

parameters. The applicant also stated that diagnostic parameters are those that provide 

assistance in interpreting chemistry variations but are not required for aging management and 

are not within the scope of the GALL Report’s Water Chemistry program. The applicant further 

stated that deviations in diagnostic parameters are discussed in the Water Chemistry Program 

basis documents but are not identified as exceptions to the GALL Report because strict 

adherence to the EPRI-recommended diagnostic parameter measurements is not required to 

ensure adequate aging management of materials in a treated water environment.

The staff reviewed the applicant’s response together with applicable sections of the EPRI PWR 

water chemistry guidelines. The staff noted that the applicant’s explanation of control and 

diagnostic water chemistry parameters is consistent with the discussions in the EPRI guidelines, 

and that the EPRI guidelines do not require strict adherence to the diagnostic parameter 

measurement recommendations but allow variations based on plant-specific considerations. On 

this basis, the staff finds the applicant’s response with regard to diagnostic parameter 

measurements to be acceptable.

Based on its review and evaluation of the applicant’s response to RAI AMP-B2.1.40, the staff 

finds that the applicant’s response resolves all issues raised in the RAI, and no additional 

exceptions to the GALL Report were identified beyond those stated in the LRA.

Exception 1. LRA Section B2.1.40 states an exception to the “parameters monitored/inspected” 

program element. The exception is that feedwater samples are not monitored for total copper 

content, as recommended by the EPRI’ Secondary Water Chemistry Guideline, because the 

plant is an all-ferrous plant with no copper sources.

During the on-site audit the staff asked the applicant whether there is any plant-specific data to 

confirm that the plant is an all-ferrous plant with no copper sources into the feedwater. In 

response to this request the applicant provided records from recent total metal analyses reports 

showing the measured copper content in the feedwater to be less than 0.005 ppb, the minimum 

detectable level. 

The staff reviewed the applicant’s AMR results for the feedwater system and for the condensate 

system. The staff noted that in the feedwater system there are not any copper alloy, brass or 

bronze components in a treated water environment; however, the staff also noted that the 

condensate system does include some brass and bronze valve bodies in an environment of 

treated water. 
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In a phone conversation dated February 3, 2009, the staff asked the applicant to identify the 

brass and bronze valves in the condensate system and to clarify whether the copper in those 

valves could be a potential source of copper intrusion to the feedwater system. In its response, 

the applicant stated that the valves are small filter vent valves or leak-off valves, which are not 

part of the main condensate-to-feedwater process stream and that the valves would be a highly 

unlikely source of copper intrusion. The applicant also stated that current chemistry department 

practice is to obtain a total metal analysis (including copper) of the feedwater on a weekly basis. 

The staff noted that the EPRI PWR Secondary Water Chemistry Guideline recommends weekly 

sampling for copper in the feedwater and asked the applicant its reason for stating an exception 

with regard to copper sampling. The applicant stated that, although the current practice is to 

take total metal samples weekly that do include total copper content, there is no procedural 

requirement for this frequency. The applicant stated that since there is no procedural 

requirement and copper is a control parameter recommended in the EPRI guideline, they had 

conservatively identified an exception to the GALL Report’s recommendation.

On the basis that the applicant confirms the presence or absence of copper ion in the 

condensate/feedwater systems by performing total metal analyses of condensate/feedwater 

samples taken from the systems, the staff finds that the applicant meets the intent of EPRI 

Secondary Water Chemistry Guidelines to perform monitoring of copper ions such that the 

identification of this as an exception for the application is unnecessary. 

Exception 2. LRA Section B2.1.40 states an exception to the “acceptance criteria” program

element. The exception is that primary water (reactor coolant) dissolved oxygen actions level 

(AL) limits are above the corresponding recommended EPRI guideline limits in EPRI 

TR-1002884, PWR Primary Water Chemistry Guidelines, Revision 5. The applicant stated, 

however, that typical plant oxygen levels are well below the EPRI action level limits and 

hydrogen levels are maintained in the reactor coolant to mitigate oxidizing effects due to 

radiolysis or oxygen ingress.

In a letter dated November 5, 2008, the staff issued RAI AMP-B2.1.40-3 asking the applicant to 

provide a comparison of the dissolved oxygen action level limits in its Technical Requirements 

Manual against the corresponding limits in the EPRI guidelines and to provide a technical 

justification of why the limits in the Technical Requirements Manual provide acceptable aging 

management mitigation during the period of extended operation.

The applicant responded to RAI AMP-B2.1.40-3 in a letter dated December 5, 2008. In that 

letter the applicant provided the following quantitative comparison of reactor coolant system 

dissolved oxygen AL limits.

Source AL 1 AL 2 AL 3

Technical Requirements 

Manual 

(All operating modes with 

reactor coolant system 

temperature greater than 250 

oF.)

--- Limit A < 100 ppb 

(Restore parameter 

within 24 hours)

Limit B < 1000 ppb (Unit 

shutdown to Mode 3 in 

6 hours and Mode 5 in 36 

hours)
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Source AL 1 AL 2 AL 3

EPRI TR-1002884, PWR 

Primary Water Chemistry 

Guidelines, Revision 5

(Power operation, reactor 

critical)

> 5 ppb

(Restore parameter 

within 7 days)

--- > 100 ppb

(Initiate orderly shutdown 

immediately)

Implementing Procedure

(Power operation in Mode 1)

> 5 ppb

(Restore parameter 

within 7 days)

>100 ppb

(Restore parameter 

within 24 hours

>1000 ppb

(Initiate orderly shutdown 

immediately)

In its response the applicant stated that a review of operating data for the last 10 years verified 

that the action level 1 limit of 5 ppb for reactor coolant system dissolved oxygen had not been 

exceeded during power operation. The applicant also stated that it has decided to revise the 

Water Chemistry Program to remove the exception. The applicant further stated that LRA, 

Section B2.1.40, is changed to add an enhancement to the “acceptance criteria” element of the 

Water Chemistry Program to require that reactor coolant system dissolved oxygen action level 

limits be in accordance with EPRI Guideline limits for reactor coolant system power operation 

control parameters. The applicant stated that the exception to the GALL Report with regard to 

primary water dissolved oxygen action limits is removed and the following LRA changes are 

made:

In LRA Section B2.1.40, under Exceptions to NUREG-1801, the first paragraph 

under the second bullet, “Acceptance Criteria,” concerning primary water 

dissolved oxygen is deleted.

In LRA Section B2.1.40, under Enhancements, a new second bullet is added to 

read as follows: “Acceptance Criteria. The program will be enhanced to require 

Reactor Coolant System dissolved oxygen Action Level limits to be consistent 

with the limits established in the EPRI PWR Primary Water Chemistry 

Guidelines.”

The applicant also stated that Commitment No. 32 contained in the Preliminary License 

Renewal Commitment List included in the LRA transmittal letter dated April 11, 2008, is revised 

to state that the Water Chemistry Program will be enhanced to require that reactor coolant 

system dissolved oxygen action level limits be consistent with the limits established in the EPRI 

PWR Primary Water Chemistry Guidelines.

The staff reviewed the applicant’s response and the proposed LRA changes. The staff noted 

that by deleting Exception 2 from the LRA and providing a new enhancement to require that 

reactor coolant system dissolved oxygen action level limits be consistent with the limits 

established in the EPRI PWR Primary Water Chemistry Guidelines, the applicant is committing 

to eliminate the difference between its procedural limits on dissolved oxygen and the limits as 

recommended in EPRI guidelines. This change will result in this feature of the applicant’s Water 

Chemistry Program being consistent with the recommendations in GALL AMP XI.M2, “Water 

Chemistry.”

The staff finds the applicant’s action levels for dissolved oxygen to be acceptable because the 

applicant has amended the LRA to make these actions levels consistent with the EPRI PWR 
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Primary Water Chemistry Guidelines and because this is consistent with the recommendations 

in the GALL AMP XI.M2 to use these guidelines for primary coolant chemistry monitoring.

In a letter dated December 5, 2008, the applicant revised Commitment No. 32 of the list of 

“Preliminary License Renewal Commitments” to include a statement that the Water Chemistry 

Program will require reactor coolant system dissolved oxygen Action Level limits to be 

consistent with the limits established in the EPRI PWR Primary Water Chemistry Guidelines. 

The staff noted that implementation of this commitment is scheduled prior to the beginning of 

the period of extended operation. The staff finds this revised commitment acceptable because it 

ensures that this feature of the applicant’s Water Chemistry Program is consistent with the 

recommendations in the GALL AMP XI.M2.

Based on its review of Exception 2 and changes made to the LRA in response to RAI AMPB2.1.40-3, including the applicant’s revision to Commitment No. 32, the staff finds the affected 

features of the applicant’s Water Chemistry program to be consistent with the GALL 

AMP XI.M2, and therefore to be acceptable.

Exception 3. LRA Section B2.1.40 states an exception to the “acceptance criteria” program 

element in that feedwater hydrazine levels during heatup, hot shutdown, and startup (Modes 2, 

3, and 4) are maintained greater than 100 ppb, which is higher, and more conservative than the 

20 ppb recommended by the EPRI guidelines.

The staff noted that the applicant has recirculating steam generators and reviewed the 

feedwater hydrazine control parameter limit in EPRI’s Pressurized Water Reactor Secondary 

Water Chemistry Guidelines, Revision 6, Table 5-2, Recirculating Steam Generator Heatup/Hot 

Shutdown and Startup Feedwater Sample. The staff noted that the hydrazine control parameter 

limit recommended in the EPRI report is a minimum concentration of 20 ppb. The staff also 

noted that the applicant uses hydrazine for oxygen control, not for pH control, and that an upper 

limit on hydrazine content is not specified in the EPRI guidelines when it is used for oxygen 

control. Because the applicant’s feedwater minimum hydrazine limit is 100 ppb, which is greater 

than 20 ppb and conservative relative to EPRI’s recommended minimum hydrazine 

concentration, the staff finds Exception 3 to the “acceptance criteria” program element to be 

acceptable.

Enhancement 1. LRA Section B2.1.40 states an enhancement to the “monitoring and trending” 

program element, to be implemented prior to the period of extended operation. The applicant 

stated that the program will be enhanced to require increased sampling to be performed as 

needed to confirm the effectiveness of corrective actions taken to address an abnormal 

chemistry condition. The applicant’s Preliminary License Renewal Commitment List, 

Commitment No. 32, includes a commitment to enhance the Water Chemistry Program to 

require increased sampling to be performed as needed to confirm effectiveness of corrective 

actions taken to address an abnormal chemistry condition.

In a letter dated November 5, 2008, the staff issued RAI AMP-B2.1.40-2 asking the applicant to 

explain what the current practices and procedural requirements are with regard to increased 

chemistry sampling after corrective actions are taken and to describe how procedures would be 

revised to implement the proposed enhancement.
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The applicant responded to RAI AMP-B2.1.40-2 in a letter dated December 5, 2008. In that 

letter the applicant provided an outline of the actions required by current sampling procedures 

and stated that the need to conduct increased sampling is currently implemented through 

Chemistry History and Records Management Software (CHRMS), and special sampling 

requirements are implemented through the issuance of a Chemistry Manager’s Special 

Sampling Report. The applicant stated that the enhancement is needed to ensure that the 

requirement to use increased sampling following an abnormal chemistry condition is formally 

documented in plant procedures.

The staff finds the applicant’s response to RAI AMP-B2.1.40-2 and Enhancement 1 to be 

acceptable because the enhancement revises existing plant procedures to formally incorporate 

increased sampling and testing criteria that are consistent with the sampling and testing 

recommendations in the “monitoring and trending” program element of the GALL AMP XI.M2, 

and because the applicant has reflected this enhancement of the program in LRA Commitment 

No. 32, which was placed on UFSAR Supplement section A2.40. 

Based on this review, the staff finds that the applicant’s Water Chemistry program, when 

enhanced by Commitment No. 32, is acceptable based on the following conclusions: (1) with the 

exception of the specific exceptions taken against particular program element recommendations 

in the GALL AMP XI.M2, “Water Chemistry” (as evaluated previously), the staff has verified that 

the program elements for the Water Chemistry Program are consistent with those 

recommended in the GALL AMP XI.M2; (2) the applicant has provided an adequate basis that 

the exceptions taken to the GALL AMP XI.M2 are acceptable and will achieve an acceptable 

level of prevention or mitigation for those aging effects that are induced by chemistry-related 

initiated mechanisms (e.g., loss of material initiated by general, pitting or crevice corrosion or 

cracking that is initiated by stress corrosion or any of its forms); and (3) consistent with 

applicable AMR items in the LRA that couple the applicant’s implementation of the Water 

Chemistry Program to a One-Time Inspection, the applicant will implement one-time inspections 

of the components in these AMRs in order to verify that the Water Chemistry Program is 

achieving its preventive or mitigative objectives.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.40. The 

applicant stated that a review of OE for the Water Chemistry Program identified no adverse 

trends or issues, but that some instances have occurred where chemistry parameters did not 

meet limits. The applicant stated that the plant has taken timely and effective corrective action in 

these cases and that many of these conditions were the result of equipment or plant transient 

conditions, such as plant startup, that were resolved once the transient condition subsided. The 

applicant stated that the time durations of these conditions were typically short and that no 

examples of component functional failures due to corrosion, cracking, or heat transfer 

degradation resulting from inadequate chemistry controls were identified.

The applicant stated that with the exception of the Unit 1 chemistry performance index, no 

adverse trends in water chemistry were identified by review of recent sampling results. The 

Unit 1 chemistry performance index demonstrated an adverse trend due to higher than desired 

sulfate levels. This issue was documented in the site’s Corrective Action Program, a 

troubleshooting plan was prepared and implemented, and the source of the elevated sulfate 

was identified as main condenser tube leakage. The applicant stated that actions were taken to 

identify and correct the specific location of the leakage during a scheduled plant down power to 
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access the main condenser tubes for testing and repair and that the chemistry performance 

index was restored to an acceptable value.

The staff reviewed the OE discussion that was provided in the applicant’s license renewal 

program basis document binder for the Water Chemistry Program. The staff confirmed that the 

applicant’s review of OE included evaluation of both industry and plant-specific events that have 

occurred since issuance of the GALL Report, Revision 1. The staff reviewed additional selected 

corrective action reports (ARs) related to the applicant’s Water Chemistry Program and 

interviewed the applicant’s subject matter experts for the Water Chemistry Program. Corrective 

action reports reviewed by the staff included ones where the applicant found species monitored 

and controlled by the Water Chemistry Program to be out of specification or trending in an 

undesirable direction. For all corrective actions reviewed, the staff noted that the applicant had 

performed adequate evaluations to determine a cause for the event and had taken corrective 

action adequate to restore operation within specification or stop continuation of an undesirable 

trend. Based on its review of the plant-specific OE, the staff finds that the applicant’s program 

has demonstrated its capability to monitor, trend and control water chemistry parameters 

consistent with recommendations of the EPRI guidelines referenced in the GALL Report, and to 

implement corrective actions adequate to prevent loss of license renewal intended functions for 

components and systems affected by the Water Chemistry Program.

Based on this review, the staff finds (1) that the OE for this AMP demonstrates that the 

applicant’s Water Chemistry Program is achieving its objective of managing aging by controlling 

the internal environment of systems and components so as to mitigate the aging effects of 

cracking, loss of material, or reduction of heat transfer due to fouling for materials exposed to 

primary, auxiliary, and secondary treated water, and (2) that the applicant is taking appropriate 

corrective actions when deficiencies are found through implementation of this 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 

element acceptable.

UFSAR Supplement. In LRA Section A2.40, the applicant provided the UFSAR supplement for 

the Water Chemistry Program. The staff verified that the UFSAR supplement summary for the 

Water Chemistry Program conforms with the staff’s recommended UFSAR supplement for this 

type of program as described in the SRP-LR. 

In its letter dated April 13. 2009, the applicant provided a list of license renewal commitments. 

The staff verified that the applicant has included the program enhancements identified in the 

LRA for the Water Chemistry Program in Commitment No. 32 of the final list of license renewal 

commitments.

Based on this review, the staff finds that the UFSAR supplement summary in LRA 

Section A2.40 provides an acceptable description of the applicant’s Water Chemistry Program 

because it is consistent with the UFSAR supplement summary description recommended in the 

SRP-LR for a Water Chemistry Program and because the applicant has appropriately included 

all program enhancements in the License Renewal Commitment list, Commitment No. 32 which 

is linked with UFSAR supplement Section A.2.40 and scheduled for implementation prior to the 

period of extended operation.
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The staff determines that the information in the UFSAR supplement is an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Program 

and the applicant’s responses to RAIs AMP-B2.1.40-1, AMP-B2.1.40-2 and AMP-B2.1.40-3, the 

staff finds that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. The staff also reviewed the exceptions and their justifications and 

determines that the AMP, with the exceptions, is adequate to manage the aging effects for 

which it is credited. In addition, the staff reviewed the enhancements and confirms that their 

implementation through license renewal Commitment No. 32, prior to the period of extended 

operation, makes the existing AMP consistent with the GALL AMP to which it was compared, 

with acceptable exceptions. The staff concludes that the applicant has demonstrated that the 

effects of aging will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3). The staff also reviewed the UFSAR 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 Metal Fatigue of Reactor Coolant Pressure Boundary 

Summary of Technical Information in the Application. LRA Section B3.2 describes the PINGP

Metal Fatigue of Reactor Coolant Pressure Boundary Program as an existing program. The 

applicant also states that the program will be enhanced to be consistent with the

recommendations described in the GALL AMP X.M1: Metal Fatigue of Reactor Coolant 

Pressure Boundary. 

The applicant states that the PINGP Metal Fatigue of Reactor Coolant Pressure Boundary 

Program monitors the thermal and pressure transients experienced at the selected RCS 

pressure boundary components to ensure those components remain within their design fatigue 

usage limits. The applicant also states that the program tracks the plant temperature and 

pressure transients to ensure that design assumptions for cumulative transient cycles are not 

exceeded. The applicant further states that the PINGP Metal Fatigue of Reactor Coolant 

Pressure Boundary Program has included monitoring the six component locations for older 

vintage Westinghouse plants identified in NUREG/CR-6260 as representative locations for the 

effect of reactor coolant environment on component fatigue life.

The applicant indicates that the PINGP Metal Fatigue of Reactor Coolant Pressure Boundary 

Program ensures that cumulative fatigue usage of each affected primary system location is 

evaluated, and corrective actions taken if necessary, when the number or magnitude of 

accumulated thermal and pressure transients approach or exceed design cycle assumptions, or 

when the projected fatigue usage approaches a value of 1.0, during the life of the plant including 

the period of extended operation.

Staff Evaluation. During the onsite audit and review of the LRA, the staff confirmed the 

applicant’s claim of consistency with the GALL Report. 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 also interviewed the applicant’s technical staff and reviewed 
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the basis documents related to the PINGP Metal Fatigue of Reactor Coolant Pressure Boundary 

Program, including the license renewal program evaluation report in which the applicant 

assessed whether the program elements are consistent with the GALL AMP X.M1.

The staff noted that the program description stated in PINGP LRA Section B3.2 includes a 

statement: “The program also uses computerized cycle-based or stress-based monitoring 

methods to track fatigue usage in critical high-usage components." However, as a result of the 

RAI 4.3.1.1-1, all references to stress-based monitoring were removed. For details about RAI 

4.3.1.1-1 and its impact to the PINGP LRA, please see Sections 4.3.1.1.2 and 4.3.1.3.2. 

The staff noted that AMP B3.2 relies on transient cycle monitoring to evaluate the fatigue usage 

described in the LRA. In LRA Section 4.3, the applicant indicates that this approach tracks the 

number of occurrences of significant thermal and pressure transients and compares the 

cumulative cycles, projected to cover the renewal period, against the number of design cycles 

specified in the design specifications. The applicant used the projected cycles to evaluate the 

total cumulative usage factor for 60 years. The staff noted that for this approach to work, none 

of the significant events tracked should produce stresses greater than those that would be 

produced by the design transients, not just the number of cycles alone. Namely, the staff noted

that the temperature and pressure characteristics, including their values, ranges, and rates, 

must all be bounded within those defined in the design specifications.

During the onsite audit, the staff interviewed the PINGP plant engineers concerning the 

transient monitoring method and procedures and reviewed the results. During the review of the 

LRA, the staff determined additional information in this regard is necessary to facilitate its 

evaluation of the fatigue management program. Therefore, the staff issued RAI 4.3.1-1, by letter 

dated February 20, 2009, in which, the staff requested the applicant to provide its basis for 

justifying that the monitored transient data remains bounded by those defined in the design 

specification.

In its response to RAI 4.3.1-1, dated February 26, 2009, the applicant stated that PINGP 

surveillance procedure requires that records be kept of the applicable thermal and pressure 

transients and these records are maintained as ongoing transient summary sheets contained in 

the procedure itself. The applicant also stated that the PINGP surveillance procedure lists the 

design pressure and temperature transients from UFSAR Section 4.1.4, and contains a 

summary sheet for each design transient which lists every cycle counted for that transient. The 

applicant further states that at least once each quarter, the program owner conducts a review of 

plant operating records to determine if a “cycle” has occurred for any of the design pressure or 

temperature transients. Then, the program owner will add the event to the proper cycle 

summary sheet along with a brief description of the transient cycle, if a cycle has occurred.

The applicant stated that the majority of transient cycles logged to date have been associated 

with heatup, cooldown and reactor trip events. The applicant stated that the historic averages of 

the PINGP plant heatup and plant cooldown temperature rates were approximately 40 o

F/hr and 

70 o

F/hr, respectively. As for the reactor trip events, the applicant stated that approximately 65

percent of the reported reactor trip events in both units have occurred from an initial power level 

between 75% and 100% power and the remaining 35 percent of reactor trip events occurred 

from an initial power level lower than 75 percent of full power. For design purposes, the reactor 
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trip transient is based on a trip from 100 percent power conditions. Therefore, the applicant 

states that the actual plant heatup, cooldown and reactor trip events are all bounded by the 

design transients.

The applicant further states that if a design limit for the number or severity of a transient were 

exceeded, a Corrective Action Program (CAP) entry would be initiated to determine the effects 

on system components. And the corrective action potentially includes reanalysis, repair, or 

replacement of the affected components, and assessment of additional pressure boundary 

locations that may be affected.

Based on its review, the staff finds the applicant’s response to RAI 4.3.1-1 acceptable because:

(1) PINGP has developed Metal Fatigue of Reactor Coolant Pressure Boundary Program to 

appropriately track the number of occurrences of design cycles, (2) PINGP has developed 

Technical Specifications and surveillance procedures to ensure that components are maintained 

within the design limits, (3) PINGP has acquired records of major thermal events such as 

heatup, cooldown and reactor trip transients confirming that the temperature and pressure

values experienced by the PINGP structural components are bounded by the design transients, 

(4) PINGP has developed a Corrective Action Program, which initiates and determines 

appropriate actions to be taken if abnormal situations should occur, and the operational 

procedures that PINGP adopts for the transient events tracking are consistent with the GALL 

Report and conservative to ensure a valid fatigue management program.

The staff notes that RAI 4.3.1-1 and the applicant response to this RAI are discussed in greater 

details in SER Section 4.3.1.

Enhancement. The applicant stated in LRA Section B3.2 that PINGP Metal Fatigue of Reactor 

Coolant Pressure Boundary Program will be enhanced in three areas: (1) monitoring of the six 

component/locations identified in NUREG/CR-6260, as applicable to PINGP; (2) implementing 

stress-based fatigue usage monitoring for selected locations subject to pressurizer 

insurge/outsurge transients; (3) Reducing cycle limit of the plant loading (at 5 percent per 

minute) and plant unloading (at 5 percent per minute) to 1835 cycles just so fatigue requirement 

for the RV internals baffle bolts is satisfied. 

The staff noted that the enhancements stated in the LRA have been revised as a result of the 

RAI 4.3.1.1-1. The staff noted that RAI 4.3.1.1-1 and the applicant response to this RAI are 

discussed in greater details in SER Section 4.3.1.1. In the new version, for Area (1) of the 

enhancement (monitoring of the NUREG/CR-6260 locations), the “monitoring type” assignment 

to each of the six NUREG/CR-6260 locations is dropped. Previously, three monitoring types 

were indicated among the six NUREG/CR-6260 locations. Specifically, two of those six 

components/locations were assigned to stress-based fatigue usage monitoring, another two 

locations were assigned to cycle-based fatigue usage monitoring, and the remaining two 

locations were assigned to cycle counting. Area (2) of the enhancement (implementing stressbased fatigue usage monitoring) is now completely removed. The staff noted that dropping out 

from enhancement does not mean fatigue requirement for the affected components is ignored.

Fatigue requirement for the affected components are addressed in the appropriate subsections 

under SER Section 4.3. 
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Based on its review of the program, the staff finds the enhancement described in this section 

acceptable because it is consistent with the GALL AMP X.M1 guidance to address the light 

water reactor environment effects on fatigue life of structural components. All changes made to 

the enhancement to remove the reference to (or performance of) stress-based fatigue 

monitoring, are necessary because FatiguePro (analytical software PINGP selected for 

performing the stress-based monitoring) does not follow the NRC endorsed ASME guidelines in 

evaluating fatigue usage. The staff noted that the changes mentioned here are caused by the 

issue described in RAI 4.3.1.1-1. The other part of the changes made to the enhancement,

which was removing the “monitoring type” assignment for each of the NUREG/CR-6260 

components/locations, is acceptable because all of the 6 components are now evaluated 

following the ASME Section III subsection NB guidelines based on the monitored transient 

cycles along with the guidelines in NUREG/CR-6583 and NUREG/CR-5704 to address the 

environmental effects.

Reactor internals baffle bolt fatigue transient limits of 1835 cycles of plant loading at 5 percent

per minute and 1835 cycles of plant unloading at 5 percent per minute will be incorporated into 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program and UFSAR Table 4.1-8 to 

conform to the baffle bolt fatigue limits discussed in LRA Section 4.3.1.2, RVIs.

On area (3) of the enhancement (reducing cycle limit of the plant loading/unloading transients), 

the applicant described the reason for the necessity of a reduction in cycle limit for these 

particular transients for this particular component (RV internals baffle bolts) in LRA Section 

4.3.1.2. Details of the staff review of the subject are shown in SER Section 4.3.1.2.2. On the 

basis of its review, the staff found the applicant’s request of cycle limit reduction acceptable for 

the reasons described in SER Section 4.3.1.2.2. The applicant will incorporate the new limit into 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program as stated in Commitment No.

34.

Operating Experience. The staff also reviewed the OE described in LRA Section B3.2. The 

applicant stated that it has reviewed the OE associated with the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program and indicates the PINGP program has demonstrated the 

ability to effectively monitor plant transients and track the accumulation of these transients.

The applicant indicated that PINGP has factored industry experience into its program, including 

evaluation of thermal/operating stresses that were not considered in the original design such as

evaluation of Pressurizer Surge Line Thermal Stratification which is described in NRC Bulletin 

88-11 and is in progress to implement EPRI guidelines provided in “Management of Thermal 

Fatigue in Normally Stagnant Non-Isolable RCS Branch Lines," which is contained in EPRI 

Report MRP-146. The staff noted that MRP-146 presents guidelines for screening, evaluating 

and inspecting potential thermal fatigue cracking issues due to swirl penetration and/or valve inleakage that may occur in normally stagnant non-isolable piping systems attached to 

pressurized water reactor coolant system (PWRCS) piping. As stated in MRP-146, the objective 

of these guidelines is to provide a common industry approach to reduce the probability of 

cracking and leakage from piping potentially susceptible to thermal fatigue.

The applicant indicated that it has performed evaluation of the effects of light water reactor 

environment on fatigue life of structural components for the six NUREG/CR-6260 components 

(or locations) applicable to PINGP. The applicant indicated that in performing the environmental 
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fatigue analyses, PINGP first has to calculate the fatigue usage under the air environment for 

three of the NUREG/CR-6260 component locations (charging nozzle, safety injection nozzle, 

and residual heat removal Class 1 piping tee). That was because these three components were 

designed in accordance with B31.1.0 and so no explicit fatigue analysis was required in the 

original design report. As a result, fatigue monitoring is now expanded to include locations not 

previously monitored by the cycle counting program.

UFSAR Supplement. In LRA Section A.4.2, the applicant provided the UFSAR supplement for 

the Metal Fatigue of Reactor Coolant Pressure Boundary Program. The staff also verified that in 

Commitment Nos. 33 and 34 the applicant has committed to the enhancement of the program 

which is scheduled for implementation prior to the period of extended operation (August 09, 

2013, for Unit 1 and October 12, 2014, for Unit 2). The staff reviewed UFSAR Supplement 

section and determines that the information in the UFSAR 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, including the applicant’s responses to RAIs 4.3.1.1-1 and 

4.3.1-1, the staff concludes 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 its implementation prior to the period of extended operation through 

Commitment Nos. 33 and 34 would make the existing AMP consistent with the GALL AMP. The 

staff concludes that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

UFSAR supplement for this AMP and determined that it provides an adequate summary 

description of the program, as required by 10 CFR 54.21(d).

3.0.3.3 AMPs Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, as amended by letters dated March 27, 2009 and May 12, 2009, the 

applicant identified the following AMPs as plant-specific AMPs for the LRA:

• AMP B2.1.27, Nickel-Alloy Nozzles and Penetrations Program

• AMP B2.1.32, PWR Vessel Internals Program

For AMPs not consistent with or not addressed in the GALL Report the staff performed a 

complete review to determine their adequacy to monitor or manage aging. The staff’s review of 

these plant-specific AMPs is documented in the following sections.

3.0.3.3.1 Nickel-Alloy Nozzles and Penetration Program

Summary of Technical Information in the Application. By letter dated March 27, 2009, the 

applicant amended the Nickel-Alloy Nozzles and Penetrations Program to redefine the program 

as an existing plant-specific AMP for the LRA that incorporates the ten program elements for 

AMPs, as recommended in SRP-LR Appendix A, Section A.1.2.3, and to delete the commitment 

in the previous version of the AMP and in LRA Commitment No. 21 from the scope of the LRA. 
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LRA Section B2.1.27, as amended in the letter dated March 27, 2009, describes the existing 

Nickel-Alloy Nozzles and Penetration Program as a plant-specific AMP for those ASME Code 

Class 1 nickel-alloy base metal and weld components. In this amended version of the AMP, the 

applicant defined the AMP in terms of the 10 program elements that are recommended for 

AMPs, as recommended in subsections of SRP-LR Appendix A, Section A.1.2.3 and how the 

program elements for this AMP are designed to conform to the general program element 

recommendations for condition monitoring programs, as given in the general recommendations 

for AMP program elements in SRP-LR Appendix A, Section A.1.2.3 and its subsections. 

Staff Evaluation. The staff noted that the original version of the applicant’s Nickel-Alloy Nozzles 

and Penetration Program indicated that the program will comply with all NRC Orders Generic 

Letters, and Bulletins related to PWSCC of nickel-alloys, and that the applicant reflected these 

activities as an LRA enhancement that is defined in LRA Commitment No. 21,

The staff also noted that by letter dated March 27, 2009, the applicant amended AMP B2.1.27, 

Nickel-Alloy Nozzles and Penetrations Program, to redefine the program as an existing plantspecific AMP for the LRA that incorporates the ten program elements for AMPs, as 

recommended in SRP-LR Appendix A, Section A.1.2.3, and to delete the commitment in the 

previous version of the AMP and in Commitment No. 21 from the scope of the LRA.

The staff reviewed the program elements for the Nickel-Alloy Nozzles and Penetration Program 

against the AMP program elements found in the in SRP-LR, Appendix A, Section A.1.2.3, and in 

SRP-LR Table A.1-1, focusing on how the program manages aging effects through the effective 

incorporation of 10 program elements. For the staff’s review, the staff reviewed the “scope of 

program," “preventive actions,” “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” “corrective actions elements against 

the staff’s corresponding recommendations for these program elements in SRP-LR Appendix A, 

Section A.1.2.3. The staff’s evaluations on these eight program elements are given in the 

paragraphs that follow. The staff evaluated the AMP’s “confirmation process,” and 

“administrative controls” program elements as part of the staff’s review of the applicant’s Quality 

Assurance Program and Administrative Controls, which is given in LRA Section B1.3 and which 

is evaluated in SER Section 3.0.4. 

Scope of the Program. LRA Section B2.1.27 states that the program manages the aging effect 

of cracking due to primary water stress corrosion cracking (PWSCC) of pressure boundary and 

structural components constructed of Alloy 600 and welds constructed of the associated Alloy 

82/182 filler metals exposed to primary coolant. The staff noted that the “scope of program” 

program element also stated that the scope of the Nickel-Alloy Nozzles and Penetrations 

Program includes the 36 Alloy 600 reactor vessel (RV) bottom mounted instrumentation (BMI) 

nozzles and in each unit, the four (4) Alloy 600 RV core support pads in each Unit; and the Unit 

2 pressurizer surge nozzle-to-safe end dissimilar metal weld (Alloy 82). The staff noted that the 

applicant indicated that its program is based upon the industry guidance provided in EPRI MRP126, “Generic Guidance for Alloy 600 Management” [EPRI Report TR-1009561, November 

2004], and in NEI 03-08, “Guideline for the Management of Materials Issues" [May 2003]. The 

staff noted that the applicant indicated that the program complies with applicable NRC Orders, 

and implements applicable NRC Bulletins, Generic Letters, and staff-accepted industry 

guidelines.
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The staff reviewed the applicant’s “scope of the program” program element against the criteria 

in SRP-LR Section A.1.2.3.1, which states that the “specific program necessary for license 

renewal should be identified,” and that the “scope of the program should include the specific 

SCs of which the program manages aging.” 

In the statement of consideration (SOC), 73 Federal Register 52736-50, on the updates of 

10 CFR 50.55a, “codes and standards,” the staff mandated new augmented inspection 

requirements for ASME Code Class 1 non-upper reactor vessel closure head (RVCH) 

penetration nozzles components that are made from either Alloy 600 Inconel base metals 

or Alloy 82 or 182 Inconel weld filler metals. The staff noted that the updated rule imposes 

new augmented bare metal visual examinations requirements pursuant to the methods and 

criteria in ASME Code Case N-722, as defined, referenced and subject to the additional 

conditions in 10 CFR 50.55a(g)(6)(ii)(E).

The staff noted that the applicant’s “scope of program” clearly identified that the scope of 

the AMP includes those ASME Code Class 1 components that are fabricated either from 

Alloy 600 based metal materials or Alloy 82 or 182 weld filler metal materials, including the 

Alloy 600 BMI nozzles, RV core support pads at Units 1 and 2, and the Unit 2 Alloy 82 

pressurizer surge line safe end nozzle weld. The staff finds the identification of these 

components as being within the scope of the Nickel-Alloy Nozzles and Penetrations 

Program is acceptable because it is in conformance with the components that are within the 

scope of the new augmented inspection rule for ASME Code Class 1 nickel-alloy 

components made from either Alloy 600 Inconel base metal materials or Alloy 82 or 182 

Inconel weld filler metal materials.

The staff also noted that, in other program elements for this AMP, the applicant identified 

that the program includes augmented inspection criteria for those components that have 

been repaired with full structural weld overlays (FSWOLs) made of Alloy 52 or 152 Inconel 

weld filler metal materials. Thus, based on these additional program element criteria, the 

staff confirmed that the scope of applicant’s Nickel-Alloy Nozzles and Penetrations Program 

also includes those components that have been repaired by FSWOLs made from these 

materials. The staff finds this to be an acceptable augmentation of the “scope of program” 

program element because it includes nickel-alloy weld filler metal components that go 

beyond those that would be required to be included in the AMP under the augmented 

inspection requirements of 10 CFR 50.55a(g)(6)(ii)(E).

The staff noted that the applicant did not identify that the Unit 1 pressurizer surge line safeend weld was within the scope of this AMP. However, the staff confirmed that 

WCAP-14574-A identifies that the Unit 1 pressurizer surge line safe-end nozzle weld is 

made of stainless steel weld filler metal that has been heat treated to minimize weld 

sensitization. The staff approved WCAP-14575-A in safety evaluation (SE) dated May 30, 

1997. Based on this review, staff finds that the applicant has provided an acceptable basis 

for omitting the Unit 1 pressurizer surge line safe-end nozzle weld from the scope of this 

AMP because it is in conformance with the basis in WCAP-14574-A that this Unit 1 weld is 

not fabricated from either Alloy 82 or 182 Inconel weld filler metal materials or Alloy 52 or 

152 improved Inconel alloy weld filler metals.
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The staff confirmed that the “scope of the program” program element satisfies the criterion 

defined in the GALL Report and in SRP-LR Section A.1.2.3.1. The staff finds this program 

element acceptable.

Preventive Actions. LRA Section B2.1.27 states that the effects of PWSCC on the Unit 2 

pressurizer surge nozzle weld (Alloy 82), are mitigated with a full structural weld overlay 

(FSWOL) on the pressurizer surge nozzle-to-safe end dissimilar metal and safe end-to-reducer 

stainless steel butt welds. The applicant further stated that the FSWOL was installed using Alloy 

52M weld material during the Unit 2 refueling outage (2R25) in October 2008. The applicant 

also stated that preventive measures to mitigate PWSCC are in accordance with the PINGP 

Water Chemistry Program which controls concentrations of known detrimental chemical species 

such as chlorides, fluorides, sulfates and dissolved oxygen below the levels known to cause 

degradation in accordance with the EPRI PWR Primary Water Chemistry Guidelines.

The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that (1) the activities for prevention and mitigation 

programs should be described, and (2) for condition or performance monitoring programs that 

do not rely on preventive actions, and thus, preventive actions need not be provided.

The staff confirmed that the Nickel-Alloy Nozzles and Penetration Program provides for 

preventive actions to minimize PWSCC, mitigative techniques such as weld overlay repair using 

a PWSCC resistant material (i. e. Alloy 52M) are employed and chemical species that promote 

PWSCC are controlled in accordance with industry standards. 

The staff confirmed that the “preventive actions” program element satisfies the criterion defined 

in the GALL Report and in SRP-LR Section A.1.2.3.2. The staff finds this program element 

acceptable.

Parameters Monitored or Inspected. LRA Section B2.1.27 states the Nickel-Alloy Nozzles and 

Penetrations Program monitors for cracking due to PWSCC of Alloy 600/82/182 materials 

exposed to primary coolant through visual examinations for boric acid residues or corrosion 

products on the lower reactor vessel head surface and each bottom-mounted instrumentation 

tube penetration which are indications of leakage of primary coolant caused by PWSCC. The 

core support pads and the Unit 2 pressurizer surge nozzle-to-safe end weld are monitored for 

evidence of cracking of the Alloy 600/82/182 materials in accordance with the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program.

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR Section A.1.2.3.3, which states that:

(1) the parameters to be monitored or inspected should be identified and linked to the 

degradation of the particular structure and component intended function(s). 

(2) for condition monitoring program, the parameter monitored or inspected should detect 

the presence and extent of aging effects.

(3) for performance monitoring program, a link should be established between degradation 

of the particular structure or component intended function(s) and the parameter being 

monitored.
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(4) for prevention and mitigation programs, the parameter monitored should be the specific 

parameter being controlled to achieve prevention or mitigation of aging effects. 

The staff noted that the Nickel-Alloy Nozzles and Penetrations Program is an inspection 

program such that only item (1) above applies to this program. The staff noted that the 

parameters to be monitored/inspected that are linked to specific degradation (PWSCC) are 

identified in the Nickel-Alloy Nozzles and Penetrations Program. The staff noted that cracking is 

monitored through the ISI program using bare metal visual (BMV) inspections (for the BMI 

penetration nozzles and associated welds), visual inspection (for the core support pads), and 

volumetric inspections (for the weld overlay of the Unit 2 surge nozzle). The staff also noted that 

the BMV examinations, VT-3 visual examinations, and volumetric inspections are performed on 

a periodic basis such that degradation can be detected in a timely manner.

The staff confirmed that the “parameters monitored or inspected” program element satisfies the 

criterion defined in the GALL Report and in SRP-LR Section A.1.2.3.3. The staff finds this 

program element acceptable.

Detection of Aging Effects. LRA Section B2.1.27 states that the program utilizes visual and 

volumetric examination techniques to detect cracking in Alloy 600/82/182 materials. 

10 CFR 50.55a requires that all power reactors maintain an Inservice Inspection Program in 

accordance with the ASME Boiler and Pressure Vessel Code, Section XI. The Nickel-Alloy 

Nozzles and Penetrations Program implements the inspection of the Alloy 600/82/182 materials 

through the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program.

The applicant further stated that:

(1) For the reactor vessel core support pads, the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program conducts a visual VT-1 examination of the 

accessible interior attachment welds per Table IWB-2500-1, Examination Category B-N2, once per Inservice Inspection interval.

(2) Inspection of the FSWOL on the pressurizer surge nozzle-to-safe end dissimilar metal 

weld (Alloy 82) and safe end-to-reducer stainless steel butt weld are ultrasonically 

examined in accordance with ASME Section XI, Nonmandatory Appendix Q, Figure Q4300-1. Inservice examinations as described in Q-4300 are performed in accordance 

with the requirements of MRP-139, "Primary System Piping Butt Weld Inspection and 

Evaluation Guidelines," with the additional requirement of at least one ultrasonic 

examination within ten years of the FSWOL application.

(3) Reactor pressure vessel bottom head bare metal visual examinations are performed by 

removing insulation sections and/or examining under the insulation using remote viewing 

equipment that provides a high degree of resolution in order to identify very small 

volumes of boric acid that may result from Alloy 600 PWSCC. The inspections are in 

compliance with ASME Code Case N-722, "Additional Examinations for PWR Pressure 

Retaining Welds in Class 1 Components Fabricated With Alloy 600/82/182 Materials," as 

required by and modified by 10 CFR 50.55a(g)(6)(ii)(E).

The staff reviewed the applicant’s “detection of aging effects” program element against the 

criteria in SRP-LR Section A.1.2.3.4, which states that AMPs should:
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 (1) Provide information that links the parameters to be monitored or inspected to the aging 

effects being managed.

 (2) Describe when, where, and how program data are collected (i.e., all aspects of activities 

to collect data as part of the program). 

 (3) Link the method or technique and frequency, if applicable, to plant-specific or industrywide OE.

 (4) Provide the basis for the inspection population and sample size when sampling is used 

to inspect a group of SCs. The inspection population should be based on such aspects 

of the SCs as a similarity of materials of construction, fabrication, procurement, design, 

installation, operating environment, or aging effects.

The staff noted that inspection for PWSCC using appropriate methods for the specific 

components are performed on a periodic basis such that cracking will be detected before the 

intended function is compromised. Inspection using volumetric, surface, and visual techniques 

are performed and scheduled in accordance with ASME Section XI, MRP-139, and the 

requirements of ASME Code Case N-722, "Additional Examinations for PWR Pressure 

Retaining Welds in Class 1 Components Fabricated With Alloy 600/82/182 Materials," as 

required by and modified by 10 CFR 50.55a(g)(6)(ii)(E). Therefore, the frequencies and 

techniques used to detect PWSCC are established in accordance with ASME code, regulatory, 

and industry program requirements. The staff noted that inspections would be carried out 

through the end of the period of extended operation.

The staff confirmed that the “detection of aging effects” program element satisfies the criterion 

defined in the GALL Report and in SRP-LR Section A.1.2.3.4. The staff finds this program 

element acceptable.

Monitoring and Trending. LRA Section B2.1.27 states that the program incorporates the 

inspection schedules and frequencies for the nickel-alloy components in accordance with the 

PINGP ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and, 

where applicable, ASME Code Case N-722, subject to the conditions specified in 10 CFR 

50.55a(g)(6)(ii)(E), where flaw indications detected during the required examinations are 

dispositioned in accordance with the Corrective Actions program. The applicant further stated 

that the PINGP Nickel-Alloy Nozzles and Penetrations Program ranks the reactor pressure 

vessel bottom head penetrations as moderate for their lower susceptibility to PWSCC given the 

cooler temperature environment, good volumetric examination experience, and the medium-tohigh failure consequence and are inspected in accordance with ASME Code Case N-722 which 

requires inspection of the reactor pressure vessel bottom head penetrations every other 

refueling outage.

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that monitoring and trending activities should 

be described, and they should provide predictability of the extent of degradation and thus effect 

timely corrective or mitigative actions, this program element describes how the data collected 

are evaluated and may also include trending, and the parameter or indicator trended should be 

described.
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The staff noted that monitoring and trending in the applicant’s Nickel-Alloy Nozzles and 

Penetrations Program is acceptable because monitoring and trending is performed in 

accordance with ASME code requirements, EPRI MRP guidelines and ASME Code Case N722, subject to the modifications specified in 10 CFR 50.55a(g)(6)(ii)(E). The staff also noted 

that the applicant’s Corrective Actions Program would provide monitoring and trending of 

degradation discovered during visual and volumetric examinations such that timely repair or 

mitigative actions will be implemented.

The staff confirmed that the “monitoring and trending” program element satisfies the criterion 

defined in the GALL Report and in SRP-LR Section A.1.2.3.5. The staff finds this program 

element acceptable.

Acceptance Criteria. LRA Section B2.1.27 states that for the reactor vessel core support pads, 

the PINGP ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program 

conducts visual VT-1 examination of the accessible welds. The PINGP ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program requires that indications and 

relevant conditions detected during examination be evaluated in accordance with ASME Section

XI, Paragraph IWB-3520.1.

The applicant also stated that the Inservice Inspection requirements for the Unit 2 pressurizer 

surge nozzle-to-safe end weld for the extended period of operation will be in accordance with 

the PINGP ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program, 

with specified limitations, modifications and NRC-approved alternatives and indications and 

relevant conditions detected during examination are required to be evaluated in accordance with 

ASME Section XI, Article IWB-3500.

The applicant also stated that the reactor pressure vessel bottom head bare metal visual 

examinations are performed in order to identify very small volumes of boric acid that may result 

from Alloy 600 PWSCC. The acceptance criteria for this examination is the lack of any relevant 

indication, namely evidence of any leakage arising from the penetration to head interface, and 

the lack of any boric acid accumulations on the carbon steel head surfaces that may result in 

corrosion. The acceptance standards are in accordance with ASME Section XI, Paragraph IWB3522 per ASME Code Case N-722, subject to the conditions specified in 10 CFR 

50.55a(g)(6)(ii)(E). 

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in 

SRP-LR Section A.1.2.3.6, which states that: 

(1) the acceptance criteria of the program and its basis should be described. The 

acceptance criteria, against which the need for corrective actions will be evaluated, 

should ensure that the SC intended function(s) are maintained under all CLB design 

conditions during the period of extended operation,

(2) the program should include a methodology for analyzing the results against applicable 

acceptance criteria, and

(3) qualitative inspections should be performed to same predetermined criteria as 

quantitative inspections by personnel in accordance with ASME Code and through 

approved site-specific programs.
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The staff noted that acceptance criteria and basis of the Nickel-Alloy Nozzles and Penetrations 

Program is adequately described because the acceptance criteria are based on ASME code 

and regulatory requirements and that ASME code methodology and ASME Code Case N-722, 

subject to the conditions specified in 10 CFR 50.55a(g)(6)(ii)(E). The staff noted that the 

methodology to evaluate inspection results are acceptable because any cracking found during 

volumetric inspection will subjected to the acceptance criteria of ASME Code Section XI IWB3500. Additionally, the staff noted that qualitative visual inspections are performed by qualified 

personnel in accordance with the ASME code and implemented through the applicant’s ISI 

Program.

The staff confirmed that the “acceptance criteria” program element satisfies the criterion defined 

in the GALL Report and in SRP-LR Section A.1.2.3.6. The staff finds this program element 

acceptable.

Corrective Actions. LRA Section B2.1.27 states that indications are evaluated per the 

acceptance criteria, which determine relevant flaw indications that are unacceptable for further 

service. The applicant further stated that if visual examination of the reactor vessel 

instrumentation tube penetrations (bottom head) in accordance with ASME Code Case N-722 

identifies leakage or evidence of cracking, additional actions shall be performed as specified in 

paragraphs 10 CFR 50.55a(g)(6)(ii)(E)(2) through (4) and if PWSCC related flaws are detected 

in the pressurizer surge nozzle FSWOL, the repair/replacement activity will include removal of 

the weld overlay and the original dissimilar metal weld. The applicant also stated that 

repair/replacement activities comply with ASME Section XI as invoked by 10 CFR 50.55a or 

approved ASME Code Cases as referenced in the latest version of NRC Regulatory Guide 

1.147. 

The staff reviewed the applicant’s “corrective actions” program element against the criteria in 

SRP-LR Section A.1.2.3.7, which states that: 

(1) Actions to be taken when the acceptance criteria are not met should be described.

Corrective actions, including root cause determination and prevention of recurrence, 

should be timely.

(2) If corrective actions permit analysis without repair or replacement, the analysis should 

ensure that the structure and component intended function(s) will be maintained 

consistent with the CLB.

The staff noted that the applicant’s corrective actions with regard to any PWSCC indications that 

exceed acceptance criteria are in accordance with 10 CFR 50.55a or NRC approved ASME 

Code Cases. The staff further noted that the applicant will remove the FSWOL and the original 

dissimilar weld inside diameter if PWSCC is detected in the FSWOL. The staff finds that actions 

to be taken by the applicant when acceptance criteria are exceeded are described and will be 

timely because all actions are in accordance with NRC regulations, ASME Section XI, and NRC 

approved ASME Code cases. The staff also finds that item (2) of SRP-LR Section A.1.2.3.7 

does not apply because flaws or unacceptable leakage that is an indication of PWSCC will 

trigger repair and replacement activities in accordance with the applicant’s Corrective Action 

Program.
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The staff confirmed that the “corrective action” program element satisfies the criterion defined in 

the GALL Report and in SRP-LR Section A.1.2.3.7. The staff finds this program element 

acceptable.

Operating Experience. The staff also reviewed the OE described in LRA Section B2.1.27. The 

applicant stated that:

(1) the PlNGP Unit 2 pressurizer surge nozzle-to-safe end weld was ultrasonically examined 

in November 2006 and September 2008 where no reportable PWSCC indications were 

detected. The applicant further stated that in October 2008, following installation of the 

FSWOL, ultrasonic examinations (UT) were performed of the new overlay weld and the 

nozzle-to-safe end dissimilar metal weld. One hundred percent of the Code-required 

volume was achieved during the examinations where no recordable indications were 

detected.

(2) PINGP conducted bare metal visual examinations of the reactor vessel instrumentation 

tube penetrations (bottom head) in May 2006 for Unit 1 and April 2005 for Unit 2 where 

no indications were observed.

(3) A visual VT-1 examination of the accessible welds of the reactor vessel core support 

pads was conducted in October 2004 for Unit 1 and in May 2005 for Unit 2. where no 

recordable indications on the core support pads were detected in either Unit.

The staff noted that the applicant did not identify any leakage of the borated reactor coolant due 

to cracking in the bottom head penetration nozzles or the nickel-alloy welds. Thus, the staff 

concludes that the applicant has addressed the generic OE for the bottom head penetrations 

because the applicant will now follow the current augmented inspection requirements, as 

mandated in 10 CFR 50.55a (g)(6)(ii)(E) and in the ASME code cases are referenced in and 

subject to the limitations of these regulatory paragraphs. The staff also noted that the applicant 

installed a FSWOL on the Unit 2 surge nozzle-to-safe end dissimilar weld and will provide 

inspection of the FSWOL in accordance with ASME Section requirements and MRP-139 

Guidelines implemented through the applicant’s augmented ISI Program. 

The staff audited the OE reports. The staff noted that the Nickel-Alloy Nozzles and Penetrations 

Program provide the inspection details for detection of PWSCC. The documents reviewed by 

the staff confirm that the plant-specific OE did not reveal any degradation not bounded by 

industry experience. The OE provides evidence that PWSCC will be adequately managed 

through the period of extended operation. 

The staff confirmed that the OE 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 element acceptable.

UFSAR Supplement. The applicant provided its UFSAR Supplement for the Nickel-Alloy 

Nozzles and Penetrations Program in PINGP LRA, Appendix A, Section A2.27. The staff 

verified that provisions of the UFSAR Supplement are acceptable because these provisions are 

in accordance with SRP-LR, Section 3.1.2.2.13. The staff noted, the applicant has amended the 

LRA to eliminate LRA Commitment No. 21 from the LRA because of the new augmented 

inspection bases for non-reactor vessel upper head nickel-alloy components in 
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10 CFR 50.55a(g)(6)(ii)(E) and ASME Code Case N-722, which are invoked (with limitations) by 

these paragraphs, respectively. The staff noted the applicant, by letter dated March 27, 2009,

provided an update of LRA Section A2.27 that provides a plant-specific Nickel-Alloy Nozzles 

and Penetrations Program, which will implement inspection, mitigation, and repair/replacement 

activities in accordance with new requirements described above through augmentation of the 

ASME Section XI Inservice Inspection Program.

The staff finds that the UFSAR Supplement for the Nickel-Alloy Nozzles and Penetrations 

Program provides an adequate summary description of the program, because the summary 

description is consistent with the NRC recommendations in SRP-LR Section 3.1.2.2.13 as 

required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant=s Nickel-Alloy Nozzles and Penetrations 

Program, the staff finds all program elements consistent with the program element criteria in 

SRP-LR Appendix A.1, Section A.1.2.3. The staff concludes that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). The staff also reviewed the UFSAR supplement for this AMP 

and concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.3.3.2 PWR Vessel Internals Program

Summary of Technical Information in the Application. In a letter dated May 12, 2009, the 

applicant amended its LRA to replace the PWR Vessel Internals Program with a plant-specific 

version of this program that is based on the recommended program element criteria that are 

defined in SRP-LR Section A.1.2.3. The applicant’s AMP includes the 10 program elements 

that are recommended in SRP-LR. The applicant indicated that the program elements for the 

PWR Vessel Internals Program are in accordance with both the ISI requirements for removable 

core support components in Examination Category B-N-3 of the ASME Code Section XI and 

with the additional augmented ISI recommendations for Westinghouse-design RVI components 

in Electric Power Research Institute, Materials Reliability Program (EPRI MRP) Report No. 

1016596, “Materials Reliability Program: Pressurized Water Reactor Internals Inspection and 

Evaluation Guidelines (MRP-227-Rev. 0),” which was submitted by the EPRI MRP as a 

proprietary report for NRC review and approval in a letter dated January 12, 2009 

(ML090162004).1

In a letter dated June 24, 2009, the applicant updated LRA Commitment No. 25 for the PWR 

Vessel Internals Program:

(A) A PWR Vessel Internals Program will be implemented. Program features will be as 

described in LRA Section B2.1.32. 

(B) An inspection plan for reactor internals will be submitted for NRC review and 

 

1 Henceforth, these guidelines will be referred to as the EPRI MRP RVI I&E Guidelines.
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approval at least twenty-four months prior to the period of extended operation. In 

addition, the submittal will include any necessary revisions to the PINGP PWR 

Vessel Internals Program, as well as any related changes to the PINGP scoping, 

screening and aging management review results for reactor internals, to conform to 

the NRC-approved Inspection and Evaluation Guidelines.

Staff Evaluation. The staff noted that by letter dated May 12, 2009, as supplemented by letter 

dated June 24, 2009, the applicant amended AMP B2.1.32, PWR Vessel Internals Program, to 

redefine the program as an new, plant-specific AMP that incorporates the 10 program elements 

as recommended in SRP-LR Section A.1.2.3. The applicant also updated LRA Commitment No. 

25.

The staff reviewed the program elements for the PWR Vessel Internals Program against the 

AMP program elements found in SRP-LR Section A.1.2.3, and in SRP-LR 

Table A.1-1, focusing on how the program manages aging effects through the effective 

incorporation of the 10 program elements. The staff reviewed the “scope of program," 

“preventive actions,” “parameters monitored or inspected,” “detection of aging effects,” 

“monitoring and trending,” “acceptance criteria,” and “operating experience” program 

elements against the staff’s corresponding recommendations for these program elements in 

SRP-LR Section A.1.2.3. The staff’s evaluations of these seven program elements are 

given in the paragraphs that follow. The staff evaluated the AMP’s “corrective actions,” 

“confirmation process,” and “administrative controls” program elements as part of the staff’s 

review of the applicant’s Quality Assurance Program and Administrative Controls, which is 

evaluated in SER Section 3.0.4.

Scope of the Program. LRA Section B.2.1.32 states that the program manages the aging effects 

that are applicable to the PINGP RVI components in the upper internals and low internals 

assemblies. The applicant clarifies that the scope of the program does not include the RV 

attachment welds or consumable items such as fuel assemblies, reactivity control assemblies, 

and nuclear instrumentation. The applicant also clarifies that the program’s aging management 

recommendations are based on conformance with the augmented inspection and flaw 

evaluation guidelines that are provided in EPRI MRP RVI I&E guidelines.

The staff reviewed the applicant’s “scope of the program” program element against the 

criteria in SRP-LR Section A.1.2.3.1, which states that the specific program necessary for 

license renewal should be identified, and that the scope of the program should include the 

specific SCs.

The staff noted that the “scope of program” program element for the PWR Vessel Internals 

Program appropriately identified that the program is applicable to the PINGP RVI 

components, which collectively include the following population of components that require 

aging management under this AMP: (1) the baffle and former plates and their fasteners 

(bolts); (2) the bottom mounted instrumentation (BMI) column cruciforms, which are made 

of CASS; (3) the BMI columns and flux thimble guide tubes; (4) radial support keys, clevis 

inserts, and clevis insert bolts; (5) core barrels and their flanges; (6) core barrel outlet 

nozzles; (7) RVI diffuser plates; (8) flux thimble tubes; (9) head and vessel alignment pins; 

(10) head cooling spray nozzles; (11) hold-down springs; (12) lower core plates and their 

fuel alignment pins; (13) lower support columns and their bolts; (14) lower support forgings; 
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(15) rod cluster control assembly (RCCA) guide tubes, pins and fasteners; (16) secondary 

core supports; (17) thermal shields; (18) upper core plates; (19) upper core plates and their 

alignment keys and pins; (20) upper instrumentation columns, conduits, and supports; (21) 

upper support columns and fasteners; and (22) upper support plate assemblies. The staff 

noted that the list and population of RVI components that are credited as being within the 

scope of this AMP was consistent with the list of Westinghouse-designed RVI components 

or commodity group items that are recommended for aging management as defined in 

Table IV.B2 of the GALL Report. 

In a letter dated August 21, 2009, the applicant clarified that the RV interior attachment 

welds are not within the scope of the PWR Vessel Internals Program because they are 

being managed through implementation of the applicant’s ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program. The staff finds this to be acceptable 

because the RV interior attachment welds are within the scope of the ASME Section XI 

Examination Category B-N-1 inspection requirements and because the scope of the 

applicant’s ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program includes these requirements.

In a letter dated August 21, 2009, the applicant also clarified that the RVI consumables are 

not within the scope of this AMP because the consumables are replaced on a specified 

period or qualified life. The staff finds this to be acceptable because the requirements of 

10 CFR 54.21(a)(1) do not require a component to be subject to an AMR or to aging 

management if it is replaced on a qualified life or specified time period.

Thus, the staff concluded that the applicant’s “scope of program” program element meets 

the criterion in SRP-LR Section A.1.2.3.1, “scope of program,” because: (1) the applicant 

defines the program as a new, plant-specific condition monitoring program for the PINGP 

RVI components, (2) the AMR items in LRA Table 3.1.2-3 define the specific RVI 

components that are within the scope of this AMP, (3) the staff has found the list and 

population of RVI components that are within the scope of the program to be consistent 

with those recommended for aging management in the GALL Report, and (4) the 

applicant’s basis meets the criteria in SRP-LR Section A.1.2.3.1 to identify and define the 

type of program that is credited for aging management and to identify the specific 

components that are within the scope of the AMP. 

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. 

Open Item 3.0.3.1.21, Part 1 is resolved with respect to the acceptability of the “scope of 

program” program element for this plant-specific AMP.

Preventative Actions. LRA Section B2.1.32 states that the PWR Vessel Internals Program is a 

condition monitoring program that does not include preventative actions. The applicant clarifies 

that control of chemical impurities in the reactor coolant, which is a mitigative control activity, is 

accomplished through implementation of the applicant’s Water Chemistry Program (LRA AMP 

B2.1.40). The applicant clarifies that the Water Chemistry Program accomplishes this by 

controlling the concentrations of impurities (e.g., fluorides, chlorides, sulfates and dissolved 

oxygen concentrations) through implementation of the EPRI Primary Water Chemistry 

Guidelines.
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The staff reviewed the applicant’s “preventive actions” program element against the criteria in 

SRP-LR Section A.1.2.3.2, which states that (1) the activities for prevention and mitigation 

programs should be described, and (2) for condition or performance monitoring programs that 

do not rely on preventive actions, preventive actions need not be provided.

The staff noted that the applicant defines the PWR Vessel Internals Program as a new, plantspecific condition monitoring program for the RVI components. As such, the program does not 

include any activities to prevent age-related degradation from occurring in the RVI components 

or to mitigate age-related degradation in these components if it does occur. The staff verified 

that control of chemical impurities and chemical additives in the reactor coolant is instead 

accomplished through implementation of the applicant’s Water Chemistry Program (LRA AMP 

B2.1.40). The staff evaluates the ability of the Water Chemistry Program to prevent corrosionrelated degradation from occurring or to mitigate its growth in SER Section 3.0.3.2.18.

Based on this review, the staff confirmed that the “preventive actions” program element is not 

applicable to the applicant’s program, therefore it does not need to satisfy the criterion defined 

in the SRP-LR Section A.1.2.3.2. Open Item 3.0.3.1.21, Part 1 is resolved with respect to the 

acceptability of the “preventative actions” program element for this plant-specific AMP.

Parameters Monitored or Inspected. LRA Section B2.1.32 states that the PWR Vessel Internals 

Program manages the following aging effects in the RVI components: (1) cracking; (2) loss of 

fracture toughness (reduction of fracture toughness); (3) loss of material by wear; (4) changes in 

dimension; and (5) loss of preload, which is only applicable to fastened, bolted, keyed, springloaded, or pinned RVI connections. The applicant clarifies that, for RVI components in which 

visual examination techniques are credited for aging management, the program monitors for 

general degradation conditions if VT-3 visual techniques are credited for the examinations, and 

for surface discontinuities or imperfections if either VT-1 or enhanced VT-1 (EVT-1) visual 

techniques are credited for examination. The applicant clarifies that, for RVI components in 

which surface examination techniques are credited for aging management, the program further 

characterizes surface discontinuities that may provide for indication of surface breaking agerelated degradation. 

The applicant clarifies that, for RVI components in which volumetric examination techniques are 

credited for aging management, the program monitors for discontinuities or flaws throughout the 

volume of a component. The applicant clarifies that some aging effects may involve changes in 

clearances or settings or physical displacement that may be monitored for by visual examination 

methods when coupled to physical measurement methods.

The staff reviewed the applicant’s “parameters monitored or inspected” program element 

against the criteria in SRP-LR BTP RLSB-1, Section A.1.2.3.3, which states that 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 for condition monitoring 

programs, that the parameter monitored or inspected should detect the presence and 

extent of aging effects.

Specifically, the staff noted that the applicant identified that the program manages the aging 

effects of cracking due to SCC, IASCC, or PWSCC; reduction in fracture toughness (loss of 
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fracture toughness) as a result of either neutron irradiation embrittlement, thermal aging, or void 

swelling; changes in dimension as a result of void swelling; and for bolted, fastened, springloaded, keyed, or pinned RVI mechanical connections, loss of preload due to stress relaxation. 

The staff finds that the applicant’s basis for crediting this program for these aging effect 

mechanisms is acceptable because it is consistent with the aging effects and mechanisms listed 

for Westinghouse-designed RVI components in Table IV.B2 of the GALL Report. The staff also 

noted that, of these aging effect mechanisms, two of the aging effect mechanisms are new 

aging effect mechanisms that were added to the scope of the program in the applicant’s letter 

dated May 12, 2009: (1) cracking by fatigue (cyclical loading), and (2) loss of material due to 

wear. The staff finds the applicant’s supplementing of the application to add cyclical loading as 

an additional cracking mechanism and wear as an additional loss of material mechanism for 

these components is acceptable because these supplements are either consistent with or more 

conservative than the aging effect mechanisms that are listed in Table IV.B2 of the GALL 

Report for Westinghouse-design RVI mechanical connection components. 

The staff also noted that the applicant had identified the specific parameters that the various 

inspection methods would monitor for in order to provide indication of these aging effects. The 

staff determined that this satisfies the general “parameters monitored” program element criterion 

in SRP-LR BTP RLSB-1, Section A.1.2.3.3, to identify the aging effects that are managed by the 

AMP and to identify the parameters that would provide indication of these aging effects. 

The staff noted that the VT-3 visual methods, which are credited only for the monitoring of 

general surface conditions, would only be applicable to those aging effects where only a gross 

change in the surface condition would need to be detected in order to provide indication of the 

aging effect. Thus, the staff concluded that the crediting of VT-3 visual examination methods by 

themselves (i.e., without coupling them to physical measurements) would only be applicable to 

the management of loss of material due to wear or to the management of loss of preload due to 

stress relaxation in a bolted, fastened, spring-loaded, keyed, or pinned RVI component (i.e.,

components in RVI mechanical connections). The staff noted that the VT-3 visual examination 

methods credited by the applicant would also be capable of detecting a change in a 

component’s dimensions if the general visual examinations under the VT-3 methods were 

coupled to some physical (quantitative) measurements. The staff noted that these 

determinations were consistent with information on the use of VT-3 visual examinations 

methods that the applicant had provided for VT-3 methods in its “detection of aging effects” 

program element for the program. Thus, the applicant’s information in the “parameters 

monitored” and “detection of aging effects” program is consistent with this determination, and 

based on this determination, the staff finds that the applicant has provided an acceptable basis 

for identifying the aging effects that the VT-3 methods would manage and parameters that the 

VT-3 methods would monitor for as provide indication of these aging effects.

The staff noted that the VT-1 and EVT-1 visual examination methods have greater visual 

detection capabilities than VT-3 visual examinations methods and thus are appropriate visual 

examination methods for detecting surface-breaking aging effect parameters that require a 

higher degree of visual resolution. Thus, the staff concluded that the crediting of VT-1 or EVT-1 

visual examination methods by themselves (i.e., without coupling them to physical 

measurements) are appropriate for detecting general surface conditions as well as for specific 

surface discontinuities or imperfections, and thus are appropriate for the management of loss of 

material due to wear, loss of preload due to stress relaxation in a bolted, fastened, spring-
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loaded, keyed, or pinned RVI component (i.e., components in RVI mechanical connections), 

surface breaking cracking as a result of either SCC, IASCC, PWSCC, or cyclical loading, and 

changes in dimension due to void swelling. The staff noted that these determinations were 

consistent with information on the use of VT-1 and EVT-1 visual examinations methods that the 

applicant had provided for the methods in its “detection of aging effects” program element for 

the program. Thus, the applicant’s information in the “parameters monitored” and “detection of 

aging effects” program is consistent with this determination, and based on this determination, 

the staff finds that the applicant has provided an acceptable basis for identifying the aging 

effects that the VT-1 and EVT-1 methods would manage and parameters that the VT-1 and 

EVT-1 methods would directly monitor to provide indication of these aging effects.

The staff noted that the applicant indicated that loss of fracture toughness due to neutron 

irradiation embrittlement or thermal aging would only be of consequence if cracking 

occurred in the components and if the local applied stress intensity at the crack tip was to 

exceed the reduced fracture toughness for the component material. The staff also noted 

that the applicant indicated that the VT-1 or EVT-1 visual examinations would be credited 

for detecting cracking and that any evaluations of relevant indications of cracking would be 

evaluated using evaluation methods that account for reduced fracture toughness properties 

as a result of irradiation or thermal aging. The staff finds that the applicant’s method and 

process for managing loss of fracture toughness in the RVI components is acceptable 

because the method and process is consistent with the aging management approach for 

managing loss of fracture toughness in GALL AMP XI.M13, “Thermal Aging and Neutron 

Irradiation Embrittlement or Cast Austenitic Stainless Steel (CASS),” which indicates that 

VT-1 (including EVT-1) visual techniques may be credited as an indirect means of 

managing reduction in fracture toughness when, upon detection of cracking, the indications 

are coupled to a critical flaw size assessment that assumes degraded fracture toughness 

properties for the component’s material. 

The staff noted that the applicant credited volumetric examination methods to monitor for 

discontinuities or flaws through the volume of the component. The staff finds this 

acceptable because it is consistent with the provision in Article IWA-2000 of the ASME 

Code Section XI that specifies that volumetric techniques are capable of identifying 

discontinuities or flaws throughout the volume of a component.

The staff also noted that the applicant had identified the specific parameters that the various 

inspection methods would monitor for in order to provide indication of these aging effects. The 

staff determined that this satisfies the general “parameters monitored” program element criterion 

in SRP-LR BTP RLSB-1, Section A.1.2.3.3 to identify the aging effects that are managed by the 

AMP and to identify the parameters that would provide indication of these aging effects. 

Based on this review, the staff confirmed that the “parameters monitored or inspected” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.3. The staff finds this program 

element acceptable. Open Item 3.0.3.1.21, Part 1 is resolved with respect to the acceptability of 

the “parameters monitored or inspected” program element for this plant-specific AMP.

Detection of Aging Effects. LRA Section B2.1.32 states, in part, that the PWR Vessel 

Internals Program uses visual inspection, surface examination and volumetric inspection 

techniques to manage the effects of aging that are applicable to the PINGP RVI 
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components. The applicant clarifies that the visual examination methods include VT-3 

visual examination techniques that monitor for general surface conditions and either VT-1 

or EVT-1 techniques that monitor for surface discontinuities or surface imperfections. The 

applicant also clarifies that if surface examination techniques are used to characterize 

surface flaws identified through the VT-1 or EVT-1 examinations, the surface examinations 

will involve eddy current testing (ET) of the component surfaces. The applicant also 

clarifies that, for those components that are examined using volumetric inspection 

techniques, the volumetric techniques will involve ultrasonic testing (UT) of the 

components. The applicant clarifies that physical measurements may be coupled to 

inspection methods used to manage aging effects (i.e., loss of material due to wear, 

changes in dimension due to void swelling, loss of preload due to stress relaxation) that can 

result in a change of a component’s clearance or setting or in a displacement of the 

component (changes in dimension). The applicant clarifies that the sample of RVI 

components (component coverage) being inspected under the PWR Vessel Internals 

Program, the inspection techniques for the components being inspected, and the inspection 

frequencies are established in the EPRI MRP RVI I&E Guidelines.

The staff reviewed the applicant’s “detection of aging effects” program element against the

criteria in SRP-LR Section A.1.2.3.4, which states that AMPs should: (1) provide information 

that links the parameters to be monitored or inspected to the aging effects being managed; 

(2) describe when, where, and how program data are collected (i.e., all aspects of activities to 

collect data as part of the program); (3) link the method or technique and frequency, if 

applicable, to plant-specific or industry-wide OE; and (4) provide the basis for the inspection 

population and sample size when sampling basis is used for the condition monitoring program. 

The staff also noted that the PWR Vessel Internals constitutes a plant-specific sampling-based 

condition monitoring program for the PINGP RVI components. Thus, to conform to the SRP-LR 

Section A.1.2.3.4 recommendations for sampling-based condition monitoring programs, the staff 

noted that the population of components would have to be based on considerations such as 

materials of construction, fabrication, procurement, design, installation, operating environment, 

or aging effects. Furthermore the sample components to be inspected would need to be based 

on factors such as the specific aging effect or effects requiring management, component 

location, existing technical information, the specific component design, materials of fabrication, 

service environment, or previous failure histories. 

The staff noted that the applicant’s program divides the population of PINGP RVI components in 

the program into those components that would be inspected: (1) as primary components for 

inspection in accordance with either existing ASME Section XI Inservice Inspection 

requirements or the MRP’s augmented inspection criteria in the EPRI MRP RVI I&E Guidelines, 

or (2) as components that would need to be inspected on an expansion basis should any of the 

primary component inspections detect relevant indications or conditions, as recommended in 

the EPRI MRP RVI I&E Guidelines. Thus, the staff determined that this program meets the 

criteria in SRP-LR Section A.1.2.3.4 for crediting a sampling-based condition monitoring 

program for aging management because:

(1) The list and population of components within the scope of this AMP, as discussed 

previously the “scope of program” program element evaluation for this AMP, is based on 

conformance with the AMR line items in the GALL Report for Westinghouse-designed 
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RVI components, which identify potential aging effects that may be applicable to these 

components based on their operating environments and materials of fabrications.

(2) The applicant’s basis for establishing the sample of components that will be inspected 

under the program is based on information, that clearly defines the RVI components that 

are designated as primary inspection components, and the components that are 

expansion-based components. The applicant takes into consideration factors such as 

component design, intended function, material of fabrication, service environment, and 

engineering analysis and judgment to identify the components in Westinghousedesigned plants that should be inspected under a primary inspection basis or expanded 

inspection basis. 

The staff noted that the applicant’s crediting of VT-3 visual examination techniques for 

detection of general surface conditions, VT-1 or EVT-1 for surface discontinuities or 

imperfections, ET surface examination methods for characterization of surface 

discontinuities or imperfections, and UT volumetric techniques for detection of 

discontinuities in a component’s volume is consistent with the examination basis criteria for 

these inspection techniques in the ASME Code Section XI, Subarticle IWA-2200. The staff 

finds this to be an acceptable basis for establishing when these techniques will be used 

because it is consistent with the criteria for these examinations in the ASME Code Section 

XI, which is endorsed in 10 CFR 50.55a.

The staff noted that for those RVI components that are part of the removable core support 

structure, the components will continue to be subjected to the VT-3 visual ISI requirements 

for Examination Category B-N-3 components and the frequency requirements for these 

examinations in Table IWB-2500-1 of the ASME Code Section XI. These requirements 

mandate that the visual examinations be performed on all accessible surfaces at a 

frequency of once every 10-year ISI interval. The staff finds this to be acceptable because it 

is in conformance with the applicable ASME Code Section XI ISI requirements for these 

components.

The staff noted that, for those RVI components that are not part of the removable core support 

structure, the applicant had indicated that the sample of components inspected, inspection 

methods for these components, and inspection frequencies for the components would be 

performed in accordance with the EPRI MRP RVI I&E Guidelines. The staff also noted that the 

applicant indicated that, for this population of components, the components would not be 

subjected to inspection during the period of extended operation if the component did not have 

any applicable AERMs. The staff finds this to be acceptable because: (1) the establishment of 

the sample components for inspection, and the examination methods and inspection 

frequencies for these components in the EPRI MRP RVI I&E Guidelines meets the criteria SRPLRA A.1.2.3.4 to define the sample of components, inspection methods, and inspection 

frequencies for condition monitoring programs that are based on sampling bases, and (2) under 

the requirements of 10 CFR Part 54, an applicant would not need to subject a component to 

aging management if there were not any applicable AERMs for the component’s service 

environments.

In a letter dated August 21, 2009, the applicant supplemented the PWR Vessel Internals 

Program with additional information on the data collection and recording activities for the 
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program and on how the relevant OE for the industry has been linked to establishing the 

inspection methods and frequencies for this AMP. In this letter, the applicant clarified that 

documentation of inspection results associated with the PWR Vessel Internals Program will be 

in accordance with approved inspection procedures, and that all necessary program 

implementing documents, including inspection procedures, will be developed in accordance with 

the PINGP NSPM Quality Assurance Program, which implements the requirements of 10 CFR 

Part 50, Appendix B. The staff finds this to be acceptable because: (1) the applicant has 

clarified that the inspection results will be documented in applicable plant records that are 

controlled by the applicant’s implementing procedures for this AMP, the implementation of the 

inspections and the documentation of the inspection results will be controlled within the scope of 

the applicant’s 10 CFR Part 50, Appendix B quality assurance program, and (3) this satisfies the 

recommendation in SRP-LR Section A.1.2.3.4 to describe the methods used for data collection 

and retention.

Based on this review, the staff concludes that the “detection of aging effects” program element, 

satisfies the criterion defined in SRP-LR Section A.1.2.3.4. The staff finds this program element 

acceptable. Open Item 3.0.3.1.21, Part 1 is resolved with respect to the acceptability of the 

“detecting of aging effects” program element for this plant-specific AMP.

Monitoring and Trending. LRA Section B2.1.32 states that the implementation of one-time, 

periodic, and conditional visual or non-destructive examinations and other aging 

management activities, scheduled in accordance with the ASME Code, Section XI or the 

augmented inspection and evaluation guidelines in the EPRI MRP RVI I&E Guidelines 

provide timely detection of aging effects. The applicant clarifies that, in addition to the 

primary inspection components, the program includes expansion inspection components 

that will be inspected if the inspections on the primary inspection components were to 

result in the detection of relevant aging effect indications. The applicant also clarifies that 

any relevant indications detected during the required examinations will be dispositioned in 

accordance with the Acceptance Criteria and Corrective Actions program elements of the 

program.

The staff reviewed the applicant’s “monitoring and trending” program element against the 

criteria in SRP-LR Section A.1.2.3.5, which states that: (1) monitoring and trending activities 

should be described, and they should provide predictability of the extent of degradation and 

thus effect timely corrective or mitigative actions, and (2) that the program element should 

describe how the data collected are evaluated and trended. With respect to making this part 

of the review, the staff accounted for any “monitoring and trending” activity information that 

the applicant had included in the “detection of aging effects,” “acceptance criteria,” or 

“corrective actions” program elements for the AMP.

The staff noted that the applicant’s “monitoring and trending” program element indicates that 

any indications of aging that are detected as a result of implementing the program’s mandatory 

ASME Code Section XI Examination Category VT-3 visual examinations for RVI removable core 

support components, augmented VT-3, VT-1/EVT-1 or UT examinations for primary inspection 

components will be evaluated in accordance with applicable evaluation methods and against the 

applicable flaw evaluation criteria in either ASME Code Section XI or the EPRI MRP RVI I&E 

Guidelines. The staff also noted that the applicant’s “monitoring and trending” program elements 

also indicated how the inspections of primary components under the mandatory ASME Section 
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XI, Examination Category B-N-3 requirements or the augmented inspection recommendations 

of the EPRI MRP RVI I&E Guidelines would be conducted, and how the inspections will be 

expanded to a specific defined set of RVI components should the VT-3, VT-1/EVT-1 or UT 

examinations result in the detection of age-related degradation indications.2 The staff finds the 

applicant’s “monitoring and trending” program element acceptable because: (1) the applicant’s 

monitoring and trending” program element defines the documents and methods that will be used 

to evaluate any indications of age-related degradation against the applicable acceptance criteria 

of the program, (2) the applicant’s “monitoring and trending” program element clarifies how the 

monitoring and trending of relevant age-related degradation data will be used by the applicant to 

expand the scope of program’s inspections should any of the inspections performed under the 

program result in the detection of age-related indications, and (3) conforms to the 

recommendation in SRP-LR Section A.1.2.3.5 for describing the monitoring and trending 

activities for an AMP and for explaining how the evaluation and trending activities will be 

used to analyze any inspection or test results against relevant acceptance criteria.

Based on this review, the staff confirmed that the “monitoring and trending” program element 

satisfies the criterion defined in SRP-LR Section A.1.2.3.5. The staff finds this program element 

acceptable. Open Item 3.0.3.1.21, Part 1 is resolved with respect to the acceptability of the 

“monitoring and trending” program element for this plant-specific AMP.

Acceptance Criteria. LRA Section B2.1.32 states that the acceptance criteria for the 

program include:

(1) “specific, descriptive relevant conditions for the visual (VT-3) examinations,” 

(2) “requirements for recording and dispositioning surface breaking indications that

are detected and sized for length by the visual (VT-1/EVT-1) examinations,” and

(3) “requirements for system-level assessment of bolted or pinned assemblies

with volumetric (UT) examination indications that exceed specified limits.” 

The applicant clarified that any detected condition that does not satisfy these examination

acceptance criteria are required to be dispositioned and that this ensures that the component's

 

2 The specific evaluation and trending methods, sample expansion criteria and acceptance criteria for 

evaluating and trending the relevant indication data that result from the implementation of the mandated 

ASME Section inspections and the EPRI MRP’s recommended augmented inspections techniques have 

been identified as proprietary information in the EPRI MRP RVI I&E Guidelines. This report was submitted 

to the NRC with a proprietary affidavit in the EPRI letter of January 12, 2009 (ML091060204). The staff is 

withholding this proprietary information from publication in accordance with the requirements in 10 CFR 

2.390. However, the staff did verify that the applicant’s “monitoring and trending” activities for the PWR 

Vessel Internals Program, as based on the requirements of the ASME Code Section XI and the 

augmented inspection activity recommendations in the EPRI MPR RVI I&E Guidelines, did conform to the 

staff’s recommendations for describing monitoring and trending activities in Section A.1.2.3.5 of the SRPLR.
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intended functions are maintained under all current licensing basis design conditions during the 

period of extended operation. The applicant clarified, that for those ASME Code Class RVI 

components that are inspected under the ASME Section XI Examination B-N-3 requirements, 

the acceptance criteria are established in ASME Section XI Article IWB-3500. The applicant 

also clarified that for the primary inspection components and expansion components examined 

under the MRP’s augmented inspection basis in the EPRI MRP RVI I&E Guidelines, the 

acceptance criteria are established in the report.

The staff reviewed the applicant’s “acceptance criteria” program element against the criteria in

SRP-LR Section A.1.2.3.6, which states that:

(1) the acceptance criteria of the program (against which the need for corrective actions will 

be evaluated) and their bases should be described and should ensure that the SC 

intended function(s) are maintained under all CLB design conditions during the period of 

extended operation,

(2) the acceptance criteria can be specific numerical values, or can consist of a discussion 

of the process for calculating specific numerical values of conditional acceptance criteria 

to ensure that the structure and component intended function(s) will be maintained under 

all CLB design conditions. Information from available references may be cited.

The staff noted that the applicant credits the applicable acceptance criteria in ASME Code 

Section XI for the evaluation of any indications or relevant conditions that are identified 

through the implementation of the ASME Code Section XI Examination Category B-N-3 

examinations for the RVI components that are associated with the removable core support 

structure (i.e., VT-3 examinations). The staff also noted that the applicant indicated that 

these types of indications will be evaluated in accordance with the requirements in the 

ASME Code Section XI Article IWB-3500. The staff finds this to be an acceptable basis for 

evaluating the VT-3 examination results for the RVI components that are associated with 

the removable core support structure because:

(1) the applicant’s basis is in accordance with the appropriate evaluation criteria in the 

ASME Code Section XI, Article IWB-3500 for VT-3 visual examination, which is part 

of the CLB for the facility, 

(2) the applicant’s basis meets the staff’s recommended program element criteria in 

SRP-LR Section A.1.2.3.6 to define the acceptance criteria for the program,

(3) the applicant’s basis meets the staff’s recommended program element criteria in 

SRP-LR Section A.1.2.3.6 that the acceptance criteria may be established through 

the use or reference of applicable acceptance criteria in the design basis or CLB for 

the facility.

For non-mandated inspections that will be performed in accordance with the 

recommendations of the EPRI MRP RVI I&E Guidelines, the staff noted that the applicant 

clarified that the acceptance criteria are defined in the report. The staff noted that the 

applicant also clarified that collectively, the acceptance criteria include those for the VT-3 

and VT-1/EVT-1 visual methods and UT volumetric methods that are credited for the 
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examinations. The staff verified that acceptance criteria for these techniques in the EPRI 

MRP RVI I&E Guidelines are in conformance with the “acceptance criteria” program 

element recommendations in SRP-LR Section A.1.2.3.6.3 The staff finds this to be an 

acceptable basis because this meets the staff’s recommended program element criterion in 

SRP-LR Section A.1.2.3.6 to define the acceptance criteria for the program.

The staff confirmed that the “acceptance criteria” program element satisfies the criterion defined

in SRP-LR Section A.1.2.3.6. The staff finds this program element acceptable. 

Open Item 3.0.3.1.21, Part 1 is resolved with respect to the acceptability of the “acceptance 

criteria” program element for this plant-specific AMP.

Operating Experience. LRA Section B2.1.32 states that the PWR Vessel Internals Program 

is a new, plant-specific AMP for the PINGP RVI components that has yet to be 

implemented for the period of extended operation, and therefore there is not yet any 

PINGP-specific experience related to the implementation of this AMP. The applicant 

clarifies that to-date, there have been relatively few incidents of aging related operating 

experience with respect to Westinghouse-design RVI components. The applicant clarifies 

that, in the past, there has been some generic operating experience with cracking that has 

been detected in baffle or former bolts, cracking in high strength bolting and in control rod 

guide tube alignment pins (rod control cluster assembly [RCCA] guide tube alignment pins), 

and wear in flux thimble tubes and potentially in control rod guide tube cards (part of the 

RCCA guide tubes). 

The staff reviewed the applicant’s “operating experience” program element against the criteria in

SRP-LR Section A.1.2.3.10, which states that:

(1) “Operating experience with existing programs should be discussed. The operating

experience of aging management programs, including past corrective actions resulting in 

program enhancements or additional programs, should be considered. A past failure 

would not necessarily invalidate an aging management program because the feedback 

from operating experience should have resulted in appropriate program enhancements 

or new programs. This information can show where an existing program has succeeded 

and where it has failed (if at all) in intercepting aging degradation in a timely manner. 

This information should provide objective evidence to support the conclusion that the 

effects of aging will be managed adequately so that the structure and component 

intended function(s) will be maintained during the period of extended operation.”

 

3 The specific acceptance criteria for the augmented inspection techniques in the EPRI MRP RVI I&E 

Guidelines are identified as proprietary information by the EPRI MRP. This report was submitted to the 

NRC with a proprietary affidavit in the EPRI letter of January 12, 2009 (ML091060204). The staff is 

withholding the specific details of the proprietary acceptance criteria from publication in accordance with 

the requirements in 10 CFR 2.390. However, the staff did confirm that the acceptance criteria are in 

conformance with the staff’s recommendations for establishing “acceptance criteria” program elements in 

Section A.1.2.3.6 of the SRP-LR.
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(2) “An applicant may have to commit to providing operating experience in the future for new 

programs to confirm their effectiveness.”

The staff noted that the applicant credits this AMP and the augmented inspection 

methodology in MRP-227-Rev. 0 to manage cracking in the PINPG baffle and former bolts, 

and in other high strength bolts, and control rod guide tube alignment pins (same as rod 

control cluster guide tube alignment pins), and potentially loss of material due to wear in the 

RCCA guide tube cards. In a letter dated August 21, 2009, the applicant clarified that the 

augmented inspection and flaw evaluation recommendations in the EPRI MRP RVI I&E 

guideline accounts for relevant operating experience (OE) for the RVI components in 

Westinghouse-designed reactor units, which include the units at PINGP. The staff verified 

that the augmented inspection and evaluation program in the EPRI MRP RVI I&E 

guidelines currently accounts for the generic operating experience for Westinghousedesigned RVI components and that the methodology will use an engineering-analysis 

defined and sampling-based inspection program to manage the aging effects that are 

applicable to the PINGP RVI components and to account for this OE. The staff finds that 

the applicant has appropriately accounted for the relevant OE because the applicant has 

adequately described the OE that is applicable to the PINGP RVI components and because 

the staff has verified that the applicable OE will be accounted for in the augmented 

inspection and evaluation activities of the PWR Vessel Internals Program when it is 

implemented during the period of extended operation.

The staff noted that, although the applicant listed loss of material due to wear as applicable 

OE for the PINGP flux thimble tubes, the applicant manages loss of material due to wear in 

the flux thimble tubes in accordance with LRA AMP B2.1.18, Flux Thimble Tube Inspection 

Program. The staff noted that this is consistent with the AMP recommended in Table IV.B2 

of the GALL Report for managing wear in the thimble tubes and that, consistent with the 

recommendations in GALL AMP XI.M37, “Flux Thimble Tube Inspection,” the program uses 

eddy current methods to monitor for wear in the thimble tubes and is designed to account 

for the generic operating experience with Westinghouse-designed flux thimble tube wear. 

The staff evaluates the ability of the applicant’s Flux Thimble Tube Inspection Program to 

manage loss of material due to wear in the flux thimble tubes in SER Section 3.0.3.2.8.

Based on this review, the staff confirmed that the Aoperating 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 element acceptable. Open Item 3.0.3.1.21, Part 1 is resolved with respect to 

the acceptability of the “operating experience” program element for this plant-specific AMP.

USAR Supplement. In LRA Section B2.1.32, the applicant provided the USAR supplement 

for the PWR Vessel Internals Program, which states that the program is used to manage 

the aging effects that are applicable to the PINGP RVI components and that the program 

implements both the inservice inspection requirements of the ASME Code Section XI and 

the augmented inspection requirements for these components of the EPRI MRP. The 

UFSAR supplement also states that the applicant participates in the augmented industry 

programs for investigating and managing the aging effects for PWR RVI and that the 

program will be implemented prior to the period of extended operation.
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The staff determined that the applicant’s UFSAR supplement summary description provided 

an adequate summary of the program because i adequately summarized that the program 

involves both the applicable implementation of the inservice inspection requirements of the 

ASME Code Section XI and the augmented inspection activities of the EPRI MRP as the 

primary bases for this program.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. The staff verified that 

the applicant placed Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. 

Open Item 3.0.3.1.21, Part 2 is resolved with respect to updating the contents of Commitment 

No. 25 relative to this plant-specific AMP.

Based on this review, the staff determined that the information in the UFSAR supplement is an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its technical review of the applicant’s PWR Vessel Internals 

Program, the staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The 

staff also reviewed the UFSAR supplement for this AMP and concludes that it provides an 

adequate summary description of the program, as required by 10 CFR 54.21(d).

3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs 

3.0.4.1 Summary of Technical Information in Application

In Appendix A, AUFSAR Supplement,” Section A2.0, ASummary Descriptions of Programs that 

Manage the Effects of Aging,@ and Appendix B, AAging Management Programs,@ Section B1.3, 

AQuality Assurance Program and Administrative Controls,@ of the LRA , 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 PINGP 

quality assurance program (QAP) is used which 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. Section A2.0 and Section B1.3, of the LRA 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 the NUREG-1800, 

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

(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 
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will be maintained consistent with the CLB for the period of extended operation. The SRP-LR, 

Branch Technical Position RLSB-1, AAging Management Review - Generic,@ describes ten 

attributes of an acceptable AMP. Three of these 10 attributes are associated with the (QA)

activities of corrective action, confirmation process, and administrative controls. Table A.1-1, 

AElements of an Aging Management Program for License Renewal,@ of Branch Technical 

Position RLSB-1 provides the following description of these quality attributes:

 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; 

and,

 Attribute No. 9 - Administrative Controls, which should provide a formal review and 

approval process.

The SRP-LR, Branch Technical Position 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 nonsafetyrelated 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. Branch Technical Position 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 nonsafetyrelated 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 NRC staff reviewed the applicant=s AMPs described in Appendix A and Appendix B of the 

LRA, and the associated implementing procedures. The purpose of this review was to ensure 

that the QA attributes (corrective action, confirmation process, and administrative controls) were 

consistent with the staff=s guidance described in Branch Technical Position IQMB-1. Based on 

the NRC staff=s evaluation, the descriptions of the AMPs and their associated quality attributes 

provided in Appendix A, Section A2.0, and Appendix B, Section B1.3, of the LRA are consistent 

with the staff=s position regarding QA for aging management.

3.0.4.3 Conclusion

On the basis of the NRC staff=s evaluation, the descriptions and applicability of the plant-specific 

AMPs and their associated quality attributes provided in Appendix A, Section A2.0, and 

Appendix B, Section B1.3 of the LRA, were determined to be consistent with the staff=s position 

regarding QA for aging management. The staff concludes that the QA attributes (corrective 
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action, confirmation process, and administrative control) of the applicant's AMPs are consistent 

with 10 CFR 54.21(a)(3).

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

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

reactor vessel, internals, and reactor coolant system components and component groups of:

• pressurizer system

• reactor coolant system

• reactor internals system

• reactor vessel system

• steam generator system

3.1.1 Summary of Technical Information in the Application 

LRA Section 3.1 provides AMR results for the reactor vessel, internals, and reactor coolant 

systems components and component groups. LRA Table 3.1.1, “Summary of Aging 

Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, and 

Reactor Coolant,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the ESF systems 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 CRs 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 

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, and reactor 

coolant system components within the scope of license renewal and subject to an AMR, will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the AMR items that the applicant had identified as being 

consistent with the GALL Report to ensure the applicant’s claim that certain AMRs were 

consistent with the GALL Report. The staff did not repeat its review of the matters described in 

the GALL Report; however, the staff did verify that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s review are 

documented in SER Section 3.1.2.1.

During the onsite audit, the staff also selected AMRs consistent with the GALL Report and for 

which further evaluation is recommended. The staff confirmed that the applicant’s further 

evaluations were consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff’s 

audit evaluations are documented in SER Section 3.1.2.2.
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The staff also conducted a 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 materialenvironment combinations specified. The staff’s evaluations are documented in SER 

Section 3.1.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management, 

the staff reviewed the AMR line items and the plant’s 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 Fatigue is a 

TLAA (See 

SER Section 

3.1.2.2.1)

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-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 Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.1)

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-alloy 

reactor coolant 

pressure boundary 

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 Not applicable Not 

applicable to 

PWRs (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 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 

7000 cycles) of 

thermal stress range

Yes Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.1)

Stainless steel and 

nickel-alloy reactor 

vessel internals 

components

(3.1.1-5)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA Fatigue is a 

TLAA (See 

SER Section 

3.1.2.2.1)

Nickel-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 Fatigue is a 

TLAA (See 

SER Section 

3.1.2.2.1)

Steel and stainless 

steel reactor coolant 

pressure boundary 

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 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; 

and nickel-alloy 

reactor coolant 

pressure boundary 

piping, piping 

components, piping 

elements; flanges; 

nozzles and safe 

ends; pressurizer 

vessel shell heads 

and welds; heater 

sheaths and sleeves; 

penetrations; and 

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 Fatigue is a 

TLAA (See 

SER Section 

3.1.2.2.1)

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-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 Fatigue is a 

TLAA (See 

SER Section 

3.1.2.2.1)

Steel; stainless steel; 

steel with nickel-alloy 

or stainless steel 

cladding; nickel-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 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 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 Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.1.1)
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

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 Not applicable Not 

applicable to 

PINGP

(See SER 

Section 

3.1.2.2.2.1)

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 Not applicable Not 

applicable to 

PWRs 

(See SER 

Section 

3.1.2.2.2.(2))

Stainless steel, 

nickel-alloy, and steel 

with nickel-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 Not applicable Not 

applicable to 

PWRs 

(See SER 

Section 

3.1.2.2.2.(3))

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor coolant 

pressure boundary 

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 Not applicable Not 

applicable to 

PWRs 

(See SER 

Section 

3.1.2.2.2.(3))

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 and for 

Westinghouse 

Model 44 and 51 

S/G, if general and 

pitting corrosion of 

the shell is known to 

exist, additional 

inspection 

procedures are to be 

developed

Yes Water Chemistry 

Program 

(B2.1.40) and 

ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.2.(4))
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 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 Loss of 

fracture 

toughness is 

a TLAA (See 

SER Section 

3.1.2.2.3.(1))

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 Reactor Vessel

Surveillance 

Program

(B2.1.34)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.3.(2))

Stainless steel and 

nickel-alloy top head 

enclosure vessel 

flange leak detection 

line

(3.1.1-19)

Cracking due to 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

A plant-specific 

aging management 

program is to be 

evaluated because 

existing programs 

may not be capable 

of mitigating or 

detecting crack 

initiation and growth 

due to SCC in the 

vessel flange leak 

detection line.

Yes Not applicable Not

applicable to 

PWRs (See 

SER Section 

3.1.2.2.4.(1))

Stainless steel 

isolation condenser 

components exposed 

to reactor coolant

(3.1.1-20)

Cracking due to 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD), 

Water Chemistry, 

and plant-specific 

verification program

Yes Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.4.(2))

Reactor vessel shell 

fabricated of SA508-

Cl 2 forgings clad 

with stainless steel 

using a high-heatinput welding process

(3.1.1-21)

Crack growth 

due to cyclic 

loading

TLAA Yes TLAA Crack growth 

due to cyclic 

loading is a 

TLAA (See 

SER Section 

3.1.2.2.5)
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

Stainless steel and 

nickel-alloy reactor 

vessel internals 

components exposed 

to reactor coolant 

and neutron flux

(3.1.1-22)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement, 

void swelling

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results (3) 

submit for NRC 

approval > 24 

months before the 

extended period an 

RVI inspection plan 

based on industry 

recommendation

No, but 

licensee 

commitment 

needs to be 

confirmed

PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with 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 

stress corrosion 

cracking

A plant-specific 

aging management 

program is to be 

evaluated

Yes Water Chemistry 

Program 

(B2.1.40), ASME 

Section XI 

Inservice 

Inspection 

Program (B2.1.3), 

and One-Time 

Inspection of 

ASME Code 

Class 1 SmallBore Piping 

Program 

(B2.1.30)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.7.(1)) 

Class 1 cast 

austenitic stainless 

steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-24)

Cracking due to 

stress corrosion 

cracking

Water Chemistry 

Program and for, 

CASS components 

that do not meet 

NUREG-0313, a 

plant-specific aging 

management 

program

Yes Water Chemistry 

Program 

(B2.1.40) and 

ASME Section XI

Inservice 

Inspection 

Subsection IWB, 

IWC, and IWD 

Program (B2.1.3)

See SER 

Section 

3.1.2.2.7.(2)

Stainless steel jet 

pump sensing line

(3.1.1-25)

Cracking due to 

cyclic loading

A plant-specific 

aging management 

program is to be 

evaluated

Yes Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.8.(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 Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.8.(2))
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 

nickel-alloy reactor 

vessel internals 

screws, bolts, tie 

rods, and hold-down 

springs

(3.1.1-27)

Loss of preload 

due to stress 

relaxation

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results (3) 

submit for NRC 

approval > 24 

months before the 

extended period an 

RVI inspection plan 

based on industry 

recommendation

No, but 

licensee 

commitment 

needs to be 

confirmed

PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with 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 

aging management 

program is to be 

evaluated

Yes Not applicable Not 

applicable to 

PINGP (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 

aging management 

program is to be 

evaluated

Yes Not applicable Not 

applicable to 

PWRs (See 

SER Section 

3.1.2.2.11)
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

Stainless steel 

reactor vessel 

internals components 

(e.g., Upper internals 

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 (CRGT) 

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 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Water Chemistry 

and FSAR 

supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period an 

RVI inspection plan 

based on industry 

recommendation

No, but 

licensee 

commitment 

needs to be 

confirmed

Water Chemistry 

Program 

(B2.1.40) and 

PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.12)

Nickel-alloy and steel 

with nickel-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 

primary water 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD) and 

Water Chemistry 

and FSAR 

supplement 

commitment to 

implement 

applicable plant 

commitments to 

(1) NRC Orders, 

Bulletins, and 

Generic Letters 

associated with 

nickel-alloys and 

(2) staff-accepted 

industry guidelines

No, but 

licensee 

commitment 

needs to be 

confirmed

ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3), 

Water Chemistry 

Program

(B2.1.40), and 

Nickel-Alloy 

Nozzles and 

Penetrations 

Program

(B2.1.27)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.13)

Steel steam 

generator feedwater 

inlet ring and 

supports

(3.1.1-32)

Wall thinning 

due to flowaccelerated 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated

Yes Not Applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.2.14)
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

Stainless steel and 

nickel-alloy reactor 

vessel internals 

components

(3.1.1-33)

Changes in 

dimensions due 

to void swelling

FSAR supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period an 

RVI inspection plan 

based on industry 

recommendation

No, but 

licensee 

commitment 

needs to be 

confirmed

PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.15)

Stainless steel and 

nickel-alloy reactor 

control rod drive 

head penetration 

pressure housings 

(3.1.1-34)

Cracking due to 

stress corrosion

cracking and

primary water 

stress corrosion 

cracking

Inservice Inspection, 

Subsections (IWB, 

IWC, and IWD) and 

the Water Chemistry 

and for nickel-alloy, 

comply with 

applicable NRC 

Orders and provide 

a commitment in the 

FSAR supplement 

commitment to

implement plant 

commitments to 

applicable (1) 

Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines

No, but 

licensee 

commitment 

needs to be 

confirmed

ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and Water 

Chemistry 

Program

(B2.1.40)

Consistent 

with GALL 

Report (SER 

Section 

3.1.2.2.16.1)

Steel with stainless 

steel or nickel-alloy

cladding primary side 

components; steam 

generator upper and 

lower heads, 

tubesheets and tubeto-tube sheet welds

(3.1.1-35)

Cracking due to 

stress corrosion 

cracking and 

primary water 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD) and 

Water Chemistry 

and for nickel-alloy, 

comply with 

applicable NRC 

Orders and provide 

a commitment in the 

FSAR supplement to 

implement 

applicable 

(1) Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines

No, but 

licensee 

commitment 

needs to be 

confirmed

Not applicable Not 

applicable.

(See SER 

Section 

3.1.2.1.1)
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

Nickel-alloy, stainless 

steel pressurizer 

spray head

(3.1.1-36)

Cracking due to 

stress corrosion 

cracking and 

primary water 

stress corrosion 

cracking

Water Chemistry 

and One-Time 

Inspection and, for 

nickel-alloy welded 

spray heads, comply 

with applicable NRC 

Orders and provide 

a commitment in the 

FSAR supplement to 

implement 

applicable 

(1) Bulletins and 

Generic Letters and 

(2) staff-accepted 

industry guidelines

Not, unless

licensee 

commitment 

needs to be 

confirmed

Water Chemistry 

Program 

(B2.1.40), and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.16.2)

Stainless steel and 

nickel-alloy reactor 

vessel internals 

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 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Water Chemistry 

and FSAR 

supplement 

commitment to 

(1) participate in 

industry RVI aging 

programs 

(2) implement 

applicable results 

(3) submit for NRC 

approval > 24 

months before the 

extended period an 

RVI inspection plan 

based on industry 

recommendation

No, but 

licensee 

commitment 

needs to be 

confirmed

Water Chemistry 

Program

(B2.1.40) and 

PWR Vessel 

Internals Program 

(B2.1.32)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.2.17)

Steel (with or without 

stainless steel 

cladding) control rod 

drive return line 

nozzles exposed to 

reactor coolant

(3.1.1-38)

Cracking due to 

cyclic loading

BWR CR Drive 

Return Line Nozzle

No Not applicable Not 

applicable to 

PWRs

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 Not applicable Not 

applicable to 

PWRs
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

Stainless steel and 

nickel-alloy

penetrations for 

control rod drive 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 

stress corrosion 

cracking, 

Intergranular 

stress corrosion 

cracking, cyclic 

loading

BWR Penetrations 

and Water 

Chemistry

No Not applicable Not 

applicable to 

PWRs

Stainless steel and 

nickel-alloy piping, 

piping components, 

and piping elements 

greater than or equal 

to 4 NPS; nozzle safe 

ends and associated 

welds

(3.1.1-41)

Cracking due to 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

BWR Stress 

Corrosion Cracking 

and Water 

Chemistry

No Not applicable Not 

applicable to 

PWRs

Stainless steel and 

nickel-alloy vessel 

shell attachment 

welds exposed to 

reactor coolant

(3.1.1-42)

Cracking due to 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

BWR Vessel ID 

Attachment Welds 

and Water 

Chemistry

No Not applicable Not 

applicable to 

PWRs

Stainless steel fuel 

supports and control 

rod drive assemblies 

control rod drive 

housing exposed to 

reactor coolant

(3.1.1-43)

Cracking due to 

stress corrosion

cracking and 

intergranular 

stress corrosion 

cracking

BWR Vessel 

Internals and Water 

Chemistry

No Not applicable Not 

applicable to 

PWRs

Stainless steel and 

nickel-alloy core 

shroud, core plate, 

core plate bolts, 

support structure, top 

guide, core spray 

lines, spargers, jet 

pump assemblies, 

control rod drive 

housing, nuclear 

instrumentation guide 

tubes

(3.1.1-44)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

BWR Vessel 

Internals and Water 

Chemistry

No Not applicable Not 

applicable to 

PWRs
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

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant

(3.1.1-45)

Wall thinning 

due to flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No Not applicable Not 

applicable to 

PWRs

Nickel-alloy core 

shroud and core 

plate access hole 

cover (mechanical 

covers)

(3.1.1-46)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD), and 

Water Chemistry

No Not applicable Not 

applicable to 

PWRs

Stainless steel and 

nickel-alloy reactor 

vessel internals 

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 Not applicable Not 

applicable to 

PWRs

Steel and stainless 

steel Class 1 piping, 

fittings and branch 

connections < NPS 4 

exposed to reactor 

coolant

(3.1.1-48)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (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 Smallbore Piping

No Not applicable Not 

applicable to 

PWRs

Nickel-alloy core 

shroud and core 

plate access hole 

cover (welded 

covers)

(3.1.1-49)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

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 Not applicable Not 

applicable to 

PWRs
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

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 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

Reactor Head 

Closure Studs

No Not applicable Not 

applicable to 

PWRs

Cast austenitic 

stainless steel 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 Not applicable Not 

applicable to 

PWRs

Steel and stainless 

steel reactor coolant 

pressure boundary 

(RCPB) pump and 

valve closure bolting, 

manway and holding 

bolting, flange 

bolting, and closure 

bolting in highpressure and hightemperature systems

(3.1.1-52)

Cracking due to 

stress corrosion 

cracking, loss 

of material due 

to wear, loss of 

preload due to 

thermal effects, 

gasket creep, 

and selfloosening

Bolting Integrity No Bolting Integrity 

Program (B2.1.6)

Consistent 

with 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 Not applicable Not 

applicable to 

PINGP. (See 

SER Section 

3.1.2.1.1)

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 Not applicable Not 

applicable to 

PINGP. (See 

SER Section 

3.1.2.1.1)

Cast austenitic 

stainless steel 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 

ASME Section XI 

Inservice Inspection 

Subsection IWB, 

IWC, and IWD

Program

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3)

Consistent 

with the 

GALL Report
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

Cooper 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 Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

Cast austenitic 

stainless steel Class 

1 piping, piping 

component, and 

piping elements and 

control rod drive 

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 (B2.1.39)

Consistent 

with GALL 

Report

Steel reactor coolant 

pressure boundary 

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 

(B2.1.4)

Consistent 

with 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 flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No Flow-Accelerated 

Corrosion 

Program 

(B2.1.17)

Steam Generator 

Tube Integrity 

Program 

(B2.1.37)

Consistent 

with the 

GALL Report 

(See SER 

Section 

3.1.2.1.2) 

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 

(B2.1.18)

Consistent 

with GALL 

Report

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 

Inservice 

Inspection 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3)

Consistent 

with GALL 

Report
3-200

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 stainless steel 

cladding reactor 

coolant system 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 Not applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

Steel reactor vessel 

flange, stainless steel 

and nickel-alloy

reactor vessel 

internals exposed to 

reactor coolant 

(e.g., upper and 

lower internals 

assembly, CEA 

shroud assembly, 

core support barrel, 

upper grid assembly, 

core support shield 

assembly, lower grid 

assembly)

(3.1.1-63)

Loss of material 

due to wear

Inservice 

Inspection (IWB, 

IWC, and IWD)

No ASME Section XI 

Inservice 

Inspection 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with GALL 

Report

Stainless steel and 

steel with stainless 

steel or nickel-alloy

cladding pressurizer 

components

(3.1.1-64)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD) and 

Water Chemistry

No ASME Section XI 

Inservice 

Inspection 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and Water 

Chemistry 

Program 

(B2.1.40)

Consistent 

with GALL 

Report
3-201

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

Nickel-alloy reactor 

vessel upper head 

and control rod drive 

penetration nozzles, 

instrument tubes, 

head vent pipe (top 

head), and welds

(3.1.1-65)

Cracking due to 

primary water 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD) and 

Water Chemistry 

and Nickel-Alloy 

Penetration Nozzles 

Welded to the Upper 

Reactor Vessel 

Closure Heads of 

Pressurized Water 

Reactors

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3), 

Water Chemistry 

Program 

(B2.1.40), and 

Nickel-Alloy 

Penetration 

Nozzles Welded 

to the Upper 

Reactor Vessel 

Closure Heads of 

Pressurized 

Water Reactors

Program 

(B2.1.28)

Consistent 

with GALL 

Report

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 Not applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

Steel with stainless 

steel or nickel-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 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and Water 

Chemistry 

(B2.1.40)

Consistent 

with GALL 

Report
3-202

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 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, reactor 

coolant system cold 

leg, hot leg, surge 

line, and spray line 

piping and fittings

(3.1.1-68)

Cracking due to 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD), and 

Water Chemistry

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and Water 

Chemistry 

(B2.1.40)

Consistent 

with GALL 

Report

Stainless steel, 

nickel-alloy safety 

injection nozzles, 

safe ends, and 

associated welds and 

buttering exposed to 

reactor coolant

(3.1.1-69)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Inservice 

Inspection (IWB, 

IWC, and IWD), and 

Water Chemistry

No ASME Section XI 

Inservice 

Inspection, 

Subsections IWB, 

IWC, and IWD 

Program (B2.1.3) 

and Water 

Chemistry 

(B2.1.40)

Consistent 

with GALL 

Report

Stainless steel; steel 

with stainless steel 

cladding Class 1 

piping, fittings and 

branch connections < 

NPS 4 exposed to 

reactor coolant 

(3.1.1-70) 

Cracking due to 

stress corrosion 

cracking, 

thermal and 

mechanical 

loading

Inservice Inspection 

(IWB, IWC, and 

IWD), Water 

chemistry, and OneTime Inspection of 

ASME Code Class 1 

Small-bore Piping

No Inservice 

Inspection (IWB, 

IWC, and IWD) 

(B2.1.3),

Water chemistry 

(B2.1.40), and

One-Time 

Inspection of 

ASME Code 

Class 1 Smallbore Piping 

(B2.1.30)

Consistent 

with GALL 

Report

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

reactor coolant 

leakage

(3.1.1-71)

Cracking due to 

stress corrosion 

cracking; loss 

of material due 

to wear

Reactor Head 

Closure Studs

No Reactor Head 

Closure Stud 

Program 

(B2.1.33)

Consistent 

with GALL 

Report
3-203

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

Nickel-alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater 

steam (3.1.1-72)

Cracking due to 

OD stress 

corrosion 

cracking and 

intergranular 

attack, loss of 

material due to 

fretting and 

wear

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

(B2.1.37)

Water Chemistry

(B2.1.40

Consistent 

with the 

GALL Report

Nickel-alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant 

(3.1.1.-73)

Cracking due to 

primary water 

stress corrosion 

cracking

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

(B2.1.37)

Water Chemistry 

(B2.1.40

Consistent 

with the 

GALL Report

Chrome plated steel, 

stainless steel, 

nickel-alloy steam 

generator antivibration bars 

exposed to 

secondary 

feedwater/steam 

(3.1.1-74)

Cracking due to 

stress corrosion 

cracking, loss 

of material due 

to crevice 

corrosion and 

fretting

Steam Generator 

Tube Integrity and 

Water Chemistry

No Steam Generator 

Tube Integrity 

Program 

(B2.1.37) and 

Water Chemistry 

Program 

(B2.1.40), or OneTime Inspection 

(B2.1.29) and 

Water Chemistry 

Program 

(B2.1.40)

Consistent 

with GALL 

Report (See 

SER Section 

3.1.2.1.3)

Nickel-alloy oncethrough steam 

generator 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 Not applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

Steel steam 

generator tube 

support plate, 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 

(B2.1.37)

Water Chemistry 

(B2.1.40)

Consistent 

with the 

GALL Report

Nickel-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 Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)
3-204

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 flowaccelerated 

corrosion

Steam Generator 

Tube Integrity and 

Water Chemistry

No Not applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

Nickel-alloy steam 

generator tubes 

exposed to 

secondary feedwater/ 

steam (3.3.1-79)

Denting due to 

corrosion of 

steel tube 

support plate

Steam Generator 

Tube Integrity; 

Water Chemistry 

and, 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 Steam Generator 

Tube Integrity 

(B2.1.37)

Water Chemistry 

(B2.1.40)

Consistent 

with the 

GALL Report

Cast austenitic 

stainless steel reactor 

vessel internals (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 PWR Vessel 

Internals Program

(B2.1.32)

Consistent 

with GALL 

Report

(See SER 

Section 

3.1.2.1.4)

Nickel-alloy or nickelalloy clad steam 

generator divider 

plate exposed to 

reactor coolant

(3.1.1-81)

Cracking due to 

primary water 

stress corrosion 

cracking

Water Chemistry No Water Chemistry 

Program 

(B2.1.40)

Consistent 

with GALL 

Report

Stainless steel steam 

generator primary 

side divider plate 

exposed to reactor 

coolant

(3.1.1-82)

Cracking due to 

stress corrosion 

cracking

Water Chemistry No Water Chemistry 

Program 

(B2.1.40)

Consistent 

with GALL 

Report
3-205

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 nickel-alloy or 

stainless steel 

cladding; and nickelalloy reactor vessel 

internals and reactor 

coolant pressure 

boundary 

components exposed 

to reactor coolant

(3.1.1-83)

Loss of material 

due to pitting 

and crevice 

corrosion

Water Chemistry No Water Chemistry 

Program 

(B2.1.40)

Consistent 

with GALL 

Report

Nickel-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 

stress corrosion 

cracking

Water Chemistry 

and One-Time 

Inspection or 

Inservice 

Inspection (IWB, 

IWC, and IWD).

No Not applicable. Not 

applicable to 

PINGP. (See 

SER Section 

3.1.2.1.1)

Nickel-alloy piping, 

piping components, 

and piping elements 

exposed to air -

indoor uncontrolled 

(external)

(3.1.1-85)

None None NA 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 None Consistent 

with the 

GALL Report

Steel piping, piping 

components, and 

piping elements in 

concrete

(3.1.1-87)

None None NA Not applicable Not 

applicable to 

PINGP (See 

SER Section 

3.1.2.1.1)

The staff’s review of the reactor vessel, reactor vessel internals (RVIs), and reactor coolant 

system component groups followed any one of several approaches. One approach, 

documented in SER Section 3.1.2.1, reviewed AMR results for components that the applicant 
3-206

indicated are consistent with the GALL Report and require no further evaluation. Another 

approach, documented in SER Section 3.1.2.2, reviewed AMR results for components that the 

applicant indicated are consistent with the GALL Report and for which further evaluation is 

recommended. A third approach, documented in SER Section 3.1.2.3, reviewed AMR results for 

components that the applicant indicated are not consistent with, or not addressed in, the GALL 

Report. The staff’s review of AMPs credited to manage or monitor aging effects of the reactor 

vessel, RVIs, and reactor coolant system components is documented in SER Section 3.0.3.

3.1.2.1 AMR Results 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 pressurizer, reactor coolant, reactor internals, reactor vessel, 

and steam generator systems components:

• ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program

• Bolting Integrity Program

• Boric Acid Corrosion Prevention Program

• Closed-Cycle Cooling Water System Program

• External Surfaces Monitoring Program

• Flow-Accelerated Corrosion Program

• Flux Thimble Tube Inspection Program

• Lubricating Oil Analysis Program

• Nickel-Alloy Nozzles and Penetrations Program

• Nickel-Alloy Penetration Nozzles Welded to the Upper Reactor Vessel Closure Heads of 

Pressurized Water Reactors Program

• One-Time Inspection Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• PWR Vessel Internals Program

• Reactor Head Closure Studs Program

• Reactor Vessel Surveillance Program

• Selective Leaching of Materials Program

• Steam Generator Tube Integrity Program

• Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program

• Water Chemistry Program

LRA Tables 3.1.2-1 through 3.1.2-5 summarize AMRs for the pressurizer, reactor coolant, 

reactor internals, reactor vessel, and steam generator systems components and indicate AMRs 

claimed to be consistent with the GALL Report.
3-207

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined whether the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with notes A through E indicating 

how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. 

The staff reviewed these line items to verify consistency with the GALL Report and validity of 

the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL AMP. The staff reviewed these line items to verify consistency with the GALL Report and 

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 

of some system components in the GALL Report; however, the applicant identified in the GALL 

Report a different component with the same material, environment, aging effect, and AMP as 

the component under review. The staff 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 sitespecific conditions.

Note D indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL AMP. The staff 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 AMPs have been reviewed and accepted. The staff also determined whether the 

applicant’s AMP was consistent with the GALL AMP and whether the AMR was valid for the 

site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP or a plant-specific AMP. The staff 

reviewed these line items to verify consistency with the GALL Report. The staff also determined 

whether the credited AMP would manage the aging effect consistently with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.
3-208

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 

reactor vessel, RVIs, and RCS 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, 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 subsection that follows

3.1.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.1.1, items 11 and 38 to 51, the applicant states that the corresponding AMR 

items in GALL Report are not applicable to PINGP because the AMR items in the GALL 

Report are only applicable to particular components in BWR reactor designs and because 

PINGP is a Westinghouse-designed PWR facility. The staff verified that the stated AMR items in 

the GALL Report are only applicable to BWR designed facilities and are not applicable to the 

PINGP LRA.

In LRA Table 3.1.1, items 35, 66, 75, and 84, the applicant states that the corresponding

AMR result line in the GALL Report is not applicable because PINGP does not have oncethrough steam generators. The staff reviewed the documentation supporting the applicant's

AMR evaluation and confirmed the applicant's claim that PINGP has no once-through steam

generators. PINGP steam generators are recirculating, as described in UFSAR for Unit 1 and 

Unit 2. Therefore, the staff agrees with the applicant's determination that the corresponding 

AMR result line in the GALL Report is not applicable to PINGP.

In LRA Table 3.1.1, item 87, the applicant states that further evaluation in LRA Section 

3.5.2.2.1.4 concluded that steel components in concrete are not susceptible to aging and do not 

require aging management. The staff noted this item applies to GALL line item IV.E-6 (RP-01), 

which indicates that there is no aging effect for this component type and environment, and 

therefore do not require an AMP. Therefore, the staff agrees with the applicant in that this line 

item does not require aging management.

In LRA Table 3.1.1, item 53, the applicant states that the corresponding AMR result line in the 

GALL Report is not applicable because PINGP does not have steel piping, piping elements, and 

components of the Reactor Vessel, Vessel Internals, or Reactor Coolant System exposed to 

closed-cycle cooling water. The staff reviewed the documentation supporting the applicant's 

AMR evaluation and confirmed the applicant's claim that PINGP does not have steel piping, 

piping elements and components of the Reactor Vessel, Vessel Internals, or Reactor Coolant 

System exposed to closed cycle cooling water. Therefore, the staff agrees with the applicant's 

determination that the corresponding AMR result line in the GALL Report is not applicable to 

PINGP.
3-209

In LRA Table 3.1.1, item 54, the applicant states that the corresponding AMR result

line in the GALL Report is not applicable because PINGP does not have copper alloy

piping components in the Reactor Vessel, Vessel Internals, or Reactor Coolant System. The 

staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed the 

applicant's claim that PINGP does not have copper alloy piping components in the Reactor 

Vessel, Vessel Internals, or Reactor Coolant System. Therefore, the staff agrees with the 

applicant's determination that the corresponding AMR result line in the GALL Report is not

applicable to PINGP.

In LRA Table 3.1.1, item 56, the applicant states that the corresponding AMR result line in the 

GALL Report is not applicable because PINGP does not have copper alloy > 15% Zn piping, 

piping components, and piping elements exposed to closed cycle cooling water in the Class 1 

Reactor Vessel, Vessel Internals, or Reactor Coolant System. The staff reviewed the 

documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim. 

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result 

line in the GALL Report is not applicable to PINGP.

In LRA Table 3.1.1, item 62, the applicant indicates that the corresponding AMR result line in 

the GALL Report is not applicable because no PINGP AMR line items correspond to this item. 

The staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed 

the applicant's claim that cracking of stainless steel components exposed to reactor coolant is

addressed in the evaluation of fatigue in other line items. Therefore, the staff agrees 

with the applicant's determination that the corresponding AMR result line in the GALL Report is 

not applicable to PINGP.

In LRA Table 3.1.1, items 77, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because PINGP does not use phosphate chemistry. The staff 

reviewed the documentation supporting the applicant's AMR evaluation and confirmed the 

applicant's claim that PINGP does not use phosphate chemistry. Therefore, the staff agrees 

with the applicant's determination that the corresponding AMR result line in the GALL Report is 

not applicable to PINGP.

In LRA Table 3.1.1, items 78, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because PINGP steam generators do not have lattice bars. The 

staff reviewed the documentation supporting the applicant's AMR evaluation and confirmed the 

applicant's claim that PINGP steam generators have tube support plates instead of lattice bars. 

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result 

line in the GALL Report is not applicable to PINGP.

3.1.2.1.2 Loss of Material due to Flow Accelerated Corrosion

In LRA Table 3.1.2-5, item 59, the applicant identified that loss of material due to flow 

accelerated corrosion (FAC) is an applicable AERM for the Unit 2 carbon steel feedwater inlet 

nozzle thermal sleeve under exposure to an external treated water environment. In this AMR 

item, the applicant applied Note E, which indicated consistency with the GALL Report item for 

material, environment, and aging effect, but credited a different AMP. The applicant indicated 

that the LRA AMP B2.1.37, “Steam Generator Tube Integrity Program,” will manage the loss of 
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material due to FAC in the external feedwater inlet nozzle thermal sleeve surfaces. The staff 

reviewed the AMR item against the applicant’s Steam Generator Integrity Program.

The staff noted that the industry, working through EPRI, has implemented steam generator 

programs that included control of secondary-side water chemistry and upgrades in secondaryside equipment. NEI 97-06 stated that industry's steam generator programs have matured to 

include improvements in programmatic features, such as degradation-specific management, 

which have been incorporated into a series of EPRI seam generator programs guidelines. EPRI 

Steam Generator Integrity Assessment Guidelines provide guidance for degradation 

assessments such as degradation mechanisms, industry experience for applicability, and 

inspections. NEI 97-06 states that secondary-side visual inspections are to be performed, and 

describes the scope of inspection and the inspection procedures and methodology to be used. 

In LRA B2.1.37, the applicant stated that its Steam Generator Tube Integrity Program 

incorporates the guidance of NEI 97-06. The applicant stated that its Steam Generator Tube 

Integrity Program is implemented in accordance with Technical Specification (TS) 5.5.8 and 

applicable industry guidance. The applicant stated that the program manages aging effects 

through a balance of prevention, inspection, and evaluation. The applicant stated that visual 

examinations are conducted on sleeves, and that visual inspections are performed to identify 

degradation of secondary side steam generator internal components. 

The staff approved the applicant’s response to NRC Generic Letter 97-06, and the amendment 

to its TSs, which included monitoring of the Unit 2 feedwater inlet nozzle thermal sleeves. In its 

response to GL 97-06, the applicant committed to implement its Steam Generator Integrity 

Program as described in NEI 97-06, “Steam Generator Program Guidelines.” The staff 

determined that the Steam Generator Tube Integrity Program included the implementation of 

the NEI 97-06 guidelines, and that the implementation procedures include visual inspections of 

feedwater inlet nozzle thermal sleeves to look for evidence of loss of material on external 

surfaces. The staff finds that the applicant’s AMP provides adequate assurance that the thermal 

sleeves will be able to perform their intended functions during the period of extended operation.

Based on the programs identified, the staff concludes that the applicant has demonstrated that 

the effects of aging for these components will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operations 

as required by 10 CFR 54.21(a)(3).

3.1.2.1.3 Cracking due to Stress Corrosion Cracking; Loss of Material due to Crevice Corrosion

and Fretting 

LRA Table 3.1.2-5 includes AMR result lines referring to LRA Table 3.1.1, item 3.1.1-74, that 

credit the One-Time Inspection Program and the Water Chemistry Program to manage cracking 

due to stress corrosion cracking (SCC) and loss of material due to crevice and pitting corrosion 

in nickel-alloy steam flow limiters in a steam environment in the Unit 1 steam generator system. 

For the AMR result lines crediting the One-Time Inspection Program, the applicant cited generic 

Note E, indicating that the material, environment, and aging effect are all consistent with the 

GALL Report, but a different AMP is credited. For the AMR result lines showing an aging effect 

of loss of material due to pitting corrosion, the applicant cited plant-specific Note 101, which 
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states that the aging mechanism is not in the GALL Report for this component, material, and 

environment combination.

The applicant referenced LRA Table 3.1-1, item 3.1.1-74 and GALL Report items IV.D1-14 and 

IV.D1-15. The staff reviewed the AMR results lines that reference Note E and confirmed that the 

component type, material, environment, and aging effect are consistent with the GALL Report. 

However, the staff noted that where the GALL Report recommends AMP XI.M19, "Steam 

Generator Tube Integrity," the applicant proposed using the One-Time Inspection Program.

During the audit and review, the staff asked the applicant to explain why the steam flow limiters 

in the Unit 1 steam generator were treated differently from other steam generator components. 

In response to this request, the applicant stated that the Unit 1 steam generators are not original 

equipment and are a different design from Unit 2 steam generators, which are original 

equipment. The applicant stated that the Unit 1 steam generator design includes additional 

steam flow limiters in the steam line exit nozzles. The applicant stated that because of this 

difference in Unit 1 and Unit 2 equipment design, it had elected not to include the Unit 1 steam 

generator flow limiters in the Steam Generator Tube Integrity Program, but to perform a onetime inspection of the unique Unit 1 components.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of this 

program, which is documented in SER Section 3.0.3.2.18, found that the Water Chemistry 

Program provides mitigation for cracking due to SCC and mitigation for loss of material due to 

crevice and pitting corrosion in nickel-alloy components. The staff reviewed the applicant’s OneTime Inspection Program. The staff’s evaluation of this program, which is documented in SER 

Section 3.0.3.1.18, found that the One-Time Inspection Program is adequate to detect the 

presence or note the absence of cracking due to SCC and of loss of material due to pitting and 

crevice corrosion for components within its scope. Based on the staff’s determination that the 

Water Chemistry Program provides mitigation and the One-Time Inspection Program provides 

detection for the aging effects of cracking due to SCC and loss of material due to pitting and 

crevice corrosion, the staff finds the applicant’s proposed AMPs for managing the aging effect of 

cracking due to SCC and loss of material due to pitting and crevice corrosion in the nickel-alloy

Unit 1 steam flow limiters to be acceptable.

Based on the programs identified, the staff concludes that the applicant’s proposed programs 

are acceptable for managing the aging effects in the applicable components. The staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.1.4 Loss of Fracture Toughness due to Thermal Aging and Neutron Irradiation

Embrittlement

LRA Table 3.1.1, AMR item 3.1.1-80, addresses loss of fracture toughness due to thermal aging 

(embrittlement) and neutron irradiation (radiation) embrittlement for CASS RVI components 

exposed to the external borated treated water environment of the reactor coolant, which for the 

RVI components includes an integrated neutron flux (i.e., neutron fluence) environment.
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The LRA credits the PINGP AMP B2.1.32 “PWR Vessels Internals Program” to manage this

aging effect for the CASS BMI column cruciforms in an external treated water environment only.

The Table 2 AMR line items in the GALL Report that correspond to LRA Table 3.1.1, item LRA 

AMR item 3.1.1-80 are IV.B2-21 and IV.B2-37, which pertain to aging management of reduction 

of fracture toughness due to thermal aging and neutron irradiation embrittlement of lower 

support castings, lower support columns, and upper support columns that are fabricated from 

CASS. In these AMR line items, the GALL Report recommends that GALL AMP XI.M13 

“Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel” be 

credited to manage loss of fracture toughness as a result of exposing the components to the 

reactor coolant with integrated neutron flux environment. The LRA Table 2 AMR line items that 

reference this line item in GALL Report Table 1 cite generic note E, indicating that the AMR line 

items are consistent with the GALL Report material, environment, and aging effect, but a 

different AMP is credited. 

The staff verified that the lower and upper support columns were fabricated from wrought 

austenitic stainless steel and the design uses a stainless steel forging instead of stainless steel 

casting, and thus for these components the guidance in GALL AMR items IV.B2-21 and IV.B2-

27 is not applicable to the components because the stainless steel in the components was not 

made using a cast fabrication method. However, the staff also confirmed that the applicant did 

reference GALL AMR item IV.B2-21 on fracture toughness for the BMI column cruciforms to 

GALL item IV.B2-21 because these components were fabricated from CASS materials. The 

staff also noted that, for these components, the applicant credited its PWR Vessel Internals 

Program to manage reduction of fracture toughness due to thermal aging and neutron 

irradiation embrittlement in lieu of crediting a program corresponding to GALL AMP XI.M13, 

“Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel.”

By letter dated December 18, 2008, the staff issued RAI 3.1.1-1 requesting the applicant to

provide its basis for crediting PINGP AMP B2.1.32 “PWR Vessels Internals Program” in lieu of

the recommended GALL AMP XI.M13 “Thermal Aging and Neutron Irradiation Embrittlement of

Cast Austenitic Stainless Steel” Program. By letter dated January 20, 2009, the applicant

provided its response to RAI 3.1.1-1. In this response, the applicant clarified that the PINGP

PWR Vessel Internals Program is based on the activities of the EPRI MRP for managing the

aging effects for RVI components, including the BMI column cruciforms that are made from

CASS. The applicant clarified that the augmented activities of the program are augmented

inspection activities for the components that go beyond the applicable ASME Section XI ISI

requirements for the RVI components in Table IWB-2500-1, Examination Category B-N-3 for

removable core support structures. The applicant stated that the PWR Vessel Internals 

Program is based on the provisions of LRA Commitment No. 25, which commits to the following 

activities and actions for the management of aging in RVI components:

• Participate in the industry programs for investigating and managing aging effects on

reactor internals;

• Evaluate and implement the results of the industry programs as applicable to the reactor

internals; and

• 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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• A PWR Vessel Internals Program will be implemented. Program features will be as 

described in LRA Section B2.1.32.

• An inspection plan for reactor internals will be submitted for NRC review and approval at 

least twenty-four months prior to the period of extended operation. In addition, the 

submittal will include any necessary revisions to the PINGP PWR Vessel Internals 

Program, as well as any related changes to the PINGP scoping, screening and AMR

results for reactor internals, to conform to the NRC-approved Inspection and Evaluation 

Guidelines.

The staff reviewed the applicant’s AMP B2.1.32 “PWR Vessels Internals Program," and the 

staff’s evaluation is documented in SER Section 3.0.3.1.21. The staff confirmed that, in a letter 

dated February 6, 2009, the applicant submitted its License Renewal Commitment List for the 

PINGP LRA and placed these commitments in the UFSAR Supplement for the application. The 

staff verified that in Commitment No. 25, the applicant committed to implementing AMP B2.1.32, 

“PWR Vessels Internal Program” at least two years prior to the period of extended operation. 

The staff also verified that Commitment No. 25 includes the actions and activities listed in the 

bullets above, which is consistent with the recommendations of the GALL Report.

Based on a review of the requirements in the ASME Code Section XI for PWR RVI components,

the staff noted that PWR RVI components may be categorized into one of the following two

groups:

• Those RVI components that are ASME Code Class 1 components and are within the

scope of the staff’s ISI of 10 CFR 50.55a and ASME Code Section XI, Examination 

Category B-N-1 for interior of the reactor vessel, B-N-2 for weld core support structure 

components, or B-N-3 for removable core support structure components

• RVI components that are not ASME Code Class and thus are not subject to the ASME

Code Section XI, Examination Category B-N-1, B-N-2, or B-N-3 requirements

In the 2005 update of the SRP-LR and the GALL Report, the NRC recommended that aging

management of PWR vessel internals needs to be done on a consistent basis among licensed

PWRs in the U.S. to account for the fact that not all of the PWR RVI components are ASME

Code Class and to account for the fact that additional aging management measures may be

necessary for some of the non-ASME Code Class PWR RVI components. Hence, the staff

updated its aging management basis in the AMRs for PWR RVI components in the GALL

Report through the following recommended commitment that was recommended to be adopted

in the UFSAR Supplements for PWR LRAs:

“(1) participate in the industry programs for investigating and managing aging 

effectson reactor internals; (2) evaluate and implement the results of the industry 

programsas 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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Thus, for current Westinghouse-designed PWR LRAs pending staff approval, the staff’s updated

basis for managing the aging effects that are attributed to the RVI components is given in NRC

NUREG-1833, Table IIIC, which states the following:

“The AMP column was changed to delete reference to XI.M16 (AMP M16 was 

alsodeleted from the GALL report) and instead require a commitment in the 

FSARSupplement to apply industry programs to be developed in the future for 

propermanagement of reactor internals. Also, added to the further evaluation 

column the requirement for the licensee commitment to be confirmed.”

The commitment that is recommended by the staff includes a provision for PWR applicant’s 

to submit an inspection plan for their RVI components that is based on the industry’s 

augmented inspection program recommendations for PWR RVI components to the NRC for 

review and approval at least two years prior to entering the period of extended operation.

By letter dated May 12, 2009, the applicant amended the LRA to resubmit the PWR Vessel 

Internals Program (LRA AMP B2.1.32) as a new-plant specific program AMP for the application 

that is based on conformance with the program element criteria in the SRP-LR Section A.1.2.3. 

The staff has verified that the program elements of the plant-specific program is relying on both 

compliance with applicable ISI activities of the ASME Code Section XI Examination Category 

B-N-3 for the RVI components that are associated with the removable core support structure, as 

well as the augmented inspection and flaw evaluation criteria and recommendations on the 

activities of the EPRI MRP to form the Westinghouse-designed RVI component, as defined in 

MRP-227-Rev. 0. 

The staff verified that collectively these activities form the basis of the applicant’s augmented 

inspection program for PWR Vessel Internals for the RVI components. The staff also verified 

that the scope of the plant-specific PWR Vessel Internals Program includes activities for the 

management of The EPRI MRP activities. This includes an assessment on whether loss of 

material, cracking, loss of fracture toughness, changes in dimension, and for fastened, keyed or 

bolted RVI connections, loss of preload are aging effects that need to be managed for the 

period of extended operation, and if so include recommendations to perform augmented 

inspections of these components in the PINGP RVI components. The staff noted that the 

applicant has incorporated this aging management basis in LRA Commitment No. 25, which 

includes a commitment to participate in the MRP activities for Westinghouse designed RVI 

components, to implement the MRP recommendations that are applicable to the RVI component 

designs at PINGP, and to submit either a MRP-based or plant-specific inspection plan for these 

components for NRC review and approval at least two years from the time PINGP is scheduled 

to enter the period of extended operation.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which states the applicant will submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components that will be approved in the staff’s issuance 

of the SER for the application from those that would be developed and approved by the staff 

through its review of Report No. MRP-227-Rev. 0. Although the staff has verified that the 

applicant’s program elements for the PWR Vessel Internals Program were acceptable and were 
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in conformance with the staff’s program element criteria in SRP-LR Section A.1.2.3, the staff 

requested and the applicant agreed to placing this commitment on the program as an additional 

measure to give the staff an opportunity to review any changes that might be proposed to the 

AMR items that credit this AMP for aging management of the PINGP RVI components or to the 

program elements for the PWR Vessel Internals Program that might be necessary as a result of 

the NRC’s review of the MRP-227-Rev. 0 report. 

The staff finds this to be a sufficient aging management basis for the PINGP managing loss of 

fracture in the CASS RVI components (i.e., in the BMI column cruciforms) because: (1) the staff 

has verified that the scope of the PWR Vessel Internals Program currently includes program 

element criteria for the management of loss of fracture toughness in the PINGP RVI 

components, (2) the applicant’s commitment for RVI components, as placed in the PWR Vessel 

Internals Program and in LRA Commitment No. 25 is consistent with the commitment 

recommendation for RVI components as given in SRP-LR Sections 3.1.2.2.6, 3.1.2.2.9, 

3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17 and in the AMRs Section of the GALL Report associated 

with these SRP-LR Sections, (3) the augmented inspection plan for the RVI components will 

supplement those mandated ISI that are required to be implemented in accordance with ASME 

Code Section XI Examination Categories B-N-1, B-N-2, or Category B-N-3 requirements, and 

(4) the inspection plan that will be submitted in accordance with LRA Commitment No. 25 will be 

subject to an NRC review and approval process. On this basis the staff finds that the applicant 

has provided an acceptable basis for managing the aging effects that are applicable to the RVI 

components at PINGP, and specifically as a basis for managing loss of fracture toughness in 

the BMI column cruciforms that are fabricated from CASS. Thus, the staff concern in 

RAI 3.1.1-1 is resolved.

On the basis of the staff’s evaluation of the AMP and the applicant’s Commitment No. 25, the

staff finds that the applicant has provided an acceptable basis for crediting the PWR Vessels 

Internals Program acceptable for the management of loss of fracture toughness in those RVI 

components (i.e., the BMI column cruciforms) that are made of CASS materials. The staff 

concludes that the applicant has demonstrated that the effects of aging for these components 

will be adequately managed so that their intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.1.5 Loss of Material due to Wear

In the a letter dated May 12, 2009, the applicant supplemented the LRA to include additional 

AMR items for managing loss of material due to wear in the RVI components, as applicable to 

the following RVI components: (1) clevis insert bolts, (2) core barrels and core barrel flanges, (3) 

lower core plates, (4) rod cluster control assembly guide tubes, and (5) thermal shields. The 

applicant identified that the AMR items for these components correlated to AMR item IV.B2-34 

in the Table IV.B2 of the GALL Report, Volume 2, which is applicable to the management of 

loss of material due to wear in nickel-alloy or stainless steel core plate alignment pins. The 

applicant identified that it is crediting its PWR Vessel Internals Program to manage loss of 

material due to wear of these components instead of its ISI Program, which is the AMP 

recommended GALL AMR item IV.B2-34 for managing loss of material due to wear in core plate 

alignment pins.
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The staff noted that the applicant amended the application on May 12, 2009, to resubmit its 

PWR Vessel Internals Program as a new, plant-specific program for the RVI components in the 

application. The staff verified that the applicant’s program includes both the ASME Section XI 

Examination B-N-3 requirements for those RVI components that are part of the removable core 

support structures, as well as the augmented inspection activities of the EPRI MRP, which are 

implemented in accordance with the methodology in EPRI Report MRP-227-Rev. 0. The staff 

also verified that the applicant’s AMP includes VT-3 visual examination methods to manage loss 

of material that occurs by wear. The staff noted that the ASME Code Section XI lists VT-3 

visual techniques as acceptable for the detection of wear in a component. Thus, based on this 

review, the staff finds that the applicant has provided an acceptable basis for managing loss of 

material due to wear in these components because the AMP includes both mandated and 

augmented inspection bases, and because these inspection bases include a valid visual 

examination method for detecting loss of material due to wear in the RVI components. The staff 

evaluates the ability of the PWR Vessel Internals Program to manage loss of material due to 

wear in SER Section 3.0.3.3.2.

3.1.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.1.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the reactor vessel, internals, and reactor coolant system components and 

provides 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 irradiation-assisted stress corrosion cracking (IASCC)

• cracking due to primary water stress corrosion cracking (PWSCC)

• wall thinning due to FAC

• changes in dimensions due to void swelling

• cracking due to SCC and PWSCC

• cracking due to SCC, PWSCC, and IASCC

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 
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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 Table 3.1.1, items 2, 3, and 4, the applicant states that the AMR result lines are not

applicable. The staff reviewed the corresponding AMR result lines in the SRP-LR and noted that 

they apply only to boiling water reactors (BWRs). On this basis, the staff agrees with the 

applicant’s determination that LRA Table 3.1.1, items 2, 3, and 4, are not applicable, because 

PINGP is a PWR.

LRA Table 3.1.1, items 1 and 5 through 10, are AMR result lines with an aging effect of 

cumulative fatigue. SER Section 4.3 documents the staff's review of the applicant's evaluation of 

these TLAAs.

3.1.2.2.2 Loss of Material due to General, Pitting, and Crevice Corrosion

 (1) LRA Section 3.1.2.2.2.1 addresses the applicant’s evaluation for LRA Table 3.1.1, item 

3.1.1-12. In the LRA, the applicant stated that this line applies for GALL line item IV.D2-8 

(R-244), which is applicable only for PWR once-through steam generators. The applicant 

stated that it does not have once-through steam generators, and this line is not 

applicable.

The staff reviewed LRA Section 3.1.2.2.2.1 against the criteria in SRP-LR Section 

3.1.2.2.2.1, which states that loss of material due to general, pitting, and crevice 

corrosion could occur in the steel PWR steam generator shell assembly exposed to 

secondary feedwater and steam.

The staff confirmed that GALL line item IV.D2-8 (R-244) is the only PWR component 

group referencing this Table 3.1.1 line item and that it is applicable only for once-through 

steam generators. The AMR results for comparable components in a recirculating steam 

generator are provided by the applicant in LRA Table 3.1.1, item 3.1.1-16. On the basis 

that the applicant has recirculating steam generators, and AMR results for the 

applicant’s recirculating steam generators are provided in LRA Table 3.1.1, item 3.1.1-

16, the staff finds the applicant’s determination that the AMR results in Table 3.1.1, item 

3.1.1-12 are not applicable to be acceptable.

(2) SRP-LR Section 3.1.2.2.2.2 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel BWR isolation condenser components exposed to 

reactor coolant. Loss of material due to general, pitting, and crevice corrosion may occur 

in steel BWR isolation condenser components.

The staff noted that PINGP is a PWR, and therefore does not have BWR isolation 

condenser components. Therefore, the criteria specified in SRP-LR Section 3.1.2.2.2.2 

does not apply to PINGP. 

(3) SRP-LR Section 3.1.2.2.2.3 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel, nickel-alloy, and steel with stainless steel or 
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nickel-alloy cladding flanges, nozzles, penetrations, pressure housings, safe ends, 

vessel shells, heads, and welds exposed to reactor coolant.

SRP-LR 3.1.2.2.2.3 references GALL items IV.A1-8 and RP-25, and is identified as an 

item specific to BWRs. The staff noted that PINGP is a PWR, and therefore does not 

have BWR isolation condenser components. Therefore, the criteria specified in SRP-LR 

Section 3.1.2.2.2.3 does not apply to PINGP. 

(4) The applicant states in LRA Section 3.1.2.2.2.4 that loss of material due to general,

pitting and crevice corrosion could occur for steel steam generator upper and lower shell 

and transition cone exposed to secondary feedwater and steam. (The LRA further states 

that 1) this aging effect is managed with a combination of the Water Chemistry Program 

and the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program; 2) the Water Chemistry Program controls detrimental contaminants such as 

halogens and sulfates that could cause corrosion and the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program provides for periodic visual, 

surface, and/or volumetric examinations of Class 1, 2, and 3 pressure-retaining 

components, their welded integral attachments, and bolting; 3) leakage tests are 

periodically performed on Class 1, 2, and 3 pressure-retaining components; and 4) the 

provisions of ASME Section XI are augmented by additional inspections to detect 

general and pitting corrosion on the shell to transition cone weld of the Westinghouse 

Model 51 steam generators in Unit 2.)

The staff reviewed LRA Section 3.1.2.2.2.4 against the criteria in SRP-LR Section 

3.1.2.2.2.4, which 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 Section 

3.1.2.2.2.4 also states that the existing program relies on control of chemistry to mitigate 

corrosion and Inservice Inspection (ISI) to detect loss of material and that the GALL 

Report recommends augmented inspection to manage this aging effect and clarifies that 

this issue is limited to Westinghouse Model 44 and 51 Steam Generators where a high 

stress region exists at the shell to transition cone weld. 

SRP-LR Section 3.1.2.2.2.4, AMR item 16 in Table 1 of the GALL Report, Volume 1, and 

GALL AMR item IV.D1-12, are applicable to loss of material in recirculating steam 

generator upper and lower shell and transition shell-to-cone welds in Westinghouse 

Model 44 or 51 steam generators. 

The staff reviewed the applicant’s Water Chemistry Program and the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program in SER Section 

3.0.3.2.18 and 3.0.3.1.3 respectively and found these programs provide control of 

contaminants that could cause general, pitting, and crevice corrosion in the steam 

generator upper and lower shell and transition cone when exposed to secondary 

feedwater and steam and provides for inspections to detect general, pitting and crevice 

corrosion. Additionally, the staff found that the provisions of the applicant’s ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program are 

augmented to detect loss of material due to general, pitting, and crevice corrosion in the 
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Unit 2 Model 51 steam generator upper and lower shells and transition cones by visual 

inspection of the interior circumference of the girth welds each ISI interval.

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 3.4.2.2.2.4, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.2 criteria. For those line items that apply to LRA Section 3.1.2.2.2, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement

The staff reviewed LRA Section 3.1.2.2.3 against the following criteria in SRP-LR 

Section 3.1.2.2.3:

 (1) LRA Section 3.1.2.2.3, item 1, states that certain aspects of the loss of fracture 

toughness due to neutron irradiation embrittlement are TLAAs as defined in 10 CFR 54.3 

and these TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1).

The applicant further states that there are no TLAAs for the PINGP RPV nozzles 

because the nozzles will receive fluence less than 1017 n/cm2 (E>1.0 MeV) at 60-years 

(end of extended period of operation). However, the RPV beltline has TLAAs that include 

Appendix G of 10 CFR 50 and 10 CFR 50.61. The staff evaluation of loss of fracture 

toughness due to neutron irradiation embrittlement of the RPV beltline materials is 

discussed in SER Section 4.2. 

SRP-LR Section 3.1.2.2.3, item 1, states that applicants must evaluate the TLAAs in 

accordance with 10 CFR 54.21(c)(1).

• LRA Section 3.1.2.2.3, item 2, states that the loss of fracture toughness aging effect for 

the PINGP RPV materials is managed by implementing the Reactor Vessel Surveillance 

Program (RVSP). The PINGP RVSP described in LRA Appendix B2.1.34, is an AMP 

that includes surveillance capsule removal and specimen mechanical testing/evaluation, 

radiation analysis, development of P-T limits, and determination of Low-Temperature 

Overpressure Protection (LTOP) setpoints. The RVSP program ensures that the RPV 

materials meet the requirements of 10 CFR 50.60 for fracture prevention and the 

requirements of 10 CFR 50.61 for PTS. The staff evaluation of the PINGP RVSP is 

discussed in SER Section 3.0.3.2.14.

SRP-LR Section 3.1.2.2.3 states that loss of fracture toughness due to neutron 

irradiation embrittlement may occur in BWR and PWR reactor vessel beltline shell, 

nozzle, and welds exposed to reactor coolant and neutron flux. A reactor vessel 
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materials surveillance program monitors neutron irradiation embrittlement of the reactor 

vessel. Reactor vessel surveillance programs are plant-specific, depending on matters 

such as the composition of limiting materials, availability of surveillance capsules, and 

projected fluence levels. In accordance with 10 CFR Part 50, Appendix H, an applicant is 

required to submit its proposed withdrawal schedule for approval prior to 

implementation. Untested capsules placed in storage must be maintained for future 

insertion. Thus, further staff evaluation is required for license renewal. Specific 

recommendations for an acceptable AMP are provided in GALL Report Chapter XI, 

Section M31.

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.3 criteria. For those line items that apply to LRA Section 3.1.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.2.4 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking

The staff reviewed LRA Section 3.1.2.2.4 against the following criteria in SRP-LR 

Section 3.1.2.2.4:

 (1) LRA Section 3.1.2.2.4 item 1 addresses GALL AMR item IV.A1-10, on the management 

of cracking in BWR RV flange leakage detection lines. In this section of the LRA, the 

applicant states that SRP-LR Section 3.1.2.2.4.1 is not applicable to PINGP because 

this item is applicable to BWR plants only.

SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in the 

stainless steel and nickel-alloy BWR top head enclosure vessel flange leak detection 

lines.

This item is not applicable to PINGP because PINGP is a PWR plant and does not have 

BWR reactor vessel top head enclosure flange leakage detection lines. On this basis, 

the staff finds that the criteria in SRP-LR 3.1.2.2.4.1 does not apply to PINGP.

 (2) LRA Section 3.1.2.2.4 item 2 addresses GALL AMR item IV.C1-4, on the management 

of cracking due to SCC and/or IGSCC in stainless steel BWR isolation condenser and 

components. In this section of the LRA, the applicant states that SRP-LR Section 

3.1.2.2.4.2 is not applicable to PINGP because this item is applicable to BWR plants 

only.

SRP-LR Section 3.1.2.2.4 states that cracking due to SCC and IGSCC may occur in 

stainless steel BWR isolation condenser components exposed to reactor coolant.

This item is not applicable to PINGP because PINGP is a PWR plant and does not have 

stainless steel BWR isolation condenser and components. On this basis, the staff finds 

that the criteria in SRP-LR 3.1.2.2.4.2 does not apply to PINGP.
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3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5 indicates crack growth due to cyclic loading associated with underclad 

cracking of the RV shell is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be

evaluated in accordance with 10 CFR 54.21(c)(1). SER Section 4.7.2 documents the staff's 

review of the applicant's evaluation of this TLAA. 

3.1.2.2.6 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement and Void

Swelling

LRA Section 3.1.2.2.6 addresses the applicant’s evaluation of whether the guidance in

SRP-LR Section 3.1.2.2.6 is applicable to the RVI components. In this LRA Section, the

applicant identifies that loss of fracture toughness due to neutron irradiation embrittlement and

void swelling is applicable to the RVI components as a result of exposing the components to a

reactor coolant with neutron flux environment. The applicant’s AMR items in LRA Table 3.1.2-3

indicate that this evaluation is applicable to the following RVI components at PINGP: (1) clevis

insert bolts, (2) lower core plate fuel alignment pins, (3) lower support column bolts, (4) lower

core plates, (5) lower support columns, (6) lower support forgings, (7) diffuser plates, (8) head

cooling spray nozzles, (9) secondary core supports, (10) core baffle and former plates and their

fasteners, (11) core barrels and core barrel flanges, (12) core barrel outlet nozzles, and (13)

thermal shields. In this LRA section, the applicant states that loss of fracture toughness is an

applicable AERM for these components as a result of exposing them to a reactor coolant with

integrated neutron flux environment. The applicant states that it credits its PWR Vessel Internals

Program to manage loss of fracture toughness of the components as a result of exposing them

to a reactor coolant with integrated neutron flux environment. The PWR Vessel Internals

Program includes the commitment requested in SRP-LR Section 3.1.2.2.6.

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6 which

states that loss of fracture toughness due to neutron irradiation embrittlement and void swelling

could occur in stainless steel and nickel-alloy RVIs components that are exposed to reactor

coolant with an integrated neutron flux environment. This SRP-LR section states that PWR

renewal applicants do not need to conduct any additional evaluation of the programs or

activities that are used to manage this aging effect if they provide a commitment on their

UFSAR Supplement to: (1) participate in the industry programs for investigating and managing

aging effects on RVI components; (2) evaluate and implement the results of the industry

programs, as applicable to the design of its RVI components; 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 RVI components to the NRC for review and approval.

The staff noted that on May 12, 2009, the applicant resubmitted its PWR Vessel Internals 

Program (LRA AMP B2.1.32) as a new, plant-specific AMP for the PINGP RVI components, and 

credited this program for the management of loss of fracture toughness for all of the stainless 

steel (including CASS) and nickel-alloy RVI components referenced in GALL AMR items IV.B2-

3, IV.B2-6, IV.B2-9, IV.B2-17, IV.B2-18, and IV.B2-22 as being susceptible to loss of fracture 

toughness as a result of either neutron irradiation embrittlement or void swelling. The staff 

verified that the applicant’s PWR Vessel Internals Program includes appropriate program 

element criteria to manage loss of fracture toughness in the stainless steel or nickel-alloy RVI 

components, as either induced by neutron irradiation embrittlement, void swelling, or for CASS 
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components, by thermal aging. Based on this review, the staff finds that the applicant has 

provided an acceptable basis for managing loss of fracture toughness in these RVI components 

because the scope of program manages this aging effect and includes appropriate program 

element criteria for managing this loss of fracture toughness as result of either neutron 

irradiation embrittlement or void swelling. The staff evaluates the ability of the PWR Vessel 

Internals Program to manage loss of fracture toughness in SER Section 3.0.3.3.2.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. 

The staff noted that Commitment No. 25 conforms to the commitment recommendations in 

SRP-LR Section 3.1.2.2.6 for participating in the industry-wide programs on managing the aging 

effects that are applicable to PWR RVI components and for submitting an inspection plan for the 

RVI components to the NRC for review and approval. The staff verified that the applicant placed 

Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. Based on this review, 

the staff finds that the applicant’s AMR basis for loss of fracture toughness due to neutron 

irradiation embrittlement or void swelling is also acceptable because the applicant’s AMR basis 

includes Commitment No. 25 and because this commitment conforms to the recommendations 

in SRP-LR Section 3.1.2.2.6 for managing this aging effect.

Based on the program identified above and Commitment No. 25, the staff concludes that the 

applicant’s programs meet SRP-LR Section 3.1.2.2.6 criteria. For those line items that apply to

LRA Section 3.1.2.2.6, the staff determines that the LRA is consistent with the GALL Report and

that the applicant has demonstrated that the effects of aging will be adequately managed so that

the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.7 Cracking due to Stress Corrosion Cracking 

 (1) LRA Section 3.1.2.2.7.1 addresses the applicant’s aging management basis for 

managing cracking due to SCC in the stainless steel flange O-ring leak detection tubes

and the BMI guide tubes. The applicant uses RV flange O-ring leak detection tubes as 

the terminology for its RV flange leak detection lines. The applicant stated that this aging 

effect/mechanism will be managed with the Water Chemistry Program.

The staff reviewed LRA Section 3.1.2.2.7.1 against the criteria in SRP-LR Section 

3.1.2.2.7.1, which states that cracking due to SCC could occur in the PWR stainless 

steel reactor vessel (RV) flange leak detection lines and bottom-mounted instrument

(BMI) guide tubes exposed to reactor coolant. SRP-LR Section 3.1.2.2.7.1, AMR item 23 

in Table 1 of the GALL Report Volume 1, and AMR items IV.A2-1 and IV.A2-5 are 

applicable to the management of cracking due to SCC in PWR BMI guide tubes and 

PWR reactor vessel flange leakage detection lines. The SRP-LR sections state that for 

these components, the GALL Report recommends further evaluation of a plant-specific
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AMP to ensure that this aging effect is adequately managed during the period of 

extended operation.

The staff noted that the applicant’s Water Chemistry Program does not include a 

component inspection activity to confirm that water chemistry control is adequate to 

prevent occurrence of the aging effect. In a letter dated December 18, 2008, the staff 

issued RAI 3.1.2.2.7-01 asking the applicant to include a component inspection activity 

or to provide a justification for not including one.

The applicant responded to the RAI in a letter dated January 20, 2009. In that letter the 

applicant revised the LRA to assign the ASME Section XI Inspection, Subsections IWB, 

IWC, and IWD Program to manage cracking due to SCC in addition to the Water 

Chemistry Program for the stainless steel BMI guide tubes and fittings exposed to 

treated water. In addition, the applicant revised the LRA to assign the ASME Section XI 

Inspection, Subsections IWB, IWC, and IWD Program and the One-Time Inspection of 

ASME Code Class 1 Small-Bore Piping Program to manage cracking due to SCC in 

addition to the Water Chemistry Program for the stainless steel flange O-ring leak 

detection tubes, which are the applicant’s components that are equivalent to the reactor 

vessel flange leakage detection lines assessed in the GALL Report. The staff confirmed 

that in the letter of January 20, 2009, the applicant amended LRA Table 3.1.1, LRA 

Table 3.1.2-4, and LRA Section 3.1.2.2.7 to incorporate these changes. The applicant 

stated that with these changes the BMI guide tubes and fittings are inspected in 

accordance with applicable Examination Categories in ASME Code Section XI, 

Table IWB-2500-1, and that the stainless steel flange O-ring leak detection tubes may 

receive a one-time volumetric examination of its small bore full penetration butt weld 

locations if the welds are determined to be potentially susceptible to cracking in 

accordance with the One-Time Inspection of ASME Code Class 1 Small-Bore Piping 

Program and the associated recommended criteria in GALL AMP XI.M35, “One-Time 

Inspection of ASME Code Class 1 Small Bore Piping.” This is done with the NRC 

approved Risk Informed ISI Program. 

The staff reviewed the applicant’s RAI response and changes made to the LRA. The 

staff also reviewed the Water Chemistry Program, the ASME Section XI Inspection, 

Subsections IWB, IWC, and IWD Program, and the ASME Code Class 1 Small-Bore 

Piping Program. The staff’s evaluations of those AMPs are documented in SER 

Section 3.0.3.2.18, Subsection 3.0.3.1.3, and Subsection 3.0.3.1.18, respectively. The 

staff’s AMP evaluations determined that the Water Chemistry Program provides 

mitigation for the aging effect of cracking due to SCC in stainless steel components 

exposed to treated water and that the ASME Section XI Inspection, Subsections IWB, 

IWC, and IWD Program, and the ASME Code Class 1 Small-Bore Piping Program both 

provide capability to detect cracking due to SCC.

The staff finds the applicant’s basis for amending the LRA to credit the ASME Section XI 

Inspection, Subsection IWB, IWC, and IWD Program for management of cracking due to 

SCC in the stainless steel BMI guide tubes and fittings to be acceptable because of the 

following: (1) BMI guide tubes are ASME Code Class 1 components, and (2) the ASME 

Code Section XI includes appropriate examination categories for BMI guide tubes. The 

staff finds the applicant’s proposal to use the One-Time Inspection of ASME Code 
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Class 1 Small-Bore Piping Program to detect potential cracking in the stainless steel 

flange O-ring leak detection tubes to be acceptable because this is consistent with the 

recommendations in Chapter IV of the GALL Report, Volume 2 that a program 

corresponding to GALL AMP XI.M35, “One-Time Inspection of ASME Code Class 1 

Small Bore Piping,” be used to manage cracking in ASME Code Class 1 small bore 

piping components. 

In addition, since the Water Chemistry Program provides mitigation for the aging effect 

and the applicant’s proposed inspection programs provide detection of the aging effect, 

the staff finds the applicant's proposed AMPs to manage the aging effect of cracking due 

to SCC in the bottom-mounted instrument guide tubes and fittings, and in the flange Oring leak detection tubes to be acceptable. For these reasons, the staff also finds that 

the applicant’s response in the letter dated January 20, 2009, resolves all issues raised 

in RAI AMR-3.1.2.2.7-01 and that the changes made to the LRA in response to this RAI 

are acceptable.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.7.1 criteria. For those line items that apply to LRA Section 

3.1.2.2.7.1, 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 function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) The applicant states in LRA Section 3.1.2.2.7.2 that cracking due stress corrosion 

cracking could occur for Class 1 CASS piping, piping components, and piping elements 

exposed to reactor coolant. LRA Section 3.1.2.2.7.2 further states that 1) this aging 

effect is managed with a combination of the Water Chemistry Program and the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program and 2) the 

Water Chemistry Program controls concentrations of known detrimental chemical 

species such as halogens, sulfates and dissolved oxygen below the levels known to 

cause degradation and the ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program provides visual and volumetric examinations of Class 1 CASS

piping, piping components, and piping elements exposed to reactor coolant.

The staff reviewed LRA Section 3.1.2.2.7.2 against the criteria in SRP-LR Section 

3.1.2.2.7.2, which states that cracking due to SCC could occur in Class 1 PWR CASS

reactor coolant system piping, piping components, and piping elements exposed to 

reactor coolant. The staff noted that the applicant’s existing program relies on control of 

water chemistry to mitigate SCC; however, SCC could occur for CASS components that 

do not meet the NUREG-0313 guidelines with regard to ferrite and carbon content. The 

staff reviewed the applicant’s Water Chemistry Program in SER Section 3.0.3.2.19 and 

found this program provides control of contaminants that could cause SCC in Class 1 

PWR CASS components. The GALL Report recommends a Water Chemistry Program 

and, for CASS components that do not meet NUREG-0313, a plant-specific AMP.

SRP-LR Section 3.1.2.2.2.7.2, AMR item 24 in Table 1 of the GALL Report, Volume 1, 

and GALL AMR item IV.C2-3, are applicable to SCC of CASS Class 1 piping, piping 

components, and piping elements.
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The applicant credits the ASME Section XI Inservice Inspection, Subsections IWB, IWC, 

and IWD Program to manage SCC in Class 1 PWR CASS components and has not 

developed a plant-specific program for components that do not meet the provisions of 

NUREG-0313 with regard to the ferrite and carbon content. The staff noted that in the 

LRA 3.1.2 Tables, the applicant has assigned “Note E” to several line items for CASS

components exposed to a treated water environment. The staff noted that the aging 

effect of concern is cracking due to SCC for CASS piping, pump casings and valve body 

components, which are addressed in GALL AMR items IV.C2-3 and IV.C2-5. Therefore, 

by letter dated December 18, 2008, the staff issued RAI 3.1.2.-02 asking the applicant 

for the following information:

(1) Clarify whether PINGP controls water chemistry in accordance with the 

guidelines in EPRI Report No. TR-105714, "PWR Primary Water 

Chemistry Guidelines" for these components.

(2) Clarify how the CASS components in these LRA AMR items meet the 

SCC susceptibility considerations of having less than a 0.035 percent

carbon alloying content or less than a 0.75 percent delta ferrite content.

(3) If it is determined that any of these CASS components do not meet the 

reduced susceptibility criteria on carbon and delta ferrite alloy contents, 

discuss the inspection methods that will be used to monitor for cracking 

in these components. Discuss the flaw evaluation methodologies used 

by PINGP to account for a change in the critical crack size used in the 

analysis as a result of a drop in the fracture toughness of the CASS 

components.

(4) UT methods may be incapable of detecting flaws in CASS components 

because of the dense, small grain-size microstructure of CASS, which 

results in significant, high amplitude UT background noise signals. If UT 

is proposed as the method for inspecting these components, provide 

your basis why the UT method selected would be capable of 

distinguishing between a UT signal that results from a flaw in the 

material as opposed to background UT signals that result from the 

CASS microstructure or abnormal geometries in the CASS component.

By letter dated January 20, 2009, the applicant responded to RAI 3.1.2-02 stating the 

following:

(1) The Water Chemistry Program manages cracking due to SCC/IGA of 

CASS components exposed to a treated water environment by 

controlling water chemistry in accordance with Revision 5 of the “PWR 

Primary Water Chemistry Guidelines," EPRI TR-1002884, for primary 

and auxiliary water systems. EPRI TR-1002884 is a later revision of 

EPRI Report No. TR-105714.

(2) The carbon alloying and delta ferrite content of the PINGP CASS

reactor coolant components is either unknown or typically greater than 
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the 0.035% carbon alloying content and the 7.5% delta ferrite which is 

discussed in NUREG-1801, item No. IV.C2-3.

(3) The PINGP ASME Section XI Inservice Inspection, Subsections IWB, 

IWC, and IWD Program currently provides for volumetric examinations 

of reactor coolant piping and fittings in accordance with the riskinformed Inservice Inspection Program. ASME Section XI, Examination 

Category B-L-1 requires VT-1 visual examination of pressure retaining 

welds in pump casings. Examination Category B-L-2 requires VT-3 

visual examination of pump casing internal surfaces, if disassembled.

Examination Category B-M-2 requires VT-3 visual examination of 

internal surfaces of valve bodies, if disassembled. In addition, 

Examination Category B-P requires visual (VT-2) examination of all 

pressure retaining piping components.

Flaws detected in CASS components will be evaluated in accordance 

with the applicable procedures of ASME Section XI, Subsections IWB3500 or IWC-3500 under the PINGP ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program. Alternatively, 

flaw tolerance evaluation for components with ferrite content up to 25

percent will be performed according to the principles associated with 

IWB-3640 procedures for submerged arc welds disregarding the Code 

restriction of 20% ferrite in IWB-3641(b)(1).

(4) The PINGP procedure for ultrasonic examination of CASS main 

coolant pipe welds is based on WCAP-11778, “Demonstration of Flaw 

Detection and Characterization Capabilities for Ultrasonic Examination 

of Main Coolant Loop Welds,” March 1988, prepared by 

Westinghouse. The report describes the development of improved 

manual ultrasonic inspection techniques, and the optimization and 

qualification of manual ultrasonic flaw detection and characterization 

capabilities. The WCAP recognized that inspection of heavy-wall 

austenitic stainless steel components is difficult. However the 

ultrasonic testing is not impossible if measures include knowledge of 

fabrication materials to be inspected, adequate surface preparation, 

knowledge of defects, sufficient training for inspection personnel, 

improved understanding of the sound beam propagation mechanism, 

appropriate selection of ultrasonic test equipment, and demonstration 

of the ultrasonic test procedures. PINGP ultrasonic examination 

procedures incorporate the research done by WCAP-11778 to improve 

the ultrasonic inspection of the CASS reactor coolant piping.

The staff finds that chemical species, particularly dissolved oxygen, that could promote 

SCC of Class 1 PWR CASS components exposed to reactor coolant, are adequately 

controlled through the applicant’s Water Chemistry Program. All CASS components 

have been identified as susceptible to SCC according to NUREG-0313 and are subject 

to inspection in accordance with the applicant’s ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. 
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However, the staff noted that UT techniques are not currently capable of differentiating 

between UT signals that are reflectors from crack-like flaws in CASS and those that 

result from the complexity of having a large grain boundary structure. The staff noted 

that UT may not be capable of detecting cracks in these materials through the 

applicant’s ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD 

Program which provides, in part, for ultrasonic examination of CASS main coolant pipe 

welds. Additionally the staff noted that the applicant can not credit risk-informed ISI for 

managing aging effects in the period of extended operation because the staff has not 

approved risk-informed ISI for the fifth and sixth PINGP ISI intervals. In a letter dated 

February 26, 2009, the applicant stated that during the period of extended operation if

volumetric examinations are required to be performed per ASME Section XI, Table IWB2500-1, Examination Category B-J on the Class 1 CASS main coolant pipe welds, then 

an ultrasonic examination method qualified will be implemented. The staff finds that the 

applicant’s updated basis for inspecting the CASS RCS piping welds, as clarified in the 

letter of February 27, 2009, is acceptable because: (1) the applicant will use staffapproved UT methods qualified under ASME Section XI, Appendix VIII for detection of 

cracking in CASS materials or a staff-approved alternative method (i.e., enhanced visual 

VT-1 examination) for detecting cracking in these components as a result of SCC/IGA, 

and (2) this is consistent with the methods for detecting cracks in CASS components, as 

specified in the “detection of aging effects” program element in GALL AMP, XI.M12. On 

this basis, the issue raised in RAI 3.1.2.-02 is resolved.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.7.2 criteria. For those line items that apply to LRA 

Section 3.1.2.2.7.2, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.8 Cracking Due to Cyclic Loading

The staff reviewed LRA Section 3.1.2.2.8 against the following criteria in SRP-LR 

Section 3.1.2.2.8:

 (1) LRA Section 3.1.2.2.8 addresses GALL AMR item IV.B1-12, on the management of 

cracking due to cyclic loading in stainless steel BWR jet pump sensing lines exposed to 

the reactor coolant. In this section of the LRA, the applicant states that SRP-LR Section 

3.1.2.2.8.1 is not applicable to PINGP because this item is applicable to BWR plants 

only. 

SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in the 

stainless steel BWR jet pump sensing lines.

This item is not applicable to PINGP because PINGP is a PWR plant and does not have 

stainless steel BWR jet pump sensing lines. On this basis, the staff finds that the criteria 

in SRP-LR 3.1.2.2.8.1 does not apply to PINGP.

(2) LRA Section 3.1.2.2.8 addresses GALL AMR item IV.C1-5, on the management of 

cracking due to cyclic loading may occur in steel and stainless steel BWR isolation 
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condenser components exposed to reactor coolant. In this section of the LRA, the 

applicant states that SRP-LR Section 3.1.2.2.8.1 is not applicable to PINGP because 

this item is applicable to BWR plants only. 

SRP-LR Section 3.1.2.2.8 states that cracking due to cyclic loading may occur in steel 

and stainless steel BWR isolation condenser components exposed to reactor coolant. 

The staff noted this item is not applicable to PINGP because PINGP is a PWR plant and 

does not have stainless steel BWR isolation condenser components. On this basis, the 

staff finds that the criteria in SRP-LR 3.1.2.2.8.2 does not apply to PINGP.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation

LRA Section 3.1.2.2.9 addresses the applicant’s evaluation on whether the guidance in

SRP-LR Section 3.1.2.2.9 is applicable to the RVI components. In this LRA section, the

applicant identifies that loss of preload due to stress relaxation is applicable to the RVI

components as a result of exposing the components to a reactor coolant environment. 

The applicant’s AMR items in LRA Table 3.1.2-3 indicate that this evaluation is applicable to the

following RVI components at PINGP: (1) core baffle and former bolts, (2) clevis insert bolts, 

(3) lower support column bolts in the lower internal assembly, (4) hold-down springs in the 

upper internals assembly, and (5) upper support column fasteners in the upper internals 

assembly. In this LRA section, the applicant states that loss of fracture toughness is an 

applicable AERM for these components exposed to a reactor coolant with integrated neutron 

flux environment. The applicant states that it credits its PWR Vessel Internals Program to 

manage loss of fracture toughness of the components as a result of exposing them to a reactor 

coolant with integrated neutron flux environment.

The staff reviewed LRA Section 3.1.2.2.9 against the criteria in SRP-LR Section 3.1.2.2.9 which

states that loss of preload due to stress relaxation could occur in bolted or fastened RVI

components that are exposed to the coolant environment. This SRP-LR section states that

PWR renewal applicants do not need to conduct any additional evaluation of the programs or

activities that are used to manage this aging effect if they provide a commitment on their

UFSAR Supplement to: (1) participate in the industry programs for investigating and managing

aging effects on RVI components; (2) evaluate and implement the results of the industry

programs, as applicable to the design of its RVI components; 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 RVI components to the NRC for review and approval.

The staff noted that on May 12, 2009, the applicant resubmitted its PWR Vessel Internals 

Program (LRA AMP B2.1.32) as a new, plant-specific AMP for the PINGP RVI components, and 

credited this program for the management of loss of preload due to stress relaxation for all of 

the RVI bolting and fasteners referenced in GALL AMR items IV.B2-5, IV.B2-14, IV.B2-25, 

IV.B2-33, and IV.B2-38 identified as being potentially susceptible to the aging mechanism of 

stress relaxation, including baffle and former plate bolts/fasteners, clevis insert bolts, hold-down 

springs, lower support column bolts, and upper support column bolts/fasteners. The staff 

verified that the applicant’s PWR Vessel Internals Program includes appropriate program 

element criteria to manage loss of preload due to stress relaxation in bolted, fastened, keyed, 

spring-loaded, or pinned RVI component connections. Based on this review, the staff finds that 

the applicant has provided an acceptable basis for managing loss of preload due to stress 
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relaxation of these RVI components because the scope of program manages this aging effect 

and includes appropriate program element criteria for managing this loss of preload due to 

stress relaxation. The staff evaluates the ability of the PWR Vessel Internals Program to 

manage loss of preload in SER Section 3.0.3.3.2.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. 

The staff noted that the Commitment No. 25 conforms to the recommendations in SRP-LR 

Section 3.1.2.2.9 for participating in the industry-wide programs on managing the aging effects 

that are applicable to PWR RVI components and for submitting an inspection plan for the RVI 

components to the NRC for review and approval. The staff verified that the applicant placed 

Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. Based on this review, 

the staff finds that the applicant’s AMR basis for managing loss of preload due to stress 

relaxation is also acceptable because the applicant’s AMR basis includes Commitment No. 25 

and because this conforms to the recommendations in SRP-LR Section 3.1.2.2.9 for managing 

this aging effect.

For those line items that apply to LRA Section 3.1.2.2.9, the staff determines that the LRA is

consistent with the GALL Report and that the applicant has demonstrated that the effects of

aging will be adequately managed so that the intended function(s) will be maintained consistent

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.10 Loss of Material Due to Erosion

The staff reviewed LRA Section 3.1.2.2.10 against the criteria in SRP-LR Section 3.1.2.2.10.

LRA Section 3.1.2.2.10 addresses loss of material due to erosion in steel steam generator 

feedwater impingement plates and supports exposed to secondary feedwater. In addition, the 

LRA states that PINGP steam generators do not have steam generator feedwater impingement 

plates and supports. 

SRP-LR Section 3.1.2.2.10 states that loss of material due to erosion may occur in steel steam 

generator feedwater impingement plates and supports exposed to secondary feedwater.

The staff reviewed the UFSAR and verified that PINGP does not have steam generator 

feedwater impingement plates and supports. On this basis, the staff finds the criteria in SRP-LR 

Section 3.1.2.2.10 do not apply to PINGP.

3.1.2.2.11 Cracking Due to Flow-Induced Vibration

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.
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SRP-LR Section 3.1.2.2.11 states that cracking due to flow-induced vibration could occur for the 

BWR stainless steel steam dryers exposed to reactor coolant.

The staff noted that this line item applies to BWR steam dryers and therefore, is not applicable 

to PINGP because PINGP is a PWR. On this basis, the staff finds that this aging effect is not 

applicable to this component type.

Based on the above, the staff concludes that SRP-LR Section 3.1.2.2.11 criteria do not apply.

3.1.2.2.12 Cracking due to Stress Corrosion Cracking (SCC) and Irradiation-Assisted Stress 

Corrosion Cracking (IASCC)

LRA Section 3.1.2.2.12 addresses whether cracking due to SCC or IASCC is applicable to the

RVI components as a result of exposing the components to a reactor coolant environment or a

reactor coolant with integrated neutron flux environment. In this LRA section, the applicant 

states that loss of fracture toughness is an applicable AERM for these components exposed to 

a reactor coolant with neutron flux environment. The applicant’s AMRs in LRA Table

3.1.2-3 indicate that this evaluation is applicable to the following RVI components at PINGP: 

(1) core baffle and former plates, (2) core baffle and former plate fasteners, (3) BMI column

cruciforms, (4) BMI columns and flux thimble guide tubes, (5) flux thimble tubes, (6) lower

support columns, (7) lower support forgings, (8) diffuser plates, (9) head cooling spray nozzles,

(10) secondary core supports, (11) RCCA guide tubes, (12) upper support columns, (13) upper 

instrumentation columns, conduits, and supports, (14) hold-down springs, (15) upper core 

plates, (16) upper support plate assemblies, (17) core barrels and core barrel flanges, (18) core 

barrel outlet nozzles, and (19) thermal shields. For these components, the applicant credits the 

Water Chemistry Program and the PWR Vessel Internals Program to manage cracking of these 

RVI components as a result of exposing them to a reactor coolant or a reactor coolant with 

integrated neutron flux environment. The applicant also indicates that the PWR Vessel Internals 

Program includes the commitment requested in SRP-LR Section 3.1.2.2.12.

The staff reviewed LRA Section 3.1.2.2.12 against the criteria in SRP-LR Section 3.1.2.2.12

which states that cracking 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. This SRP-LR section states that, although the existing program relies

on control of water chemistry for aging management, PWR renewal applicants do not need to

conduct any additional evaluation of the programs or activities that are used to manage this

aging effect if they provide a commitment in their UFSAR Supplement to: (1) participate in the

industry programs for investigating and managing aging effects on RVI components; (2)

evaluate and implement the results of the industry programs, as applicable to the design of its

RVI components; 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 RVI components

to the NRC for review and approval.

The staff noted that on May 12, 2009, the applicant resubmitted its PWR Vessel Internals 

Program (LRA AMP B2.1.32) as a new, plant-specific AMP for the PINGP RVI components, and 

credited this program for the management of cracking for all of the stainless steel (including 

CASS) and nickel-alloy RVI components referenced in GALL AMR items 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 as being susceptible to the 
3-231

aging mechanisms of SCC or IASCC. The staff verified that the applicant’s PWR Vessel 

Internals Program includes appropriate program element criteria to manage cracking in the 

stainless steel or nickel-alloy RVI components, as either induced by SCC or IASCC. Based on

this review, the staff finds that the applicant has provided an acceptable basis for managing 

cracking in these RVI components because the scope of program includes cracking due to SCC 

or IASCC and includes appropriate program element criteria for managing this aging effect. The 

staff evaluates the ability of the PWR Vessel Internals Program to manage loss of fracture 

toughness in SER Section 3.0.3.3.2.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. 

The staff noted that in Commitment No. 25 conforms to the recommendations in SRP-LR 

Section 3.1.2.2.12 for participating in the industry-wide programs on managing the aging effects 

that are applicable to PWR RVI components and for submitting and inspection plan for the RVI 

components to the NRC for review and approval. The staff verified that the applicant placed 

Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. Based on this review, 

the staff finds that the applicant’s AMR basis for managing cracking due to SCC or IASCC is 

also acceptable because the applicant’s AMR basis includes Commitment No. 25 and because 

this commitment conforms to the recommendations in SRP-LR Section 3.1.2.2.12 for managing 

this aging effect.

Based on the programs identified above and Commitment No. 25, the staff concludes that the

applicant’s programs meet SRP-LR Section 3.1.2.2.12 criteria. For those line items that apply to

LRA Section 3.1.2.2.12, the staff determines that the LRA is consistent with the GALL Report

and that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.13 Cracking Due to Primary Water Stress Corrosion Cracking

The applicant states in LRA Section 3.1.2.2.13 that cracking due to PWSCC could occur for 

nickel-alloy reactor internals components. LRA Section 3.1.2.2.13 further states that this aging 

effect is managed with a combination of the Water Chemistry Program, the ASME Section XI 

Inservice Inspection, Subsections IWB, IWC, and IWD Program and the Nickel-Alloy Nozzles 

and Penetrations Program. For the Nickel-Alloy Nozzles and Penetrations Program, PINGP 

commits to the following activities for managing the aging of nickel-alloy components 

susceptible to PWSCC: (1) comply with applicable NRC orders, and (2); implement applicable 

NRC Bulletins, Generic Letters, and staff-accepted industry guidelines. The staff noted that 

SRP-LR 3.1.2.2.13 (which is the SRP-LR section that corresponds to LRA Section 3.1.2.2.13) is 

related to management of PWSCC in ASME code Class 1 nickel-alloy piping, piping 

components, piping elements and reactor vessel components and attachments (other than the 

upper reactor vessel closure head nozzles and welds) made from nickel-alloy. This SRP-LR 

section does not apply to RVI components made from nickel-alloy. In a letter dated February 26, 
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2009 the applicant stated that the further evaluation of cracking due to PWSCC contained in 

LRA Section 3.1.2.2.13 incorrectly refers to this aging effect/mechanism occurring in RVIs 

components. The associated Table 1 Item Number 3.1.1-31 is used in LRA Table 3.1.2-1, 

Pressurizer System – Summary of Aging Management Evaluation, and Table 3.1.2-4, Reactor 

Vessel System – Summary of Aging Management Evaluation. Therefore this further evaluation 

should refer to this aging effect/mechanism occurring in pressurizer and reactor vessel 

components. The first sentence of LRA Section 3.1.2.2.13 is hereby deleted and replaced with 

the following: cracking due to primary water stress corrosion cracking could occur for nickelalloy pressurizer and reactor vessel components. The staff noted that this response corrects the 

error in the LRA.

The staff reviewed LRA Section 3.1.2.2.13 against the criteria in SRP-LR Section 3.1.2.2.13, 

which states that cracking due to PWSCC could occur in PWR components made of nickel-alloy

and steel with nickel-alloy cladding, including reactor coolant pressure boundary components 

and penetrations inside the RCS such as pressurizer heater sheathes and sleeves, nozzles, 

and other internal components. With the exception of reactor vessel upper head nozzles and 

penetrations, the GALL Report recommends ASME Section XI ISI (for Class 1 components) and 

control of water chemistry. SRP-LR Section 3.1.2.2.13 further states that for nickel-alloy

components, no further aging management review is necessary if the applicant complies with 

applicable NRC Orders and provides a commitment in the UFSAR supplement to implement 

applicable (1) Bulletins and Generic Letters and (2) staff-accepted industry guidelines.

SRP-LR Section 3.1.2.2.2.13, AMR item 31 in Table 1 of the GALL Report, Volume 1, and 

GALL AMR items IV.C2-13 and IV.C2-24, are applicable to PWSCC of nickel-alloy and steel 

with nickel-alloy cladding piping, piping components, piping elements, penetrations, nozzles,

safe ends, and welds (other than reactor vessel head) and core support pads.

The staff reviewed the applicant’s Water Chemistry Program and the ASME Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program in SER Sections 3.0.3.2.18 and 3.0.3.1.3 

respectively and found these programs provide control of contaminants that could promote 

PWSCC and provides inspection to detect PWSCC in nickel-alloy components. The staff 

reviewed the applicant’s Nickel-Alloy Nozzles and Penetrations Program, B2.1.27 in SER 

Section 3.0.3.3.1 and finds that the applicant has met the criteria of SRP-LR Section 3.1.2.2.13, 

because the applicant has committed (Commitment No. 21) to implement NRC Bulletins and 

Generic Letters and industry guidelines to manage PWSCC of RCS components fabricated with 

nickel-alloys including base metals and welds as part of LRA AMP B2.1.27. However, a revision 

to 10 CFR 50.55a, “Codes and Standards” was issued September 2008 which requires all 

licensees of PWRs to augment their ISI programs to implement ASME Code Case N-722, which 

provides for additional detection capability for partial or full penetration welds in Class 1 

components fabricated with Alloy 600/82/182 material for pressure boundary leakage in PWR

plants. The applicant’s LRA does not address the new provisions of 10 CFR 50.55a because it 

was submitted January 2008. The staff noted that the applicant committed (Commitment No.1) 

to submit amendments to the PINGP LRA including UFSAR supplements pursuant to

10 CFR 54.21(b), "Contents of application--technical information." This section states “CLB 

changes during NRC review of the application. Each year following submittal of the LRA and at 

least three months before scheduled completion of the NRC review, an amendment to the 

renewal application must be submitted that identifies any change to the CLB of the facility that 

materially affects the contents of the LRA, including the FSAR supplement.” Based on the 
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applicant’s Commitment No.1, the staff finds the applicant will implement the new mandated 

augmented inspection requirements in 10 CFR 50.55a(g)(6)(ii)(E).

The staff noted that the original version of the applicant’s Nickel-Alloy Nozzles and Penetration 

Program indicated that the program will comply with all NRC Orders Generic Letters, and 

Bulletins related to PWSCC of nickel-alloys, and that the applicant reflected these activities as 

an LRA enhancement that is defined in LRA Commitment No. 21.

The staff also noted that in its March 27, 2009 letter, the applicant amended AMP B2.1.27, 

Nickel-Alloy Nozzles and Penetrations Program, to redefine the program as an existing plantspecific AMP for the LRA that incorporates the ten program elements for AMPs, as 

recommended in SRP-LR Appendix A, Section A.1.2.3, and to delete the commitment in the 

previous version of the AMP and in Commitment No. 21 from the scope of the LRA.

The staff evaluated the amended Nickel-Alloy Nozzles and Penetrations Program and the plantspecific program elements for this AMP in SER Section 3.0.3.3.1 and found that this program 

will manage PWSCC during the period of extended operation because the program elements 

meet the criteria of SRP-LR, Appendix A.1.2.3.

The staff concluded that Commitment No. 21 is no longer necessary because the AMP is now 

based on the new augmented inspection requirements for those nickel-alloy components. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.13 criteria, as amended in LRA Section 3.1.2.2.13 to account for the 

new augmented inspection requirements that are mandated for these components in 10 CFR 

50.55a(g)(6)(ii)(E). For those line items that apply to LRA Section 3.1.2.2.13, 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 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.1.2.2.14 Wall Thinning Due to Flow-Accelerated Corrosion

LRA Section 3.1.2.2.14 addresses wall thinning due to FAC. The applicant states that the 

PINGP SG feedwater inlet rings and supports do not perform a License Renewal intended 

function. The applicant states that the inlet rings are not safety-related and are located above 

the tube bundle wrapper transition cone roof and are therefore isolated from impacting the 

U-tubes.

The staff reviewed LRA Section 3.1.2.2.14 against the criteria in SRP Section 3.1.2.2.14, which 

states that wall thinning due to FAC, may occur in steel FW inlet rings and supports. The GALL 

Report references NRC Information Notice (IN) 91-19, "Steam Generator Feedwater Distribution 

Piping Damage,” for evidence of FAC in steam generators and recommends that a plantspecific AMP be evaluated because existing programs may not be capable of mitigating or 

detecting wall thinning of the SG feedwater inlet rings and supports as a result of FAC.

SRP-LR Section 3.1.2.2.14, the AMR item 32 in Table 1 of the GALL Report, Volume 1 and 

AMR item IVD1-26 of the GALL Report, Volume 2 are applicable management of wall thinning 

due to FAC in steel with feedwater inlet ring and support that are exposed to a secondary 
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feedwater/steam environment. For this line item, the GALL Report recommends a plant-specific 

program to be evaluated. 

The staff reviewed UFSAR Section 4.3.2.1.1, and verified that feedwater to the steam 

generator, enters just above the top of the U-tubes through a feedwater ring. The water flows 

downward through an annulus between the tube wrapper and the shell and then upward 

through the tube bundle where part of it is converted to steam. On the basis that feedwater inlet 

rings and supports are not within the scope of 10 CFR 54.21(a)(1), (2) or (3), and therefore, not 

included in the scope of license renewal, the staff finds that Table 3.1.1, item 3.1.1-32 is not 

applicable.

3.1.2.2.15 Changes in Dimensions Due to Void Swelling

In LRA Section 3.1.2.2.15, the applicant identifies that changes in dimension due to void 

swelling is applicable to the RVI components as a result of exposing the components to a 

reactor coolant environment or a reactor coolant with integrated neutron flux environment. The 

applicant’s AMR items in LRA Table 3.1.2-3 indicate that this evaluation is applicable to the 

following RVI components at PINGP: (1) core baffle and former plates, (2) core baffle and 

former plate fasteners, (3) core barrels, core barrel flanges, and thermal shields, (4) BMI 

columns and flux thimble guide tubes, (5) flux thimble tubes, (6) lower core plate fuel alignment 

pins, lower support column bolts, and clevis insert bolts, (7) lower core plates, radial keys, and 

clevis inserts, (8) lower support columns and lower support forgings, (9) diffuser plates, (10) 

head cooling spray nozzles, (11) secondary core supports, (12) RCCA guide tube pins and 

fasteners, (13) RCCA guide tubes, (14) upper support columns, (15) upper instrumentation 

columns, conduits, and supports, (16) upper core plate alignment keys, upper core plate fuel 

alignment pins, and upper supper column fasteners in the upper internals assembly, (17) head 

and vessel alignment pins, and (18) upper support plates, upper core plates, and hold-down 

springs in the upper internals assembly. The applicant states that it credits its PWR Vessel 

Internals Program to manage changes in dimension that may occur in these RVI components as 

a result of exposing them to the reactor coolant with integrated neutron flux environment.

The staff reviewed LRA Section 3.1.2.2.15 against the criteria in SRP-LR Section 3.1.2.2.15,

which states that changes in dimensions due to void swelling could occur in stainless steel and

nickel-alloy PWR reactor internal components that are exposed to the reactor coolant

environment. This SRP-LR section states (from the GALL Report) that PWR renewal applicants

do not need to conduct any additional evaluation of the programs or activities that are used to

manage this aging effect if they provide a commitment on their UFSAR Supplement to: (1)

participate in the industry programs for investigating and managing aging effects on RVI

components; (2) evaluate and implement the results of the industry programs, as applicable to

the design of its RVI components; 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 RVI

components to the NRC for review and approval.

The staff noted that on May 12, 2009, the applicant resubmitted its PWR Vessel Internals 

Program (LRA AMP B2.1.32) as a new, plant-specific AMP for the PINGP RVI components, and 

credited this program for the management of changes in dimension for all of the stainless steel 

(including CASS) and nickel-alloy RVI components referenced in GALL AMR items 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-
3-235

39 as being susceptible to void swelling. The staff verified that the applicant’s PWR Vessel 

Internals Program includes appropriate program element criteria to manage changes in the 

dimensions of the RVI components as a result of void swelling. Based on this review, the staff 

finds that the applicant has provided an acceptable basis for managing changes in dimensions 

of these RVI components because the scope of program manages this aging effect and 

includes appropriate program element criteria for managing changes in dimension as a result of 

void swelling. The staff evaluates the ability of the PWR Vessel Internals Program to manage 

changes in dimension as a result of void swelling in SER Section 3.0.3.3.2.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. 

The staff noted that Commitment No. 25 conforms to the recommendations in SRP-LR Section 

3.1.2.2.15 for participating in the industry-wide programs on managing the aging effects that are 

applicable to PWR RVI components and for submitting an inspection plan for the RVI 

components to the NRC for review and approval. The staff verified that the applicant placed 

Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. Based on this review, 

the staff finds that the applicant’s AMR basis for managing changes in dimension as a result of 

void swelling is also acceptable because the applicant’s AMR basis includes Commitment No. 

25 and because this commitment conforms to the recommendations in SRP-LR Section 

3.1.2.2.15 for managing this aging effect.

Based on the program identified above and Commitment No.25, the staff concludes that the

applicant’s programs meet SRP-LR Section 3.1.2.2.15 criteria. For those line items that apply to

LRA Section 3.1.2.2.15, the staff determines that the LRA is consistent with the GALL Report

and that the applicant has demonstrated that the effects of aging will be adequately managed so

that the intended function(s) will be maintained consistent with the CLB during the period of

extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.16 Cracking due to Stress Corrosion Cracking and Primary Water Stress Corrosion

Cracking

 (1) The applicant states in LRA Section 3.1.2.2.16.1 that cracking due to stress corrosion 

cracking could occur for stainless steel CRDM rod travel housings. LRA 

Section 3.1.2.2.16.1 further states that this aging effect is managed with a combination 

of the Water Chemistry Program and the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. The Water Chemistry Program controls 

concentrations of known detrimental chemical species such as chlorides, fluorides, 

sulfates and dissolved oxygen below the levels known to cause degradation. The 

applicant further stated that the ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program includes periodic visual, surface, and/or volumetric 

examination of Class 1, 2, and 3 pressure-retaining components, their welded integral 

attachments, and bolting. The program also provides component repair and replacement 

requirements in accordance with ASME Section XI.
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The staff reviewed LRA Section 3.1.2.2.16.1 against the criteria in SRP-LR Section 

3.1.2.2.16.1 which states that cracking due to SCC could occur on the primary coolant 

side of PWR steel steam generator upper and lower heads, tubesheets, and tube-totube sheet welds made or clad with stainless steel. SRP-LR Section 3.1.2.2.16.1 further 

states that cracking due to PWSCC could occur on the primary coolant side of PWR 

steel steam generator upper and lower heads, tubesheets, and tube-to-tube sheet welds 

made or clad with nickel-alloy. SRP-LR Section 3.1.2.2.16.1 states that the GALL Report 

recommends ASME Section XI ISI and control of water chemistry to manage this aging 

and recommends no further aging management review for PWSCC of nickel-alloy if the 

applicant complies with applicable NRC Orders and provides a commitment in the 

UFSAR supplement to implement applicable (1) Bulletins and Generic Letters and (2) 

staff-accepted industry guidelines.

SRP-LR Section 3.1.2.2.2.16.1 is associated with AMR item 34 in Table 1 of the GALL 

Report, Volume 1, and GALL AMR item IV.2-11, and is applicable to SCC of stainless 

steel reactor control rod drive head penetration, pressure housings.

The only Unit 1 and Unit 2 components that apply to this category are fabricated with 

stainless steel. Therefore, the commitment recommended in the GALL Report is not 

required. The staff reviewed the applicant’s Water Chemistry Program and the ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD Program in SER 

Sections 3.0.3.2.18 and 3.0.3.1.3 respectively, and found those programs provide

control of contaminants that could promote SCC and provides inspection to detect 

PWSCC in stainless steel components. On that basis, the staff finds that the applicant’s 

aging management basis acceptable. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.16.1 criteria. For those line items that apply to LRA 

Section 3.4.2.2.16.1, 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).

 (2) LRA Section 3.1.2.2.16.2 addresses the applicant’s aging management basis for 

managing cracking due to SCC in the stainless steel pressurizer spray heads. The 

applicant stated that this aging effect/mechanism will be managed with a combination of 

the Water Chemistry Program and the One-Time Inspection Program.

The staff reviewed LRA Section 3.1.2.2.16.2 against the criteria in SRP-LR 

Section 3.1.2.2.16.2, which states that cracking due to SCC could occur in stainless 

steel pressurizer spray heads and that cracking due to PWSCC could occur in nickelalloy pressurizer spray heads. The SRP-LR states that the existing program relies on 

control of water chemistry to mitigate this aging effect and for stainless steel pressurizer 

spray heads the GALL Report recommends one-time inspection to confirm that cracking 

is not occurring. SRP-LR Section 3.1.2.2.16.2, AMR item 36 in Table 1 of the GALL 

Report Volume 1, and AMR item IV.C2-17 in Table IV.C2 of the GALL Report Volume 2, 

are applicable to the management of cracking due to SCC in stainless steel (including 
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CASS) and nickel-alloy pressurizer spray heads. The staff’s aging management 

guidance and recommendations in the AMR items are the same as those provided in 

SRP-LR Section 3.1.2.2.16.2.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.19, found that the Water 

Chemistry Program, provides mitigation for cracking due to SCC in stainless steel 

components. The staff reviewed the applicant’s One-Time Inspection Program. The 

staff’s evaluation of this program, which is documented in SER Section 3.0.3.1.18, found 

that the One-Time Inspection Program is adequate to detect the presence or note the 

absence of cracking due to SCC for components within its scope. The staff confirmed 

that the applicant is crediting the AMPs recommended in GALL AMR item IV.C2-17. The 

Water Chemistry Program provides mitigation for the identified age-related degradation, 

and that the One-Time Inspection Program provides verification of the effectiveness of 

the Water Chemistry Program to mitigate cracking due to SCC or PWSCC for the CASS 

pressurizer spray heads exposed to treated water. The staff finds the applicant’s AMR 

results acceptable because the AMPs credited with aging management are consistent 

with the guidance in SRP-LR Section 3.1.2.2.16.2 and in GALL AMR item IV.C2-17.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.1.2.2.16.2 criteria. For those line items that apply to LRA Section 

3.1.2.2.16.2, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.17 Cracking Due to Stress Corrosion Cracking, Primary Water Stress Corrosion 

Cracking, and Irradiation-Assisted Stress Corrosion Cracking

LRA Section 3.1.2.2.17 identifies that cracking due to SCC, PWSCC, and IASCC is an

applicable AERM for the stainless steel and nickel-alloy RVI components that are exposed to a

reactor coolant with neutron flux environment. The applicant’s AMRs in LRA Table 3.1.2-3

indicate that this evaluation is applicable to the following RVI components at PINGP: (1) clevis

insert bolts, (2) lower core plate fuel alignment pins, (3) lower support column bolts, (4) lower

core plates, (5) radial support keys, (6) clevis inserts, (7) RCCA guide tube fasteners, (8) RCCA

guide tube pins, (9) upper core plate alignment keys, (10) upper core plate fuel alignment pins,

and (11) upper support column fasteners. For these AMR items, the applicant credits its Water

Chemistry Program and the PWR Vessel Internals Program to manage cracking due to SCC,

PWSCC, and IASCC. The applicant states that its PWR Vessel Internals Program includes the 

commitment in SRP-LR Section 3.1.2.2.17.

The staff reviewed LRA Section 3.1.2.2.17 against the criteria in SRP-LR Section 3.1.2.2.17,

which states that cracking due to SCC, PWSCC, and IASCC could occur in PWR stainless steel

and nickel-alloy RVI components. The SRP-LR section identifies that the existing program relies

on control of water chemistry to mitigate these effects, but qualifies this recommendation by

adding that the existing program should be augmented to manage these aging effects for RVIs

components. This SRP-LR section states that to address this issue the GALL Report

recommends no further AMR if the applicant provides a commitment in the UFSAR Supplement 
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to do the following: (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 on May 12, 2009, the applicant resubmitted its PWR Vessel Internals 

Program (LRA AMP B2.1.32) as a new, plant-specific AMP for the PINGP RVI components, and 

credited this program for the management of cracking for all of the stainless steel (including 

CASS) and nickel-alloy RVI components referenced in GALL AMR items IV.B2-16, IV.B2-20, 

IV.B2-28, and IV.B2-40 as being susceptible to the aging mechanisms of SCC, PWSCC, or 

IASCC. The staff verified that the applicant’s PWR Vessel Internals Program includes 

appropriate program element criteria to manage cracking in the stainless steel or nickel-alloy

RVI components, as either induced by PWSCC or IASCC. Based on this review, the staff finds 

that the applicant has provided an acceptable basis for managing cracking in these RVI 

components because the scope of program includes cracking due to PWSCC or IASCC and 

includes appropriate program element criteria for managing this aging effect. The staff evaluates 

the ability of the PWR Vessel Internals Program to manage loss of fracture toughness in SER 

Section 3.0.3.3.2.

The staff also noted that the PWR Vessel Internals Program includes LRA Commitment No. 25, 

which calls for the applicant to submit its inspection plan for the PINGP RVI components to the 

NRC for review and approval at least two years prior to entering the period of extended 

operation, and for the submittal to identify any deviations between the AMR items and AMP 

program elements for the PINGP RVI components from those that will be developed and 

approved by the staff through its review of Report No. MRP-227-Rev. 0. 

The staff noted that Commitment No. 25 conforms to the recommendations in SRP-LR Section 

3.1.2.2.17 for participating in the industry-wide programs on managing the aging effects that are 

applicable to PWR RVI components and for submitting an inspection plan for the RVI 

components to the NRC for review and approval. The staff verified that the applicant placed 

Commitment No. 25 on the LRA in the applicant’s letter of June 24, 2009. Based on this review, 

the staff finds that the applicant’s AMR basis for managing cracking due to PWSCC or IASCC is 

also acceptable because the applicant’s AMR basis includes Commitment No. 25 and because 

this commitment conforms to the recommendations in SRP-LR Section 3.1.2.2.17 for managing 

this aging effect.

Based on the program identified above and Commitment No. 25, the staff concludes that the

applicant’s programs meet the SRP-LR Section 3.1.2.2.17 criteria. For those line items that

apply to LRA Section 3.1.2.2.17, the staff determines that the LRA is consistent with the GALL

Report and that the applicant has demonstrated that the effects of aging will be adequately

managed so that the intended function(s) will be maintained consistent with the CLB during the

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.2.18 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.
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3.1.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report 

In LRA Tables 3.1.2-1 through 3.1.2-5, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant indicated, via Notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, Note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.1.2.3.1 Pressurizer System - Summary of Aging Management Review – LRA Table 3.1.2-1

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

pressurizer system component groups. The staff determined that all AMR evaluation results in 

LRA Table 3.1.2-1 are consistent with the GALL Report.

3.1.2.3.2 Reactor Coolant System - Summary of Aging Management Review - LRA Table 

3.1.2-2

The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMRs for reactor 

coolant system component groups.

LRA Table 3.1.2-2, the applicant proposed to manage cumulative fatigue damage-fatigue in 

CASS reactor coolant pump (RCP) casings and piping/fittings in a treated water (interior) 

environment by using TLAA. The staff reviewed the applicant’s proposal and documented its 

findings in SER Sections 4.3.1.5 and 4.3.1.6.

In LRA Table 3.1.2-2, the applicant proposed to manage loss of material - selective leaching in 

copper alloy piping and fittings, cast iron filters and strainer housings, and bronze valve bodies 

in an interior environment of lubricating oil by using the Selective Leaching of Materials 

Program. The applicant referenced Footnote H for these line items indicating that the aging 

effect is not in the GALL Report for these components, material, and environment combination. 

The applicant also referenced a plant-specific note (118), which stated that for these line items 
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loss of material due to selective leaching for copper alloys and gray cast iron is evaluated in a 

fuel oil and lubricating oil internal environment. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.16. The one-time inspection credited under the applicant’s Selective 

Leaching Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. Table IX.C in the GALL Report Volume 2 identifies that copper alloys with 

greater than 15% alloying zinc content, aluminum bronzes with greater than 8% Al alloying 

contents and cast irons may be susceptible to selective leaching. On this basis, the staff finds 

the Selective Leaching of Materials Program is a valid program to credit for the management of 

loss of material due to selective leaching in these copper alloy piping and fittings because the 

basis is consistent with: the basis in GALL Table IX.C, which identifies that copper alloys with 

greater than 15% alloying zinc contents may be susceptible to selective leaching, and the basis 

in GALL AMP XI.M33 that the one-time inspection proposed in Selective Leaching Programs is 

an acceptable basis for managing loss of material in for copper alloy, aluminum bronze and cast 

iron components as a result of selective leaching.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.1.2.3.3 Reactor Internals System - Summary of Aging Management Review –

LRA Table 3.1.2-3

The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for the 

reactor internals system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.1.2-3 are consistent with the GALL Report, with the following exception.

In the applicant’s letter of May 12, 2009, the applicant supplemented the LRA to include 

additional AMR items for managing cracking due to fatigue (cyclical loading) in the RVI 

components, as applicable to the following RVI components: (1) baffle and former plates, 

(2) BMI columns, (3) flux thimble guide tubes, (4) core barrels and core barrel flanges, (5) core 

barrel outlet nozzles, (6) lower core plates, (7) lower support column bolts, (8) rod cluster control 

assembly guide tubes, (9) thermal shields, and (10) upper core plates. The applicant identified 

that it is crediting its PWR Vessel Internals Program to manage cracking due to fatigue of these 

components.

The staff noted that the applicant amended the application on May 12, 2009, to resubmit its 

PWR Vessel Internals Program as a new, plant-specific program for the RVI components in the 

application. The staff verified that the applicant’s program includes both the ASME Section XI 

Examination B-N-3 requirements for those RVI components that are part of the removable core 

support structures, as well as the augmented inspection activities of the EPRI MRP, which are 
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implemented in accordance with methodology in EPRI Report MRP-227-Rev. 0. The staff also

verified that the applicant’s AMP includes VT-1 and EVT-1 visual examination methods for 

managing cracking in the PINGP RVI components and UT volumetric techniques for the 

detection of cracking in RVI bolting. The staff noted that the ASME Code Section XI lists VT-1 

(including EVT-1) visual techniques and UT volumetric techniques as acceptable condition 

monitoring techniques for the detection of cracking in a component. Thus, based on this review, 

the staff finds that the applicant has provided an acceptable basis for managing cracking due to 

fatigue in these components because the AMP includes both mandated and augmented 

inspection bases, and because these inspection bases include appropriate visual and 

volumetric examination techniques for detecting cracking in the RVI components. The staff 

evaluates the ability of the PWR Vessel Internals Program to manage cracking due to fatigue in 

SER Section 3.0.3.3.2.

3.1.2.3.4 Reactor Vessel System - Summary of Aging Management Review –

LRA Table 3.1.2-4

The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for the 

reactor vessel system component groups. The staff determined that all AMR evaluation results 

in LRA Table 3.1.2-4 are consistent with the GALL Report.

3.1.2.3.5 Steam Generator System - Summary of Aging Management Review –

LRA Table 3.1.2-5

The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMRs for the steam 

generator system component groups.

In LRA Table 3.1.2-5, the applicant proposed to manage heat transfer degradation due to 

fouling for nickel-alloy U-tubes in the steam generator exposed to an environment of treated 

water using the Water Chemistry Program alone. The applicant cited generic Note H, indicating 

that the aging effect is not in the GALL Report for this component, material and environment 

combination.

The staff noted that in GALL Volume 2, line item V.A-16, for heat exchanger tubes, where the 

material is stainless steel, the environment is treated water, and the aging effect is reduction of 

heat transfer due to fouling and the recommended AMPs are Water Chemistry and One-Time 

Inspection. The staff also noted that the applicant did not provide any discussion in the LRA to 

explain why a confirmation of water chemistry effectiveness is not needed for this component, 

material, environment and aging effect combination. In a letter dated December 18, 2008, the 

staff issued RAI 3.1.2-5-01, asking the applicant to provide a program for confirmation of water 

chemistry effectiveness or to provide a technical justification why such a confirmation is not 

needed.

The applicant responded to the RAI in a letter dated January 20, 2009. In that letter the 

applicant stated that the One-Time Inspection Program will be used to verify effectiveness of the

Water Chemistry Program on the external side of the steam generator U-tubes where the 

environment is non-borated treated water. The applicant also stated, with technical justification, 

that an inspection activity to confirm effectiveness of the Water Chemistry Program to mitigate 
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loss of heat transfer due to fouling is not needed on the internal side of the steam generator Utubes where the environment is borated treated water.

In its response letter, the applicant revised LRA Table 3.1.2-5 AMR results for U-tubes made of 

nickel-alloy in a treated water (external) environment (non-borated demineralized water) and 

with an aging effect of heat transfer degradation due to fouling. For these AMR results, the 

applicant revised the LRA table to show that aging management is done with a combination of 

the Water Chemistry Program and the One-Time Inspection Program.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of this 

program, which is documented in SER Section 3.0.3.2.18, found that the Water Chemistry 

Program, provides mitigation for loss of heat transfer due to fouling in nickel-alloy components. 

The staff reviewed the applicant’s One-Time Inspection Program. The staff’s evaluation of this 

program, which is documented in SER Section 3.0.3.1.18, found that the One-Time Inspection 

Program is adequate to detect the presence or the absence of fouling which may cause loss of 

heat transfer for components within its scope. Based on the staff’s determination that the Water 

Chemistry Program provides mitigation and the One-Time Inspection Program provides 

detection for the aging effect of loss of heat transfer due to fouling, the staff finds the applicant’s 

proposed AMPs for managing the aging effect of loss of heat transfer due to fouling in the 

nickel-alloy steam generator U-tubes exposed to non-borated treated water (external) to be 

acceptable.

In its response letter, the applicant justified not providing an inspection on the internal (primary) 

side of the U-tubes by reference to the GALL Report, Section IX.D, Environments, in which the 

discussion of treated water environment states that the PWR reactor coolant environment 

(treated borated water) contains a recognized corrosion inhibitor. In addition, the applicant 

referenced SRP-LR Table 3.1-1, item 83 which indicates that the staff has found the Water 

Chemistry Program to be adequate for managing loss of material due to corrosion in stainless 

steel and nickel-alloy pressure boundary components exposed to borated treated water. The 

applicant stated that fouling on the reactor coolant side of the steam generator U-tubes would 

occur only through the buildup of corrosion products, and since the GALL Report and the SRPLR credit only Water Chemistry for management of loss of material due to corrosion, verification 

of the effectiveness of the Water Chemistry Program to mitigate loss of heat transfer due to 

fouling on the primary (internal) side of the steam generator U-tubes is not required.

The staff reviewed the applicant’s technical justification and compared it with sections of the 

GALL Report and the SRP-LR cited by the applicant. The staff noted that the references cited 

by the applicant state that the Water Chemistry Program provides adequate aging management 

for loss of material due to corrosion in a borated treated water environment, and confirmation of 

water chemistry effectiveness is not specified for this environment. In addition, the staff noted 

that on the primary side of the steam generator tubes, the dissolved oxygen level is monitored 

and controlled to reduce potential for oxidation, which provides added assurance that corrosion 

products cannot buildup on the primary side of the steam generator U-tubes. On the basis that 

the GALL Report and the SRP-LR state that the Water Chemistry Program is adequate to 

prevent loss of material due to corrosion in a borated treated water environment, and because 

buildup of corrosion products is the only identified age-related mechanism that could lead to 

fouling on the primary side of the steam generator U-tubes, the staff finds the applicant’s 

technical justification to be acceptable. On this basis, the staff finds the Water Chemistry 
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Program to provide adequate management for the aging effect of loss of heat transfer due to 

fouling on the primary (internal) side of the steam generator U-tubes.

On the basis described above, the staff finds that the applicant’s response resolves all issues 

raised in RAI AMR-3.1.2-5-01. The staff also finds the applicant’s proposed AMP for managing 

the aging effect of loss of heat transfer due to fouling in the nickel-alloy steam generator Utubes to be acceptable.

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, internals, and reactor coolant system components 

within the scope of license renewal and subject to an AMR will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.2 Aging Management of Engineered Safety Features

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

engineered safety features components and component groups of the following:

• containment spray system

• residual heat removal system

• safety injection system

3.2.1 Summary of Technical Information in the Application 

LRA Section 3.2 provides AMR results for the ESF systems components and component 

groups. LRA Table 3.2.1, “Summary of Aging Management Evaluations in Chapter V of 

NUREG-1801 for Engineered Safety Features,” is a summary comparison of the applicant’s 

AMRs with those evaluated in the GALL Report for the ESF systems components and 

component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry OE in 

the determination of AERM. The plant-specific evaluation included CRs and discussions with 

appropriate site personnel to identify AERM. 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 

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the ESF systems components within the 

scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).
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The staff conducted a review of the AMR items that the applicant had identified as being 

consistent with the GALL Report to ensure the applicant’s claim that certain AMRs were 

consistent with the GALL Report. The staff did not repeat its review of the matters described in 

the GALL Report; however, the staff did verify that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s audit

evaluation are documented in SER Section 3.2.2.1.

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 3.2.2.2 acceptance criteria. The staff’s 

audit evaluations are documented in SER Section 3.2.2.2.

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 3.2.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management, 

the staff reviewed the AMR line items and the plant’s 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 Systems 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 

emergency core 

cooling system

(3.2.1-1)

Cumulative 

fatigue damage

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA Consistent with 

GALL Report (See 

SER Section 

3.2.2.2.1)
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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 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 aging 

management 

program is to be 

evaluated

Reference NRC 

Information 

Notice 94-63,

“Boric Acid Corrosion 

of Charging Pump 

Casings Caused by 

Cladding Cracks”

Yes Not Applicable Not applicable to 

PINGP (See SER 

Section 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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PINGP (See SER 

Section 

3.2.2.2.3.(2))

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

Yes Not applicable Not applicable (See 

SER Section 

3.2.2.2.3.(3))

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 Lubricating Oil

Analysis 

Program 

(B2.1.24)

and One-Time

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.2.2.2.3.(4))
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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

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 aging 

management 

program 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 Not applicable Not applicable to 

PINGP (See SER 

Section 

3.2.2.2.3.(5))

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PINGP (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 Lubricating Oil

Analysis 

Program 

(B2.1.24)

and One-Time

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.2.2.2.4.(1))

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 Water Chemistry 

Program 

(B2.1.40).

Consistent with 

GALL Report (See 

SER Section 

3.2.2.2.4.(2))

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PWRs (See SER 

Section 3.2.2.2.5)
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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 highpressure safety 

injection (charging) 

pump minflow orifice 

exposed to treated 

borated water

(3.2.1-12)

Loss of material 

due to erosion

A plant-specific aging 

management 

program is to be 

evaluated for erosion 

of the orifice due to 

extended use of the 

centrifugal HPSI 

pump for normal 

charging

Yes Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.2.6)

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PWRs (See SER 

Section 3.2.2.2.7)

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

Yes Not applicable Not applicable to 

PWRs (See SER 

Section 

3.2.2.2.8(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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 Lubricating Oil

Analysis 

(B2.1.24)

and One-Time

Inspection 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.2.2.2.8.(3))
3-248

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 

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 micro 

biologicallyinfluenced 

corrosion

Buried Piping and 

Tanks Surveillance 

or 

Buried Piping and 

Tanks Inspection

No

Yes, 

detection of 

aging 

effects and 

operating 

experience 

are to be 

further 

evaluated

Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.2.9)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60°C 

(> 140°F)

(3.2.1-18)

Cracking due to 

stress corrosion 

cracking and 

intergranular 

stress corrosion 

cracking

BWR Stress 

Corrosion Cracking 

and Water Chemistry

No Not applicable Not applicable to 

PWRs

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.2.1-19)

Wall thinning 

due to flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No Not applicable Not applicable to 

PWRs

Cast austenitic 

stainless steel 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

No Not applicable Not applicable to 

PWRs

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.2.1-21)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Bolting Integrity No Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 Not applicable Addressed in line 

item 3.2.1-23 (See 

SER Section 

3.2.2.1.1)
3-249

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 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

(B2.1.6)

Consistent with 

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 selfloosening

Bolting Integrity No Bolting Integrity 

Program

(B2.1.6)

Consistent with 

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 

stress corrosion 

cracking

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program 

(B2.1.9)

Consistent with 

GALL Report

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 Not applicable Not applicable to 

PINGP (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 

(B2.1.9)

Consistent with 

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 

(B2.1.9)

Consistent with 

GALL Report
3-250

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

(3.2.1-29)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program 

(B2.1.9)

Consistent with 

GALL Report

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 

(B2.1.9)

Consistent with 

GALL Report

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

(B2.1.14)

Consistent with 

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 

PINGP (See SER 

Section 3.2.2.1.1)

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 Not applicable Addressed in item 

3.2.1-46 (See SER 

Section 3.2.2.1.1)

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

No Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)
3-251

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 containment 

isolation piping and 

components internal 

surfaces exposed to 

raw water

(3.2.1-35)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion, and 

fouling

Open-Cycle Cooling 

Water System

No Not applicable Not applicable to 

PINGP (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 

microbiologically

-influenced 

corrosion, and 

fouling

Open-Cycle Cooling 

Water System

No Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw water

(3.2.1-37)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Open-Cycle Cooling 

Water System

No Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 

microbiologically

-influenced 

corrosion, and 

fouling

Open-Cycle Cooling 

Water System

No Not applicable Not applicable to 

PINGP (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 

microbiologically

-influenced 

corrosion, and 

fouling

Open-Cycle Cooling 

Water System

No Not applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 

PINGP (See SER 

Section 3.2.2.1.1)
3-252

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, 

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 Selective 

Leaching of 

Materials 

Program

(B2.1.36)

Consistent with 

GALL Report

Gray cast iron piping, 

piping components, 

piping elements 

exposed to closedcycle cooling water

(3.2.1-42)

Loss of material 

due to selective 

leaching

Selective Leaching of 

Materials

No Selective 

Leaching of 

Materials 

Program

(B2.1.36)

Consistent with 

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 Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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

(B2.1.7)

Consistent with 

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 Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.23)

Consistent with 

GALL Report
3-253

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

Cast austenitic 

stainless steel 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 Not Applicable Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 

stress corrosion 

cracking

Water Chemistry No Water Chemistry 

Program 

(B2.1.40)

Consistent with 

GALL Report

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 Water Chemistry 

Program 

(B2.1.40)

Consistent with 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to air -

indoor uncontrolled 

(internal/external)

(3.2.1-50)

None None NA None Consistent with 

GALL Report

Galvanized steel 

ducting exposed to 

air - indoor controlled 

(external)

(3.2.1-51)

None None NA None Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

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 NA None Consistent with 

GALL Report
3-254

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, 

copper alloy, and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to air -

indoor uncontrolled 

(external)

(3.2.1-53)

None None NA None Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air -

indoor controlled 

(external)

(3.2.1-54)

None None NA None Not applicable to 

PINGP (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 NA None Not applicable to 

PINGP (See SER 

Section 3.2.2.1.1)

Steel, stainless steel, 

and copper alloy 

piping, piping 

components, and 

piping elements 

exposed to gas

(3.2.1-56)

None None NA None Consistent with 

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 NA None Consistent with 

GALL Report for 

stainless steel 

components

See item 3.2.1-45 

for cooper alloy < 

15% Zn 

components

The staff’s review of the ESF systems component groups followed any one of several 

approaches. One approach, documented in SER Section 3.2.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.2.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER Section 

3.2.2.3, reviewed AMR results for components that the applicant indicated are not consistent 
3-255

with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to manage or 

monitor aging effects of the ESF systems components is documented in SER Section 3.0.3.

3.2.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.2.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the ESF systems 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

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• One-Time Inspection Program

• Selective Leaching of Materials Program

• Water Chemistry Program

LRA Tables 3.2.2-1 through 3.2.2-3 summarize AMRs for the ESF systems components and 

indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined whether the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with Notes A through E indicating 

how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. 

The staff audited these line items to verify consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and 

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 
3-256

of some system components in the GALL Report; however, the applicant identified in the GALL 

Report a different component with the same material, environment, aging effect, and AMP as 

the component under review. The staff audited these line items to verify consistency with the 

GALL Report. The staff also determined whether the AMR line item of the different component 

was applicable to the component under review and whether the AMR was valid for the sitespecific conditions.

Note D indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL AMP. The staff audited these line items to verify consistency with 

the GALL Report. The staff verified whether the AMR line item of the different component was 

applicable to the component under review and whether the identified exceptions to the GALL 

AMPs have been reviewed and accepted. The staff also determined whether the applicant’s 

AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP or a plant-specific AMP. The staff 

audited these line items to verify consistency with the GALL Report. The staff also determined 

whether the credited AMP would manage the aging effect consistently with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL 

Report AMRs.

The staff 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 

ESF 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, 

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 follows.

3.2.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.2.1, items 18-20, the applicant states that the corresponding AMR items in 

GALL Report are not applicable to PINGP because the AMR items in the GALL 

Report are only applicable to particular components in BWR reactor designs and because 

PINGP is a Westinghouse-designed PWR facility. The staff verified that the stated AMR items in 

the GALL Report are only applicable to BWR designed facilities and are not applicable to the 

PINGP LRA.
3-257

In LRA Table 3.2.1, item 21, the applicant states that the corresponding AMR result line in the 

GALL Report is not applicable because PINGP does not have high strength closure bolting in 

the ESF Systems. The staff reviewed the documentation supporting the applicant's AMR 

evaluation and confirmed the applicant's claim that PINGP does not have high strength closure 

bolting in the ESF Systems. Therefore, the staff agrees with the applicant's determination that 

the corresponding AMR result line in the GALL Report is not applicable.

In LRA Table 3.2.1, item 22, the applicant states that the corresponding AMR result line in the

GALL Report is not used at PINGP. In addition, the LRA states to see line item 3.2.1-23 for 

further discussion. The staff noted that the aging effect and component type for item 3.2.1-23 

include the aging effect and component type for item 3.2.1-22. In addition, the applicant 

manages the components with the same AMP recommended by GALL Report for item 3.2.1-23.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result 

line in the GALL Report is not applicable.

In LRA Table 3.2.1, item 26, the applicant states that the corresponding AMR result line in the

GALL Report is not applicable because PINGP has no in-scope steel piping exposed to closedcycle cooling water in the ESF Systems. The staff reviewed the documentation supporting the 

applicant's AMR evaluation and confirmed the applicant's claim that PINGP has no in-scope 

steel piping exposed to closed-cycle cooling water in the ESF Systems. Therefore, the staff 

agrees with the applicant's determination that the corresponding AMR result line in the GALL 

Report is not applicable.

In LRA Table 3.2.1, items 32-40, 43, 44, 47, 51, and 54, the applicant states that the 

corresponding AMR result line in the GALL Report is not applicable because PINGP does not 

have the component, material, and environment combination in the ESF Systems, PINGP has a 

different GALL AMR item for the applicable component, material, and environment, or the AMR 

item in the GALL Report is only applicable to BWR-designed facilities. The staff reviewed the 

documentation supporting the applicant's AMR evaluation and confirmed the applicant's claim 

that PINGP does not have the component, material, and environment combination in the ESF 

Systems. Therefore, the staff agrees with the applicant's determination that the corresponding 

AMR result line in the GALL Report is not applicable.

In LRA Table 3.2.1, item 55, the applicant states that further evaluation in LRA Section 

3.5.2.2.1.4 concluded that steel components in concrete are not susceptible to aging and do not 

requiring aging management. The staff noted this item applies to GALL line item V.F-14 and 

V.F-17, which indicate that there is no aging effect for this component type and environment, 

and therefore do not require an AMP. Therefore, the staff agrees with the applicant in that this 

line item does not require aging management.

3.2.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.2.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the ESF systems components and provides information concerning how it 

will manage the following aging effects:

• cumulative fatigue damage
3-258

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• 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

• loss of material due to general, pitting, crevice, and MIC

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.2.2.2 as follows.

3.2.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.2.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must 

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff’s 

review of the applicant’s evaluation of this TLAA.

3.2.2.2.2 Loss of Material Due to Cladding Breach

LRA Section 3.2.2.2.2 provides the applicant’s corresponding aging management basis for 

managing loss of material due to cladding breach for steel pump casings with stainless steel 

cladding exposed to treated borated water. In this section of the LRA, the applicant identified 

this line item as not applicable because PINGP does not have steel with stainless steel cladding 

pump casings exposed to treated borated water. The charging pumps at PINGP are fabricated 

from stainless steel.

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 may occur in PWR steel pump casings with 

stainless steel cladding exposed to treated borated water and recommends further evaluation of 

a plant-specific AMP to ensure that aging effect is managed.

SRP-LR Section 3.2.2.2.2, AMR item 2 in Table 2 of the GALL Report, Volume 1, and AMR item

V.D1-32 of the GALL Report, Volume 2 address management of loss of material due to cladding 

in steel with stainless steel cladding pump casings that are exposed to a treated borated water 

environment. 

The staff reviewed LRA AMR Tables 3.2.2-1, 3.2.2-2, and 3.2.2-3 for the containment spray, 

residual heat removal, and high pressure safety injection (HPSI) systems and determined that 

the pump casings in these systems are fabricated from stainless steel materials. The staff also 

determined that the applicant has addressed loss of material for these pump casings in Table 

3.2.1, line item 3.2.1-49, and in the AMR item on page 3.2-28 for stainless steel containment 

spray pump casings (applicant has aligned to GALL AMR item V.A-27). The staff verified the 
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AMR items on pages 3.2-38 for CASS RHR pump casings and 3.2-47 for stainless steel HPSI 

pump casings that the applicant has aligned to GALL AMR item V.D1-30. The staff evaluates 

these AMR items in SER Section 3.2.2.1. On the basis that PINGP does not have steel pump 

casings with stainless steel cladding exposed to treated borated water and because the 

stainless steel pump casings are included in other lines for aging management, the staff finds 

that this line item is not applicable to PINGP.

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion 

 (1) LRA Section 3.2.2.2.3.1 addresses the applicant’s aging management basis for

managing loss of material due to pitting and crevice corrosion in stainless steel 

containment isolation piping and components internal surfaces exposed to treated 

water. In the LRA, the applicant stated that the aging effect is managed by a 

combination of the Water Chemistry Program and the One-Time Inspection Program.

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 

may occur for internal surfaces of stainless steel containment isolation piping, piping 

components, and piping elements exposed to treated water. The SRP-LR states that the 

existing AMP relies on monitoring and control of water chemistry to mitigate degradation. 

However, control of water chemistry does not preclude loss of material due to pitting and 

crevice corrosion at locations of stagnant flow conditions. The GALL Report 

recommends further evaluation of programs to verify the effectiveness of the chemistry 

control program.

SRP-LR Section 3.2.2.2.3.1, AMR item 3 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR item V.C-4, are applicable to stainless steel containment isolation piping and 

components internal surfaces exposed to treated water in the containment isolation 

components group. GALL item V.C-4 recommends aging management using the Water 

Chemistry and One-Time Inspection Programs. The applicant’s AMR result applies for 

stainless steel piping, fittings and valve bodies in the containment spray system. 

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.19, found that the Water 

Chemistry Program provides mitigation for loss of material due to crevice and pitting 

corrosion in stainless steel components. The staff reviewed the applicant’s One-Time 

Inspection Program. The staff’s evaluation of this program, which is documented in SER 

Section 3.0.3.1.18, found that the One-Time Inspection Program is adequate to detect 

the presence or note the absence of loss of material due to pitting and crevice corrosion 

for components within its scope. The staff confirmed 1) that the applicant is crediting the 

AMPs recommended in GALL AMR item V.C-4, 2) that the Water Chemistry Program 

provides mitigation for the identified age-related degradation, and 3) that the One-Time 

Inspection Program provides verification of the effectiveness of the Water Chemistry 

Program to mitigate loss of material due to pitting or crevice corrosion in stainless steel 

piping and piping components exposed to treated water. The staff finds the applicant’s 

AMR results acceptable because the AMPs credited with aging management are 

consistent with the guidance in SRP-LR Section 3.2.2.2.3.1 and in GALL AMR 

item V.C-4.
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Based on the programs identified, the staff concludes that the applicant’s proposed 

programs are acceptable for managing the aging effects in the applicable components. 

The staff determines that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

 (2) LRA Section 3.2.2.2.3.2 and in Table 3.2.1, AMR item 3.2.1-4 state that PINGP does not 

have stainless steel piping, piping components, and piping elements exposed to soil in 

NUREG-1801 Chapter V systems.

The staff reviewed LRA Section 3.2.2.2.3.2 against criteria of SRP-LR Section 

3.2.2.2.3.2, which states that loss of material from pitting and crevice corrosion could 

occur for stainless steel piping, piping components, and piping elements exposed to soil.

The staff reviewed the documentation supporting the applicant's LRA, LRA scoping 

results, and license renewal drawings, and confirmed the applicant's claim that PINGP 

does not have stainless steel piping, piping components, and piping elements exposed 

to soil. Therefore, the staff agrees with the applicant's determination that the 

corresponding AMR result line in the GALL Report is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.3.2 criteria do not 

apply.

 (3) In LRA Section 3.2.2.2.3.3 and in Table 3.2.1, AMR item 3.2.1-5, the applicant stated

that the item is applicable for BWRs only.

The staff reviewed LRA Section 3.2.2.2.3.3 against criteria of SRP-LR

Section 3.2.2.2.3.3, which states that loss of material due to pitting and crevice corrosion 

may occur for BWR stainless steel and aluminum piping, piping components, and piping 

elements exposed to treated water.

SRP-LR Section 3.2.2.2.3.3, AMR item 5 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR items V.D2-19 and V.D2-28 are applicable for aluminum or stainless steel 

piping and piping components exposed to treated water in BWR emergency core cooling 

systems.

On the basis that the applicant’s reactor is a PWR, not a BWR, the staff finds that the 

applicant has provided an acceptable basis for concluding the staff’s guidance for 

aluminum or stainless steel piping and piping components exposed to treated water in 

BWR emergency core cooling systems, as given in SRP-LR Section 3.2.2.2.3.3, AMR 

item 5 in Table 2 of the GALL Report, Volume 1, and GALL AMR items V.D2-19 and 

V.D2-28 is not applicable to the LRA.

 (4) The applicant stated in LRA Section 3.2.2.2.3.4 that loss of material due to pitting and

crevice corrosion could occur in stainless steel and copper alloy piping, piping 

components, and piping elements exposed to lubricating oil. LRA Section 3.2.2.2.3.4 
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further states that this aging effect is managed with a combination of the Lubricating Oil 

Analysis Program and the One-Time Inspection Program. The Lubricating Oil Analysis 

Program includes periodic oil sampling, analysis, and evaluation and trending of results 

to maintain contaminants (primarily water and particulates) within acceptable limits and 

the One-Time Inspection Program provides for inspections that either verify 

unacceptable degradation is not occurring or trigger additional actions. 

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 from pitting and crevice corrosion could 

occur for stainless steel and copper alloy piping, piping components, and piping 

elements exposed to lubricating oil. SRP-LR Section 3.2.2.2.3.4 further states that the 

existing program relies on the periodic sampling and analysis of lubricating oil to 

maintain contaminants within acceptable limits and the effectiveness of lubricating oil 

control should be verified with a one-time inspection of selected components at 

susceptible locations.

SRP-LR Section 3.2.2.2.3.4, AMR item 6 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR item V.D1-18 (Emergency Core Cooling System) are applicable to loss of 

material due to pitting and crevice corrosion of stainless steel and copper alloy piping, 

piping components, and piping elements exposed to lubricating oil. These components 

are identified in LRA Table 3.2.2-3, “Heat Exchanger Tubes.”

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively, 

and found that these programs provide periodic sampling of lubricating oil to maintain 

contaminants at acceptable limits to preclude loss of material and will perform one-time 

inspections of select stainless steel and copper alloy components exposed to lubricating 

oil for loss of material due to pitting and crevice corrosion to verify the effectiveness of 

the Lubricating Oil Analysis Program in applicable ESF systems. The GALL Report 

states that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item V.D1-18, and is verifying effectiveness of the Lubricating Oil Analysis Program 

with the elements of the One-Time Inspection Program, which the GALL Report states is 

an acceptable program to verify the Lubricating Oil Analysis Program effectiveness.

Therefore, the staff finds that, based on the programs identified above, the applicant has 

met the criteria of SRP-LR Section 3.2.2.2.3.4. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3.4 criteria. For those line items that apply to LRA 

Section 3.2.2.2.3.4, 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).
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 (5) LRA Section 3.2.2.2.3.5 and in Table 3.2.1, AMR item 3.2.1-7 state that PINGP does not 

have stainless steel tanks with breached moisture barrier exposed to raw water in 

NUREG-1801 Chapter V systems.

The staff reviewed LRA Section 3.2.2.2.3.5 against criteria of SRP-LR Section 

3.2.2.2.3.5, which states that loss of material from pitting and crevice corrosion could 

occur for partially encased stainless steel tanks exposed to raw water due to cracking of 

the perimeter seal from weathering.

The staff reviewed the documentation supporting the applicant's LRA, LRA scoping 

results, and license renewal drawings, and confirmed the applicant's claim that PINGP 

does not have stainless steel tanks with a breached moisture barrier exposed to raw 

water. Therefore, the staff agrees with the applicant's determination that the 

corresponding AMR result line in the GALL Report is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.3.5 criteria do not 

apply.

 (6) LRA Section 3.2.2.2.3.6 addresses the applicant’s aging management basis for

managing loss of material due to pitting and crevice corrosion in stainless steel piping, 

piping components, piping elements and tank internal surfaces exposed to internal 

condensation in the ESF. The applicant stated there are no stainless steel piping and 

piping components exposed to condensation in the GALL Report, Chapter V (ESF) 

systems.

The staff compared 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 due to pitting and crevice corrosion 

may 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 the aging effect is adequately managed.

SRP-LR Section 3.2.2.2.3.6, AMR item 8 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR items V.A-26 and VD.1-29, are applicable for stainless steel piping, piping 

components, piping elements internal surfaces and tanks in the containment spray and 

emergency core cooling systems.

The staff noted that the containment spray system includes a 6-inch diameter stainless 

steel pipe that normally is exposed (internally) to primary containment air between the 

containment spray heads and the normally-closed flow control valve. The staff also 

noted that the emergency core cooling systems include partially filled stainless steel 

tanks exposed to treated water. The staff could find no basis in the LRA explaining why 

these components would not experience internal condensation. In a letter dated 

December 18, 2008, the staff issued RAI 3.2.2.2.3.6-01 asking the applicant to provide 

its basis for stating that there are no stainless steel piping and piping components 

exposed to internal condensation in the ESF systems and to clarify whether there are 

any stainless steel tanks in the ESF systems exposed to internal condensation.
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The applicant responded to the RAI in a letter dated January 20, 2009. In that letter the 

applicant provided the following discussion:

The containment spray system spray nozzles and selected piping were 

assigned an internal environment of primary containment air (internal). 

These components are completely within the auxiliary building and 

containment. The auxiliary building indoor areas are protected from 

weather and have an ambient temperature range between 60 oF to 125

oF. The containment indoor areas are protected from weather and have 

an ambient temperature range between 50oF to 120oF. The internal 

air/gas environment of the containment spray system piping and nozzles 

is at the same temperature as the surrounding room temperature such 

that condensation is not expected.

The partially filled stainless steel tanks in the safety injection system are 

the refueling water storage tanks and the reactor coolant safety injection 

accumulators. These tanks are completely contained within the auxiliary 

building and containment, respectively. The auxiliary building indoor 

areas are protected from weather and have an ambient temperature 

range between 60oF to 125oF. The containment indoor areas are 

protected from weather and have an ambient temperature range between 

50oF to 120oF. The internal fluid environment and internal air/gas 

environment of these tanks are at the same temperature as the 

surrounding room temperature such that condensation is not expected. If 

a portion of a component was exposed to fluid, then typically the 

component was conservatively assumed to be fully exposed to the fluid 

environment for performing the aging management evaluations.

The staff noted the applicant’s statements that for containment spray system nozzles 

and piping and for partially filled stainless steel tanks in the auxiliary and containment 

buildings the internal air/gas and internal fluid environments of these components are at 

the same temperature as the surrounding room temperature. On the basis that there is 

no difference between the ambient temperature of these components and the 

temperature of the internal air/gas environment, and because a component temperature 

cooler than the internal air/gas environment would be needed for condensation to occur, 

the staff finds the applicant’s explanation to be acceptable and to resolve the issues 

raised in RAI 3.2.2.2.3.6-01.

Based on the applicant’s response to RAI 3.2.2.2.3.6-01, the staff finds that LRA Table 

3.2.1, AMR item 3.2.1-8, and the staff’s guidance in SRP-LR Section 3.2.2.2.3.6, AMR 

item 8 in the GALL Report, Volume 1, and GALL AMR items V.A-26 and VD.1-26 are not 

applicable to the LRA because the corresponding component, material and environment 

combination does not exist in ESF systems at the PINGP. RAI 3.2.2.2.3.6-1 is resolved.

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.3 criteria. For those line items that apply to LRA Section 3.2.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 
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function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.2.2.2.4 Reduction of Heat Transfer Due to Fouling 

 (1) The applicant stated in LRA Section 3.2.2.2.4.1 that reduction of heat transfer due to 

fouling could occur in steel, stainless steel, and copper alloy heat exchanger tubes 

exposed to lubricating oil. LRA Section 3.2.2.2.4.1 further states that that this aging 

effect is managed with a combination of the Lubricating Oil Analysis Program and the 

One-Time Inspection Program. The Lubricating Oil Analysis Program includes periodic 

oil sampling, analysis, and evaluation and trending of results to maintain oil systems 

contaminants (primarily water and particulates) within acceptable limits and the OneTime Inspection Program performs sampling inspections that either verify unacceptable 

degradation is not occurring or trigger additional actions. 

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.

SRP-LR Section 3.2.2.2.4.1 further states that the existing AMP relies on monitoring and 

control of lube oil chemistry to mitigate reduction of heat transfer due to fouling, the 

effectiveness of lube oil chemistry control should be verified to ensure that fouling is not 

occurring, and a one-time inspection of select 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.

SRP-LR Section 3.2.2.2.4.1, AMR item 9 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR item V.D1-8 (Emergency Core Cooling System) are applicable to reduction 

of heat transfer due to fouling of steel, stainless steel and copper alloy heat exchanger 

tubes exposed to lubricating oil. These components are identified in LRA Table 3.2.2-3: 

Heat Exchanger Tubes.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively. 

The staff found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude fouling and 2) will perform onetime inspections of select stainless steel and copper alloy heat exchanger tubing 

exposed to lubricating oil for loss of heat transfer due to fouling to verify the 

effectiveness of the Lubricating Oil Analysis Program in applicable ESF systems. The 

GALL Report states that one-time inspection is an acceptable method to verify the 

effectiveness of a mitigative AMP such as the Lubricating Oil Analysis Program. The

staff noted that the applicant is crediting the Lubricating Oil Analysis Program as 

recommended in GALL AMR item V.D1-8 and the applicant is verifying effectiveness of 

the Lubricating Oil Analysis Program with the elements of the One-Time Inspection 

Program, which the GALL Report states is an acceptable program to verify the 

Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds that, based on 

the programs identified above, the applicant has met the criteria of SRP-LR Section 

3.2.2.2.4.1.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.4.1 criteria. For those line 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) LRA Section 3.2.2.2.4.2 addresses the applicant’s aging management basis for

managing reduction of heat transfer due to fouling in stainless steel heat exchanger 

tubes exposed to treated water. The applicant stated that the aging effect is managed 

with the Water Chemistry Program. The applicant stated that the One-Time Inspection 

Program is not required to verify the water chemistry effectiveness for a borated treated 

water environment.

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 reduction of heat transfer due to fouling may occur 

for stainless steel heat exchanger tubes exposed to treated water. The SRP-LR states 

that the existing program relies on control of water chemistry to manage reduction of 

heat transfer due to fouling. However, control of water chemistry may have been 

inadequate. Therefore, the GALL Report recommends that the effectiveness of the 

chemistry control program should be verified to ensure that reduction of heat transfer 

due to fouling is not occurring and that the component’s intended function will be 

maintained during the period of extended operation. 

SRP-LR Section 3.2.2.2.4.2, AMR item 10 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR item V.A-16 are applicable to stainless steel heat exchanger tubes exposed 

to treated water in the containment spray system. GALL item V.A-16 recommends aging 

management using the Water Chemistry and One-Time Inspection Programs for 

components exposed to un-borated treated water.

The staff noted that the applicant included stainless steel heat exchanger tubes exposed 

to treated borated water in the reactor coolant system (LRA page 3.1-57), the 

containment spray system (LRA page 3.2-25), the residual heat removal system (LRA 

page 3.2-36), and the safety injection system (LRA page 3.2-43) in the AMR evaluation; 

and the applicant cited generic Note E indicating that the AMR result is consistent with 

the GALL Report for material, environment, and aging effect, but a different AMP is 

credited.

In a letter dated December 18, 2008, the staff issued RAI 3.2.2.2.4.2-01 asking the 

applicant to identify the heat exchangers included in this evaluation and to provide a 

technical justification for not including a verification of Water Chemistry Program 

effectiveness as recommended in the SRP-LR and the GALL Report.

The applicant responded to the RAI in a letter dated January 20, 2009. The applicant 

identified the heat exchangers as the reactor coolant pump thermal barrier heat 

exchanger, the containment spray pump seal cooler, the residual heat removal heat 

exchanger, the residual heat removal pump seal water cooler, and the safety injection 
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pump seal water cooler. In that letter the applicant referred to the GALL Report, Section 

IX.D, and the discussion of a treated water environment therein. In that discussion, the 

GALL Report states that treated, borated water contains a known corrosion inhibitor. The 

applicant also referred to GALL Report Section IX.F, which describes fouling as an 

accumulation of deposits that may be due to biofouling or particulate fouling, such as 

sediment, silt or corrosion products. The applicant also stated that fouling of the heat 

exchanger tubes on the treated water side would occur only through the buildup of 

corrosion products because there is no source for biofouling or other particulate buildup. 

The applicant stated that because borated treated water contains a corrosion inhibitor, 

fouling due to a buildup of corrosion products will not occur in an environment of 

borated, treated water.

The staff reviewed GALL Sections IX.D and IX.F, which were referenced in the 

applicant’s response. The staff noted that in GALL Section IX.D, treated water is 

described, in general, as demineralized water. However, the discussion in the GALL 

Report also states that treated water may include corrosion inhibitors and that the PWR 

reactor coolant environment includes boron, which is a recognized corrosion inhibitor. 

The staff also reviewed additional AMR results in the GALL Report (items V.A-27, V.A28, and V.D1-30) where the material is stainless steel and the environment is explicitly 

identified as treated borated water. The staff noted that for a treated borated water 

environment the GALL Report recommends that the Water Chemistry Program provides 

adequate management for the aging effect of loss of material due to pitting and crevice 

corrosion in stainless steel components. Because the GALL Report states that in a 

treated borated water environment the Water Chemistry program provides adequate 

aging management for loss of material due to corrosion in stainless steel components, 

and because the only source for fouling of the stainless steel heat exchanger tubes is 

corrosion products, the staff finds that the applicant’s response resolves all issues raised 

in RAI AMR-3.2.2.2.4.2-01.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides adequate control of boron content for treated borated water 

and mitigation for loss of material due to crevice and pitting corrosion in stainless steel 

components. The staff confirmed that the Water Chemistry Program is a mitigative AMP 

that is consistent with the AMP recommended in GALL item V.A-16; that in an 

environment of treated borated water, augmentation of the Water Chemistry Program is 

not needed to confirm that the program effectively prevents loss of material due to pitting 

or crevice corrosion in stainless steel components; and that because loss of material due 

to corrosion does not occur in the heat exchanger tubes, there is no source of material to 

cause fouling in the stainless steel heat exchanger tubes and examination is not 

required to confirm that fouling does not occur. The staff finds the applicant’s AMR 

results acceptable because the applicant is crediting the Water Chemistry Program for 

aging management consistent with the SRP-LR recommendations and because the 

boron in the treated water environment creates an effective corrosion inhibitor such that 

a One-Time Inspection of the components is not necessary. This is consistent with the 

aging management recommendation in GALL AMR item V.D1-30.
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Based on the programs identified, the staff concludes that the applicant’s proposed 

programs are acceptable for managing the aging effects in the applicable components. 

The staff determines that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation

The staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.

LRA Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer degradation, 

is not applicable to PINGP, a PWR plant.

SRP-LR Section 3.2.2.2.5 states that hardening and loss of strength due to elastomer 

degradation may occur in elastomer seals and components of the BWR standby gas treatment 

system ductwork and filters exposed to uncontrolled indoor air.

The staff noted that PINGP is a PWR plant and does not have BWR standby gas treatment 

system ductwork and filters. Therefore, this aging effect is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.5 criteria do not apply. 

3.2.2.2.6 Loss of Material Due to Erosion 

LRA Section 3.2.2.2.6 addresses the applicant’s aging management basis for managing loss of 

material due to erosion in the stainless steel HPSI pump miniflow recirculation orifice exposed to 

treated borated water. In the LRA the applicant stated that this AMR result line AMR item 

3.2.1-12 is not applicable because safety injection pumps are not used for normal charging.

The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6, which 

states loss of material due to erosion may occur in the stainless steel HPSI pump miniflow 

recirculation orifice exposed to treated borated water. The GALL Report recommends a plantspecific AMR be evaluated for erosion of the orifice due to extended use of the centrifugal HPSI 

pump for normal charging.

SRP-LR Section 3.2.2.2.6, AMR item 12 in Table 2 of the GALL Report, Volume 1, and GALL 

AMR item V.D1-14, are applicable for the stainless steel miniflow recirculation orifice exposed to 

treated borated water in the emergency core cooling system. The GALL Report references 

Licensee Event Report (LER) 50-275/94-023 for evidence of erosion and recommends further 

evaluation to ensure that the aging effect is adequately managed.

The staff noted that the description of the AMP for GALL AMR item V.D.1-14 states that erosion 

of the orifice is due to extended use of the centrifugal HPSI pump for normal charging. The staff 

also reviewed LER 50-275/94-023 and noted that the OE described therein is related to a 

system in which a selected HPSI pump was normally used for charging and is constantly in 

operation, resulting in constant flow through the miniflow orifice.
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The staff reviewed the description of the applicant’s safety injection system in the UFSAR

(Prairie Island Updated Safety Analysis Report, Revision 29, Section 6.2, Safety Injection 

System) and confirmed that the applicant’s safety injection system is designed so that HPSI 

pumps are not required for normal charging, and under normal standby conditions there is no 

flow through the HPSI pump miniflow recirculation orifice. Since the applicant’s HPSI pumps are 

not used for normal charging and normally there is no flow through the HPSI miniflow 

recirculation orifice, there is no mechanism to cause loss of material due to erosion. Because 

there is no mechanism to cause loss of material due to erosion in the HPSI pumps’ miniflow 

orifices, the staff finds that the applicant has provided an acceptable basis for concluding that 

Table 3.2.1, AMR item number 3.2.1-12, and the staff guidance in SRP-LR Section 3.2.2.2.6, 

AMR item 12 in Table 2 of the GALL Report, Volume 1, and GALL AMR item V.D1-14 are not 

applicable to the LRA.

3.2.2.2.7 Loss of Material Due to General Corrosion and Fouling 

The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.

LRA Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling on steel 

BWR drywell and suppression chamber spray system nozzle and flow orifice internal surfaces 

exposed to indoor uncontrolled air is not applicable to PINGP, a PWR plant.

SRP-LR Section 3.2.2.2.7 states that loss of material due to general corrosion and fouling may 

occur on steel drywell and suppression chamber spray system nozzle and flow orifice internal 

surfaces exposed to indoor uncontrolled air and may cause plugging of the spray nozzles and 

flow orifices.

The staff noted that PINGP is a PWR plant and does not have steel drywell and suppression 

chamber spray system. Therefore, this aging effect is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.7 criteria do not apply. 

3.2.2.2.8 Loss of Material Due to General, Pitting, and Crevice Corrosion 

 (1) LRA Section 3.2.2.2.8.1 and in Table 3.2.1, AMR item 3.2.1-14, the applicant stated that 

loss of material due to general, pitting and crevice corrosion could occur for BWR steel 

piping, piping components, and piping elements exposed water is not applicable to 

PINGP, a PWR plant.

SRP-LR Section 3.2.2.2.8.1 states that loss of material due to general, pitting and 

crevice corrosion could occur for BWR steel piping, piping components, and piping 

elements exposed to water.

The staff noted that PINGP is a PWR plant and does not have BWR steel piping, piping 

components, and piping elements. Therefore, this aging effect is not applicable to 

PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.8.1 criteria do not 

apply.
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(2) LRA Section 3.2.2.2.8.2 addresses the applicant’s aging management basis for 

managing loss of material due to general, pitting and crevice corrosion in steel 

containment isolation piping, piping components, and piping elements internal surfaces 

exposed to treated water. The applicant stated that for these components the aging 

effects will be managed with a combination of the Water Chemistry Program and the 

One-Time Inspection Program. The applicant also listed loss of material due to galvanic 

corrosion as a potential aging effect for this material and environment combination to be 

managed by the Water Chemistry Program and the One-Time Inspection Program and 

cited plant-specific Note 210 stating that galvanic corrosion is also included. 

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 may occur on the internal surfaces of steel containment isolation piping, piping 

components, and piping elements exposed to treated water. The SRP-LR states that the 

existing AMP monitors and controls water chemistry to mitigate degradation. However, 

control of water chemistry does not preclude loss of material due to general, pitting, and 

crevice corrosion at locations with stagnant flow conditions; therefore, the effectiveness 

of water chemistry control programs should be verified to ensure that corrosion does not 

occur. The GALL Report recommends further evaluation of programs to verify the 

effectiveness of water chemistry control programs.

SRP-LR Section 3.2.2.2.8.2, AMR item 15 in Table 2 of the GALL Report, Volume 1, and 

GALL AMR item V.C-6, are applicable for steel containment isolation piping and 

components internal surfaces exposed to treated water in the containment isolation 

components group. GALL item V.C-6 recommends aging management using the Water 

Chemistry and One-Time Inspection programs. The applicant’s AMR result applies for 

carbon steel and ductile iron components exposed to treated water in the containment 

spray system. 

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides mitigation for loss of material due to general, crevice, 

pitting and galvanic corrosion in steel components. The staff reviewed the applicant’s 

One-Time Inspection Program. The staff’s evaluation of this program, which is 

documented in SER Section 3.0.3.1.18, found that the One-Time Inspection Program is 

adequate to detect the presence or note the absence of loss of material due to general, 

pitting, crevice, and galvanic corrosion for components within its scope. The staff 

confirmed that the applicant is crediting the AMPs recommended in GALL AMR 

item V.C-6, that the Water Chemistry Program provides mitigation for the identified agerelated degradation, and that the One-Time Inspection Program provides verification of 

the effectiveness of the Water Chemistry Program to mitigate loss of material due to 

general, pitting or crevice corrosion in steel or ductile iron piping and piping components 

exposed to treated water. The staff finds the applicant’s AMR results acceptable 

because the AMPs credited with aging management are consistent with the guidance in 

SRP-LR Section 3.2.2.2.8.2 and in GALL AMR item V.C-6.
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Based on the programs identified, the staff concludes that the applicant’s proposed 

programs are acceptable for managing the aging effects in the applicable components. 

The staff determines that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

(3) The applicant states in LRA Section 3.2.2.2.8.3 that loss of material due to general, 

pitting, and crevice corrosion could occur in steel piping, piping components, and piping 

elements exposed to lubricating oil. LRA Section 3.2.2.2.8.3 further states that this aging 

effect is managed with a combination of the Lubricating Oil Analysis Program and the 

One-Time Inspection Program. The Lubricating Oil Analysis Program includes periodic 

oil sampling, analysis, and evaluation and trending of results to maintain contaminants 

(primarily water and particulates) within acceptable limits. The One-Time Inspection 

Program provides for inspections that either verify that unacceptable degradation is not 

occurring or trigger additional actions if unacceptable degradation is identified. 

SRP-LR Section 3.2.2.2.8.3 states that, loss of material due to general, pitting and 

crevice corrosion could occur for steel piping, piping components, and piping elements 

exposed to lubricating oil. The existing program relies on the periodic sampling and 

analysis of lubricating oil to maintain contaminants within acceptable limits, thereby 

preserving an environment that is not conducive to corrosion. 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 is not occurring.

SRP-LR Section 3.2.2.2.8.3, AMR item 16 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR item V.D1-28 (Emergency Core Cooling System), are applicable to loss of 

material due to general, pitting, and crevice corrosion of steel piping, piping components, 

and piping elements exposed to lubricating oil. These components are identified in LRA, 

Table 3.2.2-3: Piping / Fittings, Thermowells, and Valve Bodies.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively.

The staff found that these programs provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material and will perform 

one-time inspections of select steel and components exposed to lubricating oil for loss of 

material due to general, pitting and crevice corrosion to verify the effectiveness of the 

Lubricating Oil Analysis Program in applicable ESF systems. The GALL Report states 

that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item V.D1-28 and the applicant is verifying effectiveness of the Lubricating Oil 

Analysis Program with the elements of the One-Time Inspection Program, which the 

GALL Report states is an acceptable program to verify the Lubricating Oil Analysis 

Program effectiveness. Therefore, the staff finds that, based on the programs identified 

above, the applicant has met the criteria of SRP-LR Section 3.2.2.2.8.3.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.2.2.2.8.3 criteria. For those line items that apply to LRA 

Section 3.2.2.2.8, the staff finds that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.2.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

The staff reviewed LRA Section 3.2.2.2.9 against the criteria in SRP-LR Section 3.2.2.2.9.

LRA Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC in 

steel piping (with or without coating or wrapping), piping components, and piping elements 

buried in soil is not applicable because there are no buried carbon steel components in ESF 

systems with intended functions for license renewal at PINGP.

SRP-LR Section 3.2.2.2.9 states that loss of material due to general, pitting, crevice, and MIC

may occur in steel (with or without coating or wrapping) piping, piping components, and piping 

elements buried in soil.

The staff reviewed the documentation supporting the applicant's LRA, LRA scoping results, and 

license renewal drawings, and confirmed the applicant's claim that PINGP does not have any 

steel piping, piping components, and piping elements that are exposed to a soil environment.

Therefore, the staff agrees with the applicant's determination that the corresponding AMR result 

line in the GALL Report is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.2.2.2.9 criteria do not apply. 

3.2.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

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

In LRA Tables 3.2.2-1 through 3.2.2-3, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.2.2-1 through 3.2.2-3, the applicant indicated, via Notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, Note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 
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Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.2.2.3.1 Containment Spray System - Summary of Aging Management Review –

LRA Table 3.2.2-1

The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for the 

containment spray system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.2.2-1 are consistent with the GALL Report.

3.2.2.3.2 Residual Heat Removal System - Summary of Aging Management Review –

LRA Table 3.2.2-2

The staff reviewed LRA Table 3.2.2-2, which summarizes the results of AMR evaluations for the 

residual heat removal system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.2.2-2 are consistent with the GALL Report.

3.2.2.3.3 Safety Injection System - Summary of Aging Management Review – LRA

Table 3.2.2-3

In LRA Table 3.2.2-3, the applicant proposed to manage changes in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for safety 

injection system (SI) piping and fittings fabricated from polyvinyl chloride (PVC) that are 

exposed to an external uncontrolled plant indoor air environment. The applicant’s AMR line 

items cite Generic Note F, which indicates that the material is not addressed in the GALL Report 

for this environment. For the PVC components in these AMR items, the applicant credits PINGP 

AMP B2.1.14 “External Surfaces Monitoring Program” to manage cracking in the components 

and changes in material properties of the PVC materials.

The staff noted that the applicant has proposed to enhance the scope of "External Surfaces 

Program" to include non-metallic components, including PVC, and the aging effects of change 

in material properties and cracking. The staff further notes the intent of GALL AMP XI.M36 is to

perform visual inspections of steel components for the aging effect of loss of material. The staff 

determined that additional information was needed on the applicant’s proposed augmentation to 

PINGP AMP B2.1.14. Therefore, by letter dated November 5, 2008, the staff issued RAI 

B2.1.14-1 requesting the applicant provide an appropriate program that will manage the effects 

of aging for non-metallic components, including PVC. The applicant responded to RAI B2.1.14-1 

by letter dated December 5, 2008. The staff’s evaluation of the applicant's response is 

documented in SER Sections 3.0.3.2.5 and includes the staff's basis for resolving the issue 

raised in RAI B2.1.14-1. The staff’s evaluation of PINGP's response to RAI B2.1.14-1 in SER 

Section 3.0.3.25 also includes the staff’s basis for concluding the visual examination methods 

for elastomer (rubber), thermoplastic, or thermoset polymer materials need to be coupled to 
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physical manipulation methods in order to accomplish effective management of cracking or 

material property changes of these types of materials.

The staff verified that applicant’s program includes periodic visual inspections of external 

surfaces performed during system walkdowns at a specified frequency. The staff also verified 

that the applicant has amended its program to supplement the program’s visual examination 

methods for elastomer (rubber), thermoplastic, or thermoset polymer materials with physical 

manipulation techniques that will be used to aid the visual inspections in detecting cracking in 

the components or identifying any changes in the material properties of component materials 

(e.g., changes in the elastic, hardness or strength properties of the materials). On the basis that 

periodic visual inspections will be coupled to physical manipulation techniques and will be 

performed during system walkdowns at a specified frequency, the staff finds the applicant's use 

of the External Surfaces Monitoring Program to be acceptable for these types of component 

materials.

In LRA Table 3.2.2-3, the applicant proposed to manage loss of material-selective leaching in 

brass heat exchanger components and copper alloy heat exchanger tubes in an internal 

environment of lubricating oil by using the Selective Leaching of Materials Program. The 

applicant referenced Footnote H for these line items indicating that the aging effect is not in the 

GALL Report for these components, material, and environment combinations. The applicant 

also referenced a plant-specific note, which stated that for these line items loss of material due 

to selective leaching for copper alloys and gray cast iron is evaluated in a fuel oil and lubricating 

oil environment.

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection credited under the applicant’s Selective Leaching 

Program is consistent with the one-time inspection basis credited in GALL AMP XI.M33, 

"Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15% alloying zinc content, aluminum bronzes with greater than 8% 

aluminum alloying contents and cast irons may be susceptible to selective leaching. On this 

basis, the staff finds the Selective Leaching of Materials Program is a valid program to credit for 

the management of loss of material due to selective leaching in these copper alloy and brass 

heat exchanger components because the basis is consistent with: (1) GALL Table IX.C, which 

identifies that copper alloys with greater than 15% alloying zinc contents may be susceptible to 

selective leaching, and (2) GALL AMP XI.M33 which includes an acceptable program for 

managing loss of material in copper alloy, brass, aluminum bronze and cast iron components as 

a result of selective leaching.
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LRA Table 3.2.2-3 summarizes the results of AMRs for the Safety Injection System piping and 

fittings constructed out of PVC and exposed to treated water (internal). The applicant proposed 

no aging effect and therefore that no AMP is required. 

The applicant has indicated that generic Note F is applicable for these items with plant-specific

note 213. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-specific 

note 213 states, “Materials science evaluation for this material in this environment results in no 

aging effects." The staff confirmed that this environment is not in GALL for this component and 

material. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC has no aging effect when in contact with treated water (Roff, W. J., Fibres, 

Plastics, and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 

1956.)

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3 Aging Management of Auxiliary Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

auxiliary systems components and component groups of:

• auxiliary and radwaste area ventilation system

• chemical and volume control system

• component cooling system

• containment hydrogen control system

• control room and miscellaneous area ventilation system

• cooling water system

• diesel generator and screenhouse ventilation system

• diesel generators and support system

• fire protection system

• fuel oil system

• heating system

• miscellaneous gas system

• plant sample system

• primary containment ventilation system

• radiation monitoring system

• spent fuel pool cooling system

• station and instrument air system

• steam exclusion system

• turbine and administration building ventilation system

• waste disposal system

• water treatment 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 systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Evaluations in Chapter VII of 

NUREG-1801 for Auxiliary Systems,” is a summary comparison of the applicant’s AMRs with 

those evaluated in the GALL Report for the auxiliary systems components and component 

groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry OE in 

the determination of AERMs. The plant-specific evaluation included CRs 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 the auxiliary systems components within 

the scope of license renewal and subject to an AMR, will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff conducted 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 review

evaluation are documented in SER Section 3.3.2.1.

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 3.3.2.2 acceptance criteria. The staff’s 

audit evaluations are documented in SER Section 3.3.2.2.

The staff also conducted a technical review of the remaining AMRs, AMRs that are not 

consistent with or not addressed in the GALL Report. The technical review evaluated whether 

all plausible aging effects have been identified and whether the aging effects listed were 

appropriate for the material-environment combinations specified. The staff’s evaluations are 

documented in SER Section 3.3.2.3.

For SSCs that 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 the 

SRP-LR, Section 4.7 

for generic guidance 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)

Yes TLAA Consistent with 

GALL Report 

(See SER Section 

3.3.2.2.1)

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 Consistent with 

GALL Report 

(See SER Section 

3.3.2.2.1)

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 Not applicable to 

PWRs 

(See SER Section 

3.3.2.2.2)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to sodium 

pentaborate solution 

> 60°C (> 140°F)

(3.3.1-4)

Cracking due to 

stress corrosion 

cracking

Water Chemistry and 

One-Time Inspection

Yes Not applicable Not applicable to 

PWRs 

(See SER Section 

3.3.2.2.3.1)

Stainless steel and 

stainless clad steel 

heat exchanger 

components exposed 

to treated water 

> 60°C (> 140°F)

(3.3.1-5)

Cracking due to 

stress corrosion 

cracking

A plant-specific aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PWRs 

(See SER Section 

3.3.2.2.3.2)
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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 diesel 

engine exhaust 

piping, piping 

components, and 

piping elements 

exposed to diesel 

exhaust

(3.3.1-6)

Cracking due to 

stress corrosion 

cracking

A plant-specific aging 

management 

program is to be 

evaluated

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report

(See SER Section 

3.3.2.2.3.3)

Stainless steel nonregenerative heat 

exchanger 

components exposed 

to treated borated 

water > 60°C 

(> 140°F)

(3.3.1-7)

Cracking due to 

stress corrosion 

cracking 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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program

(B2.1.29) 

Consistent with 

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 

stress corrosion 

cracking 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 

stress corrosion 

cracking and cyclic 

loading. A plantspecific aging 

management 

program is to be 

evaluated

Yes Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program

(B2.1.29)

Consistent with 

GALL Report

(See SER Section 

3.3.2.2.4.2)

Stainless steel highpressure pump 

casing in PWR 

chemical and volume 

control system

(3.3.1-9)

Cracking due to 

stress corrosion 

cracking 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 

stress corrosion 

cracking and cyclic 

loading. A plantspecific aging

management 

program is to be 

evaluated

Yes Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program

(B2.1.29)

Consistent with 

GALL

(See SER Section 

3.3.2.2.4.3)
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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

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage.

(3.3.1-10)

Cracking due to 

stress corrosion 

cracking, 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 Not applicable to 

PINGP 

(See SER Section 

3.3.2.2.4.4)

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 aging 

management 

program is to be 

evaluated

Yes External 

Surfaces 

Monitoring 

Program

(B2.1.14)

Consistent with 

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PINGP 

(See SER Section 

3.3.2.2.5.2)

Boral, boron steel 

spent fuel storage 

racks neutronabsorbing 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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PINGP

(See SER Section 

3.3.2.2.6)

Steel piping, piping 

component, 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 

(B2.1.24), 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report 

(See SER Section 

3.3.2.2.7.1)

Steel reactor coolant 

pump 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 Lubricating Oil 

Analysis 

Program 

(B2.1.24), 

One-Time 

Inspection

Program

(B2.1.29)

Consistent with 

GALL Report 

(See SER Section 

3.3.2.2.7.1)
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

Steel reactor coolant 

pump 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 Lubricating Oil 

Analysis 

Program 

(B2.1.24), 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 Not applicable to 

PWRs 

(See SER Section 

3.3.2.2.7.2)

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 aging 

management 

program is to be 

evaluated

Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

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

No

Yes

Buried Piping 

and Tanks 

Inspection 

Program 

(B2.1.8)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.2.8)

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 

(B2.1.19), 

One-Time 

Inspection

Program

(B2.1.29) 

Consistent with 

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 micro 

biologically 

influenced 

corrosion, and 

fouling

Lubricating Oil 

Analysis and 

One-Time Inspection

Yes Lubricating Oil 

Analysis 

Program 

(B2.1.24) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.2.9.2)
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

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 Not applicable to 

PINGP (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 Not applicable to 

PWRs (See SER 

Section 

3.3.2.2.10.2)

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 Not applicable to 

PINGP (See SER 

Section 

3.3.2.2.10.2)

Copper alloy HVAC 

piping, piping 

components, piping 

elements exposed to 

condensation 

(external)

(3.3.1-25)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific aging 

management 

program is to be 

evaluated

Yes External 

Surfaces 

Monitoring 

Program 

(B2.1.14)

Consistent with 

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 

(B2.1.24) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 aging 

management 

program is to be 

evaluated

Yes Compressed Air 

Monitoring 

Program 

(B2.1.10)

Consistent with

GALL Report(See 

SER Section 

3.3.2.2.10.5)
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 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 aging 

management 

program is to be 

evaluated

Yes Compressed Air 

Monitoring 

Program 

(B2.1.10)

Consistent with 

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 aging 

management 

program is to be 

evaluated

Yes Not applicable Not applicable to 

PINGP (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 Not applicable to 

PWRs (See SER 

Section 

3.3.2.2.10.8)

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 Not applicable to 

PWRs (See SER 

Section 3.3.2.2.11)

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 Fire Protection 

Program 

(B2.1.15), Fuel 

Oil Chemistry 

Program 

(B2.1.19) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 

micro 

biologically 

influenced 

corrosion

Lubricating Oil 

Analysis and 

One-Time Inspection

Yes Lubricating Oil 

Analysis 

Program 

(B2.1.24), 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.2.12.2)
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

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 aging 

management 

program is to be 

evaluated

Yes External 

Surfaces 

Monitoring 

Program

(B2.1.14)

Consistent with 

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 aging 

management 

program is to be 

evaluated.

Reference NRC 

IN 94-63, “Boric Acid 

Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

Yes Not applicable Not applicable to 

PINGP (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 Not applicable to 

PWRs

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60°C 

(> 140°F)

(3.3.1-37)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

BWR Reactor Water 

Cleanup System

No Not applicable Not applicable to 

PWRs

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water > 60°C 

(> 140°F)

(3.3.1-38)

Cracking due to 

stress corrosion 

cracking

BWR Stress 

Corrosion Cracking 

and Water Chemistry

No Not applicable Not applicable to 

PWRs

Stainless steel BWR 

spent fuel storage 

racks exposed to 

treated water > 60°C 

(> 140°F)

(3.3.1-39)

Cracking due to 

stress corrosion 

cracking

Water Chemistry No Not applicable Not applicable to 

PWRs
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

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 Not applicable Addressed in item 

3.3.1-58 

(See SER Section 

3.3.2.1.1)

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.3.1-41)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Bolting Integrity No Not applicable Not applicable to 

PINGP 

(See SER Section 

3.3.2.1.1)

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 Not Used by 

PINGP. 

Addressed in item 

3.3.1-43 

(See SER Section 

3.3.2.1.1)

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

(B2.1.6)

Consistent with 

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 Not Used by 

PINGP.

Addressed in item

3.3.1-43 

(See SER Section 

3.3.2.1.1)

Steel closure bolting 

exposed to air -

indoor uncontrolled 

(external)

(3.3.1-45)

Loss of preload 

due to thermal 

effects, gasket 

creep, and selfloosening

Bolting Integrity No Bolting Integrity 

Program

(B2.1.6)

Consistent with 

GALL Report
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

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 

stress corrosion

cracking

Closed-Cycle 

Cooling Water 

System

No Closed-Cycle 

Cooling Water 

System Program

(B2.1.9)

Consistent with 

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 

System Program

(B2.1.9) 

Consistent with 

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 

System Program

(B2.1.9)

Consistent with 

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 Not applicable to 

PWRs 

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 

System Program

(B2.1.9)

Consistent with 

GALL Report
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

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 

System Program

(B2.1.9)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.1.8)

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 

System Program

(B2.1.9)

Consistent with 

GALL Report

Steel compressed air 

system piping, piping 

components, and 

piping elements 

exposed to internal 

condensation

(3.3.1-53)

Loss of material 

due to pitting 

and crevice 

corrosion

Compressed Air 

Monitoring

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22) and 

Compressed Air 

Monitoring 

Program 

(B2.1.10)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.1.2)

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 

(B2.1.10)

Consistent with 

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 External 

Surfaces 

Monitoring 

Program 

(B2.1.14)

Consistent with 

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 

(B2.1.14)

Consistent with 

GALL Report
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 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 

(B2.1.14)

Consistent with 

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

(B2.1.14)

Consistent with 

GALL Report

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 Not applicable Addressed in items 

3.3.1-57 and 3.3.1-

58 

(See SER Section 

3.3.2.1.1)

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

(B2.1.14)

Consistent with 

GALL Report

Elastomer fire barrier 

penetration seals 

exposed to air –

outdoor or air –

indoor uncontrolled

(3.3.1-61)

Increase 

hardness, 

shrinkage and 

loss of strength 

due to 

weathering

Fire Protection No External 

Surfaces 

Monitoring 

Program 

(B2.1.14)

Fire Protection 

Program 

(B2.1.15)

Consistent with

GALL Report (See 

SER Section 

3.3.2.1.3)

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 Not Applicable

(See SER Section 

3.3.2.1.1)
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

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 

(B2.1.15)

Consistent with 

GALL Report

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 Fire Protection 

Program 

(B2.1.15)

Fuel Oil 

Chemistry 

(B2.1.19)

Consistent with 

GALL Report

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 

Program

No Fire Protection 

Program 

(B2.1.15)

Structures 

Monitoring 

Program 

(B2.1.38)

Consistent with 

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 

Program

No Fire Protection 

Program 

(B2.1.15)

Structures 

Monitoring 

Program 

(B2.1.38)

Consistent with 

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 

Program

No Fire Protection 

Program 

(B2.1.15)

Structures 

Monitoring 

Program 

(B2.1.38)

Consistent with 

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 Water 

System Program 

(B2.1.16)

Consistent with 

GALL Report
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

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 Water 

System Program 

(B2.1.16)

Consistent with 

GALL Report

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 Water 

System Program 

(B2.1.16)

Consistent with 

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 Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report

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 Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report

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 Light 

Load (Related to 

Refueling) 

Handling 

Systems 

Program

(B2.1.23)

Consistent with 

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 Light 

Load (Related to 

Refueling) 

Handling 

Systems 

Program

(B2.1.23)

Consistent with 

GALL Report
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

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 Not applicable Not applicable to

PINGP (See SER 

Section 3.3.2.1.1)

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 

(B2.1.31) or 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report (See 

SER Section 

3.3.2.1.9)

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 

(B2.1.31)

or Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22) 

Consistent with

GALL Report (See 

SER Section 

3.3.2.1.10)

Stainless steel, 

nickel-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 Not applicable Addressed in item 

3.3.1-79 

(See SER Section 

3.3.2.1.11)

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

(B2.1.31)

Consistent with 

GALL Report
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

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 Open-Cycle 

Cooling Water 

System Program 

(B2.1.31) 

or alternatively, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22) 

Consistent with

GALL (See SER 

Section 3.3.2.1.4)

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 

(B2.1.31), 

or alternatively, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

See SER Section 

3.3.2.1.5

Copper 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 

(B2.1.31)

or alternatively, 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22) or 

Fire Water 

System Program 

(B2.1.16)

See SER Section 

3.3.2.1.6
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 

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 

(B2.1.31)

or alternatively, 

Fire Water 

System Program 

(B2.1.16) for 

heat exchanger 

components in 

the Fire 

Protection 

System

Consistent with 

GALL Report

(See SER Section 

3.3.2.1.7)

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

(B2.1.36)

Consistent with 

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

(B2.1.36)

Consistent with 

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 Not applicable to 

PINGP (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 Not applicable to 

PINGP (See SER 

Section 3.3.2.2.6)
3-292

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

(B2.1.7)

Consistent with 

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

(B2.1.7)

Consistent with 

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 

stress corrosion 

cracking

Water Chemistry No Water Chemistry 

Program

(B2.1.40)

Consistent with 

GALL Report

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 Water Chemistry 

Program

(B2.1.40)

Consistent with 

GALL Report

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to air -

indoor uncontrolled

(3.3.1-92)

None None NA None Not applicable to 

PINGP 

(See SER Section 

3.3.2.1.1)
3-293

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

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 NA None Consistent with 

GALL Report

Stainless steel and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to air -

indoor uncontrolled 

(external)

(3.3.1-94)

None None NA None Consistent with 

GALL Report

Steel and aluminum 

piping, piping 

components, and 

piping elements 

exposed to air -

indoor controlled 

(external)

(3.3.1-95)

None None NA None Not applicable to 

PINGP (See SER 

Section 3.3.2.1.1)

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.3.1-96)

None None NA None Not applicable to 

PINGP 

(See SER Section 

3.3.2.1.1)

Steel, stainless steel, 

aluminum, and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to gas

(3.3.1-97)

None None NA None Consistent with 

GALL Report

Steel, stainless steel, 

and copper alloy 

piping, piping 

components, and 

piping elements 

exposed to dried air

(3.3.1-98)

None None NA None Consistent with 

GALL Report
3-294

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 

< 15% Zn piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage

(3.3.1-99)

None None NA Not applicable Exposure of 

stainless steel and 

copper alloy piping 

components to air 

is addressed in 

item 3.3.1-94

(See SER Section 

3.3.2.1.1)

The staff’s review of the auxiliary systems component groups followed any one of several 

approaches. One approach, documented in SER Section 3.3.2.1, reviewed AMR results for 

components that the applicant indicated are consistent with the GALL Report and require no 

further evaluation. Another approach, documented in SER Section 3.3.2.2, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and for 

which further evaluation is recommended. A third approach, documented in SER 

Section 3.3.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the auxiliary systems components is documented in SER 

Section 3.0.3.

3.3.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.3.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the auxiliary systems components:

• ASME 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

• Fire Water System Program

• Flow-Accelerated Corrosion Program

• Fuel Oil Chemistry Program

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

Program
3-295

• Lubricating Oil Analysis Program

• One-Time Inspection of ASME Code Class 1 Small-Bore Piping Program

• One-Time Inspection Program

• Open-Cycle Cooling Water System Program

• Selective Leaching of Materials Program

• Water Chemistry Program

In LRA Tables 3.3.2-1 through 3.3.2-21, the applicant summarizes AMRs for the auxiliary 

system components and indicates AMRs that it claims 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 it does not recommend further evaluation, the staff’s 

audit and review determined whether the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with Notes A through E indicating 

how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. 

The staff audited these line items to verify consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and 

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 

of some system components in the GALL Report; however, the applicant identified in the GALL 

Report a different component with the same material, environment, aging effect, and AMP as 

the component under review. The staff audited these line items to verify consistency with the 

GALL Report. The staff also determined whether the AMR line item of the different component 

was applicable to the component under review and whether the AMR was valid for the sitespecific conditions.

Note D indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL AMP. The staff audited these line items to verify consistency with 

the GALL Report. The staff verified whether the AMR line item of the different component was 
3-296

applicable to the component under review and whether the identified exceptions to the GALL 

AMPs have been reviewed and accepted. The staff also determined whether the applicant’s 

AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different or a plant-specific AMP. The staff audited 

these line items to verify consistency with the GALL Report. The staff also determined whether 

the credited AMP would manage the aging effect consistently with the GALL AMP and whether 

the AMR was valid for the site-specific conditions.

The staff 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 

engineered safety features auxiliary system 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, 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 follows.

3.3.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.3.1, item 36, 37, 38, 39 and 49, the applicant states that the corresponding AMR 

items in GALL Report are not applicable to PINGP because the AMR items in the GALL 

Report are only applicable to particular components in BWR reactor designs and because 

PINGP is a Westinghouse-designed PWR facility. The staff verified that the stated AMR items in 

the GALL Report are only applicable to BWR designed facilities and are not applicable to the 

PINGP LRA.

In LRA Table 3.3.1, items 41, 62, 75, 86, 92, and 95, the applicant states that the corresponding 

AMR result lines in the GALL Report are not applicable because PINGP does not have the 

component, material, and environment combination in the Auxiliary Systems. The staff reviewed 

the documentation supporting the applicant's AMR evaluation and confirmed the applicant's 

claim that PINGP does not have the component, material, and environment combination in the 

Auxiliary Systems. Therefore, the staff agrees with the applicant's determination that the 

corresponding AMR result line in the GALL Report is not applicable to PINGP.

In LRA Table 3.3.1, item 96, the applicant states that further evaluation in LRA Section 

3.5.2.2.1.4 concluded that steel components in concrete are not susceptible to aging and do not 

require aging management. The staff noted this item applies to GALL line items IV.J-21 and 

VII.J-17, which indicates that there is no aging effect for this component type and environment, 
3-297

and therefore the component do not require an AMP. The staff agrees with the applicant in that 

this line item does not require aging management.

In LRA Table 3.3.1, items 40, 42, 44, 59, 78, and 99, the applicant states that the corresponding 

AMR result lines are not used by PINGP, and points to other items in LRA Table 3.3.1 for further 

information. The staff noted that these other items are comprised of the same components 

types and managed by the same AMPs as recommended by GALL. On the basis that the 

applicant manage the components under items 40, 42, 44, 59, 78, and 99 through the use other 

different line items, the staff agrees with the applicant's treatment of these line items.

3.3.2.1.2 Loss of Material due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-53, addresses loss of material due to general and pitting corrosion 

for carbon steel components, including manifolds, piping/fittings and tanks, with its internal 

surfaces exposed to wetted air/gas in the Waste Disposal System.

The LRA credits the PINGP AMP B2.1.22 “Inspection of Internal Surfaces in Miscellaneous

Piping and Ducting Components” to manage this aging effect for the internal surfaces of carbon 

steel valve bodies in wetted air/gas environment only. By letter dated June 5, 2009, the 

applicant amended its LRA to include the waste gas decay tanks in the scope of license 

renewal. Therefore the following components: manifolds, piping/fittings and tanks fabricated 

from carbon steel credit the PINGP AMP B2.1.22 for aging management in wetted air/gas 

environment only. The GALL Report recommends for item 3.3.1-53 that GALL AMP XI.M24, 

"Compressed Air Monitoring" to manage this aging effect. These AMR line items cite Note E, 

indicating that the AMR line items are consistent with GALL Report material, environment, and 

aging effect, but a different AMP or a plant-specific AMP is credited.

The staff noted that the component types in LRA AMR item 3.3.1-53 correspond to 

recommended AMRs in AMR item 53 in the GALL Report, Volume 1, and in AMR item VII.D-2

of the GALL Report, Volume 2 , which pertain to piping, piping components and piping elements 

in a compressed air system. The staff verified that the only PINGP components that the 

applicant had referenced to GALL AMR item VII.D-2 using a different program from the AMP 

recommended in these GALL AMR items are specific valve bodies, manifolds, piping/fittings and 

tanks in the Waste Disposal System that are fabricated from carbon steel materials. For the 

remaining auxiliary components that the applicant had referenced to AMR item 53 in the GALL 

Report, Volume 1, and in AMR item VII.D-2 of the GALL Report, Volume 2, the applicant 

credited the Compressed Air Monitoring Program to manage loss of material in the internal 

surfaces exposed to the wetted air/gas environment, which is consistent with the GALL Report

recommendations and is acceptable. The staff’s evaluation of these AMR items is given in SER 

Section 3.3.2.1. 

The staff noted that for the stated valves in the Waste Disposal System, the applicant credited 

its Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage loss of material in the internal surfaces that are exposed to a wetted air/gas 

environment. The staff noted that the wetted air/gas environment is not the same as a 

compressed air environment for which GALL AMP XI.M24 is intended to manage, and thus 

cannot be used for aging management. The staff further noted that the applicant has credited 

this program for aging management of loss of material due to crevice corrosion. The applicant 
3-298

indicates in a plant-specific note that this aging mechanism is not addressed in the GALL Report 

for this material, component and environment combination. The staff noted that loss of material 

will show evidence of material wastage on the surface regardless if the aging mechanism is 

general, pitting or crevice corrosion.

The staff reviewed the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation is documented in SER Sections 3.0.3.1.13.

The staff determined that this program credits visual inspections that will be implemented during 

periodic system and component surveillance activities or during maintenance activities when the 

internal surface is accessible for visual inspections. The staff finds that the applicant has 

provided an acceptable basis for crediting the visual examinations of the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program to manage loss of material 

in the internal surfaces of these carbon steel valve bodies, manifolds, piping/fittings and tanks

because they are equivalent to the visual examination criteria that are established in the 

"detection of aging effects” program element of GALL AMP XI.M24, “Compressed Air 

Monitoring,” for components exposed to a wetted air/gas environment and because these 

periodic visual inspections will be capable of detecting deterioration or degradation on the 

material surface that would be an indication of loss of material due to general, pitting and 

crevice corrosion.

On the basis of periodic visual inspections, the staff finds the applicant’s use of this 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 function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.3 Increased Hardness, Shrinkage and Loss of Strength due to Weathering

In LRA Table 3.3.1, item 3.3.1-61, addresses increased hardness, shrinkage and loss of 

strength due to weathering for elastomer fire barrier penetration seals exposed to outdoor air or 

uncontrolled indoor air in the Fire Protection System.

The LRA credits the PINGP AMP B2.1.14 “External Surfaces Monitoring Program,” to manage 

change in material properties due to ozone and thermal exposure and cracking due to ozone 

and thermal exposure for neoprene in the RCP oil collection components in a primary 

containment air (internal and external) environment only. The GALL Report recommends for 

item 3.3.1-61 that GALL AMP XI.M26, "Fire Protection," to manage this aging effect. These 

AMR line items cite Note E, indicating that the AMR line items are consistent with GALL Report 

material, environment, and aging effect, but a different AMP or a plant-specific AMP is credited.

The staff notes that the component type recommended by GALL item VII.G-1 is fire barrier 

penetration seals. However, the applicant referenced the RCP oil collection components when 

referencing item 3.3.1-61. The staff further notes that the applicant referenced item 3.3.1-61 of 

LRA Table 3.3.1 because there was not another applicable line item in LRA Table 3.3.1, for the 

Auxiliary Systems, which corresponded to the same combination of component type, material, 

environment, and specifically to the aging effect. The staff verified that the neoprene RCP oil 

collection components are within the Fire Protection System but are not fire barrier penetration 
3-299

seals, so the specific requirements for the inspection of fire barrier penetration seals as 

recommended by the GALL AMP XI.M26 “Fire Protection Program” are not applicable.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 

including PVC and fiberglass, and the aging effects of change in material properties and 

cracking. The staff further notes the intent of GALL AMP XI.M36 is to perform visual inspections 

of steel components for loss of material. The staff determined that additional information was 

needed on the applicant’s proposed augmentation of its program. Therefore by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including fiberglass and PVC. The applicant responded to RAI B2.1.14-1 by letter dated 

December 5, 2008, and the staff finds the applicant’s response acceptable as documented in 

the staff’s evaluation of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff noted that this program will supplement the 

visual examination with a physical manipulation in order to verify aging effects such as 

hardening, embrittlement, or gross softening are not occurring. The staff notes that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component, or by the failure of the component to return to its previous shape 

or configuration.

On the basis that the applicant will perform periodic visual inspections of the elastomeric 

components, as supplemented by a physical manipulation, and that the inspections and 

physical tests will be performed during system walkdowns at a specified frequency, the staff 

finds the applicant's use of the External Surfaces Monitoring 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 function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.1.4 Loss of Material due To Pitting, Crevice, and Microbiologically Influenced Corrosion

In LRA Table 3.3.1, item 3.3.1-80, addresses loss of material due to pitting, crevice, and 

microbiologically influenced corrosion for stainless steel components with its internal surfaces 

exposed to raw water in the Cooling Water System, Radiation Monitoring System, and Diesel 

Generators and Support System, Waste Disposal System and Water Treatment System.
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The staff noted that the applicant also referenced this item in LRA Section 3.4 for the Circulating 

Water, LRA Table 3.4.2-3. The staff noted that the applicant referenced item 3.3.1-80 in LRA 

Table 3.4.2-3 because there was not another applicable line item in LRA Table 3.4.1, for the 

Steam and Power Conversion Systems, which corresponded to the same component, material, 

environment and aging effect combination.

The staff noted that the component types in LRA AMR item 3.3.1-80 correspond to 

recommended AMRs in AMR item 80 in the GALL Report, Volume 1, and in AMR items 

VII.H2-11 and VII.H2-18 of the GALL Report, Volume 2, which pertain to copper alloy and 

stainless steel auxiliary system piping, piping components and piping elements in the 

emergency diesel generator system under internal exposure to raw water. The staff verified that 

the only PINGP components that the applicant had referenced to GALL AMR items using a 

different program from the AMP recommended in the GALL AMR items are stainless steel and 

cast austenitic stainless steel piping, piping components, and piping elements (including 

demineralizers, filter/strainer housings, flex connections, heaters, manifolds, piping/fittings, 

pump casings, restricting orifices and rupture discs, thermowells and valve bodies, etc.) in the 

Waste Disposal System, the Water Treatment System and the Circulating Water System (which 

is a steam and power conversion system) under exposure to an internal raw water environment. 

The staff noted that for the stainless steel piping, piping components, and piping elements in the 

Cooling Water System, the Radiation Monitoring System, and the Diesel Generators and 

Support System that the applicant had referenced to GALL AMR VII.H2-18, the applicant 

credited the Open-Cycle Cooling Water System Program to manage loss of material in the 

internal surfaces exposed to the wetted air/gas environment, which is consistent with the GALL 

Report recommendations and is acceptable. The staff’s evaluation of these AMR items is given 

in SER Section 3.3.2.1. 

For those stainless steel components in the Waste Disposal System, Water Treatment System, 

and Circulating Water System whose AMR items had been referenced to GALL AMR item 

VII.H2-18, the staff determined the applicant’s crediting of the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program credits periodic visual inspections and 

volumetric testing that will be performed during periodic system and component surveillance 

activities or during maintenance activities when the internal surfaces are made accessible for 

visual inspections. The staff confirmed that the program description in GALL AMP XI.M38, 

“Internal Surfaces in Miscellaneous Piping and Ducting Components,” indicates that the visual 

examinations of the program are valid for the detection of loss of material that may occur in the 

internal surfaces as a result of corrosion. The staff also noted that these visual examination 

activities are consistent with those visual examination activities that are recommended by GALL 

AMP XI.M20, “Open-Cycle Cooling Water Systems.”

Based on this review, the staff finds that the periodic visual inspections credited under the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program are 

acceptable to manage loss of material in the internal component surfaces because the visual 

examination basis credited under this AMP is consistent with the visual examination criteria that 

would be recommended under GALL AMP XI.M20, “Open-Cycle Cooling Water Systems,” and 

because the GALL recommendation in GALL AMP XI.M38, “Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” indicates that this type of program may be used to manage 
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loss of material by corrosion in internal piping surfaces. The staff reviewed the ability of the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage loss of material due to corrosion in internal piping and piping elements and the staff’s 

evaluation of this AMP is given in SER Section 3.0.3.1.13.

The staff also verified that the design of the PINGP auxiliary systems does include copper alloy 

components, but noted that the applicant had aligned its AMR items for these component to 

AMR item 81 in Table 3 of the GALL Report, and to AMR item VII.C1-9, which is an AMR item in 

the GALL report for copper alloy service water piping components that is analogous and has 

identical aging management recommendations to those in GALL AMR item VII.H2-11 for copper 

diesel generator piping components. The staff’s evaluation of the AMRs for these copper alloy 

components is given in SER Section 3.3.2.1.5.

On the basis that the applicant will perform periodic visual inspections and volumetric testing 

during periodic system and component surveillance activities or during maintenance activities, 

the staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.5 Loss Of Material Due To Pitting, Crevice, And Microbiologically Influenced Corrosion

And Fouling

LRA Table 3.3.1, item 3.3.1-81 addresses loss of material due to pitting, crevice, and MIC and 

fouling for copper alloy components with its internal surfaces exposed to raw water in the 

Cooling Water System, Station and Instrument Air System, and Diesel Generators and Support 

System, Waste Disposal System and Water Treatment System, Circulating Water System and 

Turbine Generator and Support. In addition, the applicant amended its LRA to include 

components in Heating System, LRA Table 3.3.2-11, to reference LRA Table 3.3.1, item 3.3.1-

81. By letter dated April 6, 2009, the applicant amended its LRA to include components in 

Diesel Generators and Support System, LRA Table Table 3.3.2-8, to reference LRA Table 3.3.1, 

item 3.3.1-81.

For those copper alloy components in the systems mentioned above whose AMR items had 

been referenced to GALL AMR item VII.C1-9, the staff determined the applicant’s crediting of 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program

credits periodic visual inspections and volumetric testing that will be performed during periodic 

system and component surveillance activities or during maintenance activities when the internal 

surfaces are made accessible for visual inspections. The staff confirmed that the program 

description in GALL AMP XI.M38, “Internal Surfaces in Miscellaneous Piping and Ducting 

Components,” indicates that the visual examinations of the program are valid for the detection of 

loss of material that may occur in the internal surfaces as a result of corrosion. The staff also 

noted that these visual examination activities are consistent with those visual examination 

activities that are recommended by GALL AMP XI.M20, “Open-Cycle Cooling Water Systems.” 

Based on this review, the staff finds that the periodic visual inspections credited under the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components
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Program are acceptable to manage loss of material in the internal component surfaces because 

the visual examination basis credited under this AMP is consistent with the visual examination 

criteria that would be recommended under GALL AMP XI.M20, “Open-Cycle Cooling Water 

Systems,” and because the GALL recommendation in GALL AMP XI.M38, “Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” indicates that this type of program may be 

used to manage loss of material by corrosion in internal piping surfaces. The staff reviewed the 

ability of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program to manage loss of material due to corrosion in piping components and piping elements

surfaces and the staff’s evaluation of this AMP is given in SER Section 3.0.3.1.13.

On the basis that the applicant will perform periodic visual inspections and volumetric testing 

during periodic system and component surveillance activities or during maintenance activities, 

the staff concludes that the applicant has demonstrated that he effects of aging for these 

components will be adequately managed so that their intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.6 Loss Of Material due to Pitting, Crevice, Galvanic, and Microbiologically Influenced

Corrosion and Fouling

In LRA Table 3.3.1, item 3.3.1-82, addresses loss of material due to pitting, crevice, galvanic, 

and MIC corrosion and fouling for copper heat exchanger components (i.e., heat exchanger 

tubes and other components) in the Control Room and Miscellaneous Area Ventilation System, 

Cooling Water System, Diesel Generators and Support System, Primary Containment 

Ventilation System, Station and Instrument Air System, Waste Disposal System, and Fire 

Protection System whose surfaces are exposed either internally or externally to a raw water 

environment. By letter dated December 5, 2008, the applicant amended its LRA to include 

components in Heating System, LRA Table 3.3.2-11, to reference LRA Table 3.3.1, item 3.3.1-

82. By letter dated January 20, 2009, the applicant amended its LRA to include components in 

Turbine Generator and Support Systems to reference LRA Table 3.3.1-82.

The staff noted that the referenced AMR items for the copper alloy heat exchanger components 

in the Waste Disposal System are not in the scope of an open-cycle cooling water system that is 

tied to the ultimate heat-sink, as described in GL 89-13, and thus, are not within the scope of 

GALL AMP XI.M20, "Open-Cycle Cooling Water System." During its review, the staff also noted 

that, in the stated AMR items for the cooper alloy heat exchanger components and heaters in 

the Waste Disposal System and Heating System, the applicant indicated that the Internal 

Surfaces in Miscellaneous Piping and Ducting Components is used to manage the external 

surfaces of the components that are exposed to the raw water environment. However, the staff 

noted that, for these components that are exposed to the raw water environment, the applicant 

credited a program that will implement visual inspections of internal component surfaces. 

Therefore, by letter dated December 18, 2008, the staff issued RAI 3.3.2-20-01 to the applicant 

and requested that the applicant clarify why a program crediting visual inspection of the internal 

component surfaces had been credited for aging management of component surfaces that are 

exposed to an external raw water environment.

By letter dated January 20, 2009, the applicant responded to RAI 3.3.2-20-01. In this response, 

the applicant stated these components that credit this program in a raw water environment are 
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heat exchanger tubes and tubesheets. The applicant further stated that the internal and external 

environments are assigned based on the side of the heat exchanger tubes and tubesheets that 

is exposed to the environment. However, the applicant clarified that these components (tubes 

and tubesheets) are located internally to the heat exchanger shells and that is why this program 

is credited for aging management. The staff verified that the applicant used an equivalent aging 

management basis to evaluate the components whose internal and external heat exchanger 

surfaces were exposed to a raw water environment because the surfaces are exposed to 

identical material and environmental conditions. On the basis of its review, the staff finds that 

the applicant has provided an acceptable basis for crediting the Inspection of Internal Surfaces 

in Miscellaneous Piping and Ducting Components Program to manage loss of material in the

external surfaces of the copper alloy heat exchanger tube and tubesheets in the Waste Disposal 

System raw water because: (1) the copper alloy material-raw water environmental combination 

for these externals surfaces is the same as those referenced in GALL AMR VII.C1-3 for internal 

surfaces, (2) these surfaces are really located internal to the shells of these heat exchangers, 

(3) the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program implements visual examinations of internal metallic piping and ducting surfaces to 

monitor for loss of material that may occur as a result of corrosion-based aging mechanism and 

(4) thus use of the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is a valid program to credit for managing of loss of material due to 

corrosion in the copper alloy heat exchanger tubes and tubesheets of the Waste Disposal 

System that are exposed to raw water. The staff reviewed the ability of the applicant’s 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program to 

manage loss of material in the internals surfaces of metallic components and its evaluation is 

documented in SER Section 3.0.3.1.13.

For those copper alloy heat exchanger components in the Fire Protection System whose AMR 

items had been referenced to GALL AMR item VII.C1-3, the staff determined the applicant’s 

crediting of the Fire Water System Program will credit (upon its enhancement, as indicated in 

the LRA B2.1.16) periodic visual examination and volumetric testing of the fire protection system 

components. The staff confirmed that the program description in GALL AMP XI.M27, “Fire 

Water System,” indicates that the volumetric examinations of the program are valid for the 

detection of loss of material that may occur in the internal surfaces as a result of corrosion. The 

staff also noted that these volumetric examination activities are more stringent than the visual 

examination activities recommended by GALL AMP XI.M20, “Open-Cycle Cooling Water 

Systems.” Based on this assessment, the staff finds that it is acceptable to credit the inspections 

of the Fire Water System Program in lieu of those that would be implemented if the Open-Cycle 

Cooling Water Program were used for aging management because the program will implement 

at least the visual examination that would be recommended for implementation under GALL 

AMP XI.M20, “Open-Cycle Cooling Water,” and potential volumetric examinations of the Fire 

Protection Heat Exchanger Components if they are accessible for ultrasonic testing (a 

volumetric examination technique) transducers. 

The staff also noted that the GALL AMP XI.M20, “Open-Cycle Cooling Water,” if it were used for 

these Fire Protection System heat exchanger components, would recommend that a chemical 

treatment be implemented as part of the preventive actions and a test program be implemented 

to verify heat transfer capabilities. The staff issued RAI 3.3.2.9-2 by letter dated

February 20, 2009, and asked the applicant to confirm whether or not the Fire Water System 
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Program includes any chemical treatment and heat transfer testing activities, and if not, justify 

why these activities are not credited for aging management.

In its letter dated February 26, 2009, in response to RAI 3.3.2.9-2, the applicant stated the 

following:

“The Fire Water System Program is used in lieu of the Open-Cycle Cooling 

Water System Program to manage aging of Fire Protection (FP) System 

components that are exposed to a raw water environment other than open-cycle 

cooling water. For LRA Table 3.3.2-9, Auxiliary Systems - Fire Protection System 

– Summary of Aging Management Evaluation, on Pages 3.3-198, 199 and 200, 

for copper alloy heat exchanger components and heat exchanger tubes in an 

internal environment of raw water, the components are exposed to untreated 

Mississippi River (ultimate heat sink) water. Although the Mississippi River 

(ultimate heat sink) is the source for both the Cooling Water (CL) System and the 

FP System, these FP System components are supplied by the Fire Water subsystem which is not managed by the Open-Cycle Cooling Water System 

Program. Therefore, PINGP has appropriately credited the Fire Water System 

Program.

In addition, the affected components, 121 Motor Driven Fire Pump Enclosure 

Cooler and the 122 Diesel Driven Fire Pump Heat Exchanger, are not safety 

related components and are not within the scope of NRC Generic Letter 89-13, 

“Service Water System Problems Affecting Safety-Related Equipment."

Preventive actions associated with the PINGP Fire Water System Program 

include periodic flushing, performance testing, and inspections. Heat transfer 

degradation of the 121 Motor Driven Fire Pump Enclosure Cooler is managed by 

periodic inservice flushing during the 121 Motor Driven Fire Pump Performance 

Test. Heat transfer degradation of the 122 Diesel Driven Fire Pump Heat 

Exchanger is managed by periodically monitoring and recording the engine 

operating temperature during the 122 Diesel Driven Fire Pump Performance 

Test.”

The staff reviewed the applicant response and finds the response acceptable because: (1) the 

copper alloy heat exchanger components are supplied by the fire water sub-system which is not 

managed by the Open-Cycle Cooling Water System Program; (2) the motor driven fire pump 

enclosure cooler and diesel driven fire pump heat exchangers are nonsafety-related and are not 

included in the scope of GL 89-13; and (3) the Fire Water System Program includes preventive 

actions such as periodic flushing, which would remove and clean any fouling, and periodic 

performance testing and inspection, which will monitor the performance of the heat exchangers 

and visually inspect for loss of material. Based on this review, the staff finds that the Fire Water 

System Program will adequately manage the aging effect of loss of material due to pitting, 

crevice, galvanic, and microbiologically-influenced corrosion, and fouling of copper alloy heat 

exchanger components and heat exchanger tubes in an internal environment of raw water 

through the period of extended operation because the program credits appropriate periodic 

performance testing and condition monitoring activities to monitor for loss of material in the heat 

exchanger components as a result of the corrosion-based mechanisms mentioned in this 
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sentence, as well as periodic flushes of the system, which should mitigate loss of material from 

occurring in the components.

Based on the programs identified, and response to staff’s RAI, the staff concludes that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.1.7 Reduction of Heat Transfer due to Fouling

In LRA Table 3.3.2-9, page 3.3.1-199, Fire Protection System, for copper alloy heat exchanger 

tubes exposed to raw water in an internal environment of raw water, PINGP has credited the

Fire Water System Program to manage the aging effects of reduction of heat transfer. 

The staff noted that the applicant applied Note E to this item. The applicant referenced LRA 

Table 3.3-1, item 3.3.1-83 and GALL Report item VII.C1-6. The staff reviewed the AMR results 

lines that reference Note E and determines that the component type, material, environment, and 

aging effect are consistent with the GALL Report. However, the staff noted that where the GALL 

Report recommends AMP XI.M20, "Open-Cycle Cooling Water," the applicant proposed using 

the Fire Water System Program.

The staff noted that the GALL AMP recommends chemical treatment as part of the preventive 

actions and a test program to verify heat transfer capabilities. The staff issued RAI 3.3.2.9-2 by 

letter dated February 20, 2009, requesting the applicant to confirm that the Fire Water System 

Program includes chemical treatment and heat transfer testing capabilities, and if not, to justify 

how the Fire Water System Program manages the aging effect of reduction of heat transfer.

In its letter dated February 26, 2009, in response to RAI 3.3.2.9-2, the applicant stated the 

following:

The Fire Water System Program is used in lieu of the Open-Cycle Cooling Water 

System Program to manage aging of Fire Protection (FP) System components 

that are exposed to a raw water environment other than open-cycle cooling 

water. For LRA Table 3.3.2-9, Auxiliary Systems - Fire Protection System –

Summary of Aging Management Evaluation, on Pages 3.3-198, 199 and 200, for 

copper alloy heat exchanger components and heat exchanger tubes in an 

internal environment of raw water, the components are exposed to untreated 

Mississippi River (ultimate heat sink) water. Although the Mississippi River 

(ultimate heat sink) is the source for both the Cooling Water (CL) System and the 

FP System, these FP System components are supplied by the Fire Water subsystem which is not managed by the Open-Cycle Cooling Water System 

Program. Therefore, PINGP has appropriately credited the Fire Water System 

Program.

In addition, the affected components, 121 Motor Driven Fire Pump Enclosure 

Cooler and the 122 Diesel Driven Fire Pump Heat Exchanger, are not safety 

related components and are not within the scope of NRC Generic Letter 89-13, 

“Service Water System Problems Affecting Safety-Related Equipment."
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Preventive actions associated with the PINGP Fire Water System Program 

include periodic flushing, performance testing, and inspections. Heat transfer 

degradation of the 121 Motor Driven Fire Pump Enclosure Cooler is managed by 

periodic in-service flushing during the 121 Motor Driven Fire Pump Performance 

Test. Heat transfer degradation of the 122 Diesel Driven Fire Pump Heat 

Exchanger is managed by periodically monitoring and recording the engine 

operating temperature during the 122 Diesel Driven Fire Pump Performance 

Test.

The staff reviewed the applicant response and finds the response acceptable because (1) the 

copper alloy heat exchanger components are supplied by the fire water sub-system which is not 

managed by the Open-Cycle Cooling Water System Program; (2) the motor driven fire pump 

enclosure cooler and diesel driven fire pump heat exchangers are nonsafety-related and are not 

included in the scope of GL 89-13; and (3) the Fire Water System Program includes preventive 

actions such as periodic flushing, which would remove and clean any fouling, and periodic 

performance testing and inspection, which the applicant will monitor the performance of the heat 

exchangers and visually inspect for fouling. Based on this review, the staff finds that the Fire 

Water System Program will adequately manage the aging effect of reduction of heat transfer 

due to fouling of copper alloy heat exchanger components and heat exchanger tubes in an 

internal environment of raw water through the period of extended operation.

Based on the programs identified and the response to staff’s RAI, the staff concludes that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.1.8 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 

LRA Table 3.3.1, AMR item 3.3.1-51, addresses loss of material due to pitting, crevice, and 

galvanic corrosion, for copper alloy piping, piping components, piping elements, and heat 

exchanger components exposed to closed cycle cooling water in the auxiliary systems. For 

these components, the GALL Report recommends managing the aging effect with the ClosedCycle Cooling Water System Program (GALL AMP XI.M21).

LRA Tables 3.3.2-3, 3.3.2.5, 3.3.2-8, 3.3.2-9, 3.3.2-11, 3.3.2-13 and 3.3.2-20 all include AMR 

results referring to LRA Table 3.3.1, AMR item 3.3.1-51 for heat exchanger components, heat 

exchanger tubes, heaters, piping/fittings, and valve bodies made of copper alloy, brass or 

bronze, in an environment of treated water (closed-cycle cooling water). For all of these AMR 

result lines, the applicant stated that the aging effects of loss of material due to pitting and 

crevice corrosion will be managed by the Closed-Cycle Cooling Water System Program.

The staff noted that the component, material, environment, aging effect, and AMP for these 

components are consistent with the recommendation in the GALL Report, Volume 1, Table 3, 

AMR item 51 and with GALL items VII.C2-4, VII.E1-2, VII.F1-8, VII.F1-15, and VII.H2-8. The 

staff noted that the applicant listed the aging effect/mechanisms as loss of material due to pitting 

and crevice corrosion; however, the staff also noted that the applicant did not list loss of material 

due to galvanic corrosion as an applicable aging effect/mechanism for these components.
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In a letter dated December 18, 2008, the staff issued RAI 3.3.1-51-01 asking the applicant why 

loss of material due to galvanic corrosion had not been listed as an applicable aging effect/ 

mechanism for these components.

The applicant responded to the RAI in a letter dated January 20, 2009. In the response, the 

applicant stated that analysis tools provided by EPRI reports, Westinghouse generic topical 

reports and other industry guidelines were the primary means to identify and evaluate aging 

effects. The applicant further stated that OE, both industry and plant-specific, was also used. 

The applicant stated that copper and copper alloys are in the middle of the galvanic series and 

will preferentially corrode when coupled with more cathodic metals such as stainless steel; 

however, the rate of corrosion is expected to be low due to the small electrochemical potential 

difference. The applicant also stated that OE at their plant has not identified galvanic corrosion 

concerns with copper and copper alloys.

The staff reviewed the applicant’s RAI response and noted that the response provides a 

reasonable technical basis, confirmed by plant-specific OE, for the applicant to expect that loss 

of material due to galvanic corrosion is not an expected aging effect/mechanism for copper 

components exposed to treated water in systems at their plant. The staff further noted that the 

same inspection activities that detect loss of material due to pitting and crevice corrosion will 

also detect loss of material due to galvanic corrosion, if it should occur. Because the applicant 

has a reasonable expectation that loss of material due to galvanic corrosion will not occur, and 

because the applicant provides inspection for loss of material due to pitting and crevice 

corrosion, which would also detect indications of galvanic corrosion, the staff finds that the 

applicant response resolves the issues raised in RAI 3.3.1-51-01.

Based on the programs identified and the applicant’s response to RAI 3.3.1-51-01, the staff 

finds that the effects of aging for these components have been appropriately identified and will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.1.9 Loss of Material Due to General, Pitting, Crevice, and Microbiologically Influenced

Corrosion, and Fouling, and Lining/Coating Degradation 

LRA Table 3.3.1, AMR item 3.3.1-76, addresses loss of material due to general, pitting, crevice, 

and MIC, fouling, and lining/coating degradation for steel piping, piping components, and piping 

elements (without lining/coating or with degraded lining/coating) exposed to raw water in the 

auxiliary systems. For these components, the GALL Report recommends managing the aging 

effect with the Open-Cycle Cooling Water System program (GALL AMP XI.M20).

LRA Tables 3.3.2-5, 3.3.2-6, 3.3.2-7, 3.3.2-8, 3.3.2-11, 3.3.2-20, and 3.3.2-21 all include AMR 

results referring to LRA Table 3.3.1, AMR item 3.3.1-76, for which the applicant proposes using 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program. 

The components are 1) humidifiers in the control room and miscellaneous area ventilation 

system; 2) piping and fittings in the cooling water system; 3) piping and fittings in the diesel 

generator and screen house ventilation system; 4) tanks, valve bodies, and pipe/fittings in the 

diesel generators and support system; 5) filter/strainer housings, manifolds, piping and fittings, 

pump casings, thermowells, and valve bodies in the waste disposal system; 6) demineralizers, 

eductors, filter/strainer housings, heaters, manifolds, piping and fittings, pump casings, and 
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valve bodies in the water treatment system; and 7) piping/fittings, pump casings, thermowells, 

traps and valve bodies in the heating system. For these AMR results, the material is carbon 

steel, cast iron or galvanized steel, the environment is raw water and aging effect is loss of 

material due to general, pitting, crevice, galvanic corrosion, or MIC. The AMR results refer to 

GALL item VII.C1-19. GALL item VII.C1-19 has the same material, environment, and aging 

effect combination, but recommends aging management using the Open-Cycle Cooling Water 

System Program. For these AMR results, the applicant cited generic Note E, indicating that the 

result is consistent with the GALL Report for material, environment, and aging effect, but a 

different or a plant-specific AMP is credited. The staff noted that the applicant has 

conservatively included the aging effect of loss of material due to galvanic corrosion when 

referencing AMR item 3.3.1-76; the addition of this aging effect will be discussed in the staff’s 

evaluation below.

The staff noted that in LRA Table 3.3.1, AMR item 3.3.1-76, the discussion column states that 

the AMR results are consistent with the GALL Report and that the aging effect is managed by 

the Open-Cycle Cooling Water System Program. The staff noted that the discussion column 

was either incorrect or misleading because the Open-Cycle Cooling Water System Program is 

used to manage the aging effect for only some of the AMR result lines referring to AMR 

item 3.3.1-76.

In a letter dated December 18, 2008, the staff issued RAI 3.3.1-76-01 asking the applicant why 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program, 

rather than the Open-Cycle Cooling Water System Program, is used for the components 

associated with these AMR items; and asking the applicant to revise the discussion in LRA 

Table 3.3.1, AMR item 3.3.1-76, to clarify that two different AMPs are used.

The applicant responded in a letter dated January 20, 2009. In that response the applicant 

stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program is used in lieu of the Open-Cycle Cooling Water System program where the 

components managed are not exposed to an open-cycle cooling water environment. The 

applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is credited for managing the aging effects for components exposed to 

waste water or potable water environments in the control room and miscellaneous area 

ventilation, the cooling water, the diesel generator and screen house ventilation, the diesel 

generator and support, the waste disposal, and the water treatment systems. The applicant also 

stated that in LRA Table 3.3.1, AMR item 3.3.1-76, the discussion column should include 

reference to the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The applicant revised the discussion column entry for LRA Table 3.3.1, 

AMR item 3.3.1-76 to read as follows: “Consistent with NUREG-1801. This aging effect is 

managed with the Open-Cycle Cooling Water System Program. In some cases, the Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is credited in 

lieu of the Open-Cycle Cooling Water System Program.”

The staff finds the applicant’s change to Table 3.3.1, AMR item 3.3.1-76, acceptable because it 

resolves issues raised in RAI 3.3.1-76-01 by correcting a previous omission in the discussion 

column. The staff’s evaluation of the applicant’s basis for crediting the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Component Program for aging management is 

presented in the paragraphs that follow.
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The staff verified that the only piping, piping components and piping elements that the applicant 

aligned to GALL item VII.C1-19 are fabricated from steel materials (carbon steel, cast iron, or 

galvanized steel). The staff noted that those AMR line items are not in the scope of an opencycle cooling water system as described in GL 89-13 and not associated with the ultimate heat 

sink, and therefore are not within the scope of GALL AMP XI.M20. The staff noted that the 

applicant referenced GALL item VII.C1-19 because the material, environment and AERM 

corresponded. For those AMR line items that are in-scope of the GL 89-13, the staff confirmed 

that for the same combination of component, material, environment and aging effect requiring 

management the applicant has credited the Open-Cycle Cooling Water System Program. The 

staff reviewed the Open-Cycle Cooling Water System Program and its evaluation is 

documented in SER Section 3.0.3.1.20.

During its review of the applicant’s AMR line items, the staff noted that the applicant has 

credited the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program with managing the aging effect of loss of material due to galvanic corrosion. The staff 

noted that in the GALL Report, item VII.C1-19 is not applicable for this aging mechanism.

However the staff confirmed in the LRA that the applicant is managing loss of material due to 

general, pitting, or crevice corrosion, and MIC, fouling, and lining/coating degradation that are 

applicable based on the recommendations of the GALL Report item VII.C1-19. The staff noted 

that the applicant is conservatively managing the additional aging mechanism of galvanic 

corrosion. The staff finds it acceptable for the applicant to include the aging effect of loss of 

material due to galvanic corrosion to the scope of this GALL AMR line item because the 

applicant is managing all aging mechanisms recommended by the GALL Report in addition to

galvanic corrosion.

The staff’s review of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation are documented in SER Section 3.0.3.1.13.

The staff determined that this program which includes periodic visual inspections and volumetric 

testing, when appropriate, during periodic system and component surveillance activities or 

during maintenance activities when the internal surface is accessible for visual inspections are 

adequate to manage loss of material for steel piping, piping components and piping elements 

exposed to raw water (internal) addressed by this AMR. The staff further noted that these 

activities are consistent with those recommended by GALL AMP XI.M20. The staff also 

determined that the periodic visual inspections will be capable of detecting deterioration or 

degradation on the material surface that would be an indication of loss of material.

On the basis of periodic visual inspections, the staff finds the applicant’s use of this program 

acceptable because the visual examination credited under the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program for these components are consistent 

with the visual examinations that would be recommended under GALL AMP XI.M20 if the raw 

water source for the components was tied to the ultimate heat sink. The staff concludes that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that their intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).
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3.3.2.1.10 Loss of Material Due to General, Pitting, Crevice, Galvanic, and Microbiologically 

Influenced Corrosion, and Fouling 

LRA Table 3.3.1, AMR item 3.3.1-77, addresses loss of material due to general, pitting, crevice, 

galvanic corrosion and by MIC, and fouling for steel heat exchanger components exposed to 

raw water in auxiliary systems. For these components, the GALL Report recommends 

managing the aging effect with the Open-Cycle Cooling Water System program (GALL 

AMP XI.M20).

LRA Table 3.3.2-20 includes AMR results for carbon steel heat exchanger components in the 

waste disposal system referring to LRA Table 3.3.1, AMR item 3.3.1-77, for which the applicant 

proposes using the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. For these AMR results, the environment is raw water, and the aging 

effect is loss of material due to general, pitting, crevice, or galvanic corrosion, and by MIC. The 

AMR results refer to GALL item VII.C1-5, which recommends aging management using the 

Open-Cycle Cooling Water System Program. For these AMR results, the applicant cited generic 

Note E, indicating that the result is consistent with the GALL Report for material, environment, 

and aging effect, but a different or plant-specific AMP is credited.

The staff noted that the discussion column in LRA Table 3.3.1, AMR item 3.3.1-77, states that 

the AMR results are consistent with the GALL Report and that the aging effect is managed by 

the Open-Cycle Cooling Water System Program. The staff also noted that the discussion further 

states that in some cases, the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program or the Fire Water System Program is credited in lieu of the OpenCycle Cooling Water System Program. The staff reviewed all AMR results lines referring to LRA 

Table 3.3.1, AMR item 3.3.1-77, but was unable to find any AMR results where the Fire Water 

System Program was credited.

In a letter dated December 18, 2008, the staff issued RAI 3.3.1-77-01 asking the applicant to 

identify the AMR results line in the LRA that refer to AMR item 3.3.1-77 and where the Fire 

Water System Program is credited to provide aging management. The RAI also asked the 

applicant to explain why the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program or the Fire Water System Program (if actually used) are credited in lieu of 

the Open-Cycle Cooling Water System Program for some of these AMR result lines.

The applicant responded in a letter dated January 20, 2009. In that response the applicant 

stated that in LRA Table 3.3.1, AMR item 3.3.1-77, reference to the Fire Water System Program 

for providing aging management is incorrect, and that the reference to the Fire Water System 

Program should be deleted. The applicant revised the discussion column entry for LRA 

Table 3.3.1, AMR item 3.3.1-77 to read as follows: “Consistent with NUREG-1801. This aging 

effect is managed with the Open-Cycle Cooling Water System Program. In some cases, the 

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program is 

credited in lieu of the Open-Cycle Cooling Water System Program.”

The applicant also stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program is used in lieu of the Open-Cycle Cooling Water System Program 

where the components managed are not exposed to an open-cycle cooling water environment. 

The applicant stated that for LRA Table 3.3.1, AMR item 3.3.1-77, the Inspection of Internal 
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Surfaces in Miscellaneous Piping and Ducting Components Program is credited for components 

exposed to a waste water environment in the waste disposal system.

The staff finds the applicant’s change to Table 3.3.1, AMR item 3.3.1-77, acceptable because it 

corrects an error. The staff’s evaluation of the applicant’s use of the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Component Program in lieu of the Open-Cycle 

Cooling Water System Program is presented below.

The staff reviewed all components evaluated under AMR item 3.3.1-77 where the Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Component Program is credited for aging 

management in lieu of the Open-Cycle Cooling Water System Program, which is the AMP 

recommended in the GALL Report for aging management. The staff confirmed that the only 

components in this category are carbon steel heat exchanger components in a raw water 

environment in the waste disposal system.

The staff noted that those AMR line items are not in the scope of an open-cycle cooling water 

system as described in GL 89-13 and not associated with the ultimate heat sink, and therefore 

are not within the scope of GALL AMP XI.M20. The staff noted that the applicant referenced 

GALL item VII.C1-5 because the material, environment and aging effect requiring management 

corresponded. For those AMR line items that are in-scope of the GL 89-13, the staff confirmed 

that for the same combination of component, material, environment and aging effect requiring 

management the applicant has credited the Open-Cycle Cooling Water System Program. The 

staff reviewed the Open-Cycle Cooling Water System Program and its evaluation is 

documented in SER Section 3.0.3.1.20.

The staff noted during its review that several of the heat exchanger components are exposed to 

an external environment of raw water; however, the applicant credits a program that will perform 

visual inspections of the internal surfaces for aging management. Therefore by letter dated 

December 18, 2008, the staff issued RAI 3.3.2-20-01, requesting the applicant to clarify why a 

program that performs visual inspections of internal surfaces has been credited for aging 

management of component surfaces that are exposed to an external raw water environment. By 

letter dated January 20, 2009, the applicant responded to RAI 3.3.2-20-01, by stating that the 

components that credit this program in a raw water environment are heat exchanger tubes and 

tubesheets. The applicant further stated that the internal and external environments are 

assigned based on the side of the heat exchanger tubes and tubesheets that are exposed to the 

raw water environment. The applicant clarified that though the external surfaces of the heat 

exchanger tube and tubesheets are exposed to raw water environment, these component 

surfaces are located internally to the heat exchanger shells. Therefore, the applicant clarified 

that it was appropriate to credit this program for aging management because they would have to 

access the internals of the heat exchangers to be able to implement the inspections of this 

program credited for aging management. The applicant also clarified that the internal 

environment for the heat exchanger tubes and tubesheets are also located internally to the heat 

exchanger shells but are evaluated in other AMR items of the LRA.

The staff noted the applicant’s response to RAI 3.3.2-20-01, but was of the opinion that 

additional information was needed to clarify exactly how the visual examination of these tubes 

and tubesheets would be accomplished. Therefore, in a letter dated December 18, 2008, the 

staff issued RAI 3.3.2-20-02. In this RAI, the staff requested that the applicant justify how a 
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visual inspection would be capable of detecting loss of material in these components in those 

regions that are not directly visible or accessible (for example the bend of a heat exchanger 

tube). The applicant responded to RAI 3.3.2-20-02 in a letter dated January 20, 2009. In this 

response, the applicant stated that this program is credited for aging management of heat 

exchanger components that include tubes, shells, tubesheets and channelheads. The applicant 

further stated the activities that will be performed as part of this program to detect degradation 

of these carbon steel components include periodic visual inspections during surveillance and 

maintenance activities, when the heat exchangers are opened up for access.

The staff noted that, in its response to RAI 3.3.2-20-01, the applicant stated that it will choose 

the inspection locations based on conditions that are susceptible to the aging effects of concern.

The staff further noted that the applicant’s inspection will monitor parameters such as rust, 

discoloration, scale/deposits, pitting and surface discontinuities which are indications that loss of 

material and degradation are occurring. Based on the applicant’s response to RAI 

3.3.2-20-01, the staff noted the applicant evaluated the internal and external environments of 

these heat exchanger tubes and components separately because these components are 

physically internal to the heat exchanger. The staff confirmed in LRA Table 3.3.2-20 that the 

applicant evaluated the external side and internal side of the heat exchanger tubes and 

components, separately. Furthermore, the staff noted that the applicant is crediting a visual 

inspection on the external side of these heat exchanger tubes and components, which will be 

capable of identifying indications of loss of material on all areas of the heat exchanger tubes, 

including the bends of the components. The staff confirmed that for the internal side of these 

heat exchanger tubes and components the applicant has credited the GALL recommended 

program for aging management. On the basis of its review, the staff finds the applicant’s 

response to RAI 3.3.2-20-01 acceptable because (1) the visual inspections of these 

components are at locations that have conditions that are susceptible to the aging effect of loss 

of material and (2) a visual inspection of these components will be capable of identifying 

evidence that may be indicative of degradation and loss of material.

The staff reviewed the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation are documented in SER Section 3.0.3.1.13.

The staff’s evaluation is documented in SER Section 3.0.3.1.13. This program includes periodic 

visual inspections and volumetric testing, when appropriate, during periodic system and 

component surveillance activities or during maintenance activities when the internal surface is 

accessible for visual inspections. Therefore, the staff finds it to be adequate to manage loss of 

material for metallic exchanger components that are exposed to raw water (external and 

internal) addressed by this AMR. Thus, the staff noted that the condition monitoring activities 

credited under the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program are consistent with the visual examinations that are recommended in

GALL AMP XI.M20, “Open-Cycle Cooling Water System,” and that the periodic visual 

inspections will be capable of detecting deterioration or degradation on the material surface that 

would be an indication of loss of material.

The staff finds the applicant’s use of this program acceptable because the visual examination of

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

for these components are consistent with the visual examinations recommended by GALL AMP 

XI.M20. The staff finds this program acceptable also because it is identified by the GALL Report 

as an appropriate program for managing loss of material in internal metallic component 
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surfaces. The staff concludes that the applicant has demonstrated that the effects of aging for 

these components will be adequately managed so that their intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.3.2.1.11 Loss of Material Due to Pitting and Crevice Corrosion 

LRA Table 3.3.1, AMR item 3.3.1-78, addresses loss of material due to pitting and crevice 

corrosion for stainless steel, nickel-alloy, and copper alloy piping, piping components, and 

piping elements exposed to raw water in auxiliary systems. For these components GALL Report 

recommends managing the aging effect with the Open-Cycle Cooling Water System Program 

(GALL AMP XI.M20).

The staff noted that the discussion column in LRA Table 3.3.1, AMR item 3.3.1-78, states that 

the AMR evaluation line was not used and refers to line 3.3.1-79 for further discussion. The staff 

also noted that the discussion column for AMR item 3.3.1-79 did not include any discussion of 

AMR item 3.3.1-78, although the discussion column in 3.3.1-78 suggested that it would. 

In a letter dated December 18, 2008, the staff issued RAI 3.3.1-78-01 asking the applicant to 

revise the statement in the discussion column of AMR item 3.3.1-78 or to add a discussion of 

AMR item 3.3.1-78 into the discussion column of AMR item 3.3.1-79.

The applicant responded in a letter dated January 20, 2009. The applicant stated that in LRA 

Table 3.3.1, the discussion column for LRA AMR item 3.3.1-78 is intended to provide a 

convenient link to clarify that the material, environment, aging effect combination in line 3.3.1-78 

is applicable, but is evaluated under a different line (3.3.1-79). The applicant further stated that 

AMR item 3.3.1-78 is not used, but that no additional detail is needed in the line 3.3.1-79 

discussion column.

The staff notes that the applicant’s response does not make the change requested in the RAI.

However, the response does clarify that components that might have been evaluated under 

Table 3.3.1, AMR item 3.3.1-78 are included in the evaluation of Table 3.3.1, item 3.3.1-79.

The staff reviewed all components included in LRA Table 3.3.1, AMR item 3.3.1-79, and noted 

that the component materials are stainless steel or CASS. The staff also noted that stainless 

steel is one of the materials called out in LRA Table 3.3.1, AMR item 3.3.3-78. The staff noted 

that for both AMR item 3.3.1-78 and AMR item 3.3.1-79 the environment is raw water. The staff 

further noted that the aging effect/mechanisms identified for AMR item 3.3.1-78 are a subset of 

those identified for AMR item 3.3.1-79 because AMR item 3.3.1-79 lists fouling in addition to 

loss of material due to pitting and crevice corrosion, which are the only aging effect/mechanisms 

listed for AMR item 3.3.1-78. The staff also noted that, for both AMR items, GALL AMR items 78 

and 79 in Table 3 of the GALL Report, Volume 1, both recommend that the Open-Cycle Cooling 

Water System Program be credited to manage loss of material in the stainless steel piping, 

piping component and piping element surfaces that are exposed to raw water. Because the 

components, material and environment at the applicant’s plant are listed in both AMR item 

3.3.1-78 and in AMR item 3.3.1-79, and because the aging effects in AMR item 3.3.1-78 are 

also included in AMR item 3.3.1-79, and the recommended AMP is the same in both AMR result 

lines, the staff finds that it is acceptable for the applicant to indicate that AMR item 3.3.1-78 is 
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not used for the PINGP LRA and that instead the applicant evaluates loss of material in these 

CASS components in LRA AMR item 3.3.1-79.

Because the applicant’s RAI response states that Table 3.3.1, AMR item 3.3.1-78, is not used 

and the discussion column is simply providing a link to Table 3.3.1, AMR item 3.3.1-79, where 

the same component, material environment and aging effect combinations are evaluated, the 

staff finds that the applicant’s response resolved all issues raised in RAI 3.3.1-78-01. The staff 

also finds it acceptable for the applicant to designate Table 3.3.1, AMR item 3.3.1-78, as not 

used because all components that might have been included in this AMR result line have been 

included and evaluated in Table 3.3.1, AMR item 3.3.1-79.

Based on the program identified and the applicant’s response to RAI 3.3.1-78-01, the staff finds 

that the effects of aging for these components have been appropriately identified and will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.3.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the auxiliary system components and provides 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 MIC

• loss of material due to general, pitting, crevice, MIC and fouling

• loss of material due to pitting and crevice corrosion

• loss of material due to pitting, crevice, and galvanic corrosion

• loss of material due to pitting, crevice, and MIC

• loss of material due to wear

• loss of material due to cladding breach

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.3.2.2. The staff’s review of the applicant’s 

further evaluation follows.
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3.3.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.3.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must 

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.7.4 and 4.3 documents 

the staff’s review of the applicant’s evaluation of this TLAA.

3.3.2.2.2 Reduction of Heat Transfer Due to Fouling 

LRA Section 3.3.2.2.2 addresses reduction of heat transfer due to fouling for stainless steel heat 

exchanger tubes exposed to treated water in the auxiliary systems. For this component, 

material, environment and aging effect combination, the GALL Report recommends aging 

management using the Water Chemistry Program (GALL AMP XI.M2) and the One-Time 

Inspection Program (GALL AMP XI.M32). In LRA Section 3.3.2.2.2 the applicant stated that the 

GALL Report line items referring to the SRP-LR and GALL Report, Volume 1, AMR item 3.3.1-3, 

are applicable to BWR systems only. In LRA Table 3.3.1, AMR item 3.3.1-3, the applicant also 

stated that the AMR result line is not applicable to PWRs, but is applicable to the auxiliary 

systems in BWRs. The applicant designated the AMR result line as not applicable because the 

applicant’s plant is a PWR.

The staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2, which 

states that reduction of heat transfer due to fouling may occur for stainless steel heat exchanger 

tubes exposed to treated water. The SRP-LR states that the existing program relies on control 

of water chemistry to manage reduction of heat transfer due to fouling. In addition, the GALL 

Report recommends that the effectiveness of the water chemistry control program should be 

verified to ensure that reduction of heat transfer due to fouling is not occurring.

SRP-LR Section 3.3.2.2.2, AMR item 3 in Table 3 of the GALL Report, Volume 1, and GALL 

AMR items VII.A4-4 and VII.E3-6, are applicable for stainless steel heat exchanger tubes 

exposed to treated water in the BWR spent fuel pool cooling and cleanup systems and in BWR 

reactor water cleanup systems.

The staff noted that the AMR items in the GALL Report that refer to SRP-LR Section 3.3.2.2.2 

are for heat exchanger tubes in a BWR spent fuel pool cooling system and in a reactor water 

cleanup system, which is a BWR system, not a PWR system. The staff also noted that the 

Closed-Cycle Cooling Water System Program provides management for the aging effect of 

reduction of heat transfer due to fouling in stainless steel heat exchangers exposed to treated 

water in the applicant’s auxiliary systems. On the basis that the systems listed in the GALL 

Report are applicable only for BWRs and the applicant manages the aging effect of reduction of 

heat transfer due to fouling with the Closed-Cycle Cooling Water System Program for heat 

exchangers in the auxiliary systems, the staff finds the applicant’s determination that LRA 

Table 3.3.1, AMR item 3.3.1-3, is not applicable to be acceptable.

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking 

 (1) LRA Section 3.3.2.2.3.1 addresses GALL AMR items VII.E2.4-a, VII.E2.1-a, VII.E2.2-a, 

and VII.E2.3-a, on the management of cracking due to SCC of stainless steel and 

stainless clad steel heat exchanger components exposed to a treated water > 60 °C 

(>140 °F) environment. In this section of the LRA, the applicant states that [SRP-LR]
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Section 3.3.2.2.3.1 is not applicable to PINGP because this item is applicable to BWR 

plants only.

SRP-LR Section 3.3.2.2.3.1 states that cracking due to SCC may occur in stainless steel 

and stainless clad steel heat exchanger components exposed to treated water greater 

than 60 °C (>140 °F) environment.

The staff noted this item is not applicable to PINGP because PINGP is a PWR plant and 

does not have BWR Standby Liquid Control System, which contains the component type 

specified in LRA Section 3.3.2.2.3.1. On this basis, the staff finds that the criteria in 

SRP-LR 3.3.2.2.3.1 do not apply to PINGP.

 (2) LRA Section 3.3.2.2.3.2 addresses cracking due to SCC for stainless steel and stainless 

steel clad heat exchanger components exposed to treated water >60oC (>140oF) in the 

auxiliary systems. For this component, material, environment and aging effect 

combination, the GALL Reports recommends that a plant-specific AMP be evaluated. In 

LRA Section 3.3.2.2.3.2 the applicant stated that the [SRP-LR] and the GALL Report 

indicate Table 3.3.1, AMR item 3.3.1-5, is applicable to both PWR and BWR nuclear 

power plants. However, the applicant also stated that the GALL Report, Volume 2, line 

items VII.E-3 and VII.3-19, which refer to this AMR result line, are applicable only for 

BWR systems. Similarly, in the discussion column in LRA Table 3.3.1, AMR item 3.3.1-5, 

the applicant stated that the line item is not applicable to PWRs, but is applicable to the 

auxiliary systems in BWRs. The applicant designated the AMR result line as not 

applicable because the applicant’s plant is a PWR.

The staff reviewed LRA Section 3.3.2.3.2 against the criteria in SRP-LR 

Section 3.3.2.2.3.2, which states that cracking due to SCC could occur in stainless steel 

and stainless clad steel heat exchanger components exposed to treated water greater 

than 60°C (>140°F).

SRP-LR Section 3.3.2.2.3.2, AMR item 5 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR items VII.E3-3 and VII.E3-19, are applicable to stainless steel and steel with 

stainless steel cladding heat exchanger components in BWR spent fuel cleanup and 

cooling systems and to stainless steel regenerative heat exchanger components in BWR 

reactor water cleanup systems.

The staff noted that the AMR item in the GALL Report are for components in a reactor 

water cleanup system, which is a BWR system. Therefore, the staff finds it acceptable 

that the applicant has designated AMR item 3.3.1-5 to be not applicable.

 (3) LRA Section 3.3.2.2.3.3 addresses cracking due to SCC in stainless steel diesel engine 

exhaust piping, piping components and piping elements exposed to diesel exhaust. The 

applicant stated that the Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program will manage this aging effect in stainless steel internal 

surfaces exposed to diesel exhaust.

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 can occur in stainless steel diesel engine exhaust 
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piping, piping components, and piping elements exposed to diesel exhaust can occur 

and recommends further evaluation of a plant-specific AMP to ensure this aging effect is 

adequately managed.

The GALL Report, under item VII.H2-1 recommends that a plant-specific program be 

credited to manage cracking due to stress corrosion cracking for diesel engine exhaust 

piping, piping components and piping elements in the Auxiliary Systems. 

The staff verified that only flex connections align to GALL AMR VII.H2-1 for the Auxiliary

System – Diesel Generators and Support System that are fabricated from stainless steel 

materials are applicable to PINGP that credit this program.

The staff’s review of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program and its evaluation are documented in SER 

Sections 3.0.3.1.13. The applicant stated that this is a new PINGP program that will 

perform periodic visual inspection of the internal surfaces of components to manage loss 

of material due to several mechanisms.

However, the staff noted that a visual inspection alone may not be capable of identifying 

the aging effect of cracking due to stress corrosion cracking in components fabricated 

from stainless steel. Therefore, by letter dated November 5, 2008, the staff issued RAI 

B2.1.22-1, in which it asked the applicant to identify and justify the inspection techniques 

that will be used by this program to manage cracking due to stress corrosion cracking or 

provide an appropriate program that will be capable of managing this aging effect. By 

letter dated December 5, 2008, the applicant responded to the RAI by stating the 

inspection techniques that will be utilized to detect this aging effect are either a visual 

inspection with a magnified resolution as described in 10 CFR 50.55a(b)(2)(xxi)(A) or an 

ultrasonic inspection method. The staff further notes that the inspection method 

described in 10 CFR 50.55a(b)(2)(xxi)(A) is an enhanced VT-1 inspection technique and 

that GALL AMP XI.M32 recommends the use of an enhanced VT-1 or ultrasonic 

inspection technique as an acceptable means to detect cracking due to stress corrosion 

cracking. The staff notes that the inspection techniques described by the applicant will 

be performed by qualified personnel in accordance with PINGP procedures and 

processes. The staff’s evaluation of RAI B2.1.22-1 is documented in SER Section 

3.0.3.1.13.

Based on these clarifications, the staff noted that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program includes enhanced VT-1 or 

ultrasonic inspection of the internal surfaces of components during periodic system and 

component surveillance activities or during maintenance activities when the internal 

surface becomes accessible for inspections to detect aging effects that could result in a 

loss of the component's intended function. The staff finds this to be an acceptable basis 

for managing cracking due to SCC of the components because the program includes 

enhanced VT-1 visual examination activities that are consistent with the

recommendations in the GALL Report, and these activities will be adequate to any 

cracking that may occur in stainless steel diesel engine exhaust piping, piping 

components and piping elements as a result of SCC.
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Based on the program identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.3.2.2.3.3 criterion. For those line 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.4 Cracking Due to Stress Corrosion Cracking and Cyclic Loading 

The staff reviewed LRA Section 3.3.2.2.4 against the following criteria in SRP-LR 

Section 3.3.2.2.4:

 (1) LRA Section 3.3.2.2.4.1 addresses cracking due to SCC and cyclic loading in stainless 

steel non-regenerative heat exchanger components exposed to treated borated water 

> 60oC (>140oF) in the auxiliary systems. The applicant stated that the aging effect will 

be managed by the Water Chemistry Program in combination with the One-Time 

Inspection Program. For applicable AMR results in LRA Table 3.3.2-2, the applicant 

cited generic Note E, indicating that the result is consistent with the GALL Report for 

material, environment and aging effect, but a different AMP is credited or that the GALL 

Report identifies a plant-specific AMP. 

The staff reviewed LRA Section 3.3.2.2.4.1 against the criteria of SRP-LR Section 

3.3.2.2.4.1, which states that cracking due to SCC and cyclic loading may occur in 

stainless steel PWR non-regenerative heat exchanger components exposed to treated 

borated water greater than 60°C (>140°F) in the chemical and volume control system. 

This SRP-LR section states that the existing AMP relies on monitoring and control of 

primary water chemistry in PWRs to manage the aging effects of cracking due to SCC. 

However, the SRP-LR section clarifies that control of water chemistry does not preclude 

cracking due to SCC and cyclic loading, and therefore recommends that the 

effectiveness of the water chemistry control program be verified to ensure that cracking 

is not occurring. The SRP-LR section identifies that 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 managed adequately, and that an

acceptable verification program is to include temperature and radioactivity monitoring of 

the shell side water and eddy current testing of the tubes.

SRP-LR Section 3.3.2.2.4.1, AMR item 7 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR item VII.E1-9, are applicable to stainless steel non-regenerative heat 

exchanger components exposed to treated borated water greater than 60°C (>140°F) in 

the chemical and volume control system (PWR). The staff’s aging management 

recommendations in these GALL AMR items are the same as those discussed in SRPLR Section 3.3.2.2.4.1.

In a letter dated December 18, 2008, the staff issued RAI AMR-3.3.2.2.4.1-01 asking the 

applicant to provide additional details about the methodology it proposed to use for 

examination of the non-regenerative heat exchangers and previous OE with these 

components.
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The applicant provided a response to RAI AMR-3.3.2.2.4.1-01 in a letter dated January 

20, 2009, and further clarification of that response in a letter dated February 26, 2009. In 

its response and subsequent clarification, the applicant stated that the non-regenerative 

heat exchangers addressed by this AMR item are the letdown and the excess letdown 

heat exchangers in the chemical and volume control system. The applicant also included 

in its response discussion of the chemical and volume control system’s regenerative 

heat exchangers which are addressed by AMR item 8 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR item VII.E1-5. The applicant stated that the Water Chemistry 

Program and the One-Time Inspection Program will be used to manage the aging effect 

of cracking due to SCC in these stainless steel components exposed to treated borated 

water greater than 60°C (>140°F). The applicant further stated that the One-Time 

Inspection Program was selected in lieu of eddy current testing of the non-regenerative 

heat exchanger tubes and that the One-Time Inspection Program uses enhanced visual 

(VT-1 or equivalent) and/or volumetric methods to detect cracking due to SCC. The 

applicant stated that the One-Time Inspection Program uses a representative sampling 

approach to verify that significant degradation is not occurring, and that the sampling is 

based on an assessment of material of fabrication, environment, plausible aging effects, 

and OE. The applicant stated that the letdown and excess letdown heat exchangers are 

highly contaminated components, and that one-time Inspections of similar components 

with the equivalent material and environment combinations provides confirmation of the 

effectiveness of the Water Chemistry Program without requiring unnecessarily high 

personnel exposure. The applicant further stated that temperature and radioactivity 

monitoring of these non-regenerative heat exchangers is provided by installed plant 

instrumentation, and that the instrumentation provides points that are monitored on the 

plant’s process computer. 

The staff noted that the applicant’s proposed management for the aging effect of 

cracking due to SCC in the non-regenerative heat exchangers is as recommended in the 

GALL Report; however, it does not include the recommended eddy current testing of the 

heat exchanger tubes. The staff noted, however, that for GALL Report, Volume 1, Table 

3, item 90, the AMP recommended to manage the aging effect of cracking in stainless 

steel piping exposed to treated borated water greater than 60°C (>140°F) is the Water 

Chemistry Program, alone. The staff also noted that for GALL Report, Volume 1, Table 

4, AMR item 14, the AMPs recommended to manage the aging effect of cracking in 

stainless steel piping exposed to treated water greater than 60°C (>140°F) are the Water 

Chemistry Program augmented by the One-Time Inspection Program for verification of 

water chemistry effectiveness. In this regard, the staff noted that the One-Time 

Inspection Program accomplishes verification of Water Chemistry Program effectiveness 

by crediting volumetric or enhanced VT-1 inspection techniques to confirm that cracking 

has not initiated in the components or, if it has, that it is progressing very slowly . The 

staff finds that the applicant has provided an acceptable basis for crediting the Water 

Chemistry Program and the One-Time Inspection Program because it is in accordance 

with the recommendations in GALL Report, Volume 1, Table 4, AMR item 14 and 

because GALL AMP XI.M32, “One-Time Inspection,” indicates that volumetric 

examination methods or enhanced VT-1 visual examination methods are acceptable 

methods for the detection of cracking.
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In its supplemental response dated February 26, 2009, the applicant stated that cracking 

due to cyclic loading is not an applicable aging mechanism because of the design and 

operation of the regenerative and non-regenerative heat exchangers in the chemical and 

volume control system. The applicant stated that a full fatigue analysis was not required 

for these heat exchangers; however, the Westinghouse design specification for these 

components included requirements to demonstrate that the heat exchangers satisfied all 

conditions of ASME Code Section III, Paragraph N-415.1, “Vessels Not Requiring 

Analysis for Cyclic Operation,” for the transient conditions specified. The applicant stated 

that through compliance with N-415.1 (a) through (f), which consider pressure 

fluctuations, thermal cycling, and mechanical loading, the allowable peak stress limit is 

satisfied for these heat exchangers so that an analysis for cyclic operation is not 

required. The applicant stated that from a design standpoint, the regenerative heat 

exchangers, the letdown heat exchangers and the excess letdown heat exchangers are 

not subject to cracking due to cyclic loading. The applicant further stated that the 

regenerative heat exchangers and letdown heat exchangers typically remain in service 

throughout the entire operating cycle and that the excess letdown heat exchanger is 

normally isolated during plant operation and is put into service only when the normal 

letdown path is not available. The applicant stated that as a result of these operating 

practices, the heat exchangers are not subject to repeated thermal and pressure cycling, 

and that, therefore, from an operational standpoint, cracking due to cyclic loading does 

not apply to these heat exchangers. As part of its supplemental response, the applicant 

revised LRA Table 3.3.1, items 3.3.1-7 and 3.3.1-8, to state that cracking due to cyclic 

loading is not an applicable aging effect; the applicant also revised LRA Sections 

3.3.2.2.4, item 1 and item 2, in their entirety to include summary presentation of the 

additional information described above.

The staff noted that in the applicant’s response, both a design basis and an operational 

basis was provided to support a conclusion that cracking due to cyclic loading is not 

applicable for the regenerative heat exchangers and for the letdown and the excess 

letdown heat exchangers exposed to treated borated water greater than 60°C (>140°F) 

in the chemical and volume control system. Because the applicant has provided an 

adequate technical basis to exclude cracking due to cyclic loading as an applicable 

aging mechanism for these heat exchangers, the staff finds that this aging mechanism is 

not applicable for the subject heat exchanges.

For reasons stated above, the staff finds the applicant’s proposed aging management of 

cracking due to SCC to be acceptable. The staff also finds the applicant’s determination 

that cracking due to cyclic loading is not applicable to be acceptable. On these bases, 

including the applicant’s response and further clarification related to RAI AMR3.3.2.2.4.1-01, the staff finds the applicant’s AMR results to be acceptable.

Based on the programs identified and on the applicant’s response to RAI AMR3.3.2.2.4.1-01 in a letter dated January 20, 2009, and further clarification in a letter dated 

February 26, 2009, the staff concludes that the applicant’s programs meet SRP-LR

Section 3.3.2.2.4 criteria. For those AMR 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 
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intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.3.2.2.4.2 addresses cracking due to SCC and cyclic loading in 

stainless steel regenerative heat exchanger components exposed to treated water 

>60oC (>140oF) in the auxiliary systems. The applicant stated that the aging effect will be 

managed by the Water Chemistry Program in combination with the One-Time Inspection 

Program.

The staff reviewed LRA Section 3.3.2.2.4.2 against the criteria of SRP-LR Section 

3.3.2.2.4.2, which states that cracking due to SCC and cyclic loading may occur in 

stainless steel PWR regenerative heat exchanger components exposed to treated 

borated water greater than 60°C (>140°F). This SRP-LR section states that the existing 

AMP relies on monitoring and control of primary water chemistry in PWRs to manage the 

aging effects of cracking due to SCC. However, the SRP-LR section clarifies that control 

of water chemistry does not preclude cracking due to SCC and cyclic loading and 

therefore recommends that the effectiveness of the water chemistry control program 

should be verified to ensure that cracking is not occurring. The SRP-LR section identifies 

that 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 managed adequately.

SRP-LR Section 3.3.2.2.4.2, AMR item 8 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR item VII.E1-5, applicable to stainless steel heat exchanger components 

exposed to treated borated water greater than 60°C (>140°F) in the chemical and 

volume control system (PWR). The GALL Report credits use of the Water Chemistry 

Program for PWR Primary Water and recommends that the AMP be augmented by a 

plant-specific verification program.

The staff noted that the applicant proposes to use the One-Time Inspection Program to 

verify effectiveness of the Water Chemistry Program to mitigate the aging effect of 

cracking in both the non-regenerative heat exchangers (AMR item 3.3.1-7) and in the 

regenerative heat exchangers (AMR item 3.3.1-8). The staff asked the applicant to 

address examination of both heat exchanger types in RAI AMR-3.3.2.2.4.1-01, which is 

discussed in SER Section 3.3.2.2.4.1. The staff’s evaluation of the applicant’s response 

is provided in that SER section.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides mitigation for cracking due to SCC in stainless steel 

components. The staff reviewed the applicant’s One-Time Inspection Program. The 

staff’s evaluation of this program, which is documented in SER Section 3.0.3.1.18 found 

that the One-Time Inspection Program is adequate to detect the presence or note the 

absence of cracking due to SCC for components within its scope. The staff confirmed 1) 

that the applicant is crediting AMPs as recommended in GALL AMR item VII.E1-5,

2) that the Water Chemistry Program implements chemistry related activities to mitigate 

degradation caused by cracking due to SCC, and 3) that the One-Time Inspection 

Program is identified in the GALL Report as an acceptable program to provide 
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verification of the effectiveness of the Water Chemistry Program to mitigate cracking due 

to SCC in stainless steel components. The staff finds the applicant’s AMR results 

acceptable because the AMPs credited with aging management are consistent with the 

guidance in SRP-LR Section 3.3.2.2.4.2 and in GALL AMR item VII.E1-5.

Based on the programs identified and on the applicant’s response to RAI AMR3.3.2.2.4.1-01, as evaluated in SER Section 3.3.2.2.4.1 and applied to the staff’s 

evaluation in this SER section, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4.2 criteria. For those AMR items that apply to LRA Section 

3.3.2.2.4.2, 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 function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (3) LRA Section 3.3.2.2.4.3 addresses cracking due to SCC and cyclic loading in stainless 

steel high pressure pump casing in PWR chemical and volume control system. The 

applicant stated that the aging effect will be managed by the Water Chemistry Program 

in combination with the One-Time Inspection Program. For the AMR result line showing 

the One-Time Inspection Program, the applicant cites generic Note E, indicating that the 

result is consistent with the GALL Report for material, environment, and aging effect, but 

a different AMP is credited or that the GALL Report identifies a plant-specific AMP.

The staff reviewed LRA Section 3.3.2.2.4.3 against the criteria of SRP-LR Section 

3.3.2.2.4.3, which states that cracking due to SCC and cyclic loading may occur in 

stainless steel pump casing for the PWR high-pressure pumps in the chemical and 

volume control system. The SRP-LR states that the existing AMP relies on 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 managed 

adequately.

SRP-LR Section 3.3.2.2.4.3, AMR item 9 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR item VII.E1-7, are applicable to stainless steel high pressure pump casings 

exposed to treated borated water in the chemical and volume control system (PWR). 

The GALL Report recommends that a plant-specific AMP be credited to manage 

cracking of these pump casings as a result of SCC or cyclical loading. 

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides mitigation for cracking due to SCC in stainless steel 

components. The staff also reviewed the applicant’s One-Time Inspection Program. The 

staff’s evaluation of this program, which is documented in SER Section 3.0.3.1.18, found 

that the One-Time Inspection Program is consistent with GALL AMP XI.M32, “One-Time 

Inspection,” and that the program is adequate to detect the presence or note the 

absence of cracking due to SCC or cyclic loading for components within its scope. The 
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staff noted that the GALL Report states that a one-time inspection program is an 

acceptable program to verify effectiveness of a mitigative AMP (e.g., the Water 

Chemistry Program). Thus, the staff confirmed that: (1) the applicant is crediting the 

Water Chemistry Program as recommended in GALL AMR item VII.E1-7; and (2) that 

the applicant is verifying effectiveness of the Water Chemistry by use of the One-Time 

Inspection Program, which the GALL Report states is an acceptable program for 

verification of Water Chemistry Program effectiveness. Based on this review, the staff 

finds the applicant’s AMR results acceptable because the AMRs credited for aging 

management of cracking in these stainless steel pump casing are consistent with the 

guidance in SRP-LR Section 3.3.2.2.4.3 and with the staff’s recommended AMR position 

established in GALL AMR item VII.E1-7.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.4 criteria. For those line items that apply to LRA Section 

3.3.2.2.4.3, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (4) LRA Section 3.3.2.2.4.4 states that stress corrosion cracking of high strength steel 

closure bolting in an air with steam or water leakage environment is not managed for 

auxiliary systems at PINGP because they do not exist at PINGP. Furthermore, the 

applicant states that the conditions leading to SCC, including use of lubricants containing 

molybdenum disulfide, and high yield strength materials (>150 ksi) do not exist at 

PINGP. The staff reviewed the applicant’s justification, and verified that although there 

are bolts with yield strength of 130 ksi in the Nuclear Steam Supply System component 

supports, and are conservatively treated by the applicant as high strength bolts, there 

are no high strength bolts in the plants auxiliary systems. Furthermore, the staff 

reviewed LRA Section B2.1.6 “Bolting Integrity Program” and found that the program 

includes preventive measures for lubricant control in accordance with the 

recommendations in EPRI NP-5769. Therefore, the staff finds that this is acceptable 

because it adequately considers the GALL Report recommendations for the Bolting 

Integrity Program. On this basis, the staff finds the criterion in SRP-LR Section 

3.3.2.2.4.4 does not apply.

3.3.2.2.5 Hardening and Loss of Strength Due to Elastomer Degradation 

The staff reviewed LRA Section 3.3.2.2.5 against the following criteria in SRP-LR 

Section 3.3.2.2.5:

 (1) LRA Section 3.3.2.2.5.1 addresses hardening and loss of strength due to elastomer 

degradation that could occur in seals and components of HVAC and other plant systems 

exposed to plant indoor air-uncontrolled (internal or external), primary containment air, 

raw water and treated water environments. The applicant stated that these aging effects 

are managed with the External Surfaces Monitoring Program. In a letter dated

January 15, 2009, the applicant added additional line items as a result of its response to 

RAI 2.3.3.5-04. The staff noted that these line items are flex connections made of 

ethylene propylene diene monomer (EPDM) and are managed with the External 
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Surfaces Monitoring Program. The External Surfaces Monitoring Program includes 

periodic system inspections and walk downs to visually inspect accessible external 

surfaces for degradation. The applicant also stated that the External Surfaces Monitoring 

Program is credited with managing aging effects of internal surfaces where the external 

surfaces are subject to the same environment or stressor as the internal surfaces such 

that that external condition is representative of the internal surface condition. The 

applicant stated that this program assures the intended function of affected components 

will be maintained during the period of extended operation. The applicant further stated 

that it added change in material properties due to ultraviolet radiation and ozone 

exposure and, cracking due to ultraviolet radiation and ozone exposure for non-metallic, 

both elastomers and plastics (PVC, fiberglass, neoprene, rubber, etc.), in these 

environments.

The staff reviewed LRA Section 3.3.2.2.5.1 and the line items included in letter dated 

January 15, 2009, against the following criteria in SRP-LR Section 3.3.2.2.5.1, which 

states that hardening and loss of strength due to elastomer degradation may occur in 

elastomer seals and components of heating and ventilation systems exposed to air -

indoor uncontrolled (internal/external). The GALL Report recommends further evaluation 

of a plant-specific AMP to ensure that these aging effects are adequately managed.

The staff reviewed the External Surfaces Monitoring Program in SER Section 3.0.3.2.5.

The program is a condition monitoring program that implements inspections and 

walkdowns of systems and components within the scope of the program. The staff 

confirmed that in the applicant’s response to RAI B2.1.14-1, which was submitted in a 

letter dated December 5, 2008, the applicant amended the scope of its External 

Surfaces Monitoring Program, as applied to the management of cracking, hardening, 

and loss of strength in elastomeric components to include physical manipulation testing 

in addition to the visual examinations that will be performed on these components. On 

the basis that the applicant will perform periodic inspections and walk downs of the 

elastomeric components with appropriate physical manipulation tests, the staff 

determines that External Surfaces Monitoring Programs is an acceptable program to 

credit for the management of hardening and loss of strength in these elastomeric 

components through the period of extended operation.

Based on the program identified above, the staff concludes that the applicant’s program 

meets the SRP-LR Section 3.3.2.2.5.1 criteria. For those line 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) LRA Section 3.3.2.2.5.2 addresses hardening and loss of strength due to elastomer 

degradation that could occur in elastomer lining exposed to treated water or treated 

borated water. The applicant stated that it does not have any elastomer-lined 

components in the Spent Fuel Pool Cooling and Cleanup System that are exposed to 

treated water or treated borated water.
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The staff reviewed LRA Section 3.3.2.2.5.2 against the criteria in SRP-LR Section 

3.3.2.2.5.2, which states that hardening and loss of strength due to elastomer 

degradation may occur in elastomer linings of the filters, valves, and ion exchangers in 

spent fuel pool cooling and cleanup systems (BWR and PWR) that are exposed to 

treated water or treated borated water. The staff reviewed the UFSAR and verified that 

the components in the Spent Fuel Pool Cooling and Cleanup Systems are not lined with 

protective elastomeric materials. On the basis that the Spent Fuel Pool Cooling and 

Cleanup Systems do not include any components lined with internal elastomer linings, 

the staff finds the applicant has provided an acceptable basis for concluding that the 

guidance in SRP-LR Section 3.3.2.2.5.2 is not applicable to the LRA.

3.3.2.2.6 Reduction of Neutron-Absorbing Capacity and Loss of Material Due to General 

Corrosion 

LRA Section 3.3.2.2.6 states that reduction of neutron-absorbing capacity and loss of material 

due to general corrosion could occur in boral, boron steel spent fuel storage racks neutron 

absorbing sheets exposed to treated water, or treated borated water. In addition, the LRA states 

that PINGP does not have boral, boron steel spent fuel storage racks neutron-absorbing sheets 

exposed to treated water or treated borated water.”

LRA Table 3.3.1 line item 3.3.1-13, which pertains to Boral, states the following:

“This line item is not applicable to PINGP. PINGP does not have boral, boron 

steel spent fuel storage racks neutron-absorbing sheets exposed to treated water 

or treated borated water. Further evaluation is documented in Section 3.3.2.2.6.” 

Also in LRA Table 3.3.1 line item 3.3.1-87, which pertains to Boraflex, states the following:

“This line item is not applicable to PINGP. The UFSAR states that Boraflex 

neutron-absorbing sheet material is not credited in the spent fuel pool criticality 

analysis. Therefore since this component does not perform any intended function, 

it is not in scope of License Renewal and requires no further review.”

The staff has reviewed LRA Section 3.3.2.2.6 and Table 3.3.1 line item 3.3.1-13 and has 

confirmed that the PINGP spent fuel pool design does not utilize boral or boron steel neutron 

absorption materials in their spent fuel storage rack designs. Therefore, the staff finds that 

Section 3.3.2.2.6 and Table 3.3.1 line item 3.3.1-13 are not applicable to the applicant’s LRA

and that the applicant’s rationale is acceptable.

The staff has reviewed Table 3.3.1 line item 3.3.1-87 and in RAI 3.3.2.2.6-1 dated November 

25, 2008, asked the applicant to describe how the potential degradation of Boraflex would be 

identified in the case that material degradation may impede safe fuel handling if blistering and/or 

bulging occurs. 

In its response by letter dated December 11, 2008, the applicant provided the following:
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The spent fuel storage racks are described in the PINGP UFSAR, Section 10.2.1.

Criticality is prevented by the design of the racks which limits fuel assembly 

interaction by fixing the minimum separation between assemblies, and by 

maintaining soluble neutron poison in the spent fuel pool water. No mitigative 

strategy is required for monitoring the spent fuel pool Boraflex material used in 

the design of spent fuel storage rack fuel module assemblies. The design of the 

PINGP spent fuel storage rack fuel module assemblies allows for the release of 

gasses created by the degrading Boraflex material without degrading the 

surrounding stainless steel material.

The spent fuel storage rack fuel module assembly design at PINGP incorporates 

Boraflex which differs from the design that incorporates BoralTM. Boraflex is a 

material composed of 46% silica, 4% polydimethyl, and 50% boron carbide. The 

fuel module assemblies consist of an inner stainless steel casing, a layer of 

Boraflex neutron absorbing material, and an outer stainless steel casing. The 

inner and outer square stainless steel casings are tubular. The outer casing 

holds the Boraflex in place and is only one-quarter the thickness of the inner 

casing. The outer casing is attached to the inner casing by four spot welds at the 

top and bottom of the outer casing on each of the four sides. Thus, the outer 

casing is not leak tight. This vented cavity design allows the release of gasses 

and ingress of water to alleviate the potential for cell wall bulging as a result of 

the Boraflex material off gassing.

Industry OE indicates that Boraflex degrades over time, but the degradation 

process does not impede the ability to remove or accept fuel since the fuel 

module assembly’s open flow design allows gasses to vent safely to the spent 

fuel pool water. Bulging, blistering, or other deformation, known to occur in poorly 

vented designs, is not applicable at PINGP.

The staff has reviewed the applicant’s response to the RAI, and finds it to be acceptable since 

the racks are vented and this will prevent blistering and/or bulging to occur. Without the 

possibility of blister and/or bulging, the staff finds acceptable the applicant’s rationale that no 

mitigative strategy is necessary and that fuel handling will not be impeded.

On the basis of its review of the LRA Section 3.3.2.2.6 and Table 3.3.1 line item 3.3.1-13, the 

staff has determined that these items are not applicable to PINGP and finds the licensee’s 

rationale to be acceptable as stated above.

On the basis of its review of Table 3.3.1 line item 3.3.1-87 and the response to RAI 3.3.2.2.6-1, 

the staff has determined that a Boraflex Monitoring Program is not necessary, there is adequate 

assurance that fuel handling will not be impeded in the period of life extension and finds the 

licensee’s rationale to be acceptable as stated above as required by 10 CFR 54.21(a)(3).

3.3.2.2.7 Loss of Material Due to General, Pitting, and Crevice Corrosion 

 (1) The applicant states in LRA Section 3.3.2.2.7.1, Part I that the loss of material due to 

general, pitting, and crevice corrosion could occur in steel components exposed to 

lubricating oil. LRA Section 3.3.2.2.7.1, Part I further states that 1) this aging effect is 
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managed with a combination of the Lubricating Oil Analysis Program and the One-Time

Inspection Program 2) the Lubricating Oil Analysis Program includes periodic oil 

sampling, analysis, and evaluation and trending of results, and 3) the program maintains 

oil systems contaminants (primarily water and particulates) within acceptable limits,

thereby preserving an environment that is not conducive to degradation and the OneTime Inspection Program performs sampling inspections using NDEs techniques that 

either verify unacceptable degradation is not occurring or trigger additional actions.

The staff reviewed LRA Section 3.3.2.2.7.1, Part I 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 could occur in steel piping, piping components, and piping elements including 

the tubing, valves, and tanks in the reactor coolant pump oil collection system, exposed 

to lubricating oil (as part of the fire protection system). SRP-LR Section 3.3.2.2.7.1 

states that the existing AMP relies on the periodic sampling and analysis of lubricating oil 

to maintain contaminants within acceptable limits, thereby preserving an environment 

that is not conducive to corrosion. SRP-LR Section 3.3.2.2.7.1 further states that the 

effectiveness of lubricating oil control should be verified to ensure that corrosion is not 

occurring and one-time inspection of selected components at susceptible locations is an 

acceptable method to use to ensure that corrosion is not occurring.

SRP-LR Section 3.3.2.2.7.1, AMR item 14 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR items VII.E1-19 (Chemical and Volume Control System), VII.F1-19 (Control 

Room and Miscellaneous Area Ventilation System), VII.C1-17 (Cooling Water System, 

Water Treatment System), VII.H2-20 (Diesel Generators and Support System) and 

VII.G-22 (Fire Protection System) are applicable to loss of material due to general, 

pitting, and crevice corrosion of steel piping, piping component, and piping elements 

exposed to lubricating oil. These components are identified in LRA Table 3.3.2-2: Pump 

Casings, Tanks, LRA 3.3.2-5: Pump Casings, Piping/Fittings, LRA 3.3.2-6: 

Piping/Fittings, LRA Table 3.3.2-8: filter/strainer housings and elements, heaters, oil 

pans, piping/fittings, pump casings, tanks, thermowells, turbochargers, valve bodies; and 

LRA Table 3.3.2-9: filter/strainer housings, piping/fittings, and LRA 3.3.2-21: Pump 

Casings, Piping/Fittings.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively 

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting and crevice corrosion and 2) will perform one-time inspections of select steel 

piping, piping components, piping elements, and tanks exposed to lubricating oil for loss 

of material due to general, pitting, and crevice corrosion to verify the effectiveness of the 

Lubricating Oil Analysis Program in applicable Auxiliary Systems. The GALL Report 

states that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item VII.C1-17, VII.E1-19, VII.G-22, VII.F1-19 and VII.H2-20 and the applicant is 

verifying effectiveness of the Lubricating Oil Analysis Program with the elements of the 

One-Time Inspection Program, which the GALL Report states is an acceptable program 

to verify the Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds 
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that, based on the programs identified above, the applicant has met the criteria of 

SRP-LR Section 3.3.2.2.7.1. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7.1 criteria. For those line items that are addressed in LRA 

Section 3.3.2.2.7.1, Part I, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

LRA Section 3.3.2.2.7.1, Part II refers to LRA Section 3.3.2.2.7.1, Part I. LRA

Section 3.3.2.2.7.1, Part I states that 1) the loss of material due to general, pitting, and 

crevice corrosion could occur in steel components exposed to lubricating oil, 2) this 

aging effect is managed with a combination of the Lubricating Oil Analysis Program and 

the One-Time Inspection Program, 3) the Lubricating Oil Analysis Program includes 

periodic oil sampling, analysis, and evaluation and trending of results, 4) the program 

maintains oil systems contaminants (primarily water and particulates) within acceptable 

limits, thereby preserving an environment that is not conducive to degradation, and 

5) the One-Time Inspection Program performs sampling inspections using NDE

techniques that either verify unacceptable degradation is not occurring or trigger 

additional actions. 

The staff reviewed LRA Section 3.3.2.2.7.1, Part I against the criteria in SRP-LR Section 

3.3.2.2.7.1. SRP-LR Section 3.3.2.2.7.1, invokes AMR item 15 in Table 3 of the GALL 

Report, Volume 1, and GALL AMR item VII.G-26 (Fire Protection System) as applicable 

to loss of material due to general, pitting, and crevice corrosion of steel piping, piping 

component, and piping elements including the tubing, valves, and tanks in the reactor 

coolant pump oil collection system, exposed to lubricating oil. These components are 

identified in LRA Table 3.3.2-9: RCP Oil Collection components.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively 

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting and crevice corrosion and 2) will perform one-time inspections of select steel 

piping, piping components, piping elements, and tanks exposed to lubricating oil for loss 

of material due to general, pitting, and crevice corrosion to verify the effectiveness of the 

Lubricating Oil Analysis Program in applicable Auxiliary systems. The GALL Report 

states that one-time inspection is acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item VII.G-26 and the applicant is verifying effectiveness of the Lubricating Oil 

Analysis Program with the elements of the One-Time Inspection Program, which the 

GALL Report states is an acceptable program to verify the Lubricating Oil Analysis 

Program effectiveness. Therefore, the staff finds that, based on the programs identified 

above, the applicant has met the criteria of SRP-LR Section 3.3.2.2.7.1. 
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7.1 criteria. For those line items that are addressed in LRA 

Section 3.3.2.2.7.1, Part II, the staff determines that the LRA is consistent with the GALL 

Report and that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

The applicant states in LRA Section 3.3.2.2.7.1, Part III that loss of material due to 

general, pitting, and crevice corrosion could occur in the steel reactor coolant pump oil 

collection system tank exposed to lubricating oil. LRA Section 3.3.2.2.7.1, Part III further 

states that 1) this aging effect is managed with a combination of the Lubricating Oil 

Analysis Program and the One-Time Inspection Program, 2) the Lubricating Oil Analysis 

Program includes periodic oil sampling, analysis, and evaluation and trending of results 

3) the program maintains oil systems contaminants (primarily water and particulates) 

within acceptable limits, thereby preserving an environment that is not conducive to 

degradation and 4) the One-Time Inspection Program performs sampling inspections 

using NDE techniques that either verify unacceptable degradation is not occurring or 

trigger additional actions.

SRP-LR Section 3.3.2.2.7.1, invokes AMR item 16 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR item VII.G-27 (Fire Protection System) as applicable to loss 

of material due to general, pitting, and crevice corrosion of steel piping, piping 

component, and piping elements including the tubing, valves, and tanks in the reactor 

coolant pump oil collection system, exposed to lubricating oil. These components are 

identified in LRA Table 3.1.2-2: Tanks.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively 

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting and crevice corrosion and 2) will perform one-time inspections of steel reactor 

coolant pump oil collection system tanks exposed to lubricating oil for loss of material 

due to general, pitting, and crevice corrosion to verify the effectiveness of the Lubricating 

Oil Analysis Program in applicable Auxiliary systems. The GALL Report states that onetime inspection is an acceptable method to verify the effectiveness of a mitigative AMP

such as the Lubricating Oil Analysis Program. The staff noted that the applicant is 

crediting the Lubricating Oil Analysis Program as recommended in GALL AMR item 

VII.G-27 and the applicant is verifying effectiveness of the Lubricating Oil Analysis 

Program with the elements of the One-Time Inspection Program, which the GALL Report 

states is an acceptable program to verify the Lubricating Oil Analysis Program 

effectiveness. Therefore, the staff finds that, based on the programs identified above, the 

applicant has met the criteria of SRP-LR Section 3.3.2.2.7.1. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.7.1 criteria. For those line items that are addressed in LRA 

Section 3.3.2.2.7.1, Part III, 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 
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adequately managed so that the intended function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

(2) LRA Section 3.3.2.2.7.2 indicates that the item addressed by SRP-LR 3.3.2.2.7.2 is a 

BWR item, and therefore not applicable to PINGP.

SRP-LR Section 3.3.2.2.7.2 states that loss of material due to general, pitting, and 

crevice corrosion of steel piping components, and piping elements exposed to treated 

water in the BWR reactor water cleanup and shutdown cooling systems.

The staff notes that PINGP is a PWR, and therefore does not have BWR reactor water 

cleanup and shutdown cooling systems. On this basis, the staff finds the criteria in SRPLR 3.3.2.2.7.2 do not apply to PINGP.

 (3) LRA Section 3.3.2.2.7.3 addresses loss of material due to general (steel only), pitting 

and crevice corrosion in steel and stainless steel diesel engine exhaust piping, piping 

components and piping elements exposed to diesel exhaust. The applicant stated that 

the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program will manage this aging effect in steel and stainless steel internal surfaces 

exposed to diesel exhaust.

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 in steel and stainless steel diesel engine exhaust piping, piping 

components and piping elements exposed to diesel exhaust can occur and recommends 

further evaluation of a plant-specific AMP to ensure this aging effect is adequately 

managed.

The GALL Report, under item VII.H2-2 recommends that a plant-specific program be

credited to manage loss of material due to general (steel only), pitting and crevice 

corrosion for stainless steel and steel piping, piping components and piping elements in 

the Auxiliary System. 

The staff verified that only piping, fittings, muffler, silencers and flex connections that 

align to GALL AMR VII.H2-2 for the Auxiliary System –Diesel Generator and Support 

System that are fabricated from steel and stainless steel materials are applicable to 

PINGP that credit this program.

The staff’s review of the applicant’s Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program and its evaluation are documented in SER 

Sections 3.0.3.1.13. The applicant stated that this is a new PINGP program that will 

perform periodic visual inspections of the internal surfaces of components to manage 

loss of material due to general (steel only), pitting and crevice corrosion. The staff finds 

that the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program performs visual inspections of internal surfaces of components 

during periodic system and component surveillance activities or during maintenance 

activities when the internal surface becomes accessible for visual inspections to detect 

aging effects that could result in a loss of the component's intended function. The staff 
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also determined that the periodic visual inspections will be capable of detecting 

deterioration or degradation on the material surface that would be an indication of loss of 

material due to general, pitting and crevice corrosion.

Based on the program identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.3.2.2.7.3 criteria. For those line items that are addressed in 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.8 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

The applicant states in LRA Section 3.3.2.2.8 that the loss of material due to general, pitting, 

crevice corrosion, and MIC could occur for steel piping, piping components, and piping elements 

buried in soil regardless of the presence of pipe coatings or wrappings and that this aging effect 

is managed with the Buried Piping and Tanks Inspection Program. LRA Section 3.3.2.2.8 further 

states that the Buried Piping and Tanks Inspection Program includes preventive measures to 

mitigate degradation (e.g., coatings and wrappings required by design) and visual inspections of 

external surfaces of buried piping components, when excavated, for evidence of coating 

damage and degradation and these inspections either verify that unacceptable degradation is 

not occurring or trigger additional actions.

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 corrosion, and MIC could occur for 

steel (with or without coating or wrapping) piping, piping components, and piping elements 

buried in soil. SRP-LR Section 3.3.2.2.8 further states that 1) the buried piping and tanks 

inspection program relies on industry practice, frequency of pipe excavation, and OE to manage 

the effects of loss of material from general, pitting, and crevice corrosion and MIC and 2) the 

effectiveness of the buried piping and tanks inspection program should be verified to evaluate 

an applicant’s inspection frequency and OE with buried components, ensuring that loss of 

material is not occurring.

SRP-LR Section 3.3.2.2.8 invokes AMR item 19 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR items VII.H1-9 (Diesel Fuel Oil System), VII.C1-18 (Open-Cycle Cooling Water 

System), and VII.G-25 (Fire Protection System) as applicable to loss of material due to general, 

pitting, crevice, and MIC of steel piping, piping component, piping elements, and tanks exposed 

to soil. These components are identified in LRA Tables 3.3.2-6, 3.3.2-10 and 3.3.2-17: Piping 

and Fittings, and LRA Table 3.3.2-9: Piping and Fittings, Valve Bodies. These components are 

identified in LRA Table 3.3.2-10: Piping and Fittings, and LRA Table 3.3.2-9: Piping and Fittings, 

Valve Bodies.

The staff reviewed LRA Appendix B, Sections B2.1.8, “Buried Piping and Tanks Inspection” in 

SER Section 3.0.3.1.7 and found that this program provides focused or opportunistic 

excavations and inspections for general, pitting, crevice, and MIC of buried steel piping and 

tanks within 10 years before the period of extended operation and within 10 years after the 

initiation of the period of operation. The staff finds that these activities are consistent with
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industry practice because this program include for periodic excavations and visual inspections 

of buried piping and tanks for general, pitting and crevice corrosion and MIC. 

The GALL AMP XI.34 program element “parameters monitored/inspected” states that 

parameters such as coating and wrapping integrity, that are directly related to corrosion 

damage, of the external surface of buried steel piping and tanks should be monitored. The staff 

noted that the applicant is crediting the Buried Piping and Tanks Inspection Program as 

recommended in GALL AMR items VII.H1-9, VII.G-25, and VII.C1-18 which the GALL Report 

states is an acceptable program to monitor possible corrosion damage to the external surface of 

piping and tanks. These components are identified in LRA Table 3.3.2-6, 3.3.2-10 and 3.3.2-17: 

Piping and Fittings, and LRA Table 3.3.2-9: Piping and Fittings, Valves Bodies. Therefore, the 

staff finds that, based on the program identified above, the applicant meets the criteria of 

SRP-LR Section 3.3.2.2.8. 

Based on the programs identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.2.2.2.8 criteria. For those line items that are addressed in LRA 

Section 3.2.2.2.8, the staff determines that the LRA is consistent with the GALL Report and that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.9 Loss of Material Due to General, Pitting, Crevice, Microbiologically-Influenced 

Corrosion and Fouling 

Steel Piping, Piping Components, Piping Elements, and Tanks Exposed to Fuel Oil. The 

applicant states in LRA Section 3.3.2.2.9.1 that loss of material due to general, pitting, crevice

corrosion, MIC and fouling could occur for steel piping, piping components, piping elements, 

and tanks exposed to fuel oil. LRA Section 3.3.2.2.9.1 further states that 1) this aging effect is 

managed with a combination of the Fuel Oil Chemistry Program and the One-Time Inspection 

Program 2) the Fuel Oil Chemistry Program includes periodic sampling and testing of fuel oil, 

integrity testing, visual inspection and one-time inspections of selected components to assure 

the continued effectiveness of fuel oil chemistry control activities to ensure that degradation is 

not occurring and 3) the One-Time Inspection Program performs sampling inspections using 

NDE techniques that either verify unacceptable degradation is not occurring or trigger additional 

actions.

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 corrosion, MIC, and fouling 

could occur for steel piping, piping components, piping elements, and tanks exposed to fuel oil. 

SRP-LR Section 3.3.2.2.9.1 further states that 1) the existing AMP relies on the fuel oil 

chemistry program for monitoring and control of fuel oil contamination to manage loss of 

material due to corrosion or fouling, 2) corrosion or fouling may occur at locations where 

contaminants accumulate and 3) the effectiveness of the fuel oil chemistry control should be 

verified to ensure that corrosion is not occurring.

SRP-LR Section 3.3.2.2.9.1, AMR item 20 in Table 3 of the GALL Report, Volume 1, and GALL 

AMR items VII.H2-24 (Emergency Diesel Generator System) and VII.H1-10 (Diesel Fuel) are 

applicable to loss of material due to general, pitting, crevice, and MIC of steel, piping, piping 
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components, and piping elements exposed to fuel oil. These components are identified in LRA 

Table 3.3.2-8: piping and fittings, filter/strainer housings, pump casings, tanks, valve bodies and 

Table 3.3.2-10: filter/strainer housings, manifolds, piping/fittings, pump casings, restricting 

orifices, tanks, valve bodies.

The GALL Report recommends further evaluation of programs to manage loss of material due 

to general, pitting, crevice corrosion, MIC, and fouling to verify the effectiveness of the Fuel Oil 

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 the component’s intended 

function will be maintained during the period of extended operation.

The staff reviewed LRA Appendix B, Sections B2.1.19, “Fuel Oil Chemistry” and B2.1.29, “OneTime Inspection” in SER Sections 3.0.3.2.9 and 3.0.3.1.18 respectively and found that these 

programs 1) provide for periodic sampling of fuel oil and periodic, draining, cleaning, and visual 

inspection of fuel tanks to maintain contaminants at acceptable limits to preclude loss of 

material due to pitting and corrosion and 2) one-time inspections of select steel piping, piping 

components, piping elements, and tanks exposed to fuel oil for loss of material due to general, 

pitting, crevice corrosion, MIC and fouling to verify the effectiveness of the Fuel Oil Chemistry 

Program in applicable Auxiliary systems. The GALL Report states that one-time inspection is an 

acceptable method to verify the effectiveness of mitigative aging management and condition 

monitoring programs. The staff noted that the Fuel Oil Chemistry provides for both mitigation of 

aging and condition monitoring of fuel oil tanks. The staff noted that the applicant is crediting the 

Fuel Oil Chemistry Program as recommended in GALL AMR items VII.H2-24 and VII.H1-10 and 

the applicant is verifying effectiveness of the Fuel Oil Chemistry Program with the elements of 

the One-Time Inspection Program, which is also consistent with the recommendations in GALL 

AMR items VII.H2-24 and VII.H1-10. Therefore, the staff finds that, based on the programs 

identified above, the applicant meets the criteria of SRP-LR Section 3.3.2.2.9.1. 

Based on the applicant's programs discussed above, the staff concludes that the applicant’s 

programs meet SRP-LR Section 3.3.2.2.9.1 criteria. For those line 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 function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

Steel Heat Exchanger Components Exposed to Lubricating Oil. The applicant states in LRA 

Section 3.3.2.2.9.2 that loss of material due to general, pitting, crevice, MIC, and fouling could 

occur for steel heat exchanger components exposed to lubricating oil. PINGP excludes loss of 

material due to fouling or MIC in a lubricating oil environment based upon an evaluation of the 

materials of construction and operating environment, along with industry and plant specific 

operation experience. LRA Section 3.3.2.2.9.2 further states that 1) this aging effect is managed 

with a combination of the Lubricating Oil Analysis Program and the One-Time Inspection 

Program 2) the Lubricating Oil Analysis Program includes periodic oil sampling, analysis, and 

evaluation and trending of results 3) the program maintains oil systems contaminants (primarily 

water and particulates) within acceptable limits, thereby preserving an environment that is not 

conducive to degradation and, 4) the One-Time Inspection Program performs sampling 

inspections using NDE techniques that either verify unacceptable degradation is not occurring 

or trigger additional actions.
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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, MIC, and fouling could occur 

for steel heat exchanger components exposed to lubricating oil. SRP-LR Section 3.3.2.2.9.2 

further states that 1) the existing AMP relies on the periodic sampling and analysis of lubricating 

oil to maintain contaminants within acceptable limits, thereby preserving an environment that is 

not conducive to corrosion 2) the effectiveness of lubricating oil control should be verified to 

ensure that corrosion is not occurring and 3) the GALL Report recommends further evaluation of 

programs to manage corrosion to verify the effectiveness of the oil control program such as a 

one-time inspection of selected components at susceptible locations. 

SRP-LR Section 3.3.2.2.9.2, AMR item 21 in Table 3 of the GALL Report, Volume 1, and GALL 

AMR item VII.H2-5 (Emergency Diesel Generator System) are applicable to loss of material due 

to general, pitting, crevice, and MIC and fouling of steel heat exchanger components, exposed 

to lubricating oil. These components are identified in LRA Table 3.3.2-6: Chiller Components, 

and LRA Table 3.3.2-8: Heat Exchanger Components.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and B2.1.29, 

“One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively and found that 

these programs 1) provide for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material due to general, pitting, and crevice corrosion and 

2) will perform one-time inspections of select steel heat exchanger components for loss of 

material due to general, pitting and crevice corrosion to verify the effectiveness of the 

Lubricating Oil Analysis Program in applicable Auxiliary systems. The staff noted that the 

applicant does not specifically manage loss of material due to MIC and fouling; however the 

control of contaminants in the lubrication oil in conjunction with One-Time Inspection Program 

will manage the aging effect, loss of material, regardless of the aging mechanism. The GALL 

Report states that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the applicant 

is crediting the Lubricating Oil Analysis Program as recommended in GALL AMR item VII.H2-5 

and the applicant is verifying effectiveness of the Lubricating Oil Analysis Program with the 

elements of the One-Time Inspection Program, which the GALL Report states is an acceptable 

program to verify the Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds 

that, based on the programs identified above, the applicant meets the criteria of SRP-LR 

Section 3.3.2.2.9.2. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.9.2 criteria. For those line 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 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).
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3.3.2.2.10 Loss of Material Due to Pitting and Crevice Corrosion 

The staff reviewed LRA Section 3.3.2.2.10 against the following criteria in SRP-LR 

Section 3.3.2.2.10:

 (1) LRA Section 3.3.2.2.10.1 addresses loss of material due to pitting and crevice corrosion 

for steel piping, piping components, and piping elements with either elastomer liners or 

stainless steel cladding exposed to treated water and treated borated water in the spent 

fuel pool cooling and cleanup system. In LRA Section 3.3.2.2.10.1 the applicant stated 

that its spent fuel pool cooling and cleanup components do not have elastomer lining. In 

LRA Table 3.3.1, AMR item number 3.3.1-22, the applicant designated the item as not 

applicable and stated that the spent fuel pool cooling and cleanup components do not 

have steel with elastomer lining or stainless steel cladding piping and piping elements 

exposed to treated water or treated borated water.

The staff reviewed LRA Section 3.3.2.2.10.1 against the criteria of SRP-LR 

Section 3.3.2.2.10.1, which states that loss of material due to pitting and crevice 

corrosion could occur in BWR and PWR steel piping with elastomer lining or stainless 

steel cladding that are exposed to treated water and treated borated water if the cladding 

or lining is degraded.

SRP-LR Section 3.3.2.2.10.1, AMR item 22 in Table 3 of the GALL Report, Volume 1, 

and GALL AMR item VII.A3-9 are applicable for steel spent fuel cleanup and cooling 

system piping and piping components with either internal elastomeric liners or stainless 

steel cladding that are exposed to a treated borated water environment. The SRP-LR 

section identifies that, for these material environmental combinations, the GALL Report 

recommends the Water Chemistry Program be credited for aging management of loss of 

material in the steel components if the liners or cladding is breached and that a condition 

monitoring program be credited to verify the effectiveness of the Water Chemistry 

Program.

The staff reviewed the description of the spent fuel storage pool in PINGP UFSAR

Section 10.2.1.2.1.c and of the spent fuel pool cooling system in PINGP UFSAR

Section 10.2.2.2. The staff confirmed that the UFSAR description says that all piping in 

contact with spent fuel pool water is austenitic stainless steel, and there is no description 

of elastomer lined or stainless steel clad piping or piping components. The staff noted 

that stainless steel piping and piping components exposed to treated water and borated 

treated water in the spent fuel pool cooling system and with an aging effect of loss of 

material due to pitting and crevice corrosion are evaluated in LRA Table 3.3.1, AMR item 

number 3.3.1-91. On the basis that the applicant has no steel piping or components with 

elastomer lining or stainless steel cladding in the spent fuel pool cooling and cleanup 

system, and stainless steel pipes with the same environment and aging effect are 

evaluated elsewhere in the LRA for the auxiliary systems, the staff finds it acceptable 

that the applicant designated LRA Table 3.3.1, AMR item 3.3.1-22, as an AMR item that 

is not applicable to the LRA.
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 (2) LRA Section 3.3.2.2.10.2 addresses loss of material due to pitting and crevice corrosion 

for stainless steel and aluminum piping, piping components, and piping elements 

exposed to treated water in the auxiliary systems. In LRA Section 3.3.2.2.10.2 the 

applicant stated that all of the GALL Report line items that refer to this SRP-LR section 

are applicable only for BWR plants. In Table 3.3.1, the applicant stated that AMR items 

3.3.1-23 and 3.3.1-24 apply to BWRs only.

SRP-LR Section 3.3.2.2.10.2 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel and aluminum piping, piping components, piping 

elements, and for stainless steel and steel with stainless steel cladding heat exchanger 

components exposed to treated water. This SRP-LR section states that the existing AMP

relies on monitoring and control of water chemistry to manage the aging effects. 

However, the SRP-LR section clarifies that high concentration of impurities at crevices 

and locations of stagnant flow conditions could cause pitting, or crevice corrosion, and 

therefore recommends that the effectiveness of the chemistry control program should be 

verified to ensure that corrosion is not occurring. The SRP-LR section states that the 

GALL Report recommends further evaluation of programs to verify effectiveness of the 

Water Chemistry Program to mitigate loss of material from pitting and crevice corrosion, 

and states that a one-time inspection of selected components at susceptible locations is 

an acceptable verification program. 

SRP-LR Section 3.3.2.2.10.2, AMR items 23 and 24 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR items VII.A4-2, VII.A4-5, VII.A4-11, VII.E3-7, VII.E3-15, 

VII.E4-4, and VII.E4-14 are applicable for components in BWR spent fuel pool cooling 

and cleanup systems, BWR reactor water cleanup systems, and the BWR shutdown 

cooling systems (i.e., for older BWR design models that have shutdown cooling systems 

instead of residual heat removal systems). 

The staff reviewed all line items in the GALL Report that refer to this SRP section and 

confirmed the applicant’s claim that the items in the GALL Report apply only to BWRs. 

The staff also noted that PWR line items with the same material, environment and aging 

effect are evaluated under LRA Table 3.3.1, AMR item 3.3.1-91, which is designated in 

the GALL Report as applicable to PWRs only. The staff’s evaluation of LRA AMR item 

3.3.1-91 is in SER Section 3.3.2.1. On the basis that all line items in the GALL Report 

referencing SRP-LR Section 3.3.2.2.10.2 are applicable only to BWRs, and that the 

corresponding AMR item for the applicant’s PWR design are provided in LRA Table 

3.3.1, AMR item 3.3.1-91 and is evaluated in SER Section 3.3.21, the staff finds it 

acceptable that the applicant designated LRA Table 3.3.1, AMR items 3.3.1-23 

and 3.3.2-24 as AMR items that are not applicable.

 (3) LRA Section 3.3.2.2.10.3 addresses loss of material due to pitting and crevice corrosion 

for copper alloy components exposed to condensation (external) in the heating, 

ventilation, and air conditioning (HVAC) and other systems. By letter dated April 13, 

2009, the applicant submitted its annual update to the LRA. The applicant stated that 

heat exchanger tubes in certain ventilation air coolers are normally in service and may 

potentially be exposed to condensation. The applicant further stated that these

components should have been evaluated for an external environment of wet air/gas 

(external), but were incorrectly evaluated for plant indoor air – uncontrolled (external) or 
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primary containment air (external). The staff noted that exposure to condensation may 

result in aging related degradation that was not initially accounted for when these 

components were evaluated for a plant indoor air - uncontrolled or primary containment 

air environment. The applicant stated that this aging effect is managed with the External 

Surfaces Monitoring Program. 

SRP-LR Section 3.3.2.2.10.3 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’s review of the applicant’s External Surfaces Monitoring Program and its 

evaluation are documented in SER Sections 3.0.3.2.5. The staff notes that the External 

Surfaces Monitoring Program will include periodic visual inspections of external surfaces 

performed during system walkdowns at a specified frequency. The staff further notes 

that these periodic visual inspections are adequate to manage loss of material due to 

pitting and crevice corrosion for copper alloy heat exchanger tubes exposed to the 

external wet air/gas (external) environment addressed by this AMR because a visual 

inspection will be capable of detecting corrosion wastage, discoloration, and surface 

discontinuities and pitting that are indicative of loss of material on the accessible external 

surface of the copper alloy heat exchanger tube. On the basis that External Surfaces 

Monitoring Program includes periodic visual inspections during system walkdowns at a 

specified frequency for managing heat transfer degradation due to fouling, the staff finds 

the applicant's use of the External Surfaces Monitoring Program acceptable.

Based on the program identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.3.2.2.10.3 criteria. For those line 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 function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (4) The applicant states in LRA Section 3.3.2.2.10.4 that loss of material due to pitting and

crevice corrosion could occur for copper alloy piping, piping components and piping 

elements exposed to lubricating oil. LRA Section 3.3.2.2.10.4 further states that 1) 

PINGP excludes loss of material due to fouling in a lubricating oil environment based on 

plant-specific OE, 2) this aging effect is managed with a combination of the Lubricating 

Oil Analysis Program and the One-Time Inspection Program, 3) the Lubricating Oil 

Analysis Program includes periodic oil sampling, analysis, and evaluation and trending 

of results to maintain oil systems contaminants (primarily water and particulates) within 

acceptable limits, thereby preserving an environment that is not conducive to

degradation, and 4) the One-Time Inspection Program either verifies unacceptable 

degradation is not occurring or trigger additional actions.

The staff reviewed LRA Section 3.3.2.2.10.4 against the criteria in SRP-LR Section 

3.3.2.2.10.4 that states that loss of material due to pitting and crevice corrosion could 

occur for copper alloy piping, piping components, and piping elements exposed to 
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lubricating oil. SRP-LR Section 3.3.2.2.10.4 further states that 1) the GALL Report 

recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the lubricating oil program and 2) a one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is 

not occurring.

SRP-LR Section 3.3.2.2.10.4, AMR item 26 in Table 3 of the GALL Report, Volume 1, 

and GALL AMR items VII.E1-12 (Chemical and Volume Control System) and VII.H2-10 

(Emergency Diesel Generator System) are applicable to loss of material due to pitting 

and crevice corrosion of copper alloy piping, piping components, and piping elements 

exposed to lubricating oil. These components are identified in LRA Table 3.3.2-1: heat 

exchanger tubes, LRA Table 3.3.2-2: piping/fittings, valve bodies, LRA Table 3.3.2-5: 

piping/fittings, and LRA Table 3.3.2-8: heat exchanger components, heat exchanger 

tubes, heaters, and valve bodies. 

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively 

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to pitting and 

crevice corrosion and 2) will perform one-time inspections of select copper alloy piping, 

piping components, and piping elements exposed to lubricating oil for loss of material 

due to pitting and crevice corrosion to verify the effectiveness of the Lubricating Oil 

Analysis Program. The GALL Report states that one-time inspection is an acceptable 

method to verify the effectiveness of a mitigative AMP such as the Lubricating Oil 

Analysis Program. The staff noted that the applicant is crediting the Lubricating Oil 

Analysis Program as recommended in GALL AMR items VII.E1-12 and VII.H2-10 and 

that the applicant is verifying effectiveness of the Lubricating Oil Analysis Program with 

the elements of the One-Time Inspection Program, which the GALL Report states is an 

acceptable program to verify the Lubricating Oil Analysis Program effectiveness.

Therefore, the staff finds that, based on the programs identified above, the applicant 

meets the criteria of SRP-LR Section 3.3.2.2.10.4. 

Based on the program identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.3.2.2.10.4 criteria. For those line 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 function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

 (5) LRA Subsection 3.3.2.2.10.5 states that loss of material due to pitting and crevice 

corrosion could occur for stainless steel HVAC ducting and aluminum HVAC piping, 

piping components and piping elements exposed to condensation. The applicant stated 

that this aging effect is managed with the Compressed Air Monitoring Program. The 

applicant further stated that the Compressed Air Monitoring Program performs periodic 

air quality sampling, inspections, component functional testing, and leakage testing; and 

additionally, preventive maintenance is performed at regular intervals to ensure system 

components continue to operate reliably; thereby ensuring that quality air is supplied to 

plant equipment. By letter dated April 13, 2009, the applicant submitted its annual 
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update to the LRA. The applicant stated that heat exchanger tubes in certain ventilation 

air coolers are normally in service and may potentially be exposed to condensation. The 

applicant further stated that these components should have been evaluated for an 

external environment of wet air/gas (external), but were incorrectly evaluated for plant 

indoor air – uncontrolled (external) or primary containment air (external). The staff noted 

that exposure to condensation may result in aging related degradation that was not 

initially accounted for when these components were evaluated in a plant indoor air -

uncontrolled or primary containment air environment. The applicant stated that this aging 

effect is managed with the Compressed Air Monitoring Program or the External Surfaces 

Monitoring Program.

The staff reviewed LRA Section 3.3.2.2.10.5 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 and components exposed to condensation. The GALL Report recommends 

further evaluation of a plant-specific AMP to ensure that the aging effect is adequately 

managed.

SRP-LR Section 3.3.2.2.10.5 invokes AMR item 27 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR item VII.F2-12, applicable to aluminum piping components 

exposed to condensation in the auxiliary and radwaste area ventilation system, and 

recommends a plant-specific AMP.

The staff reviewed the Compressed Air Monitoring Program, which includes periodic 

visual inspection of internal surfaces of piping and heat exchanger components for loss 

of material and fouling, monitoring of system air quality in accordance with industry 

standards and guidelines, and is consistent with the GALL AMP XI.M24, “Compressed 

Air Monitoring.” The staff’s review of the Compressed Air Monitoring program and its 

evaluation are documented in SER Section 3.0.3.2.3. On the basis that periodic visual 

inspection and monitoring of system air quality will be performed, the staff finds that the 

Compressed Air Monitoring Program will adequately manage loss of material due to 

pitting and crevice corrosion of copper alloy piping, piping components, piping elements, 

and heat exchanger components exposed to wetted air in the Station and Instrument Air

system, and instrument and control air system through the period of extended operation. 

The staff’s review of the applicant’s External Surfaces Monitoring Program and its 

evaluation are documented in SER Section 3.0.3.2.5. The staff notes that the External 

Surfaces Monitoring Program will include periodic visual inspections of external surfaces 

performed during system walkdowns at a specified frequency. The staff further notes 

that these periodic visual inspections are adequate to manage loss of material due to 

pitting and crevice corrosion for aluminum heat exchanger tubes exposed to external wet 

air/gas (external) environment addressed by this AMR because a visual inspection will 

be capable of detecting corrosion wastage, discoloration, and surface discontinuities and 

pitting that are indicative of loss of material on the accessible external surface of the 

aluminum heat exchanger tube. On the basis that External Surfaces Monitoring Program 

includes periodic visual inspections at a specified frequency for managing heat transfer 

degradation due to fouling, the staff finds the applicant's use of the External Surfaces 

Monitoring Program acceptable.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10.5 criteria. For those line 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 function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (6) LRA Subsection 3.3.2.2.10.6 states that loss of material due to pitting and crevice 

corrosion could occur for copper alloy piping, piping components, and piping elements 

exposed to condensation (internal). The applicant stated that this aging effect is 

managed with the Compressed Air Monitoring Program. The applicant further stated that 

the Compressed Air Monitoring Program performs periodic air quality sampling, 

inspections, component functional testing, and leakage testing; and additionally, 

preventive maintenance is performed at regular intervals to assure system components 

continue to operate reliably; thereby assuring that quality air is supplied to plant 

equipment.

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 components exposed to internal 

condensation. The GALL Report recommends further evaluation of a plant-specific AMP

to ensure these aging effects are adequately managed.

SRP-LR Section 3.3.2.2.10.6, AMR item 28 in Table 3 of the GALL Report, Volume 1, 

and GALL AMR item VII.G-9, are applicable to copper alloy piping components exposed 

to condensation in the fire protection system, and recommends a plant-specific AMP.

LRA Table 3.1.1, line item 3.3.1-28 is referenced in LRA Table 3.3.2-17, station and 

instrument air system for copper alloy, brass and bronze valve bodies and heat 

exchanger tubes. The staff reviewed the Compressed Air Monitoring Program, which 

includes periodic visual inspection of internal surfaces of piping and heat exchanger 

components for loss of material and fouling, monitoring of system air quality in 

accordance with industry standards and guidelines, and is consistent with the GALL 

AMP XI.M24, “Compressed Air Monitoring.” The staff’s review of the Compressed Air 

Monitoring Program and its evaluation are documented in SER Section 3.0.3.2.3. On the 

basis that periodic visual inspection and monitoring of system air quality will be 

performed, the staff finds that the Compressed Air Monitoring Program will adequately 

manage loss of material due to pitting and crevice corrosion of copper alloy piping, 

piping components, piping elements, and heat exchanger components exposed to 

wetted air in the Station and Instrument Air System, and instrument and control air 

system through the period of extended operation. 

Based on the program identified, the staff concludes that the applicant’s program meets

the SRP-LR Section 3.3.2.2.10.6 criteria. For those line items that apply to LRA Section 

3.3.2.2.10.6, 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 
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so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (7) LRA Section 3.3.2.2.10.7 addresses loss of material due to pitting and crevice corrosion 

in stainless steel piping, piping components, and piping elements exposed to soil, stating 

that this aging effect is not applicable because at PINGP, there are no stainless steel 

piping components exposed to soil in the auxiliary systems.

SRP-LR Section 3.3.2.2.10.7 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel piping, piping components, and piping elements 

exposed to soil.

The staff verified, through review of the PINGP UFSAR, that the auxiliary system does 

not contain any stainless steel piping, piping components, and piping elements. On this 

basis, the staff finds that the criteria in SRP-LR Section 3.3.2.2.10.7 are not applicable to 

PINGP. 

 (8) LRA Section 3.3.2.2.10.8 indicates that the aging effect described in SRP-LR Section 

3.3.2.2.10.8 is related to BWR plants, and therefore not applicable to PINGP.

SRP-LR Section 3.3.2.2.10.8 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel piping, piping components, and piping elements of 

the BWR standby liquid control system exposed to sodium pentaborate solution.

The staff noted that PINGP is a PWR, and therefore does not have standby liquid control 

system. On this basis, the staff finds the criteria in SRP-LR 3.3.2.2.10.8 are not 

applicable to PINGP.

Based on the programs identified above, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.10 criteria or else that the applicant has provided an acceptable basis 

for concluding that a particular recommendation in SRP-LR Section 3.3.2.2.10 is either not 

applicable to the LRA or did not need to be applied to the LRA. For those line items that apply to 

LRA Section 3.3.2.2.10, the staff determines that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately managed so 

that the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.11 Loss of Material Due to Pitting, Crevice, and Galvanic Corrosion 

The staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.

LRA Section 3.3.2.2.11 addresses loss of material in copper alloy auxiliary system components

exposed to a treated water environment, stating that this aging effect is not applicable to 

PINGP, a PWR plant.

SRP-LR Section 3.3.2.2.11 states that loss of material due to pitting, crevice, and galvanic 

corrosion may occur in copper alloy piping, piping components, and piping elements exposed to 

treated water.
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The staff noted that all GALL Report AMR items that correspond to SRP-LR Section 3.3.2.2.11 

are components in BWR systems, and therefore do not apply to PINGP, a PWR plant.

Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.11 criteria do not apply to 

the LRA. 

3.3.2.2.12 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

 (1) LRA Subsection 3.3.2.2.12.1 states that loss of material due to pitting corrosion, crevice 

corrosion and MIC could occur in stainless steel, aluminum, and copper alloy piping, 

piping components, and piping elements exposed to fuel oil. The applicant stated that 

this aging effect is managed with the Fuel Oil Chemistry Program, the One-Time 

Inspection Program and the Fire Protection Program. The applicant further stated that 

the Fire Protection Program provides diesel-driven fire pump inspection activities that 

require the pump to be periodically performance tested to ensure that the fuel supply line 

can perform its intended function; and the fuel supply line intended function is confirmed 

by visually inspecting the diesel engine and its fuel supply line, and by starting and 

running the diesel-driven fire pump.

In LRA Table 3.3.2-8 and 3.3.2-10, the applicant clarifies that for the stainless steel and 

copper alloy piping and fittings in the Diesel Generators and Support System and the 

Fuel Oil System, the Fuel Oil Chemistry Program is credited to manage loss of material 

in the components as result of exposing the components to fuel oil and that the OneTime Inspection Program is credited to verify the effectiveness of the Fuel Oil Chemistry 

Program in managing this aging effect.

In LRA Table 3.3.2-9, the applicant clarifies that for the copper alloy piping and fittings in 

the fuel supply line to the diesel-driven fire pumps (i.e. part of the Fire Protection 

System), the Fuel Oil Chemistry Program is credited to manage loss of material in the 

component surfaces as a result of exposing the component surfaces to fuel oil and that 

the One-Time Inspection Program is credited to verify the effectiveness of the Fuel Oil 

Chemistry Program in managing this aging effect. For these components, the applicant

also clarifies that the Fire Protection Program is conservatively credited as an additional 

AMP for managing loss of material in the copper alloy piping and fittings in the fuel 

supply line to the diesel-driven fire pumps. 

The staff reviewed LRA Section 3.3.2.2.12.1 against the criteria in SRP-LR

Section 3.3.2.2.12.1, which states that loss of material due to pitting and crevice 

corrosion, and MIC may occur in stainless steel, aluminum, and copper alloy piping, 

piping components, and piping elements exposed to fuel oil. The existing AMP relies on 

the fuel oil chemistry program for monitoring and control of fuel oil contamination to 

manage loss of material due to corrosion. However, corrosion may occur at locations 

where contaminants accumulate and the effectiveness of fuel oil chemistry control 

should be verified to ensure that corrosion does not occur. The GALL Report 

recommends further evaluation of programs to manage corrosion to verify the 

effectiveness of the fuel oil chemistry control program. A one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion 
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does not occur and that component intended functions will be maintained during the 

period of extended operation.

SRP-LR Section 3.3.2.2.12.1, AMR item 32 in Table 3 of the GALL Report, Volume 1, 

and GALL Report AMR items VII.H1-1, VII.H2-7, VII.G-10, VII.H1-3, VII.H2-9, VII.G-17, 

VII.H1-6 and VII.H2-16, applicable to stainless steel, aluminum, and copper alloy piping, 

piping components, and piping elements exposed to fuel oil in the fire protection, diesel 

fuel oil, and emergency diesel generator systems, and recommends Fuel oil Chemistry 

and effectiveness verification program.

The staff noted that, for the stainless steel and copper alloy piping and fittings in the 

Diesel Generators and Support System and the Fuel Oil System, and in the copper alloy 

piping and fittings in the fuel supply line to the diesel-drive fire protection pumps, the 

applicant crediting of the Fuel Oil Chemistry Program and One-Time Inspection Program 

was consistent with the recommendations in GALL AMR items VII.H1-6, VIIl.H1-3, 

VII.H2-16, VII.H2-9, and VII.G-10 that these programs be credited for aging 

management of loss material in the surfaces that are exposed to the fuel oil 

environment. Specifically, the staff noted that the Fuel Oil Chemistry Program is 

designed to monitor for fuel oil quality and the levels of water, sediment, and 

contaminants, which if present could induce corrosion in components, and that the 

One-Time Inspection Program is used to verify the effectiveness of the Fuel Oil 

Chemistry Program and to confirm that aging degradation is not occurring. The staff 

finds that the applicant has provided an acceptable basis for managing loss of material 

in the components surfaces that are exposed to fuel oil because the AMPs credited for 

aging management are in conformance with the AMPs recommended for aging 

management in SRP-LR Section 3.3.2.2.12.1 and GALL AMR items VII.H1-6, VIIl.H1-3, 

VII.H2-16, VII.H2-9, and VII.G-10.

The staff also noted that in addition to the Fuel Oil Chemistry and One-Time Inspection 

Programs, the applicant also credits the Fire Protection Program for aging management 

of copper alloy piping and fittings in the diesel-driven fire pump fuel supply line. The staff 

reviewed the Fire Protection Program and its evaluation is documented in SER Section 

3.0.3.2.6. The staff noted that consistent with GALL Report recommendation, the PINGP 

Fire Protection Program requires that the diesel driven fire pump be periodically 

performance tested to ensure that the fuel oil supply line can perform its intended 

function. The staff also noted that the fuel oil supply line intended function is confirmed 

by starting and running the diesel-driven fire pump for 30 minutes every week and that 

the periodic pump performance test provides an indirect means of verifying the absence 

of fuel line loss of material by confirming satisfactory pump performance. On the basis 

that the applicant’s Fire Protection Program is consistent with the GALL AMP XI.M26, 

“Fire Protection,” and the applicant is crediting the Fuel Oil Chemistry and One-Time 

Inspection Programs for monitoring chemistry and inspection of the internal surfaces of 

the diesel-driven fire pump fuel supply line, the staff finds that it is a conservatively 

acceptable practice to credit the Fire Protection Program as an additional aging 

management program for managing loss of material due to pitting and crevice corrosion

in the copper alloy piping and fittings of the diesel-driven fire pump fuel supply line that 

are exposed to fuel oil environment.
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Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12.1 criteria. For those line 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 the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) The applicant states in LRA Section 3.3.2.2.12.2 that loss of material due to pitting, 

crevice corrosion, and MIC could occur in stainless steel, piping, piping components, 

and piping elements exposed to lubricating oil. LRA Section 3.3.2.2.12.2 further states 

that 1) PINGP excludes loss of material due to MIC in a lubricating oil environment 

based on plant-specific OE, 2) loss of material is managed with a combination of the 

Lubricating Oil Analysis Program and the One-Time Inspection Program 3) the 

Lubricating Oil Analysis Program includes periodic oil sampling, analysis, and evaluation 

and trending of results, 4) the program maintains oil systems contaminants (primarily 

water and particulates) within acceptable limits, thereby preserving an environment that 

is not conducive to degradation and 5) the One-Time Inspection Program performs 

sampling inspections using NDE techniques that either verify unacceptable degradation 

is not occurring or trigger additional actions. 

The staff reviewed LRA Section 3.3.2.2.12.2 against the criteria in SRP-LR Section 

3.3.2.2.12.2, which states that loss of material due to pitting, crevice corrosion, and MIC 

could occur in stainless steel piping, piping components, and piping elements exposed 

to lubricating oil. SRP-LR Section 3.3.2.2.12.2 further states that 1) the existing program 

relies on the periodic sampling and analysis of lubricating oil to maintain contaminants 

within acceptable limits, thereby preserving an environment that is not conducive to 

corrosion and 2) the effectiveness of the lubricating oil program is verified through 

one-time inspection of selected components at susceptible locations to ensure that 

corrosion is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

SRP-LR Section 3.3.2.2.12.2, AMR item 33 in Table 3 of the GALL Report, Volume 1, 

and GALL AMR items VII.E1-15 (Chemical and Volume Control System), VII.H2-17 

(Emergency Diesel Generator System) and VII.G-18 (Fire Protection System) are 

applicable to loss of material due to pitting and crevice corrosion of stainless steel 

piping, piping components, and piping elements exposed to lubricating oil. These 

components are identified in LRA Table 3.3.2-2: piping/fittings, LRA Table 3.3.2-8: 

manifolds, piping/fittings, thermowells, valve bodies, LRA Table 3.3.2-9: RCP oil 

collection components.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 and found 

that these programs 1) provide for periodic sampling of lubricating oil to maintain 

contaminants at acceptable limits to preclude loss of material due to pitting, crevice

corrosion and 2) will perform one-time inspections of select stainless steel piping, piping 

components, and piping elements exposed to lubricating oil for loss of material due to 

pitting, crevice corrosion to verify the effectiveness of the Lubricating Oil Analysis 

Program in applicable auxiliary systems. The GALL Report states that one-time 
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inspection is an acceptable method to verify the effectiveness of a mitigative AMP such 

as the Lubricating Oil Analysis Program. The staff noted that the applicant is crediting 

the Lubricating Oil Analysis Program as recommended in GALL AMR items VII.E1-15, 

VII.H2-17 and VII.G-18, and that the applicant is verifying effectiveness of the 

Lubricating Oil Analysis Program with the elements of the One-Time Inspection 

Program, which the GALL Report states is an acceptable program to verify the 

Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds that, based on 

the programs identified above, the applicant meets the criteria of SRP-LR Section 

3.3.2.2.12.2. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.3.2.2.12.2 criteria. For those line 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 function(s) will be maintained consistent with 

the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.13 Loss of Material Due to Wear 

LRA Section 3.3.2.2.13 addresses loss of material due to wear that could occur in elastomer 

seals and components in an indoor air environment (internal or external). The applicant stated 

that this aging effect is managed with the External Surfaces Monitoring Program. In a letter 

dated January 15, 2009, the applicant added additional line items as a result of its response to 

RAI 2.3.3.5-04. The staff noted that these line items are flex connections made of EPDM and 

are managed with the External Surfaces Monitoring Program. The External Surfaces Monitoring 

Program performs periodic system inspections and walkdowns to visually inspect accessible 

external surfaces for degradation. The applicant also stated that the External Surfaces 

Monitoring Program is credited with managing aging effects of internal surfaces where the 

external surfaces are subject to the same environment or stressor as the internal surfaces such 

that that external condition is representative of the internal surface condition. The applicant 

concluded that this program assures the intended function of affected components will be 

maintained during the period of extended operation. The applicant identified that this AMR 

evaluation is applicable to the management of loss of material in EDPM flexible connections in 

the Auxiliary and Radwaste Ventilation System, Turbine and Administration Building Ventilation

System, Control Area and Miscellaneous Ventilation System, Diesel Generator Ventilation 

System, and Primary Containment Heating and Ventilation System under exposure to either an 

internal or external indoor air environment. 

The staff reviewed LRA Section 3.3.2.2.13 and the line items included in letter dated January 

15, 2009, against the criteria in SRP-LR Section 3.3.2.2.13, which states that loss of material 

due to wear may occur in the elastomer seals and components exposed to air - indoor 

uncontrolled (internal or external). The GALL Report recommends further evaluation of an AMP 

to ensure that the aging effect is adequately managed. This SRP-LR Section references AMR 

item 34 in Table 3 of the GALL Report, Volume 1, and AMR items VII.F1-6, VII.F2-6, VII.F3-6, 

VII.F4-5, VII.F1-5, VII.F2-5, VII.F3-5, and VII.F4-4 in the GALL Report Volume 2, as applicable 

to the management of loss of material due to wear in elastomeric seals and components in 

Auxiliary and Radwaste Ventilation System, Turbine and Administration Building Ventilation
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System, Control Area and Miscellaneous Ventilation System, Diesel Generator Ventilation 

System, and Primary Containment Heating and Ventilation System.

The staff noted that the applicant credited its External Surfaces Monitoring Program to manage 

loss of material due to wear of these EDPM elastomer flexible connections. The staff’s review of 

the applicant’s External Surfaces Monitoring Program is documented in SER Section 3.0.3.2.5.

The staff notes that the applicant’s External Surfaces Monitoring Program include periodic visual 

inspections of external surfaces that are periodically performed during system walkdowns of the 

plant. The staff also noted the ASME Code Section XI lists VT-1 and VT-3 visual inspection 

methods as acceptable inspection techniques for monitoring for discontinuities in component 

materials, including those that may be induced by loss of material. 

Based on this determination, the staff concludes that the applicant’s basis for crediting the 

External Surfaces Monitoring Program for aging management of loss of material due to wear in 

these flexible connections is valid because: (1) the program will perform visual examinations of 

the external surfaces to monitor for discontinuities that are induced by wear, (2) visual VT-1 and 

VT-3 examination methods are acceptable examination methods for detecting surface breaking 

discontinuities, such as those that may be induced by wear, and (3) the program conforms to 

the recommendation in SRP-LR Section 3.3.2.2.13 that a valid AMP be evaluated and credited 

for managing loss of material in elastomeric ventilation system seals and components.

Based on the program identified above, the staff concludes that the applicant’s program meets 

the SRP-LR Section 3.3.2.2.13 criteria. For those line 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 function(s) will be maintained consistent with the CLB during the period of extended

operation, as required by 10 CFR 54.21(a)(3).

3.3.2.2.14 Loss of Material Due to Cladding Breach 

LRA Section 3.3.2.2.14 addresses cracking due to underclad cracking in PWR steel charging 

pump casings with stainless steel cladding exposed to treated borated water, stating that this 

aging effect is not applicable because the charging pump casings are not carbon steel with 

stainless steel clad but made of stainless steel.

SRP-LR Section 3.3.2.2.14 states that loss of material due to cladding breach (also referred to 

as underclad cracking may occur in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The GALL Report references IN 94-63 and 

recommends further evaluation of a plant-specific AMP to ensure that the aging effect is 

adequately managed.

The staff reviewed LRA Section 3.3.2.2.14 against the criteria in SRP-LR Section 3.3.2.2.14.

Through a review of PINGP UFSAR, the staff verified that charging pump casings are made of 

stainless steel and do not have a cladding. Therefore, the aging effect of cracking due to 

underclad cracking in PWR steel charging pumping casings with stainless steel cladding 

exposed to treated borated water is not applicable to PINGP.

Based on the above, the staff concludes that SRP-LR Section 3.3.2.2.14 criteria do not apply. 
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3.3.2.2.15 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

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

In LRA Tables 3.3.2-1 through 3.3.2-21, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.3.2-1 through 3.3.2-21, the applicant indicated, via notes F through J that the 

combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, Note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.3.2.3.1 Auxiliary and Radwaste Area Ventilation System - Summary of Aging Management 

Review – LRA Table 3.3.2-1 

The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for the 

auxiliary and radwaste area ventilation system component groups. The staff determined that all 

AMR evaluation results in LRA Table 3.3.2-1 are consistent with the GALL Report.

3.3.2.3.2 Chemical and Volume Control System - Summary of Aging Management Review –

LRA Table 3.3.2-2 

The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for the 

chemical and volume control system component groups.

LRA Table 3.3.2-2 summarizes the results of an AMR for the Chemical and Volume Control 

System piping and fittings constructed out of copper alloy exposed to lubricating oil (internal).

The applicant proposed an aging effect of loss of material (selective leaching) and proposed the 

Selective Leaching of Materials Program to manage the aging effect.
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The applicant has indicated that generic Note H is applicable for these items with plant-specific

Note 318. Generic Note H is “Aging effect not in NUREG-1801 for this component, material, and 

environment.” Plant-specific note 318 states, “loss of material due to selective leaching for 

copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil environment.” The 

staff confirmed that the aging effect for this component, material, and environment is not in the 

GALL Report for this component, material and environment. The GALL Report lists the aging 

effect for copper alloy in lubricating oil with no water pooling as none with no AMP required.

However, if the copper alloy has greater than 15 percent zinc or greater than 8 percent 

aluminum, then selective leaching is possible. (M. G. Fontana, Corrosion Engineering, Third 

Edition, McGraw-Hill, New York, 1986). The GALL Report does not have an AMR line item for 

copper alloy with greater than 15 percent zinc or greater than 8 percent aluminum exposed to 

lubricating oil. Because it is possible that the copper alloy has greater than 15 percent zinc or 8 

percent aluminum, the staff finds that it is conservative to identify loss of material by selective 

leaching as the AERM for the LRA and to credit the use of the Selective Leaching of Material 

Program to manage loss of material that may occur in these components as a result of selective 

leaching. The staff evaluates the ability of the Selective Leaching Program to manage loss of 

material due to selective leaching in SER Section 3.0.3.2.15.

LRA Table 3.3.2-2 summarizes the results of an AMR for the Chemical and Volume Control 

System pump casings constructed out of cast iron exposed to lubricating oil (internal). The 

applicant proposed an aging effect of loss of material (selective leaching) and proposed the 

Selective Leaching of Materials Program to manage the aging effect.

The applicant has indicated that generic Note H is applicable for these items with plant-specific

note 318. Generic Note H is “Aging effect not in NUREG-1801 for this component, material, and 

environment.” Plant-specific note 318 states, “Loss of material due to selective leaching for 

copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil environment.” The 

staff confirmed that the aging effect for this component, material, and environment is not in 

GALL for this component, material and environment. Selective leaching of cast iron, also called 

graphitization is common for cast iron. (M. G. Fontana, Corrosion Engineering, Third Edition, 

McGraw-Hill, New York, 1986). The iron in the cast iron is selectively leached out leaving the 

graphite behind. The staff finds that the use of Selective Leaching of Material Program for this 

component, material, environment combination aging effect is appropriate because the aging 

effect has previously been identified.

LRA Table 3.3.2-2 summarizes the results of an AMR for the Chemical and Volume Control 

System valve bodies constructed out of brass exposed to lubricating oil (internal). The applicant 

proposed an aging effect of loss of material (selective leaching) and proposed the Selective 

Leaching of Materials Program to manage the aging effect.

The applicant has indicated that generic Note H is applicable for these items with plant-specific

note 318. Generic Note H is “Aging effect not in NUREG-1801 for this component, material, and 

environment.” Plant-specific note 318 states, “Loss of material due to selective leaching for 

copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil environment.” The 

staff confirmed that the aging effect for this component, material, and environment is not in 

GALL for this component, material and environment. The staff noted that selective leaching is a 

common aging mechanism for brass materials (refer to M. G. Fontana, Corrosion Engineering, 

Third Edition, McGraw-Hill, New York, 1986). The staff finds that the use of this AMP for this 
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component, material, environment combination aging effect is appropriate because the aging 

effect has previously been identified.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.3 Component Cooling System - Summary of Aging Management Review –

LRA Table 3.3.2-3 

The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for the 

component cooling system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.3.2-3 are consistent with the GALL Report.

3.3.2.3.4 Containment Hydrogen Control System - Summary of Aging Management Review –

LRA Table 3.3.2-4 

The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for the 

containment hydrogen control system component groups.

In LRA Table 3.3.2-4, the applicant proposed to manage loss of preload- thermal, gasket creep, 

loosening for copper alloy bolting and fasteners externally exposed to an uncontrolled plant 

indoor air environment using the Bolting Integrity Program. The AMR line item cites Generic 

Note H, which indicates that the aging effect is not addressed in the GALL Report for this 

component, material and environment combination. The AMR line item also cites plant-specific 

Note 304, which indicates that SCC is not an applicable aging effect/mechanism since there are 

no bolts with a minimum yield strength > 150 ksi. 

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will manage the loss 

of preload through periodic inspection and preventive measures. The staff reviewed the Bolting 

Integrity Program to verify that loss of preload due to thermal effects, gasket creep, and self 

loosening will be managed in accordance with the recommendations specified by the Bolting 

Integrity Program. On the basis of its review, the staff finds that because these components will 

be inspected through the specifications of the Bolting Integrity Program, they will be adequately 

managed.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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3.3.2.3.5 Control Room and Miscellaneous Area Ventilation System - Summary of Aging 

Management Review – LRA Table 3.3.2-5 

The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for the 

control room and miscellaneous area ventilation system component groups.

In LRA Table 3.3.2-5, the applicant proposed to manage change in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for flex 

connections fabricated from PVC exposed to an external uncontrolled plant indoor air 

environment. The AMR line items cite Generic Note F, which indicates that the material is not 

addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring” to include non-metallic components, 

including PVC, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.5. The staff notes that this program will include periodic 

visual inspections of external surfaces performed during system walkdowns at a specified 

frequency. The staff further notes that age-related degradation of non-metallic components, 

such as change in material properties and cracking, can be detected by a visual inspection, 

coupled by a physical manipulation when appropriate, by evidence of surface discontinuities 

that include cracking, crazing, peeling, blistering, chalking, flaking, physical distortion, 

discoloration, loss of material from wear, and signs of leakage. The applicant amended its LRA, 

by letter dated December 5, 2008, to supplement the visual inspection with a physical 

manipulation when appropriate. The staff notes that this program will supplement the visual 

examination with a physical manipulation in order to verify aging effects such as hardening, 

embrittlement, or gross softening are not occurring. The staff notes that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component, or by the failure of the component to return to its previous shape 

or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.
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By letter dated April 13, 2009, the applicant submitted its annual update to the LRA. The 

applicant stated that heat exchanger tubes in certain ventilation air coolers are normally in 

service and may potentially be exposed to condensation. The applicant further stated that this 

should have been evaluated for an external environment of wet air/gas (external), but were 

incorrectly evaluated as plant indoor air – uncontrolled (external) or primary containment air 

(external). The staff noted that exposure to condensation may result in aging related 

degradation that were not initially accounted for when these components were evaluated in a 

plant indoor air - uncontrolled or primary containment air environment. In LRA Table 3.3.2-5, 

the applicant proposed to manage heat transfer degradation due to fouling for heat exchanger 

tubes fabricated from copper alloy exposed to a wet air/gas (external) environment. The AMR 

line items cite Generic Note H, which indicates that the aging effect is not addressed in the 

GALL Report for this component, material and environment combination. The applicable heat 

exchangers are located within the Control Room and Miscellaneous Area Ventilation System 

with the external side of the tubes exposed to a wet air/gas (external) environment.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that the External Surfaces 

Monitoring Program will include periodic visual inspections of external surfaces performed 

during system walkdowns at a specified frequency. The staff further notes that these periodic 

visual inspections are adequate to manage heat transfer degradation due to fouling for copper 

alloy heat exchanger tubes exposed to wet air/gas (external) environment addressed by this 

AMR because a visual inspection will be capable of detecting any fouling (buildup from 

whatever source) on the external surface of the copper alloy heat exchanger tube. On the basis 

of periodic visual inspections being performed during system walkdowns at a specified 

frequency of these components by the PINGP AMP B2.1.14, External Surfaces Monitoring, for 

heat transfer degradation due to fouling, the staff finds the applicant's use of the External 

Surfaces Monitoring Program acceptable.

In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selective 

leaching in copper alloy piping and fittings in an internal environment of lubricating oil and 

copper alloy heat exchanger tubes in a wet air/gas external environment by using the Selective 

Leaching of Materials Program. The applicant referenced Footnote H for this line item indicating 

that the aging effect is not in the GALL Report for these components, material, and environment 

combinations. The applicant also referenced a plant-specific note, which stated that for this line 

item loss of material due to selective leaching for copper alloys and gray cast iron is evaluated 

in a fuel oil and lubricating oil environment.

LRA B2.1.36 stated that the Selective Leaching of Materials Program will include a one-time 

visual inspection in conjunction with a hardness measurement, or other suitable detection 

technique of selected components that may be susceptible to selective leaching. The staff's 

evaluation of the Selective Leaching of Materials Program is documented in SER Section 

3.0.3.2.15. The staff finds that this new one-time program is consistent with GALL AMP XI.M33, 

"Selective Leaching," and includes an approved exception related to physical examinations.

The staff noted that the one-time inspection credited under the applicant’s Selective Leaching 

Program is consistent with the one-time inspection basis credited in the GALL AMP XI.M33, 

"Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that Table IX.C in the GALL Report Volume 2 identifies 
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that copper alloys with greater than 15 percent alloying zinc content, aluminum bronzes with 

greater than 8 percent aluminum alloying contents and cast irons may be susceptible to 

selective leaching. On this basis, the staff finds the Selective Leaching of Materials Program is a 

valid program to credit for the management of loss of material due to selective leaching in these 

copper alloy piping and fittings because the basis is consistent with: (1) the basis in 

GALL Table IX.C, which identifies that copper alloys with greater than 15 percent alloying zinc 

contents may be susceptible to selective leaching, and (2) basis in GALL AMP XI.M33 that the 

one-time inspection proposed in Selective Leaching Programs is an acceptable basis for 

managing loss of material in for copper alloy, aluminum bronze and cast iron components as a 

result of selective leaching. 

LRA Table 3.3.2-5 summarizes the results of AMRs for the Control Room and Miscellaneous 

Area Ventilation System flex connections constructed from PVC and exposed to dry/filtered 

instrument air (internal). The applicant stated that there are no aging effect and therefore no 

AMP is required. 

The applicant has indicated that Generic Note F is applicable for these items with plant-specific

Note 313. Generic Note F is “[m]aterial not in NUREG-1801 for this component.” Plant-specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects.” The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC has no aging effect when in contact with dry filtered air (refer to Roff, W. J., 

Fibres, Plastics, and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New 

York, 1956).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.6 Cooling Water System - Summary of Aging Management Review – LRA Table 3.3.2-6 

The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for the 

cooling water system component groups.

By letter dated April 13, 2009, the applicant submitted its annual update to the LRA. The 

applicant stated that heat exchanger tubes in certain ventilation air coolers are normally in 

service and may potentially be exposed to condensation. The applicant further stated that this 

should have been evaluated for an external environment of wet air/gas (external), but was 

incorrectly evaluated as plant indoor air – uncontrolled (external) or primary containment air 

(external). The staff noted that exposure to condensation may result in aging related 

degradation that was not initially accounted for when these components were evaluated in a 

plant indoor air - uncontrolled or primary containment air environment. In LRA Table 3.3.2-6, the 

applicant proposed to manage heat transfer degradation due to fouling for heat exchanger tubes 

fabricated from copper alloy exposed to a wet air/gas (external) and an external uncontrolled 

plant indoor air environment with the External Surfaces Monitoring Program. The AMR line 
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items cite Generic Note H, which indicates that the aging effect is not addressed in the GALL 

Report for this component, material and environment combination. The applicable heat 

exchangers are located within the cooling water system with the external side of the tubes 

exposed to a wet air/gas (external) and an external uncontrolled plant indoor air environment.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Section 3.0.3.2.5. The staff noted that the External Surfaces Monitoring 

Program will include periodic visual inspections of external surfaces performed during system 

walkdowns at a specified frequency. The staff further noted that these periodic visual 

inspections are adequate to manage heat transfer degradation due to fouling for copper alloy 

heat exchanger tubes exposed to wet air/gas (external) and an external uncontrolled plant 

indoor air environment addressed by this AMR because a visual inspection will be capable of 

detecting any fouling (buildup from whatever source) on the external surface of the copper alloy 

heat exchanger tube. On the basis of periodic visual inspections being performed during system 

walkdowns at a specified frequency of these components by the PINGP AMP B2.1.14, “External 

Surfaces Monitoring,” for heat transfer degradation due to fouling, the staff finds the applicant's 

use of the External Surfaces Monitoring Program acceptable.

In LRA Table 3.3.2-6, the applicant proposed to manage change in material properties and 

cracking for piping and fittings fabricated from polyvinylidene difluoride (PVDF) and valve bodies 

fabricated from PVC exposed to an external uncontrolled plant indoor air environment with the 

External Surfaces Monitoring Program. The AMR line items cite Generic Note F, which indicates 

that the material is not addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program” for aging 

management. The staff noted that the applicant has enhanced the “scope of program” program 

element of the applicant’s External Surfaces Monitoring Program to include non-metallic 

components, including PVDF and PVC, and to include management of the aging effects of 

change in material properties and cracking (i.e., in addition to managing loss of material). The 

staff also noted that the intent of GALL AMP XI.M36, “External Surfaces Monitoring,” is to 

perform visual inspections of steel components for loss of material. The staff determined that 

additional information was needed on the applicant’s proposed augmentation to PINGP AMP 

B2.1.14. Therefore, by letter dated November 5, 2008, the staff issued RAI B2.1.14-1 requesting 

the applicant provide an appropriate program that will manage the effects of aging for nonmetallic components, including PVC. The applicant responded to RAI B2.1.14-1 by letter dated 

December 5, 2008, and the staff finds the applicant’s response acceptable as documented in 

the staff’s evaluation of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is 

documented in SER Sections 3.0.3.2.5. The staff noted that this program will include periodic 

visual inspections of external surfaces performed during system walkdowns at a specified 

frequency. The staff further noted that age-related degradation of non-metallic components, 

such as cracking and changes in material properties, can be detected by a visual inspection, 

coupled by a physical manipulation when appropriate, by evidence of surface discontinuities 

that include cracking, crazing, peeling, blistering, chalking, flaking, physical distortion, 

discoloration, loss of material from wear, and signs of leakage. The applicant amended its LRA, 

by letter dated December 5, 2008, to supplement the visual inspection with a physical 

manipulation when appropriate. The staff noted that this program will supplement the visual 
3-354

examination with a physical manipulation in order to verify aging effects such as hardening, 

embrittlement, or gross softening are not occurring. The staff noted that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component, or by the failure of the component to return to its previous shape 

or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to general 

corrosion, crevice corrosion, galvanic corrosion, and MIC in carbon steel bolting and fasteners 

exposed to a buried environment using the Bolting Integrity Program. The AMR line item cites 

Generic Note G, which indicates that the environment is not addressed in the GALL Report for 

this component and material. The AMR line item also cites Plant-Specific Note 306, which 

indicates that components that are buried in the ground are analyzed in the same manner as 

raw water (damp soil containing groundwater).

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will manage the loss 

of material for buried bolts and fasteners through the implementation of the Buried Piping and 

Tanks Inspection Program. This program is documented in PINGP LRA AMP B2.1.8, “Buried 

Piping and Tanks Inspection Program.” The staff’s evaluation of the Buried Piping and Tanks 

Inspection Program is documented in SER Section 3.0.3.1.7. The staff reviewed the Buried 

Piping and Tanks Inspection Program to verify that loss of material for buried carbon steel bolts 

and fasteners will be managed in accordance with the recommendations specified by the 

Bolting Integrity Program. On the basis of its review, the staff finds that because these 

components will be inspected through the specifications of the Bolting Integrity Program, which 

are implemented by the Buried Piping and Tanks Inspection Program, they will be adequately 

managed.

In LRA Table 3.3.2-6, the applicant proposed to manage loss of preload due to thermal gasket 

creep, and loosening for carbon steel bolting and fasteners exposed to a buried environment 

using the Bolting Integrity Program. The AMR line item cites Generic Note G, which indicates 

that the environment is not addressed in the GALL Report for this component and material. The 

AMR line item also cites Plant-Specific Note 306, which indicates that components that are 

buried in the ground are analyzed in the same manner as raw water (damp soil containing 

groundwater).

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will manage the loss 

of preload for buried bolts and fasteners through the implementation of the Buried Piping and 

Tanks Inspection Program. This program is documented in PINGP LRA AMP B2.1.8, “Buried 

Piping and Tanks Inspection Program.” The staff’s evaluation of the Buried Piping and Tanks 

Inspection Program is documented in SER Section 3.0.3.1.7. The staff reviewed the Buried 
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Piping and Tanks Inspection Program to verify that loss of preload for buried carbon steel bolts 

and fasteners will be managed in accordance with the recommendations specified by the 

Bolting Integrity Program. On the basis of its review, the staff finds that because these 

components will be inspected through the specifications of the Bolting Integrity Program, which 

are implemented by the Buried Piping and Tanks Inspection Program, they will be adequately 

managed.

LRA Table 3.3.2-6 summarizes the results of AMRs for the cooling water system valve bodies 

constructed from PVC exposed to raw water (internal). The applicant proposed no aging effect 

and therefore states that no AMP is required.

The applicant has indicated that Generic Note F is applicable for these items with Plant-Specific

Note 313. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-Specific 

Note 313 states, “Materials science evaluation for this material in this environment results in no 

aging effects." The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC is has no aging effect when in contact with raw water (Roff, W. J., Fibres, Plastics, 

and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956.)

In LRA Table 3.3.2-6, the applicant proposed to manage loss of material-selective leaching in 

copper alloy heat exchanger tubes in a wet air/gas external environment by using the Selective 

Leaching of Materials Program. The applicant referenced Footnote H for this line item indicating 

that the aging effect is not in the GALL Report for these components, material, and environment 

combinations. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection credited under the applicant’s 

Selective Leaching Program is consistent with the one-time inspection basis credited in 

GALL AMP XI.M33, "Selective Leaching," for component materials that are identified as being 

susceptible to selective leaching. The staff also noted that Table IX.C in the 

GALL Report Volume 2 identifies that copper alloys with greater than 15 percent alloying zinc 

content, aluminum bronzes with greater than 8 percent aluminum alloying contents and cast 

irons may be susceptible to selective leaching. On this basis, the staff finds the Selective 

Leaching of Materials Program is a valid program to credit for the management of loss of 

material due to selective leaching in these copper alloy piping and fittings because the basis is 

consistent with: (1) the basis in GALL Table IX.C, which identifies that copper alloys with greater 

than 15 percent alloying zinc contents may be susceptible to selective leaching, and (2) the 

basis in GALL AMP XI.M33 which states that the one-time inspection proposed in the Selective

Leaching Program is an acceptable basis for managing loss of material in for copper alloy, 

aluminum bronze and cast iron components as a result of selective leaching.
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In LRA Table 3.3.2-6, the applicant credited its Bolting Integrity Program to manage loss of 

material due to general corrosion, pitting corrosion, crevice corrosion, galvanic corrosion, and

MIC for carbon steel bolting and fasteners that are externally exposed to a raw water 

environment. The AMR line item cites Generic Note G, which indicates that the environment is 

not addressed in the GALL Report for this component and material. 

The LRA credits the PINGP AMP B2.1.6, “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The staff noted that the applicant’s Bolting Integrity Program is an existing PINGP 

program that manages the aging effects of loss of material and loss of preload aging effects for 

carbon steel bolts and fasteners in a raw water environment. The staff also noted that the 

applicant accomplishes this through its implementation of the “RG 1.127 Inspection of WaterControl Structures Associated with Nuclear Power Plants Program” which is discussed in 

PINGP LRA AMP B2.1.35, RG 1.127 Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program. The staff’s evaluation of the RG 1.127, Inspection of WaterControl Structures Associated with Nuclear Power Plants Program is documented in SER 

Section 3.0.3.2.14. The staff reviewed the RG 1.127 Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program, to verify that loss of material and loss of 

preload for carbon steel bolts and fasteners in a raw water environment will be managed in 

accordance with the recommendations specified by the Bolting Integrity Program. On the basis 

of its review, the staff finds that because these components will be inspected through the 

specifications of the Bolting Integrity Program, which are implemented by the RG 1.127 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program, they will 

be adequately managed. 

On the basis of its review for the cooling water system components, the staff finds that the 

applicant has appropriately evaluated the AMR results of material, environment, AERM, and 

AMP combinations not evaluated in the GALL Report. The staff finds that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.3.2.3.7 Diesel Generator and Screenhouse Ventilation System - Summary of Aging 

Management Review – LRA Table 3.3.2-7 

The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for the 

diesel generator and screenhouse ventilation system component groups.

In LRA Table 3.3.2-7, the applicant proposed to manage change in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for tanks 

fabricated from acrylonitrile-butadiene stryene (ABS) rubber exposed to an external 

uncontrolled, plant indoor air environment. The External Surfaces Monitoring Program manages 

this AMR line item. The AMR line items cite Generic Note F, which indicates that the material is 

not addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 
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of GALL AMP XI.M36, “External Surfaces Monitoring” to include non-metallic components, 

including ABS, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff noted that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further noted that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff noted that this program will supplement the 

visual examination with a physical manipulation in order to verify that aging effects such as 

hardening, embrittlement, or gross softening are not occurring. The staff noted that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component or by the failure of the component to return to its previous shape or 

configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

LRA Table 3.3.2-7 summarizes the results of AMRs for the piping and fittings constructed from 

ABS and exposed to raw water (internal). The applicant proposed no aging effect and therefore 

stated that no AMP is required.

The applicant has indicated that Generic Note F is applicable for these items with plant-specific

Note 313. Generic Note F is “[m]aterial not in NUREG-1801 for this component.” Plant-specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects. The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that ABS has no aging effect when exposed to raw water. (Harper C.A., Handbook of plastic 

and elastomers, McGraw-Hill, New York, 1975, pp. 1-3,1-62, 2-42, 3-1.)

On the basis of its review for the diesel generator and screenhouse ventilation system 

components, 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 
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staff finds that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.8 Diesel Generators and Support System - Summary of Aging Management Review –

LRA Table 3.3.2-8 

The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for the 

diesel generator and support system component groups.

In LRA Table 3.3.2-8, the applicant proposed to manage change in material properties due to 

thermal exposure and cracking due to thermal exposure for flex connections fabricated from 

natural rubber exposed to an internal treated water environment. The External Surfaces 

Monitoring Program manages these AMR line items. The AMR line items cite Generic Note H, 

which indicates that the aging effect is not addressed in the GALL Report for this component, 

material and environment combination.

The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 

including natural rubber, and the aging effects of change in material properties and cracking.

The staff further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

During its review the staff notes that the applicant utilized a plant-specific note which indicates 

that this program is credited to manage aging of internal surfaces because the external surfaces 

are subject to the same environment or stressor as the internal surfaces. The staff notes that 

the applicant’s use of this program is consistent with the recommendations in the GALL Report.

However, the staff determined that additional information was needed pertaining to the internal 

and external environments of these natural rubber components. Therefore, by letter dated 

December 18, 2008, the staff issued RAI 3.3.2-08-01 requesting the applicant to clarify the 

external environment of these components, and to consider the program’s ability to manage 

aging in non-metallic components. By letter dated January 20, 2009, the applicant responded to 

RAI 3.3.2-08-01 by stating that the external environment is plant-indoor air – uncontrolled and is 

not identical to the internal environment of treated water. The applicant further stated that the 

external thermal stressor (i.e., temperature), which can cause cracking and changes in material 

properties for non-metallic components, is the same as the internal environment. The staff notes 

that the applicant’s statement is reasonable because these natural rubber flex connections are 

not insulated; therefore, the external surface of these components will be representative of the 

temperature of the internal treated water environment. The staff further notes that the external 

surface may be subject to ultraviolet and ozone exposure which can contribute to the aging 

effects of cracking and change in material properties in non-metallic components. Furthermore, 
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the staff notes this additional exposure may potentially create a more aggressive environment 

on the external surface when compared to the internal environment. On the basis of its review, 

the staff finds the applicant’s response acceptable because the external environment is 

potentially more aggressive than the internal environment; therefore, the applicant’s program, 

which performs inspections on the external surface of these components, will be representative 

of the conditions on the external surface.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes that this program will supplement the 

visual examination with a physical manipulation in order to verify aging effects such as 

hardening, embrittlement, or gross softening are not occurring. Further, the staff notes that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-8, the applicant proposed to manage heat transfer degradation due to 

fouling for heat exchanger tubes fabricated from carbon steel and copper alloy exposed to an 

external uncontrolled plant indoor air environment. The External Surfaces Monitoring Program 

manages these AMR line items. The AMR line items cite Generic Note H, which indicates that 

the aging effect is not addressed in the GALL Report for this component, material and 

environment combination. The applicable heat exchangers are located within the diesel 

generator and support system with the external side of the tubes exposed to an external 

uncontrolled plant indoor air environment.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that the External Surfaces 

Monitoring Program will include periodic visual inspections of external surfaces performed 

during system walkdowns at a specified frequency. The staff further notes that these periodic 

visual inspections are adequate to manage heat transfer degradation due to fouling for carbon 

steel and copper alloy heat exchanger tubes exposed to external uncontrolled plant indoor air 

environment addressed by this AMR because a visual inspection will be capable of detecting 

any fouling (buildup from whatever source) on the external surface of the carbon steel and 

copper alloy heat exchanger tube. On the basis of periodic visual inspections being performed 

during system walkdowns at a specified frequency of these components by the PINGP AMP 
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B2.1.14, “External Surfaces Monitoring,” for heat transfer degradation due to fouling, the staff 

finds the applicant's use of the External Surfaces Monitoring Program acceptable.

In LRA Table 3.3.2-8, the applicant proposed to manage cracking due to SCC/IGA for piping/ 

fittings made of copper alloy and for valve bodies made of brass or bronze exposed to a fuel oil 

environment using the Fuel Oil Chemistry Program and the One-Time Inspection Program. For 

these AMR results the applicant cited Generic Note H, indicating that the aging effect is not in 

the GALL Report for this component, material and environment combination.

The staff reviewed the applicant’s Fuel Oil Chemistry Program. The staff’s evaluation, which is 

documented in SER Section 3.0.3.2.9, found that this program provides for periodic sampling of 

fuel oil and periodic, draining, cleaning and visual inspection of fuel tanks to maintain 

contaminants at acceptable limits. The staff noted that the Fuel Oil Chemistry Program is 

focused on periodic sampling and testing of stored fuel oil and testing of new fuel oil, and on 

periodic testing and examination of the fuel oil storage tanks. However, because the fuel oil 

storage tanks are the most likely source for contamination of the fuel oil, and fuel oil typically is 

not recirculated to the tanks, the staff finds it is reasonable to expect that maintaining fuel oil 

purity in the storage tanks is expected to result in purity of fuel oil going to individual 

components, such as piping/fittings and valve bodies that are part of the diesel generator fuel 

system. Furthermore, the staff does not expect cracking due to SCC/IGA to occur in copper 

alloy piping/fittings or in brass and bronze valve bodies exposed fuel oil.

The staff reviewed the applicant’s One-Time Inspection Program. The staff’s evaluation, which 

is documented in SER Section 3.0.3.1.18, determined that the One-Time Inspection Program is 

consistent with the One-Time Inspection AMP XI.M32, as described in the GALL Report. The 

staff determined that the One-Time Inspection Program uses established NDE techniques such 

as enhanced visual or volumetric examination to detect cracking and is adequate to detect the 

presence or note the absence of cracking due to SCC/IGA for components within its scope. The 

staff noted that the “program description” for GALL AMR.XI.M32 states that a one-time 

inspection program is appropriate to verify effectiveness of a mitigative AMP (e.g., the Fuel Oil 

Chemistry Program) and to confirm that the aging effect is not occurring or is occurring very 

slowly so as not to affect the component or structure intended function during the period of 

extended operation.

Because 1) the staff does not expect cracking due to SCC/IGA to occur in copper alloy 

piping/fittings or brass and bronze valve bodies exposed to fuel oil; 2) the applicant is crediting a 

mitigation program that is expected to maintain purity of fuel oil going to individual components; 

and 3) the applicant is confirming effectiveness of its mitigation program with an inspection 

program that is appropriate; the staff finds the applicant’s proposed AMPs for managing the 

aging effect for cracking due to SCC/IGA for piping/fittings made of copper alloy and for valve 

bodies made of brass or bronze exposed to fuel oil in the diesel generator system to be 

acceptable.

In LRA Table 3.3.2-8, the applicant proposed to manage loss of material-selective leaching in 

copper alloy heat exchanger components, heat exchanger tubes, heaters, piping, and fittings; 

brass valve bodies; and bronze valve bodies in an internal environment of hydraulic oil, fuel oil, 

and lubricating oil by using the Selective Leaching of Materials Program. The applicant 

referenced Footnote H for this line item indicating that the aging effect is not in the GALL Report 
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for these components, material, and environment combinations. The applicant also referenced a 

plant-specific note, which stated that for this line item loss of material due to selective leaching 

for copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil environment.

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection credited under the applicant’s Selective Leaching 

Program is consistent with the one-time inspection basis credited in GALL AMP XI.M33, 

"Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15 percent alloying zinc content, aluminum bronzes with greater than 

8 percent aluminum alloying contents and cast irons may be susceptible to selective leaching. 

On this basis, the staff finds the Selective Leaching of Materials Program is a valid program to 

credit for the management of loss of material due to selective leaching in these copper alloy 

piping and fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which 

identifies that copper alloys with greater than 15 percent alloying zinc contents may be 

susceptible to selective leaching, and (2) basis in GALL AMP XI.M33 that the one-time 

inspection proposed in Selective Leaching Program is an acceptable basis for managing loss of 

material in copper alloy, aluminum bronze and cast iron components as a result of selective 

leaching.

LRA Table 3.3.2-8 summarizes the results of AMRs for the Diesel Generator and Support 

System flexible connections constructed from natural rubber exposed to fuel oil (internal) and 

lubricating oil (internal). The applicant proposed no aging effect and therefore stated that no 

AMP is required.

The applicant has indicated that Generic Note G is applicable for these items with Plant-Specific

Note 313. Generic Note G is “Environment not in NUREG-1801 for this component and 

material.” Plant-Specific Note 313 states, “[m]aterials science evaluation for this material in this 

environment results in no aging effects." The staff confirmed that this environment is not in the 

GALL Report for this component and material. The staff does not agree that there will not be an 

aging mechanism for this material/environment combination and that no AMP is required. This 

conclusion is based on the fact that natural rubber is not resistant to lubricating oil and fuel oil. 

(P.A. Schweitzer, “Corrosion Resistance Tables – Metals, Nonmetals, Coatings, Mortars, 

Plastics, Elastomers and Linings, and Fabrics,” Fourth Edition, Part B, Marcel Dekker, Copyright 

1995.) By letter dated March 31, 2009, RAI 3.3.2-8-1 was sent to the applicant asking the 

applicant to justify the use of natural rubber in fuel oil and lubricating oil with no aging effects 

and no need for an aging management program. In a letter dated April 6, 2009, the applicant 

provided its response to RAI 3.3.2-8-1. The applicant stated that certain rubber hoses were 

identified as being made of natural rubber when the actual materials could not be readily 

identified. The applicant agreed that natural rubber is not resistant to fuel oil or lubrication oil. 

The applicant stated that, in general, rubber flexible connections in the diesel generators and 
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support system are constructed using nitrile rubber or are lined with Teflon, both of which have 

outstanding resistance to oils. The applicant stated that based on vendor recommendations, the 

rubber flexible hoses in the diesel generators and support system will be periodically replaced 

and, therefore, are not subject to aging management review. The applicant has added a new 

License Renewal Commitment No. 43 which reads as follows:

“Preventive maintenance requirements will be implemented to require periodic replacement of 

rubber flexible hoses in the Diesel Generators and Support System that are exposed to fuel oil 

or lubricating oil internal environments.”

The applicant stated that conforming changes are made to the LRA as follows:

“In LRA Table 3.3.2-8, Auxiliary Systems – Diesel Generators and Support System – Summary 

of Aging Management Evaluation, on Page 3.3-156, the line items for Flex Connections / 

Natural Rubber / Fuel Oil (Int) and Lubricating Oil (Int), are deleted.”

Based on the information provided by the applicant, the staff agrees that these rubber hoses are 

not in-scope for license renewal because they are replaced on a periodic basis and are 

exempted from license renewal review as stated in 10 CFR Part 54.21(a)(1)(ii).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.9 Fire Protection System - Summary of Aging Management Review –

LRA Table 3.3.2-9 

The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for the 

fire protection system component groups.

In LRA Table 3.3.2-9, the applicant proposed to manage heat transfer degradation due to 

fouling for heat exchanger tubes fabricated from copper alloy exposed to an external 

uncontrolled plant outdoor air environment. The applicant credits PINGP AMP B2.1.14,

“External Surfaces Monitoring Program,” for aging management. The AMR line items cite 

Generic Note H, which indicates that the aging effect is not addressed in the GALL Report for 

this component, material and environment combination. The applicable heat exchangers are 

located within the fire protection system with the external side of the tubes exposed to an 

external uncontrolled plant indoor air environment.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that the External Surfaces 

Monitoring Program will include periodic visual inspections of external surfaces performed 

during system walkdowns at a specified frequency. The staff further notes that these periodic 

visual inspections are adequate to manage heat transfer degradation due to fouling for copper 

alloy heat exchanger tubes exposed to external uncontrolled plant indoor air environment 

addressed by this AMR because a visual inspection will be capable of detecting any fouling 
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(buildup from whatever source) on the external surface of the copper alloy heat exchanger tube.

On the basis of periodic visual inspections being performed during system walkdowns at a 

specified frequency of these components by the PINGP AMP B2.1.14, “External Surfaces 

Monitoring,” for heat transfer degradation due to fouling, the staff finds the applicant's use of the 

External Surfaces Monitoring Program acceptable.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to crevice and 

pitting corrosion for spray nozzles fabricated from copper alloy exposed to an external nonsheltered outdoor air environment. The applicant credits PINGP AMP B2.1.14 “External 

Surfaces Monitoring Program,” for aging management. The AMR line items cite Generic Note H, 

which indicates that the aging effect is not addressed in the GALL Report for this component, 

material and environment combination.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that the External Surfaces 

Monitoring Program will include periodic visual inspections of external surfaces performed 

during system walkdowns at a specified frequency. The staff further notes that these periodic 

visual inspections are adequate to manage loss of material due to crevice and pitting corrosion 

for copper alloy spray nozzles exposed to external non-sheltered outdoor air environment 

addressed by this AMR because a visual inspection will be capable of detecting any surface 

deterioration and degradation on the external surface of the copper alloy spray nozzles. On the 

basis of periodic visual inspections being performed during system walkdowns at a specified

frequency of these components by the PINGP AMP B2.1.14, “External Surfaces Monitoring,” for 

loss of material due to crevice and pitting corrosion, the staff finds the applicant's use of the 

External Surfaces Monitoring Program acceptable.

In LRA Table 3.3.2-9, the applicant proposed to manage change in material properties due to 

thermal exposure and cracking due to thermal exposure for flex connections fabricated from 

rubber exposed to an internal treated water environment. The AMR line items cite Generic Note 

H, which indicates that the aging effect is not addressed in the GALL Report for this component, 

material and environment combination.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 

including rubber, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

During its review, the staff notes that the applicant utilized a plant-specific note, which indicates 

that this program is credited to manage aging of internal surfaces because the external surfaces 

are subject to the same environment or stressor as the internal surfaces. The staff notes that 
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the applicant’s use of this program is consistent with the recommendations in the GALL Report.

However, the staff determined that additional information was needed pertaining to the internal 

and external environments of these rubber components. Therefore, by letter dated 

December 18, 2008, the staff issued RAI 3.3.2-08-01 requesting the applicant to clarify the 

external environment of these components, and to consider the program’s ability to manage 

aging in non-metallic components. By letter dated January 20, 2009, the applicant responded to 

RAI 3.3.2-08-01 by stating that the external environment is plant-indoor air – uncontrolled and is 

not identical to the internal environment of treated water. The applicant further stated the 

external thermal stressor (i.e. temperature), that can cause cracking and change in material 

properties for non-metallic components, is the same as the internal environment. The staff 

notes that the applicant’s statement is reasonable because these rubber flex connections are 

not insulated; therefore, the external surface of these components will be representative of the 

temperature of the internal treated water environment. The staff further notes that the external 

surface may be subject to ultraviolet and ozone exposure which can contribute to the aging 

effects of cracking and change in material properties in non-metallic components. Furthermore, 

the staff notes this additional exposure may potentially create a more aggressive environment 

on the external surface when compared to the internal environment. On the basis of its review, 

the staff finds the applicant’s response acceptable because the external environment is 

potentially more aggressive than the internal environment; therefore, the applicant’s program, 

which performs inspections on the external surface of these components, will be representative 

of the conditions on the external surface.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff noted that this program will supplement the 

visual examination with a physical manipulation in order to verify aging effects such as 

hardening, embrittlement, or gross softening are not occurring. The staff noted that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component, or by the failure of the component to return to its previous shape 

or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-9, the applicant proposed to manage cracking due to SCC/IGA for piping/ 

fittings made of copper alloy exposed to a fuel oil environment using the Fire Protection 

Program, the Fuel Oil Chemistry Program, and the One-Time Inspection Program. For these 

AMR results the applicant cited Generic Note H, indicating that the aging effect is not in the 

GALL Report for this component, material and environment combination.
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Because the applicant indicated use of three different AMPs to manage the aging effect, it was 

not clear whether all three AMPs are being credited for each piping/fitting component, or 

whether for some piping/fitting components the Fuel Oil Chemistry Program in combination with 

the Fire Protection Program is credited, and for other piping/fitting components the Fuel Oil 

Chemistry Program in combination with the One-Time Inspection Program is credited. In a letter 

dated December 18, 2008, the staff issued RAI 3.3.2-9-01 asking the applicant to clarify what 

combinations of AMPs are credited to manage the aging effect in the subject components.

The applicant responded to the RAI in a letter dated January 20, 2009. In that letter the 

applicant stated that for all copper alloy piping/fittings addressed in these AMR line items, the 

aging effect of cracking due to SCC/IGA is managed with all three of these AMPs: the Fire 

Protection Program, the Fuel Oil Chemistry Program, and the One-Time Inspection Program. 

The applicant further stated that the Fire Protection Program does not provide for mitigation of 

the aging effect but is credited with providing detection of the aging effect; however, the 

applicant further stated that the diesel-driven fire pump is under observation during performance 

tests and aging related degradation such as leakage will be observed, documented and 

evaluated. 

The staff finds the applicant RAI response acceptable because it clarifies that all three AMPs 

are credited to manage cracking due to SCC/IGA for piping/fittings made of copper alloy 

exposed to a fuel oil in the fire protection system. The staff noted the applicant’s statement that 

the diesel-driven fire pump is under observation during performance tests such as flow and 

discharge tests, and sequential starting capability tests, and any age-related degradation that 

results in leakages will be documented and evaluated. The staff finds this response consistent 

with GALL AMP XI.M26 recommendations that the pump be periodically performance tested to 

ensure that the fuel supply line can perform its intended function. 

The staff reviewed the Fire Protection Program and noted that this program stated that the 

diesel-driven fire pump inspection activities require that the pump be periodically performance 

tested. The staff issued RAI B2.1.15-1 by letter dated November 5, 2008, requesting the 

applicant to confirm how the periodic performance test will manage the aging effect of cracking 

in the fuel oil lines. In its letter dated December 5, 2008, in response to RAI B2.1.15-1, the 

applicant stated that in addition to the pump performance test, the internal surface of the dieseldriven fire pump fuel oil supply line is managed for cracking by the Fuel Oil Chemistry Program 

and the One-Time Inspection Program. The staff’s evaluation of the Fire Protection Program 

and the RAI response is documented in SER Section 3.0.3.2.6. 

The staff reviewed the applicant’s Fuel Oil Chemistry Program. The staff’s evaluation, which is 

documented in SER Section 3.0.3.2.9, found that this program provides for periodic sampling of 

fuel oil and periodic, draining, cleaning and visual inspection of fuel tanks to maintain 

contaminants at acceptable limits. The staff noted that the Fuel Oil Chemistry Program is 

focused on periodic sampling and testing of stored fuel oil and testing of new fuel oil, and on 

periodic testing and examination of the fuel oil storage tanks. However, because the fuel oil 

storage tanks are the most likely source for contamination of the fuel oil, and fuel oil typically is 

not recirculated to the tanks, the staff finds it is reasonable to expect that maintaining fuel oil 

purity in the storage tanks is expected to result in purity of fuel oil going to individual 

components, such as piping/fittings and valve bodies that are part of the diesel generator fuel 
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system. Furthermore, the staff does not expect cracking due to SCC/IGA to occur in copper 

alloy piping/fittings exposed fuel oil.

The staff reviewed the applicant’s One-Time Inspection Program. The staff’s evaluation, which 

is documented in SER Section 3.0.3.1.18, determined that the One-Time Inspection Program is 

consistent with the One-Time Inspection AMP XI.M32, as described in the GALL Report. The 

staff determined that the One-Time Inspection Program uses established NDE techniques such 

as enhanced visual or volumetric examination to detect cracking and is adequate to detect the 

presence or note the absence of cracking due to SCC/IGA for components within its scope. The 

staff noted that the “program description” for GALL AMP.XI.M32, “One-Time Inspection,” states 

that a one-time inspection program is appropriate to verify effectiveness of a mitigative AMP

(e.g., the Fuel Oil Chemistry Program) and to confirm that the aging effect is not occurring or is 

occurring very slowly so as not to affect the component or structure intended function during the 

period of extended operation.

Because 1) the staff does not expect cracking due to SCC/IGA to occur in copper alloy 

piping/fittings or brass and bronze valve bodies exposed to fuel oil; 2) the applicant is crediting a 

mitigation program that is expected to maintain purity of fuel oil going to individual components;

3) the applicant is confirming effectiveness of its mitigation program with a one-time inspection 

program that is appropriate; and 4) the applicant is crediting diesel fire pump testing in the Fire 

Protection Program with providing additional confirmation that age-related degradation is not 

occurring, the staff finds the applicant’s proposed AMPs for managing the aging effect for 

cracking due to SCC/IGA for piping/fittings made of copper alloy and for valve bodies made of 

brass or bronze exposed to a fuel oil in the fire protection system to be acceptable.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to crevice, 

galvanic, general, pitting corrosion and MIC for carbon steel bolting and fasteners exposed to a 

buried environment using the Bolting Integrity Program. The AMR line item cites Generic Note 

G, which indicates that the environment is not addressed in the GALL Report for this component 

and material. The AMR line item also cites Plant-Specific Note 306, which indicates that 

components that are buried in the ground are analyzed in the same manner as raw water (damp 

soil containing groundwater).

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that manages the loss of 

material for buried bolts and fasteners through the implementation of the Buried Piping and 

Tanks Inspection Program. This program is documented in PINGP LRA AMP B2.1.8, “Buried 

Piping and Tanks Inspection Program.” The staff’s evaluation of the Buried Piping and Tanks 

Inspection Program is documented in SER Section 3.0.3.1.7. The staff reviewed the Buried 

Piping and Tanks Inspection Program to verify that loss of material for buried carbon steel bolts 

and fasteners will be managed in accordance with the recommendations specified by the 

Bolting Integrity Program. On the basis of its review, the staff finds that because these 

components will be inspected through the specifications of the Bolting Integrity Program, which 

is implemented by the Buried Piping and Tanks Inspection Program, they will be adequately 

managed.
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In LRA Table 3.3.2-9, the applicant proposed to manage loss of preload due to thermal gasket 

creep, and loosening for carbon steel bolting and fasteners exposed to a buried environment 

using the Bolting Integrity Program. The AMR line item cites Generic Note G, which indicates 

that the environment is not addressed in the GALL Report for this component and material. The 

AMR line item also cites Plant-Specific Note 306, which indicates that components that are 

buried in the ground are analyzed in the same manner as raw water (damp soil containing 

groundwater).

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will manage the loss 

of preload for buried bolts and fasteners through the implementation of the Buried Piping and 

Tanks Inspection Program. This program is documented in PINGP LRA AMP B2.1.8, “Buried 

Piping and Tanks Inspection Program.” The staff’s evaluation of the Buried Piping and Tanks 

Inspection Program is documented in SER Section 3.0.3.1.7. The staff reviewed the Buried 

Piping and Tanks Inspection Program to verify that loss of preload for buried carbon steel bolts 

and fasteners will be managed in accordance with the recommendations specified by the 

Bolting Integrity Program. On the basis of its review, the staff finds that because these 

components will be inspected through the specifications of the Bolting Integrity Program, which 

is implemented by the Buried Piping and Tanks Inspection Program, they will be adequately 

managed.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of preload due to thermal, gasket 

creep, and loosening for carbon steel bolts and fasteners externally exposed to an outdoor airsheltered environment using the Bolting Integrity Program. The AMR line item cites Generic 

Note G, which indicates that the environment is not addressed in the GALL Report for this 

component and material. The AMR line item also cites Plant-Specific Note 304, which indicates 

that SCC is not an applicable aging effect/mechanism since there are no bolts with a minimum 

yield strength > 150 ksi (> 150,000 psi). 

The LRA credits the PINGP AMP B2.1.6, “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 

3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will manage the loss 

of preload due to thermal effects, gasket creep, and self loosening. As described in EPRI 

NP-5067, the loss of preload aging effect is most common in high temperature environments.

However, thermal cycling as may be experienced in outdoor environments during the change 

from summer to winter months can also contribute to a loss of preload. The applicant clearly 

states in LRA section AMP B2.1.6, “Bolting Integrity Program,” that loss of preload (leaking or 

loose bolts/nuts) for closure and structural bolting is inspected periodically. These periodic 

inspections monitor for indications of the loss of preload. On the basis of its review, the staff 

finds that because these components will be inspected through the specifications of the Bolting 

Integrity Program, they will be adequately managed.

In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to selective 

leaching in copper alloy piping and fittings exposed to internal environment of fuel oil and in 

spray nozzles exposed to outdoor air-not sheltered external environment by using the Selective 

Leaching of Materials Program. The applicant referenced Footnote H for these line items 

indicating that the aging effect is not in the GALL Report for this component-material-
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environment combination. The applicant also referenced a plant-specific note which stated that 

for these line items loss of material due to selective leaching for copper alloys and gray cast iron 

is evaluated in a fuel oil and lubricating oil internal environment.

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection credited under the applicant’s Selective Leaching 

Program is consistent with the one-time inspection basis credited in GALL AMP XI.M33, 

"Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C states that copper 

alloys with greater than 15 percent alloying zinc content, aluminum bronzes with greater than 8

percent aluminum alloying contents and cast irons may be susceptible to selective leaching. On 

this basis, the staff finds the Selective Leaching of Materials Program is a valid program to 

credit for the management of loss of material due to selective leaching in these copper alloy 

piping and fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which 

identifies that copper alloys with greater than 15 percent alloying zinc contents may be 

susceptible to selective leaching, and (2) basis in GALL AMP XI.M33 that the one-time 

inspection proposed in Selective Leaching Program is an acceptable basis for managing loss of 

material in for copper alloy, aluminum bronze and cast iron components as a result of selective 

leaching. 

LRA Table 3.3.2-9, summarizes the results of AMRs for the Fire Protection System flexible 

connections made of natural rubber exposed to halon gas (internal). The applicant proposes 

that for these combinations of components, materials and environment conditions, there is no 

AERM and therefore that no AMR is required. 

The applicant has indicated that Generic Note G is applicable for these items with Plant-Specific

Note 313. Generic Note G is “Environment not in NUREG-1801 for this component and 

material.” Plant-Specific Note 313 states, “Materials science evaluation for this material in this 

environment results in no aging effects." The staff confirmed that this environment is not in 

GALL for these components and materials. The staff also agrees that there will not be an aging 

mechanism for this material/environment combination and that no AMP is required. DuPont, the 

manufacturer of halon, has conducted tests on natural rubber exposed to halon and 

demonstrated that there is no aging effect.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
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3.3.2.3.10 Fuel Oil System - Summary of Aging Management Review – LRA Table 3.3.2-10 

The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations for 

the fuel oil system component groups.

In LRA Table 3.3.2-10, the applicant proposed to manage cracking due to SCC/IGA for piping/ 

fittings made of copper alloy and for valve bodies made of brass, bronze or copper alloy 

exposed to a fuel oil environment using the Fuel Oil Chemistry Program and the One-Time 

Inspection Program. For these AMR results the applicant cited generic Note H, indicating that 

the aging effect is not in the GALL Report for this component, material and environment 

combination.

The staff reviewed the applicant’s Fuel Oil Chemistry Program. The staff’s evaluation, which is 

documented in SER Section 3.0.3.2.9, found that this program provides for periodic sampling of 

fuel oil and periodic, draining, cleaning and visual inspection of fuel tanks to maintain 

contaminants at acceptable limits. The staff noted that the Fuel Oil Chemistry Program is 

focused on periodic sampling and testing of stored fuel oil and testing of new fuel oil, and on 

periodic testing and examination of the fuel oil storage tanks. However, because the fuel oil 

storage tanks are the most likely source for contamination of the fuel oil, and fuel oil typically is 

not recirculated to the tanks, the staff finds it is reasonable to expect that maintaining fuel oil 

purity in the storage tanks is expected to result in purity of fuel oil going to individual 

components, such as piping/fittings and valve bodies that are part of the diesel generator fuel 

system. Furthermore, the staff does not expect cracking due to SCC/IGA to occur in copper 

alloy piping/ fittings or in copper alloy, brass and bronze valve bodies exposed to fuel oil.

The staff reviewed the applicant’s One-Time Inspection Program. The staff’s evaluation, which 

is documented in SER Section 3.0.3.1.18, determined that the One-Time Inspection Program is 

consistent with the One-Time Inspection AMP XI.M32, as described in the GALL Report. The 

staff determined that the One-Time Inspection Program uses established NDE techniques such 

as enhanced visual or volumetric examination to detect cracking and is adequate to detect the 

presence or note the absence of cracking due to SCC/IGA for components within its scope. The 

staff noted that the “program description” for GALL AMR.XI.M32 states that a one-time 

inspection program is appropriate to verify effectiveness of a mitigative AMP (e.g., the Fuel Oil 

Chemistry Program) and to confirm that the aging effect is not occurring or is occurring very 

slowly so as not to affect the component or structure intended function during the period of 

extended operation.

Because 1) the staff does not expect cracking due to SCC/IGA to occur in copper alloy 

piping/fittings or brass and bronze valve bodies exposed to fuel oil, 2) the applicant is crediting a 

mitigation program that is expected to maintain purity of fuel oil going to individual components, 

and 3) the applicant is confirming effectiveness of its mitigation program with an inspection 

program that is appropriate, the staff finds the applicant’s proposed AMPs for managing the 

aging effect for cracking due to SCC/IGA for piping/fittings made of copper alloy and for valve 

bodies made of brass or bronze exposed to a fuel oil in the fuel oil system to be acceptable.

In LRA Table 3.3.2-10, the applicant proposed to manage loss of material–selective leaching in 

cast iron filters, strainer housings, and pump casings, copper alloy valve bodies, piping and 

fittings, brass valve bodies and bronze valve bodies exposed to an internal environment of fuel 
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oil by using the Selective Leaching of Materials Program. The applicant referenced General 

Note H for these line items indicating that the aging effect is not in the GALL Report for this 

components, material, and environment combination. The applicant also referenced a plantspecific note, which stated that for these line items loss of material due to selective leaching for 

copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil internal environment. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection program credited under the applicant’s Selective 

Leaching Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15 percent alloying zinc content, aluminum bronzes with greater than 

8 percent aluminum alloying contents and cast irons may be susceptible to selective leaching. 

On this basis, the staff finds the Selective Leaching of Materials Program is a valid program to 

credit for the management of loss of material due to selective leaching in these copper alloy 

piping and fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which 

identifies that copper alloys with greater than 15 percent alloying zinc contents may be 

susceptible to selective leaching, and (2) basis in GALL AMP XI.M33 that the one-time 

inspection proposed in Selective Leaching Program is an acceptable basis for managing loss of 

material in for copper alloy, aluminum bronze and cast iron components as a result of selective 

leaching.

LRA Table 3.3.2-10 summarizes the results of an AMR for the Fuel Oil System flame arrestors 

constructed from aluminum and exposed to outdoor air - not sheltered. The applicant claims that 

for this combination of component, material, and environment there is no AERM and therefore 

states that no AMR is required.

The staff noted that the applicant has indicated that Generic Note G is applicable for these items 

with Plant-Specific Note 313. Nuclear Energy Institute (NEI) Standard Note G states 

“Environment not in NUREG-1801 for this component and material.” Plant-Specific Note 313 

states, “[m]aterials science evaluation for this material in this environment results in no aging 

effects." The staff noted that aluminum has an excellent resistance to corrosion when exposed 

to humid air (outdoor environment) because aluminum oxide film is bonded strongly to its 

surface and, if damaged, reforms immediately in most environments. In addition, the oxide film 

is only 5 to 10 nanometers thick but is highly effective in protecting (i.e. passivating) the 

aluminum from corrosion. 

The staff confirmed that this environment is not in the GALL Report for these components and 

materials. The staff also agrees that there is no aging effect for aluminum exposed to outdoor 

air. Aluminum alloys develop a passive film that quickly reforms if disturbed. (W. H. Ailor, 

Atmospheric Corrosion, McGraw-Hill, New York, 1986.)
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On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.11 Heating System - Summary of Aging Management Review – LRA Table 3.3.2-11 

The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations for 

the heating system component groups.

In LRA Table 3.3.2-11, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal steam environment. The 

applicant stated this is TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1).

The AMR line items cite Generic Note H, which indicates that the aging effect is not addressed 

in the GALL Report for this component, material and environment combination.

In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to general pitting, 

crevice, galvanic and MIC for carbon steel tanks exposed to an internal raw water environment 

using the Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The 

applicant stated this is a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1). 

The AMR line items cite Generic Note H, which indicates that the aging effect is not addressed 

in the GALL Report for this component, material and environment combination.

The LRA credits the PINGP AMP B2.1.22, "Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components," to manage this aging effect for tanks in a raw water (internal) 

environment only. The staff's review of the applicant's Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and its evaluation is documented in 

SER Sections 3.0.3.1.13. The staff finds that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program performs periodic visual inspections of 

internal surfaces during maintenance activities when the internal surface is accessible for visual 

inspections to detect aging effects that could result in a loss of the component's intended 

function. The staff finds that these visual inspections will be capable of detecting loss of material 

because evidence of material wastage will be visible on the internal surface of these 

components during the inspections. On the basis of its review, the staff finds that because these 

components will be inspected periodically by visual inspections when exposed to an internal raw 

water environment they will be adequately managed by this program.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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3.3.2.3.12 Miscellaneous Gas System - Summary of Aging Management Review –

LRA Table 3.3.2-12 

The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations for 

the miscellaneous gas system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.3.2-12 are consistent with the GALL Report.

3.3.2.3.13 Plant Sample System - Summary of Aging Management Review – LRA Table

3.3.2-13 

The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations for 

the plant sample system component groups.

In LRA Table 3.3.2-13, the applicant proposed to manage cracking due to SCC for heat 

exchanger components, piping/fittings, pump casings, tanks, and valve bodies made of carbon 

steel exposed to a treated water environment using the Closed-Cycle Cooling Water System 

Program. For these AMR results the applicant cited Generic Note H, indicating that the aging 

effect is not in the GALL Report for this component, material and environment combination.

The staff noted that cracking due to SCC is not normally associated with carbon steel 

components and also that the Closed-Cycle Cooling Water System Program does not include 

examination techniques capable of detecting cracking in carbon steel components. In a letter 

dated December 18, 2008, the staff issued RAI 3.3.2-13-01 asking the applicant to provide a 

basis for expecting that cracking due to SCC may occur in carbon steel components in the plant 

sample system. The staff also asked the applicant to provide an examination technique for 

detection of cracking in these carbon steel components, or to explain why such an examination 

is not needed.

The applicant responded to the RAI in a letter dated January 20, 2009. In the response the 

applicant stated that to control anaerobic bacteria in the cold lab sample chiller, which is a part 

of the plant sample system, the cold lab sample chiller was drained, flushed and refilled with an 

approximately 50/50 mix of fleet-charge antifreeze which also contains a nitrite-based corrosion 

inhibitor. The applicant stated that EPRI 1010639, Non-Class 1 Mechanical Implementation 

Guidelines and Mechanical Tools, Revision 4, January 2006, describes one reported case 

suspected to be nitrite-induced SCC of carbon steel in a treated water system with a nitrite 

based corrosion inhibitor. The applicant stated that their cold lab sample chiller has 

environmental conditions similar to those described in the EPRI document where SCC of carbon 

steel may have occurred. The applicant stated that cracking due to SCC was conservatively 

assumed to occur in the plant sample system hot and cold lab sample chiller components made 

of carbon steel.

The applicant stated that the Closed-Cycle Cooling Water System Program is both a preventive 

and condition monitoring program based on EPRI’s “Closed Cooling Water Chemistry 

Guideline.” The applicant stated that the program includes preventive measures to minimize 

corrosion, heat transfer degradation, and SCC. The applicant stated that the program performs 

inspections to identify corrosion, fouling and SCC that may be present. The applicant further 
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stated that inspections for SCC will be performed by visual examination with a magnified 

resolution (i.e., enhanced visual) as described in 10 CFR 50.55a(b)(2)(xxi)(A) or with ultrasonic 

methods. As part of its RAI response, the applicant revised an enhancement to the “monitoring 

and trending” program element of the Closed-Cycle Cooling Water System Program to state 

explicitly that enhanced visual or volumetric examination techniques will be used to detect 

cracking.

The staff’s evaluation of the applicant’s change to Closed-Cycle Cooling Water System 

Program’s enhancement is documented in SER Section 3.0.3.2.2. The staff found the revised 

enhancement to be acceptable as documented in SER Section 3.0.3.2.2.

The staff reviewed the applicant’s Closed-Cycle Cooling Water System Program. The staff’s 

evaluation, which is documented in SER Section 3.0.3.2.2, determined that the Closed-Cycle 

Cooling Water System Program is consistent with the Closed-Cycle Cooling Water System 

AMP XI.M21, as described in the GALL Report, with acceptable exceptions and enhancement. 

Based both on its review of the Closed-Cycle Cooling Water System Program and on the 

applicant’s response to RAI AMR-3.3.2-13-01, the staff finds that the Closed-Cycle Cooling 

Water System Program, when enhanced, uses NDE techniques such as enhanced visual or 

volumetric examination to detect cracking and is adequate to detect the presence or note the 

absence of cracking due to SCC for components within its scope. 

The staff finds that the applicant’s amended aging management basis, as amended in the 

applicant’s response to RAI 3.3.2-13-01 is acceptable because: (1) applicant has conservatively 

assumed that SCC may occur in these carbon steel components under exposure to treated 

water; (2) GALL AMP XI.M21, “Closed Cycle Cooling Water System,” indicates that these 

programs are appropriate to use for heat exchanger and piping components that are exposed to 

treated water in closed-cycle cooling water systems; and (3) the applicant has enhanced the 

Closed-Cycle Cooling Water System Program to include both preventive measures to decrease 

the likelihood of SCC and examination techniques capable of detecting the presence of SSC. 

Thus based on this determination, the staff finds the applicant’s use of the Closed-Cycle Cooling 

Water System Program to manage the aging effect of cracking due to SCC in carbon steel 

components exposed to treated water in the plant sample system to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.14 Primary Containment Ventilation System - Summary of Aging Management Review 

– LRA Table 3.3.2-14 

The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations for 

the primary containment ventilation system component groups.

By letter dated April 13, 2009, the applicant submitted its annual update to the LRA. The 

applicant stated that heat exchanger tubes in certain ventilation air coolers are normally in 

service and may potentially be exposed to condensation. The applicant further stated that this 
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should have been evaluated for an external environment of wet air/gas (external), but were 

incorrectly evaluated as plant indoor air – uncontrolled (external) or primary containment air 

(external). The staff noted that exposure to condensation may result in aging related 

degradation that was not initially accounted for when these components were evaluated in a 

plant indoor air - uncontrolled or primary containment air environment. In LRA Table 3.3.2-14, 

the applicant proposed to manage heat transfer degradation due to fouling for heat exchanger 

tubes fabricated from copper alloy (copper-nickel) exposed to a wet air/gas (external) 

environment. The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring 

Program,” for aging management. The AMR line items cite Generic Note H, which indicates that 

the aging effect is not addressed in the GALL Report for this component, material and 

environment combination. The applicable heat exchangers are located within the Primary 

Containment Ventilation System with the external side of the tubes exposed to a wet air/gas 

(external) environment.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that the External Surfaces 

Monitoring Program will include periodic visual inspections of external surfaces performed 

during system walkdowns at a specified frequency. The staff further notes that these periodic 

visual inspections are adequate to manage heat transfer degradation due to fouling for carbon 

steel and copper alloy (copper-nickel) heat exchanger tubes exposed to wet air/gas (external) 

environment addressed by this AMR because a visual inspection will be capable of detecting 

any fouling (buildup from whatever source) on the external surface of the carbon steel and 

copper alloy (copper-nickel) heat exchanger tube. On the basis of periodic visual inspections 

being performed during system walkdowns at a specified frequency of these components by the 

PINGP AMP B2.1.14, “External Surfaces Monitoring,” for heat transfer degradation due to 

fouling, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-14, the applicant proposed to manage loss of material due to selective 

leaching in copper nickel heat exchanger tubes in a wet air/gas external environment by using 

the Selective Leaching of Materials Program. The applicant referenced Footnote H for this line 

item indicating that the aging effect is not in the GALL Report for these components, material, 

and environment combinations. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection credited under the applicant’s Selective Leaching of 

Materials Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that Table IX.C in the GALL Report Volume 2 identifies 

that copper alloys with greater than 15 percent alloying zinc content, aluminum bronzes with 

greater than 8 percent aluminum alloying contents and cast irons may be susceptible to 
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selective leaching. On this basis, the staff finds the Selective Leaching of Materials Program is a 

valid program to credit for the management of loss of material due to selective leaching in these 

copper alloy heat exchanger tubes because the basis is consistent with: (1) the basis in GALL 

Table IX.C, which identifies that copper alloys with greater than 15 percent alloying zinc 

contents may be susceptible to selective leaching, and (2) basis in GALL AMP XI.M33 that the 

one-time inspection proposed in Selective Leaching Programs is an acceptable basis for 

managing loss of material in for copper alloy, aluminum bronze and cast iron components as a 

result of selective leaching. 

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.15 Radiation Monitoring System - Summary of Aging Management Review –

LRA Table 3.3.2-15 

The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations for 

the radiation monitoring system component groups. The staff determined that all AMR 

evaluation results in LRA Table 3.3.2-15 are consistent with the GALL Report.

3.3.2.3.16 Spent Fuel Pool Cooling System - Summary of Aging Management Review –

LRA Table 3.3.2-16 

The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations for 

the spent fuel pool cooling system component groups. The staff determined that all AMR 

evaluation results in LRA Table 3.3.2-16 are consistent with the GALL Report.

3.3.2.3.17 Station and Instrument Air System - Summary of Aging Management Review –

LRA Table 3.3.2-17 

The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations for 

the station and instrument air system component groups.

In LRA Table 3.3.2-17, the applicant proposed to manage change in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for flex 

connections fabricated from PVC exposed to an external uncontrolled plant indoor air 

environment. The AMR line items cite Generic Note F, which indicates that the material is not 

addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 

including PVC, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 
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November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant to provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes that this program will supplement the 

visual examination with a physical manipulation in order to verify aging effects such as 

hardening, embrittlement, or gross softening are not occurring. The staff notes that the physical 

manipulation will supplement and aid the visual inspection in detecting age-related degradation 

because changes in material properties, such as hardening and loss of strength, can be 

detected during manipulation of non-metallic components, when appropriate, by the relative 

inflexibility of the component, or by the failure of the component to return to its previous shape 

or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-17, the applicant proposed to manage loss of preload due to thermal, gasket 

creep, and loosening for copper alloy bolting and fasteners externally exposed to uncontrolled 

plant indoor air and primary containment air environments using the Bolting Integrity Program.

The AMR line item cites Generic Note H, which indicates that the aging effect is not addressed 

in the GALL Report for this component, material and environment combination. The AMR line 

item also cites Plant-Specific Note 304, which indicates that SCC is not an applicable aging 

effect/mechanism since there are no bolts with a minimum yield strength > 150 ksi (> 150,000 

psi). 

The LRA credits the PINGP AMP B2.1.6, “Bolting Integrity Program,” to manage this aging 

effect. The staff’s evaluation of the Bolting Integrity Program is documented in 

SER Section 3.0.3.2.1. The Bolting Integrity Program is an existing PINGP program that will 

manage the loss of preload through periodic inspection and preventive measures. The staff 

reviewed the Bolting Integrity Program to verify that loss of preload due to thermal effects, 

gasket creep, and self loosening will be managed in accordance with the recommendations 

specified by the Bolting Integrity Program. On the basis of its review, the staff finds that because 

these components will be inspected through the specifications of the Bolting Integrity Program, 

they will be adequately managed.

LRA Table 3.3.2-17 summarizes the results of AMRs for the station and instrument air system 

flexible connectors constructed from PVC exposed to dry, filtered air (internal). The applicant 
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proposes that this component, material, environment combination have no AERM and therefore 

no AMP is required.

The applicant has indicated that Generic Note F is applicable for these items with Plant-Specific

Note 313. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-Specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects.” The staff confirmed that this material is not in GALL for this component. The staff 

also agrees that there will not be any aging mechanism for this material/environment 

combination and that no AMP is required. This conclusion is based on the fact that PVC has no 

aging effect when in contact with raw water (Roff, W. J., Fibres, Plastics, and Rubbers: A 

Handbook of Common Polymers, Academic Press Inc., New York, 1956.)

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.18 Steam Exclusion System - Summary of Aging Management Review –

LRA Table 3.3.2-18 

The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations for 

the steam exclusion system component groups. The staff determined that all AMR evaluation 

results in LRA Table 3.3.2-18 are consistent with the GALL Report.

3.3.2.3.19 Turbine and Administration Building Ventilation System - Summary of Aging 

Management Review – LRA Table 3.3.2-19 

The staff reviewed LRA Table 3.3.2-19, which summarizes the results of AMR evaluations for 

the turbine and administration building ventilation system component groups. The staff 

determined that all AMR evaluation results in LRA Table 3.3.2-19 are consistent with the GALL 

Report.

3.3.2.3.20 Waste Disposal System - Summary of Aging Management Review –

LRA Table 3.3.2-20

The staff reviewed LRA Table 3.3.2-20, which summarizes the results of AMR evaluations for 

the waste disposal system component groups.

In LRA Table 3.3.2-20, the applicant proposed to manage change in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for tanks 

fabricated from PVC exposed to an external uncontrolled plant indoor air environment. The 

AMR line items cite Generic Note F, which indicates that the material is not addressed in the 

GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 
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including PVC, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes stated that this program will 

supplement the visual examination with a physical manipulation in order to verify aging effects 

such as hardening, embrittlement, or gross softening are not occurring. The staff notes that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-20, the applicant proposed to manage loss of material due to general, 

pitting, crevice, galvanic and MIC for carbon steel and stainless steel material for tanks exposed 

to an internal raw water environment using the Internal Inspection of Miscellaneous Piping and 

Ducting Components Program. The AMR line items cite Generic Note H, which indicates that 

the aging effect is not addressed in the GALL Report for this component, material and 

environment combination.

The LRA credits the PINGP AMP B2.1.22, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to manage this aging effect of tanks in a raw water (internal) 

environment only. The staff’s review of the applicant’s Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and its evaluation are documented in 

SER Sections 3.0.3.1.13. The staff finds that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program performs periodic visual inspections of 

internal surfaces during periodic system and component surveillance activities or during 

maintenance activities when the internal surface is accessible for visual inspections to detect 

aging effects that could result in a loss of the component's intended function. The staff finds that 

these visual inspections will be capable of detecting loss of material because evidence of 
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material wastage will be visible on the internal surface of these components during the 

inspections. On the basis of its review, the staff finds that because these components will be 

inspected periodically by visual inspections when exposed to an internal raw water environment 

they will be adequately managed by this program.

LRA Table 3.3.2-20 summarizes the results of AMRs for the waste disposal system flex 

connectors constructed using natural rubber exposed to raw water (internal). The applicant 

proposed that there is no aging effect for the material environment combination and that no 

AMR is required.

The applicant has indicated that Generic Note G is applicable for these items with Plant-Specific

Note 313. Generic Note G is “Environment not in NUREG-1801 for this component and 

material.” Plant-Specific Note 313 states, “[m]aterials science evaluation for this material in this 

environment results in no aging effects." The staff confirmed that this environment is not in the 

GALL Report for these components and materials. The staff also agrees that there will not be an 

aging mechanism for this material/environment combination and that no AMP is required.

Natural rubber is unaffected by raw water after exposure. (Phillip A. Schweitzer, PE, 

“Encyclopedia of Corrosion Technology,” Second Edition, Revised and Expanded, CRC Press, 

March 17, 2004.)

LRA Table 3.3.2-20 summarizes the results of AMRs for the waste disposal system tanks 

constructed using PVC exposed to raw water (internal). The applicant proposed no aging effect 

and therefore states that no AMP is required.

The applicant has indicated that Generic Note F is applicable for these items with Plant-Specific

Note 313. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-Specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects. The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC is has no aging effect when in contact with raw water (Roff, W. J., Fibres, Plastics, 

and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956.)

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 

3.3.2.3.21 Water Treatment System - Summary of Aging Management Review –

LRA Table 3.3.2-21

The staff reviewed LRA Table 3.3.2-21, which summarizes the results of AMR evaluations for 

the water treatment system component groups.

In LRA Table 3.3.2-21, the applicant proposed to manage change in material properties due to 

ozone and ultraviolet exposure and cracking due to ozone and ultraviolet exposure for 

demineralizers, piping, fittings, pump casings, thermowells and valve bodies fabricated from 
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PVC and tanks fabricated from fiberglass exposed to an external uncontrolled plant indoor air 

environment. The AMR line items cite Generic Note F, which indicates that the material is not 

addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14, “External Surfaces Monitoring Program,” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring,” to include non-metallic components, 

including PVC and fiberglass, and the aging effects of change in material properties and 

cracking. The staff further notes the intent of GALL AMP XI.M36 is to perform visual inspections 

of steel components for loss of material. The staff determined that additional information was 

needed on the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter 

dated November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff’s review of the applicant’s External Surfaces Monitoring Program and its evaluation 

are documented in SER Sections 3.0.3.2.5. The staff notes that this program will include 

periodic visual inspections of external surfaces performed during system walkdowns at a 

specified frequency. The staff further notes that age-related degradation of non-metallic 

components, such as change in material properties and cracking, can be detected by a visual 

inspection, coupled by a physical manipulation when appropriate, by evidence of surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes stated that this program will 

supplement the visual examination with a physical manipulation in order to verify aging effects 

such as hardening, embrittlement, or gross softening are not occurring. The staff notes that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation, when appropriate, being performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

In LRA Table 3.3.2-21, the applicant proposed to manage loss of material due to general, 

pitting, crevice, galvanic and MIC for carbon steel tanks exposed to an internal raw water 

environment using the Internal Inspection of Miscellaneous Piping and Ducting Components 

Program. The AMR line items cite Generic Note H, which indicates that the aging effect is not 

addressed in the GALL Report for this component, material and environment combination.

The LRA credits the PINGP AMP B2.1.22, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to manage this aging effect tanks in a raw water (internal) 

environment only. The staff’s review of the applicant's Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and its evaluation are documented in 
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SER Sections 3.0.3.1.13. The staff finds that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program performs periodic visual inspections of 

internal surfaces during periodic system and component surveillance activities or during 

maintenance activities when the internal surface is accessible for visual inspections to detect 

aging effects that could result in a loss of the component's intended function. The staff finds that

these visual inspections will be capable of detecting loss of material because evidence of 

material wastage will be visible on the internal surface of these components during the 

inspections. On the basis of its review, the staff finds that because these components will be 

inspected periodically by visual inspections when exposed to an internal raw water environment 

they will be adequately managed by this program.

LRA Table 3.3.2-21 summarizes the results of AMRs for the water treatment system

demineralizers, piping/fittings, pump casings, thermowells, and valve bodies constructed from 

PVC exposed to raw water (internal). The applicant proposed no aging effect and therefore 

states that no AMP is required.

The applicant has indicated that Generic Note F is applicable for these items with Plant-Specific

Note 313. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-Specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects." The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC has no aging effect when in contact with raw water (Roff, W. J., Fibres, Plastics, 

and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956.)

LRA Table 3.3.2-21 summarizes the results of AMRs for the water treatment system tanks 

constructed from fiberglass exposed to raw water (internal). The applicant proposed no aging 

effect and therefore states that no AMP is required.

The applicant has indicated that generic Note F is applicable for these items with Plant-Specific

Note 313. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-Specific 

Note 313 states, “[m]aterials science evaluation for this material in this environment results in no 

aging effects." The staff confirmed that this material is not in the GALL Report for this 

component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. Common uses of fiberglass 

include fiberglass swimming pools and boat hulls. Fiberglass is chosen for these applications 

because it does not have an aging effect when in contact with water. (Roff, W. J., Fibres, 

Plastics, and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 

1956.)

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3). 
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3.3.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the auxiliary systems components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4 Aging Management of Steam and Power Conversion System

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

steam and power conversion systems components and component groups of:

• auxiliary feedwater system

• bleed steam system

• circulating water system

• condensate system

• feedwater system

• main steam system

• steam generator blowdown system

• turbine generator and support system

3.4.1 Summary of Technical Information in the Application 

LRA Section 3.4 provides AMR results for the steam and power conversion systems 

components and component groups. LRA Table 3.4.1, “Summary of Aging Management 

Evaluations in Chapter VIII of NUREG-1801 for Steam and Power Conversion System,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

steam and power conversion systems 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 CRs 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.

3.4.2 Staff Evaluation 

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the steam and power conversion 

systems components within the scope of license renewal and subject to an AMR will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the AMR items that the applicant had identified as being 

consistent with the GALL Report to verify 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 
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the GALL Report; however, the staff did verify that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s audit 

evaluation are documented in SER Section 3.4.2.1.

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 3.4.2.2 acceptance criteria. The staff’s 

audit evaluations are documented in SER Section 3.4.2.2.

The staff also conducted a technical review of the remaining AMRs 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 3.4.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management, 

the staff reviewed the AMR line items and the plant’s 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 Systems 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 Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.1)

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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.2.1)
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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 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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 Not applicable (See 

SER Section 

3.4.2.2.9.)

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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

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 

(B2.1.24) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 

microbiologically

-influenced 

corrosion, and 

fouling

Plant-specific Yes Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report (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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.4.1)
3-385

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, 

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 

(B2.1.24)

and One-Time

Inspection 

Program 

(B2.1.29)

Consistent with 

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 micro 

biologically-influ

enced corrosion

Buried Piping and 

Tanks Surveillance 

or

Buried Piping and 

Tanks Inspection

No

Yes Buried Piping 

and Tanks 

Inspection 

Program 

(B2.1.8)

Consistent with 

GALL Report (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 

microbiologically 

influenced 

corrosion

Lubricating Oil 

Analysis and

One-Time Inspection

Yes Lubricating Oil

Analysis 

Program 

(B2.1.24)

and One-Time

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.5.2)

Stainless steel 

piping, piping 

components, piping 

elements exposed to 

steam

(3.4.1-13)

Cracking due to 

stress corrosion 

cracking

Water Chemistry and 

One-Time Inspection

Yes Not applicable Not applicable to 

PWRs (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 

stress corrosion 

cracking

Water Chemistry and 

One-Time Inspection

Yes Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.6)
3-386

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 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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time

Inspection 

Program 

(B2.1.29), or

Closed-Cycle 

Cooling Water 

Program 

(B2.1.9) or 

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

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 Water Chemistry 

Program 

(B2.1.40) and 

One-Time 

Inspection 

Program 

(B2.1.29)

Consistent with 

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 Not applicable to 

PINGP (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 

(B2.1.24)

and One-Time

Inspection

Program

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.7.3)
3-387

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, and heat 

exchanger 

components exposed 

to lubricating oil

(3.4.1-19)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

- influenced 

corrosion

Lubricating Oil 

Analysis and

One-Time Inspection

Yes Lubricating Oil

Analysis 

Program 

(B2.1.24)

and One-Time

Inspection

Program

(B2.1.29)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.2.8)

Steel tanks exposed 

to air - outdoor 

(external)

(3.4.1-20)

Loss of material, 

general, pitting, 

and crevice 

corrosion

Aboveground Steel 

Tanks

No Aboveground 

Steel Tanks 

Program

(B2.1.2)

Consistent with 

GALL Report

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage

(3.4.1-21)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Bolting Integrity No Not applicable Not applicable to 

PINGP (See SER 

Section 3.4.2.1.1)

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 selfloosening

Bolting Integrity No Bolting Integrity 

Program

(B2.1.6)

Consistent with 

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 

stress corrosion 

cracking

Closed-Cycle 

Cooling Water 

System

No Not applicable Not applicable (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 Not applicable Not applicable (See 

SER Section 

3.4.2.1.1)
3-388

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, 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 Closed-Cycle 

Cooling Water 

System Program 

(B2.1.9)

Consistent with 

GALL Report

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 Not applicable Not applicable (See 

SER Section 

3.4.2.1.1)

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 Not applicable (See 

SER Section 

3.4.2.1.1)

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 

(B2.1.14) or 

Above Ground 

Steel Tank 

Program 

(B2.1.2)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.1.2)

Steel piping, piping 

components, and 

piping elements 

exposed to steam or 

treated water

(3.4.1-29)

Wall thinning 

due to flowaccelerated 

corrosion

Flow-Accelerated 

Corrosion

No FlowAccelerated 

Corrosion

(B2.1.17)

Consistent with 

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 Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report
3-389

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 heat exchanger 

components exposed 

to raw water

(3.4.1-31)

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 

(B2.1.31)

Consistent with 

GALL Report

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 

microbiologically 

influenced 

corrosion

Open-Cycle Cooling 

Water System

No Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Program

(B2.1.22) or 

Open-Cycle 

Cooling Water 

System Program 

(B2.1.31)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.1.3)

Stainless steel heat 

exchanger 

components exposed 

to raw water

(3.4.1-33)

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 

(B2.1.31)

Inspection of 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components 

Program 

(B2.1.22)

Consistent with 

GALL Report (See 

SER Section 

3.4.2.1.4)

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 Not applicable (See 

SER Section 

3.4.2.1.1)
3-390

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

(B2.1.36)

Consistent with 

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

(B2.1.36)

Consistent with 

GALL Report

Steel, stainless steel, 

and nickel-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 Water Chemistry 

Program 

(B2.1.40)

Consistent with 

GALL Report

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 

(B2.1.7)

Consistent with 

GALL Report 

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to steam

(3.4.1-39)

Cracking due to 

stress corrosion 

cracking

Water Chemistry No Water Chemistry 

(B2.1.40)

Consistent with 

GALL Report

Glass piping 

elements exposed to 

air, lubricating oil, 

raw water, and 

treated water

(3.4.1-40)

None None NA None Consistent with 

GALL Report
3-391

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, 

copper alloy, and 

nickel-alloy piping, 

piping components, 

and piping elements 

exposed to air -

indoor uncontrolled 

(external)

(3.4.1-41)

None None NA None Consistent with 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air -

indoor controlled 

(external)

(3.4.1-42)

None None NA None Not Used (See 

SER Section 

3.4.2.1.1)

Steel and stainless 

steel piping, piping 

components, and 

piping elements in 

concrete

(3.4.1-43)

None None NA None Not applicable to 

PINGP (See SER 

Section 3.4.2.1.1)

Steel, stainless steel, 

aluminum, and 

copper alloy piping, 

piping components, 

and piping elements 

exposed to gas

(3.4.1-44)

None None NA None Consistent with 

GALL Report

The staff’s review of the steam and power conversion systems component groups followed any 

one of several approaches. One approach, documented in SER Section 3.4.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.4.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report 

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.4.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the steam and power conversion systems components is 

documented in SER Section 3.0.3.

3.4.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.4.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the steam and power conversion systems components:
3-392

• Aboveground Steel Tanks Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• External Surfaces Monitoring Program

• Flow-Accelerated Corrosion Program

• Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components

• Lubricating Oil Analysis Program

• One-Time Inspection Program

• Open-Cycle Cooling Water System Program

• Selective Leaching of Materials Program

• Water Chemistry Program

LRA Tables 3.4.2-1 through 3.4.2-8 summarize AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined whether the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with Notes A through E indicating 

how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. 

The staff audited these line items to verify consistency with the GALL Report and validity of the 

AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL AMP. The staff audited these line items to verify consistency with the GALL Report and 

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP is 

consistent with the GALL AMP. This note indicates that the applicant was unable to find a listing 

of some system components in the GALL Report; however, the applicant identified in the GALL

Report a different component with the same material, environment, aging effect, and AMP as 

the component under review. The staff audited these line items to verify consistency with the 

GALL Report. The staff also determined whether the AMR line item of the different component 

was applicable to the component under review and whether the AMR was valid for the sitespecific conditions.
3-393

Note D indicates that the component for the AMR line item, although different from, is consistent 

with the GALL Report for material, environment, and aging effect. In addition, the AMP takes 

some exceptions to the GALL AMP. The staff audited these line items to verify consistency with 

the GALL Report. The staff verified whether the AMR line item of the different component was 

applicable to the component under review and whether the identified exceptions to the GALL 

AMPs have been reviewed and accepted. The staff also determined whether the applicant’s 

AMP was consistent with the GALL AMP and whether the AMR was valid for the site-specific 

conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff audited these line items to 

verify consistency with the GALL Report. The staff also determined whether the credited AMP 

would manage the aging effect consistently with the GALL AMP and whether the AMR was valid 

for the site-specific conditions.

The staff 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 

steam and power conversion system 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 3.4.1, 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 follows.

3.4.2.1.1 AMR Results Identified as Not Applicable

In LRA Table 3.4.1, item 13, the applicant states that the corresponding AMR items in the GALL 

Report are not applicable to PINGP because the AMR items in the GALL Report are only 

applicable to particular components in BWR reactor designs and because PINGP is a 

Westinghouse-designed PWR facility. The staff verified that the stated AMR items in the GALL 

Report are only applicable to BWR designed facilities and are not applicable to the PINGP LRA.

In LRA Table 3.4.1, items 21, 23, 24, 26, 27, 34, and 42, the applicant states that the 

corresponding AMR result lines in the GALL Report are not applicable because PINGP does not 

have the component, material, and environment combination in the Steam and Power 

Conversion System. The staff reviewed the documentation supporting the applicant's AMR 

evaluation and confirmed the applicant's claim that PINGP does not have the component, 

material, and environment combination in the steam and power conversion system. Therefore, 

the staff agrees with the applicant's determination that the corresponding AMR result lines in the 

GALL Report are not applicable to PINGP.
3-394

In LRA Table 3.4.1, item 43, the applicant states that further evaluation in LRA Section 

3.5.2.2.1.4 concluded that steel components in concrete are not susceptible to aging and do not 

require aging management. The staff noted this item applies to GALL line items VIII.I-14 and 

VIII.I-11, which indicates that there is no aging effect for this component type and environment, 

and therefore does not require an AMP. Therefore, the staff agrees with the applicant in that this 

line item does not require aging management.

3.4.2.1.2 Loss of Material due to General Corrosion

In LRA Table 3.4.1, item 3.4.1-28, addresses loss of material due to general corrosion for 

carbon steel external surfaces exposed externally to air – indoor uncontrolled, condensation, or 

air outdoor in the condensate system. 

In LRA Tables, 3.4.2-1, 3.4.2-2, 3.4.2-3, 3.4.2-4, 3.4.2-5, 3.4.2-6, 3.4.2-7, and 3.4.2-8, the 

applicant credits either AMP B2.1.14, External Surfaces Monitoring Program to manage loss of 

material due to general corrosion in the external carbon steel surfaces of steam and power 

conversion system piping, piping components, piping elements, (including pump casings, valve 

bodies, traps, and flow restrictors, filter/strainer housings, eductors, flow restrictors, manifold, 

and demineralizers), tanks, blowers, flex connections, restricting orifices (strike flow restrictors

in two places), rupture disks, thermowells and turbine castings, and heat exchanger 

components that are exposed to an uncontrolled environment or alternatively, AMP B2.1.2 

“Aboveground Steel Tanks Program,” to manage loss of material due to general corrosion in the 

carbon steel condensate storage tank surfaces that are exposed externally to an uncontrolled 

indoor air environment. These AMR result line items cite Generic Note E, indicating that the 

AMR line items are consistent with GALL Report material, environment, and aging effect, but a 

different AMP is credited. 

The staff noted that AMR item 28 in Table 4 of the GALL Report, Volume 1, and GALL AMR 

item VIII.H-7 both recommend that GALL AMP XI.M36, "External Surfaces Monitoring" be 

credited to manage loss of material in the external steel tank surfaces that are exposed to an 

uncontrolled indoor air environment. The staff noted that for all the stated carbon steel 

components managed in accordance with LRA AMR item 3.4.1-28, the applicant credited the 

External Surfaces Monitoring Program to manage loss of material in the external carbon steel 

surfaces that are exposed to an uncontrolled indoor air environment. The staff finds this to be 

acceptable because it is consistent with the AMP that is recommended for aging management 

of these components in GALL AMR item VII.H-7.

The staff noted and verified that the only tanks at PINGP which correspond to recommended 

position in GALL AMR item VIII.H-7 and for which the applicant had credited the Aboveground 

Steel Tanks Program for aging management are slurry tanks, which are fabricated from carbon 

steel materials. Upon further review by the applicant, the applicant determined that the pre-coat 

slurry tanks do not fulfill a 10 CFR 54.4(a)(1), (a)(2), or (a)(3) scoping function. Therefore, in a 

letter dated December 5, 2008 the applicant amended its LRA to remove the pre-coated slurry 

tanks and any AMR items associated with these tanks from the scope of the LRA. The applicant 

stated that these tanks (pre-coat slurry tanks) were removed from the scope of license renewal 

because these tanks are normally dry and are only used during refueling outages. The staff 

notes that the pre-coat slurry tanks do not meet the criteria in 10 CFR 54.4(a)(1), (2) or (3); 

therefore, these tanks are not within the scope of license renewal and therefore do not need to 
3-395

be addressed in the AMR items for the LRA, including those that are referenced to AMR item 28 

in Table 4 of the GALL Report, Volume 1 or to AMR item VIII.H-7 in the GALL Report, 

Volume 2.

On the basis of its review, the staff concludes that these pre-coat slurry tanks do not meet the 

criteria of 10 CFR 54.4(a)(1), (2) or (3); therefore, these tanks are not within the scope of license 

renewal.

3.4.2.1.3 Loss of Material Due to Pitting, Crevice, and Microbiologically Influenced Corrosion

In LRA Table 3.4.1, item 3.4.1-32 addresses loss of material due to pitting, crevice, and MIC for 

stainless steel and copper alloy components with internal surfaces exposed to raw water in the 

circulating water system and turbine generator and support system.

The LRA credits the PINGP AMP B2.1.22, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to manage this aging effect for stainless steel heat exchanger 

tubes and components in a raw water (internal and external) environment only. The GALL 

Report recommends for item 3.4.1-32 that GALL AMP XI.M20, "Open-Cycle Cooling Water 

System," to manage this aging effect. These AMR line items cite Note E, indicating that the 

AMR line items are consistent with GALL Report material, environment, and aging effect, but a 

different AMP is credited. 

The staff noted that the component type recommended by GALL item VIII.A-4 is piping, piping 

components and piping elements. However, the applicant included copper alloy (copper-nickel) 

heat exchanger tubes when referencing item 3.4.1-32. The staff further noted that the applicant 

referenced item 3.4.1-32 of LRA Table 3.4.1 because there was not another applicable line item 

in LRA Table 3.4.1, for the steam and power conversion systems, which corresponded to the 

same component, material, environment and aging effect combination. The staff’s evaluation of 

heat exchanger tubes that referenced item 3.4.1-32 is evaluated separately, below.

The staff verified that only piping, fittings, pump casings and valve body components align to 

GALL item VIII.E-18 and VIII.E-27 and are fabricated from copper alloy and stainless steel 

materials that are applicable to PINGP. The staff noted that those AMR Line items that 

referenced GALL item VIII.A-4, VIII.E-18 and VIII.E-27 in circulating water system and turbine 

generator and support system are not in the scope of an open-cycle cooling water system as 

described in GL 89-13 and not associated with the ultimate heat sink, and, therefore, are not 

within the scope of GALL AMP XI.M20. The staff noted that the applicant referenced GALL item

VII.C1-3 because the material, environment and aging effect requiring management 

corresponded.

The staff finds that the applicant’s inclusion of heat exchanger tube components referencing 

GALL item VIII.A-4 to be reasonable because the material, environment and aging effect 

requiring management correspond. However, the staff noted during its review that the applicant 

credits a visual inspection to detect the aging effect of loss of material in heat exchanger 

components and tubes. The staff determined that additional information was needed. Therefore, 

by letter dated December 18, 2008, the staff issued RAI 3.3.2-20-02 requesting the applicant to 

justify how a visual inspection is capable of detecting loss of material in these components in 

those regions that are not directly visible (e.g. the bend of a heat exchanger tube). By letter 
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dated January 20, 2009, the applicant responded by stating the AMR result line items in LRA 

Table 3.4.2-8 that are heat exchanger tubes in a raw water (internal) environment which 

reference LRA Table 3.4.1, item 3.4.1-32, are supplied by the cooling water system. The 

applicant further stated these AMR result line items should have credited the Open-Cycle 

Cooling Water Program, which performs ECT on these heat exchanger components to detect 

loss of material. The applicant amended its LRA such that these AMR result line items now 

credit the Open-Cycle Cooling Water Program and reference LRA Table 3.3.1, item 3.3.1-82 

and GALL item VII.C1-3. The staff determined that based on the applicant’s amendment to 

credit the Open-Cycle Cooling Water Program for these AMR result line items, the LRA is 

consistent with the recommendations of the GALL Report. On the basis of its review, the staff 

finds that this portion of RAI 3.3.2-20-02 is acceptable because the applicant is now crediting 

the Open-Cycle Cooling Water Program for aging management of these heat exchanger tubes 

in a raw water (internal) environment that is associated with the ultimate heat sink, which is 

consistent with the GALL Report recommendations in GALL item VII.C1-3.

On the basis of periodic visual inspections, the staff finds the applicant’s use of this 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 function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.1.4 Loss of Material due to Pitting, Crevice, and Microbiologically-Influenced Corrosion

and Fouling

In LRA Table 3.4.1, item 3.4.1-33, addresses loss of material due to pitting, crevice, and MIC

and fouling for stainless steel heat exchanger tubes with its external and internal surfaces 

exposed to a raw water environment in the waste disposal system. The staff noted that the 

applicant referenced item 3.4.1-33 in LRA Table 3.3.2-20 because there was not another 

applicable line item in LRA Table 3.3.1 for the auxiliary systems, which corresponded to the 

same component, material, environment and aging effect combination.

The LRA credits the PINGP AMP B2.1.22 “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components” to manage this aging effect for stainless steel heat exchanger 

tubes and components in a raw water (internal and external) environment only. The GALL 

Report recommends for item 3.4.1-33 that GALL AMP XI.M20, "Open-Cycle Cooling Water 

System" manage this aging effect. These AMR line items cite Note E, indicating that the AMR 

line items are consistent with GALL Report material, environment, and aging effect, but a 

different AMP is credited. The staff verified that only piping, piping components, heat exchanger 

components, heat exchanger tubes, piping/fittings, valve bodies and piping elements align to 

GALL item VIII.E-3 and are fabricated from stainless steel materials that are applicable to 

PINGP. The staff noted that those AMR Line items in Waste Disposal System and Water 

Treatment System are not in the scope of an open-cycle cooling water system as described in 

GL 89-13 and not associated with the ultimate heat sink, and, therefore, are not within the scope 

of GALL AMP XI.M20.

The staff noted during its review that several of the heat exchanger components are exposed to 

an external environment of raw water. However, the applicant credits a program that will 

perform visual inspections of the internal surfaces for aging management. Therefore, by letter 
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dated December 18, 2008, the staff issued RAI 3.3.2-20-01 requesting the applicant to clarify 

why a program that performs visual inspections of internal surfaces has been credited for aging 

management of component surfaces that are exposed to an external raw water environment. By 

letter dated January 20, 2009, the applicant responded to RAI 3.3.2-20-01 by stating that these 

components that credit this program in a raw water environment are heat exchanger tubes and 

tubesheets. The applicant further stated that the internal and external environments are 

assigned based on the side of the heat exchanger tubes and tubesheets that is exposed to the 

environment. The applicant clarified that these components (tubes and tubesheets) are 

physically internal to the heat exchanger and that is why this program is credited for aging 

management. The applicant also stated that the internal environment of these components 

(tubes and tubesheets) are also internal to the heat exchanger and are evaluated in separate 

AMR result line items. The staff verified that for the same component, material, environment and 

aging effect combination, the applicant has evaluated the internal and external environments.

On the basis of its review, the staff finds the applicant’s response acceptable because the 

applicant clarified that these components (tubes and tubesheets) are internal to the heat 

exchanger and the internal and external environments of these components are evaluated 

separately.

The staff also noted during its review that the applicant credits a visual inspection to detect the 

aging effect of loss of material in heat exchanger components and tubes. However, the staff 

determined that additional information was needed, so by letter dated December 18, 2008, the 

staff issued RAI 3.3.2-20-02 requesting the applicant to justify how a visual inspection is 

capable of detecting loss of material in these components in those regions that are not directly 

visible (ex. the bend of a heat exchanger tube). By letter dated January 20, 2009, the applicant 

responded to RAI 3.3.2-20-02 by stating that this program is credited for aging management of 

heat exchanger components that include tubes, shells, tubesheets and channelheads. The 

applicant further stated the activities that will be performed as part of this program to detect 

degradation of these stainless steel components include periodic visual inspections during 

surveillance and maintenance activities. The staff noted that the applicant will choose the 

inspection locations based on conditions that are susceptible to the aging effects of concern.

The staff further noted that the applicant’s inspection will monitor parameters such as rust, 

discoloration, scale/deposits, pitting and surface discontinuities which are indications that loss of 

material and degradation are occurring. Based on the applicant’s response to RAI 3.3.2-20-02, 

the staff noted the applicant evaluated the internal and external environments of these heat 

exchanger tubes and components separately because these components are physically internal 

to the heat exchanger. The staff confirmed in LRA Table 3.3.2-20 that the applicant evaluated 

the external side and internal side of the heat exchanger tubes and components, separately.

Furthermore, the staff noted that the applicant is crediting a visual inspection on the external 

side of these heat exchanger tubes and components only since a visual inspection will be 

capable of identifying indications of loss of material on all areas of the heat exchanger tubes, 

including the bends of the components. The staff confirmed that for the internal side of these 

heat exchanger tubes and components the applicant has credited the GALL Report 

recommended program for aging management. On the basis of its review, the staff finds the 

applicant’s response acceptable because (1) the inspection of these components at locations 

that have conditions that are susceptible to the aging effect of loss of material and (2) a visual 

inspection of these components will be capable of identifying evidence that may be indicative of 

degradation and loss of material.
3-398

The staff’s review of the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation are documented in SER Section 3.0.3.1.13.

The staff determined that this program, which includes periodic visual inspections and 

volumetric testing, when appropriate, during periodic system and component surveillance 

activities or during maintenance activities when the internal surface is accessible for visual 

inspections, is adequate to manage loss of material for stainless steel heat exchanger tubes 

and components exposed to raw water (external and internal) addressed by this AMR. The staff 

further noted that these activities are consistent with those recommended by GALL 

AMP XI.M20. The staff also determined that the periodic visual inspections will be capable of 

detecting deterioration or degradation on the material surface that would be an indication of loss 

of material.

On the basis of periodic visual inspections, the staff finds the applicant’s use of this 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 function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.4.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the steam and power conversion systems components and provides 

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 MIC, and fouling

• reduction of heat transfer due to fouling

• loss of material due to general, pitting, crevice, and MIC cracking due to SCC

• loss of material due to pitting and crevice corrosion

• loss of material due to pitting, crevice, and MIC

• loss of material due to general, pitting, crevice, and galvanic corrosion

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the report recommends further evaluation, the staff 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.4.2.2.The staff’s review of the applicant’s 

further evaluation follows.

3.4.2.2.1 Cumulative Fatigue Damage 

LRA Section 3.4.2.2.1 states that fatigue is a TLAA, as defined in 10 CFR 54.3. Applicants must 

evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the staff’s 

review of the applicant’s evaluation of this TLAA.
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3.4.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion 

 (1) LRA Section 3.4.2.2.2.1 addresses the applicant’s aging management basis for 

managing loss of material due to general, pitting, and crevice corrosion in steel piping, 

piping components, piping elements exposed to treated water or steam, and in steel 

heat exchanger components exposed to treated water. The applicant stated that the 

aging effect of loss of material due to general, pitting, and crevice corrosion in these 

components will be managed by a combination of the Water Chemistry and the OneTime Inspection Programs. The applicant also included loss of material due to galvanic 

corrosion as an aging effect in the affected components managed by the Water 

Chemistry and One-Time Inspection Programs.

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 may occur in steel piping, piping components, piping elements, tanks, and 

heat exchanger components exposed to treated water and for steel piping, piping 

components, and piping elements exposed to steam. The SRP-LR states that the 

existing AMP relies on monitoring and control of water chemistry to manage the effects 

of loss of material due to general, pitting, and crevice corrosion. However, control of 

water chemistry does not preclude loss of material due to general, pitting, and crevice 

corrosion at locations with stagnant flow conditions. Therefore, the effectiveness of water 

chemistry control programs should be verified to ensure that corrosion does not occur. 

The GALL Report recommends further evaluation of programs to verify the effectiveness 

of water chemistry control programs. The SRP-LR 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.

SRP-LR Section 3.4.2.2.2.1 invokes AMR items 2, 3, and 4 in Table 4 of the GALL 

Report, Volume 1 and GALL AMR items VIII.A-16, VIII.B1-11, VIII.C-4, VIII.C-7, 

VIII.D1-8, VIII.E-34, VIII.F-25 and VIII.G-38, applicable for steel piping, piping 

components and piping elements exposed to treated water or steam in the auxiliary 

systems; and GALL item VIII.E-37 and VIII.F-28, applicable for steel heat exchanger 

components in the auxiliary systems. For all of these GALL AMR items, the 

recommended AMPs are Water Chemistry (GALL AMP XI.M.32) and One-Time 

Inspection (GALL AMP XI.M32).

The staff noted that piping, piping components, pump casings, turbine casings, 

demineralizers, heat exchanger components, blowers, eductors, restricting orifices, 

rupture discs, thermowells, traps, valve bodies, demineralizers, feedwater inlet nozzle 

thermal sleeve, filter/strainer housings and elements, manifolds, pump casings and traps

in the feedwater system, bleed steam system, condensate system, circulating water 

system, heating system, main steam system, turbine generator and support system, 

auxiliary feedwater system, chemical and volume control system, control room and 

miscellaneous area ventilation system, plant sample system, steam generator blowdown 

system, steam generator system, and water treatment system are included in the AMR 

results referring to LRA Section 3.4.2.2.2.1.
3-400

The staff also noted that the applicant had identified loss of material due to galvanic 

corrosion as a potential aging effect for piping, piping components, pump casings, 

blowers, eductors, demineralizers, feedwater inlet nozzle thermal sleeve, filter/strainer

housings and elements, manifolds, restricting orifices, rupture discs, turbine casings, 

thermowells, traps, valve bodies and heat exchanger components made of carbon steel, 

cast iron, ductile iron, and chrome-molybdenum alloy exposed to treated water or steam 

in the systems listed above. For these components, the applicant had included a plantspecific note stating that loss of material due to galvanic corrosion is included as a 

potential aging effect/mechanism. The applicant also proposed to manage this aging 

effect/mechanism using the Water Chemistry Program and the One-Time Inspection 

Program.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides mitigation for loss of material due to corrosion in 

components in a treated water environment. The staff reviewed the applicant’s OneTime Inspection Program. The staff’s evaluation of this program, which is documented in 

SER Section 3.0.3.1.18, determined that the applicant’s One-Time Inspection Program is 

consistent with the One-Time Inspection AMP XI.M32, as described in the GALL Report, 

and is adequate to detect the presence or note the absence of loss of material due to

general, pitting, crevice and galvanic corrosion for components within its scope. The staff 

confirmed 1) that the applicant is crediting the AMPs recommended in GALL AMR items 

VIII.A-16, VIII.B1-11, VIII.C-4, VIII.C-7, VIII.D1-8, VIII.E-37, VIII.F-25 and VIII.G-38; 2)

that the Water Chemistry Program provides mitigation for the identified age-related

degradation, and 3) that the One-Time Inspection Program provides verification of the 

effectiveness of the Water Chemistry Program to mitigate loss of material due to 

general, pitting or crevice corrosion in steel piping, piping components, pump casings, 

and heat exchanger exposed to treated water. The staff finds the applicant’s AMR 

results acceptable because the AMPs credited with aging management are consistent 

with the guidance in SRP-LR Section 3.4.2.2.2.1 and in GALL AMR items VIII.A-16, 

VIII.B1-11, VIII.C-4, VIII.C-7, VIII.D1-8, VIII.E-37, VIII.F-25 and VIII.G-38.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.2 criteria. For those line items that apply to LRA Section 

3.4.2.2.2.1, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) The applicant stated in LRA Section 3.4.2.2.2.2 that loss of material due to general, 

pitting and crevice corrosion could occur for steel piping, piping components, and piping 

elements exposed to lubricating oil. LRA Section 3.4.2.2.2.2 further states that 1) this 

aging effect is managed with a combination of the Lubricating Oil Analysis Program and 

the One-Time Inspection Program; 2) the Lubricating Oil Analysis Program includes 

periodic oil sampling, analysis, and evaluation and trending of results; 3) the program 

maintains oil systems contaminants (primarily water and particulates) within acceptable 

limits, thereby preserving an environment that is not conducive to degradation; 4) the 
3-401

One-Time Inspection Program performs sampling inspections using NDE techniques 

that either verify unacceptable degradation is not occurring or trigger additional actions 

and 5) components containing hydraulic fluid and not lubricating oil are also managed by 

the Lubricating Oil Analysis Program and the One-Time Inspection Program.

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 could occur for steel piping, piping components, and piping elements exposed 

to lubricating oil. SRP-LR Section 3.4.2.2.2.2 further states that: 1) the existing AMP

relies on the periodic sampling and analysis of lubricating oil to maintain contaminants 

within acceptable limits, thereby preserving an environment that is not conducive to 

corrosion; 2) the GALL Report recommends further evaluation of programs to manage 

corrosion to verify the effectiveness of the lube oil chemistry control program; and 3) a 

one-time inspection of selected components at susceptible locations is an acceptable 

method to ensure that corrosion is not occurring.

SRP-LR Section 3.4.2.2.2.2 invokes AMR item 7 in Table 4 of the GALL Report, Volume 

1, and GALL AMR item VIII.G-35, VIII.A-14, VIII.D1-6, VIII.D2-5 and VIII.E-32 as 

applicable to loss of material due to general, pitting, and crevice corrosion of steel 

piping, piping components, and piping elements exposed to lubricating oil. These 

components are identified in LRA Table 3.2.1-02: Filter/Strainer Housings, 

Piping/Fittings, Pump Casings, and Valve Bodies; LRA Table 3.4.2-1: Filter/Strainer 

Housings, Piping/Fittings, Pump Casings, Valve Bodies, and Tanks; LRA Table 3.4.2-5: 

Filter/Strainer Housings, Piping/Fittings, Pump Casings, Tanks and Valve Bodies; and 

LRA Table 3.4.2-8: Filter/Strainer Housings, Flex Connections, Manifolds, 

Piping/Fittings, Pump Casings, Restricting Orifices, Tanks, Thermowells, and Valve 

Bodies. 

The staff reviewed LRA Appendix B, Sections B2.1.23, “Lubricating Oil Analysis,” and 

B2.1.18, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively,

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material and 2) will 

perform one-time inspections of select steel components in the most susceptible 

locations exposed to lubricating oil for loss of material due to general, pitting and crevice 

corrosion at susceptible locations to verify the effectiveness of the applicant’s Lubricating 

Oil Analysis Program in applicable steam and power systems. The GALL Report states 

that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item VIII.G-35, VIII.A-14, VIII.D1-6, VIII.D2-5 and VIII.E-32 and the applicant is 

verifying effectiveness of the Lubricating Oil Analysis Program with the elements of the 

One-Time Inspection Program, which the GALL Report states is an acceptable program 

to verify the Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds 

that, based on the programs identified above, the applicant meets the criteria of SRP-LR 

Section 3.4.2.2.2.2. 

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 
3-402

the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB during the period of extended operation, as required 

by 10 CFR 54.21(a)(3).

3.4.2.2.3 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion, and Fouling 

LRA Section 3.4.2.2.3 addresses loss of material due to general, pitting, crevice, 

microbiologically-influenced corrosion and fouling in steel piping, piping components and piping 

elements exposed to raw water. The applicant stated that the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program will manage this aging effect in steel 

internal surfaces exposed to internal raw water.

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 pitting general, pitting, crevice, MIC and fouling in steel piping, 

piping components and piping elements exposed to raw water can occur and recommends 

further evaluation of a plant-specific AMP to ensure this aging effect is adequately managed.

The GALL Report, under item VIII.G-36, recommends that a plant-specific program be credited 

to manage loss of material due to pitting and crevice corrosion for steel piping, piping 

components, and piping elements in the Steam and Power Conversion Systems. 

The staff verified that the only piping, fittings, valve bodies and aligning to GALL AMR VIII.G-36 

for the Steam and Power Conversion System - Circulating Water System and Turbine 

Generator and Support System are fabricated from steel and cast iron materials.

The staff noted during its review that the applicant credits a visual inspection to detect the aging 

effect of loss of material in heat exchanger components and tubes. However, the staff 

determined that additional information was needed. Therefore, by letter dated December 18, 

2008, the staff issued RAI 3.3.2-20-02 requesting the applicant to justify how a visual inspection 

is capable of detecting loss of material in these components in those regions that are not 

directly visible (e.g. the bend of a heat exchanger tube). By letter dated January 20, 2009, the 

applicant responded by stating the AMR result line items in LRA Table 3.4.2-8 that are heat 

exchanger components in a raw water (internal) environment which reference LRA Table 3.4.1, 

item 3.4.1-08, are supplied by the cooling water system. The applicant further stated these AMR 

result line items should have credited the Open-Cycle Cooling Water Program because eddy 

current testing is performed on these heat exchanger components to detect loss of material by 

this program. The applicant amended its LRA such that these AMR result line items now credit 

the Open-Cycle Cooling Water Program and reference LRA Table 3.4.1, item 3.4.1-32 and 

GALL item VIII.E-6. The staff determined that based on the applicant’s amendment to credit the 

Open-Cycle Cooling Water Program for these AMR result line items, the LRA is consistent with 

the recommendations of the GALL Report. On the basis of its review, the staff finds that that 

applicant’s aging management basis, as amended in its response to RAI 3.3.2-20-02 is 

acceptable because the applicant is now crediting the Open-Cycle Cooling Water Program for 

aging management of these heat exchanger components in a raw water (internal) environment, 

which is consistent with the GALL Report recommendations in GALL item VIII.E-6.
3-403

The staff reviewed the applicant’s Inspection of Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program and its evaluation is documented in SER Section 3.0.3.1.13. The 

staff notes that the applicant credits this program with managing the aging effect of loss of 

material due to galvanic corrosion. The staff verified that the applicant has credited this program 

with the applicable aging effects addressed in SRP-LR Section 3.4.2.2.3 and the applicant is 

conservatively managing loss of material due to galvanic corrosion in an internal raw water 

environment with this program. This program performs visual inspections of internal surfaces of 

components during periodic system and component surveillance activities or during 

maintenance activities when the internal surface becomes accessible for visual inspections to 

detect aging effects that could result in a loss of the component's intended function. The staff 

finds that these visual inspections will be capable of detecting loss of material because evidence 

of material wastage will be visible on the internal surface of these components during the 

inspections.

Based on the programs identified, the staff concludes that the applicant’s program meets

SRP-LR Section 3.4.2.2.3 criteria. For those line items that apply to LRA Section 3.4.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.4.2.2.4 Reduction of Heat Transfer Due to Fouling 

 (1) LRA Section 3.4.2.2.4.1 addresses the applicant’s aging management basis for 

managing reduction of heat transfer due to fouling in stainless steel and copper alloy 

heat exchanger tubes exposed to treated water. In the LRA, the applicant stated that the 

aging effect of reduction of heat transfer due to fouling in these components will be 

managed by a combination of the Water Chemistry Program and the One-Time 

Inspection Program.

The staff reviewed LRA Section 3.4.2.2.4.1 against the criteria of SRP-LR 

Section 3.4.2.2.4.1, which states that reduction of heat transfer due to fouling may occur 

for stainless steel and copper alloy heat exchanger tubes exposed to treated water. The 

SRP-LR states that the existing AMP relies on control of water chemistry to manage 

reduction of heat transfer due to fouling. However, control of water chemistry may not 

always have been adequate to preclude fouling. Therefore, 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 states 

that a one-time inspection is an acceptable method to ensure that reduction of heat 

transfer is not occurring and that the component’s intended function will be maintained 

during the period of extended operation.

SRP-LR Section 3.4.2.2.4.1 invokes AMR item 9 in Table 4 of the GALL Report, 

Volume 1, and GALL AMR items VIII.E-13 and VIII.G-10 for stainless steel heat 

exchanger tubes exposed to treated water in the condensate system and for copper 

alloy heat exchanger tubes exposed to treated water in the auxiliary feedwater system. 

The staff noted that the applicant’s AMR results are for stainless steel and copper alloy 

heat exchanger tubes exposed to treated water in the auxiliary feedwater system.
3-404

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, found that the Water 

Chemistry Program provides mitigation for reduction of heat transfer due to fouling in 

heat exchanger components exposed to treated water. The staff reviewed the 

applicant’s One-Time Inspection Program. The staff’s evaluation of this program, which 

is documented in SER Section 3.0.3.1.18, found that the One-Time Inspection Program 

is adequate to detect the presence or note the absence of fouling which might cause 

reduction of heat transfer in heat exchanger tubes. The staff confirmed 1) that the 

applicant is crediting the AMPs recommended in GALL AMR items VIII.E-13 and 

VIII.G-10; 2) that the Water Chemistry Program implements chemistry related activities 

for the mitigation corrosion-induced age-related degradation; and 3) that the One-Time 

Inspection Program provides verification of the effectiveness of the Water Chemistry 

Program to mitigate reduction of heat transfer due to fouling in stainless steel and 

copper alloy heat exchanger tubes exposed to treated water. The staff finds the 

applicant’s AMR results acceptable because the AMPs credited with aging management 

are consistent with the guidance in SRP-LR Section 3.4.2.2.4.1 and in GALL AMR items 

VIII.E-13 and VIII.G-10.

Based on the programs identified, the staff concludes that the applicant’s proposed 

programs are acceptable for managing the aging effects in the applicable components. 

The staff determines that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended function(s) will be maintained consistent with the CLB during the period of 

extended operation, as required by 10 CFR 54.21(a)(3).

 (2) The applicant stated in LRA Section 3.4.2.2.4.2 that reduction of heat transfer due to

fouling could occur in steel, stainless steel, and copper alloy heat exchanger tubes 

exposed to lubricating oil. LRA Section 3.4.2.2.4.2 further states that 1) this aging effect 

is managed with a combination of the Lubricating Oil Analysis Program and the OneTime Inspection Program 2) the Lubricating Oil Analysis Program includes periodic oil 

sampling, analysis, and evaluation and trending of results to maintain oil systems 

contaminants (primarily water and particulates) within acceptable limits and 3) the OneTime Inspection Program performs sampling inspections that either verify unacceptable 

degradation is not occurring or trigger additional actions. 

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 reduction of heat transfer due to fouling could occur for 

steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil.

SRP-LR Section 3.4.2.2.4.2 further states that 1) this aging effect is managed with a 

combination of the Lubricating Oil Analysis Program and the One-Time Inspection 

Program; 2) the Lubricating Oil Analysis Program includes periodic oil sampling, 

analysis, and evaluation and trending of results. The program maintains oil systems 

contaminants (primarily water and particulates) within acceptable limits, thereby 

preserving an environment that is not conducive to degradation; 3) the One-Time 

Inspection Program performs sampling inspections using NDE techniques that either 

verify unacceptable degradation is not occurring or trigger additional actions; and 4) 
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components containing hydraulic fluid and not lubricating oil are also managed by the 

Lubricating Oil Analysis Program and the One-Time Inspection Program.

SRP-LR Section 3.4.2.2.4.2 invokes AMR item 10 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR items VIII.G-8 (Auxiliary Feedwater System) and VIII.G-12 

(Auxiliary Feedwater System) as applicable to reduction of heat transfer due to fouling of 

steel, stainless steel, and copper alloy heat exchanger tubes exposed to lubricating oil.

These components are identified in LRA Table 3.4.2-1: Heat Exchanger Tubes, LRA 

Table 3.3.2-8: Heat Exchanger Tubes.

The staff reviewed LRA Appendix B, Sections B2.1.29, “Lubricating Oil Analysis” and 

B2.1.24, “One-Time Inspection,” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively,

and found that these programs 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of heat transfer due to 

fouling and 2) will perform one-time inspections of select steel, stainless steel and 

copper alloy heat exchanger tubing exposed to lubricating oil for loss of heat transfer 

due to fouling to verify the effectiveness of the Lubricating Oil Analysis Program in 

applicable steam and power conversion systems.

The GALL Report states that one-time inspection is an acceptable method to verify the 

effectiveness of a mitigative AMP such as the Lubricating Oil Analysis Program. The 

staff noted that the applicant is crediting the Lubricating Oil Analysis Program as 

recommended in GALL AMR items VIII.G-8 and VIII.8-12 and the applicant is verifying 

effectiveness of the Lubricating Oil Analysis Program with the elements of the One-Time 

Inspection Program, which the GALL Report states is an acceptable program to verify 

the Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds that based 

on the programs identified above, the applicant meets the criteria of SRP-LR Section 

3.4.2.2.4.2. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.4.2 criteria. For those line items that apply to LRA 

Section 3.4.2.2.4.2, 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.5 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion 

 (1) The applicant stated in LRA Section 3.4.2.2.5.1 that the loss of material due to general, 

pitting, crevice, and MIC could occur for steel piping, piping components, and piping 

elements buried in soil regardless of the presence of pipe coatings or wrappings and this 

aging effect is managed with the Buried Piping and Tanks Inspection Program. LRA 

Section 3.3.2.2.5.1 further states that the Buried Piping and Tanks Inspection Program 

includes preventive measures to mitigate degradation (e.g., coatings and wrappings 

required by design) and visual inspections of external surfaces of buried piping 

components, when excavated, for evidence of coating damage and degradation and 
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these inspections either verify that unacceptable degradation is not occurring or trigger 

additional actions.

The staff reviewed LRA Section 3.4.2.2.5.1 against the criteria in SRP-LR Section 

3.4.2.2.5.1, which states that loss of material due to general, pitting, crevice corrosion, 

and MIC could occur for steel (with or without coating or wrapping) piping, piping 

components, and piping elements buried in soil. SRP-LR Section 3.4.2.2.5.1 further 

states that 1) the buried piping and tanks inspection program relies on industry practice, 

frequency of pipe excavation, and OE to manage the effects of loss of material from 

general, pitting, and crevice corrosion and MIC and 2) the effectiveness of the buried 

piping and tanks inspection program should be verified to evaluate an applicant’s 

inspection frequency and OE with buried components, ensuring that loss of material is 

not occurring.

SRP-LR Section 3.4.2.2.5.1 invokes AMR item 11 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR item VIII.E-1 (Condensate System) as applicable to loss of 

material due to general, pitting, crevice, and MIC of steel piping, piping component, 

piping elements, and tanks exposed to soil. These components are identified in LRA 

Table 3.3.2-10: Tanks.

The staff reviewed LRA Appendix B, Sections B2.1.8, “Buried Piping and Tanks 

Inspection,” in SER Section 3.0.3.1.7 and found that this program provides focused or 

opportunistic excavations and inspections for general, pitting, crevice, and MIC of buried 

steel piping and tanks within 10 years before the period of extended operation and within 

10 years after the initiation of the period of extended operation. The staff finds that these 

activities are based on industry practice and provide for periodic excavations and visual 

inspections of buried piping and tanks for general, pitting and crevice corrosion and MIC. 

The GALL AMP XI.34 program element “parameters monitored/inspected” states that 

the program monitors parameters such as coating and wrapping integrity that are directly 

related to corrosion damage of the external surface of buried steel piping and tanks. The 

staff noted that the applicant is crediting the Buried Piping and Tanks Inspection 

Program as recommended in GALL AMR item VIII.E-1 which the GALL Report states is 

an acceptable program to monitor possible corrosion damage to the external surface of 

piping and tanks. Therefore, the staff finds that, based on the programs identified above, 

the applicant meets the criteria of SRP-LR Section 3.4.2.2.5.1. 

Based on the program identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.5.1 criteria. For those line items that apply to LRA 

Section 3.4.2.2.5.1, 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

 (2) The applicant stated in LRA Section 3.4.2.2.5.2 that loss of material due to general, 

pitting, and crevice corrosion could occur for steel heat exchanger components exposed 

to lubricating oil. The LRA further states that: 1) this aging effect is managed with a 

combination of the Lubricating Oil Analysis Program and the One-Time Inspection 
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Program; 2) the Lubricating Oil Analysis Program includes periodic oil sampling, 

analysis, and evaluation and trending of results; 3) the program maintains oil systems 

contaminants (primarily water and particulates) within acceptable limits, thereby 

preserving an environment that is not conducive to degradation; 4) the One-Time 

Inspection Program performs sampling inspections using NDE techniques that either 

verify unacceptable degradation is not occurring or trigger additional actions; and 5) 

components containing hydraulic fluid and not lubricating oil are also managed by the 

Lubricating Oil Analysis Program and the One-Time Inspection Program.

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, and crevice 

corrosion, and MIC could occur in steel heat exchanger components exposed to 

lubricating oil. SRP-LR Section 3.4.2.2.5.2 further states that 1) the existing AMP relies 

on the periodic sampling and analysis of lubricating oil to maintain contaminants within 

acceptable limits, thereby preserving an environment that is not conducive to corrosion 

and 2) the effectiveness of lubricating oil contaminant control can be achieved through a 

one-time inspection of selected components at susceptible locations.

SRP-LR Section 3.4.2.2.5.2 invokes AMR item 12 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR item VIII.G-6 (Auxiliary Feedwater System) as applicable to 

loss of material due to general, pitting, crevice, and MIC of heat exchanger components, 

exposed to lubricating oil. These components are identified in LRA Table 3.1.2-2: Heat 

Exchanger Components, LRA Table 3.4.2-1: Heat Exchanger Components, LRA Table 

3.4.2-5: Heat Exchanger Components, LRA Table 3.4.2-8: Heat Exchanger 

Components.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.18 respectively 

and found that these programs: 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to general, 

pitting, and crevice corrosion; and 2) will perform one-time inspections of select steel 

heat exchanger tubing exposed to lubricating oil for loss of material due to general, 

pitting, crevice corrosion, and MIC to verify the effectiveness of the Lubricating Oil 

Analysis Program in applicable steam and power conversion systems. The GALL Report 

states that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR item VIII.G-6 and the applicant is verifying effectiveness of the Lubricating Oil 

Analysis Program with the elements of the One-Time Inspection Program, which the 

GALL Report states is an acceptable program to verify the Lubricating Oil Analysis 

Program effectiveness. In addition, the staff finds the applicant's use of the Lubricating 

Oil Analysis Program to manage components containing hydraulic fluid conservative and 

therefore acceptable. Therefore, the staff finds that, based on the programs identified 

above, the applicant meets the criteria of SRP-LR Section 3.4.2.2.5.2. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.5.2 criteria. For those line items that apply to LRA 

Section 3.4.2.2.5.2, the staff determines that the LRA is consistent with the GALL Report 
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and that the applicant has demonstrated that the effects of aging will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.6 Cracking Due to Stress Corrosion Cracking 

LRA Section 3.4.2.2.6 addresses the applicant’s aging management basis for managing 

cracking due to SCC in stainless steel piping, piping components, piping elements, tanks, and 

heat exchangers components exposed to treated water greater than 60 °C (>140 °F). In the 

LRA, the applicant stated that the aging effect of cracking due to SCC in these components will 

be managed by a combination of the Water Chemistry program and the One-Time Inspection 

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 may 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 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 water chemistry control program be 

verified to ensure that SCC is not occurring and that the component’s intended function would

be maintained during the period of extended operation.

SRP-LR Section 3.4.2.2.6 invokes AMR item 14 in Table 4 of the GALL Report, Volume 1, and 

GALL AMR items VIII.B-1, VIII.C-2, VIII.D1-5, VIII.E-30, VIII.E-38, VIII.F-3, and VIII.F-24. The 

staff noted that for all of the GALL AMR items, the recommended AMPs are Water Chemistry 

(GALL AMP XI.M2) and One-Time Inspection (GALL AMP XI.M32).

The staff noted that piping and piping components, expansion joints, feedwater inlet nozzle 

thermal sleeve, flex connections, heat exchanger tubes, tanks, and pump casings, LEFM 

transducer housings, manifolds, restricting orifices, thermowells, valve bodies and secondary 

closures with inserts in the bleed steam system, the chemical and volume control system, the 

condensate system, the feedwater system, the heating system, the plant sample system, the 

radiation monitoring system, the reactor coolant system, the steam generator blowdown system, 

the steam generator system, and the turbine generator and support system are included in the 

AMR results referring to LRA Section 3.4.2.2.6.

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of this 

program, which is documented in SER Section 3.0.3.2.19, found that the Water Chemistry 

Program provides mitigation for cracking due to SCC for stainless steel components in a treated 

water environment. The staff reviewed the applicant’s One-Time Inspection Program. The staff’s 

evaluation of this program, which is documented in SER Section 3.0.3.1.18, found that the OneTime Inspection Program is adequate to detect the presence or note the absence of cracking 

due to SCC for components within its scope. The staff confirmed 1) that the applicant is 

crediting the AMPs recommended in GALL AMR items VIII.B-1, VIII.C-2, VIII.D1-5, VIII.E-30, 

VIII.E-38, VIII.F-3, and VIII.F-24; 2) that the Water Chemistry Program provides mitigation for 

the identified age-related degradation; and 3) that the One-Time Inspection Program provides 
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verification of the effectiveness of the Water Chemistry Program to mitigate cracking due to 

SCC in stainless steel piping, piping components, piping elements, tanks, and heat exchanger 

components exposed to treated water greater than 60 °C (>140 °F). The staff finds the 

applicant’s AMR results acceptable because the AMPs credited with aging management are 

consistent with the guidance in SRP-LR Section 3.4.2.2.6 and in GALL AMR items VIII.B-1-5, 

VIII.C-2, VIII.D1-5, VIII.E-30, VIII.E-38, VIII.F-3, and VIII.F-24.

Based on the programs identified, the staff concludes that the applicant’s proposed programs 

are acceptable for managing the aging effects in the applicable components. The staff 

determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.4.2.2.7 Loss of Material Due to Pitting and Crevice Corrosion

 (1) LRA Section 3.4.2.2.7.1 addresses the applicant’s aging management basis for 

managing loss of material due to general (steel only), pitting, and crevice corrosion in 

steel and stainless steel tanks; in aluminum and copper alloy piping, piping components, 

and piping elements; and in stainless steel piping, piping components, and piping 

elements, tanks and heat exchanger components exposed to treated water. The 

applicant stated that for steel and stainless steel tanks, for stainless steel piping, piping 

components, and piping elements, and for stainless steel heat exchanger components,

the aging effect is managed by a combination of the Water Chemistry Program and the 

One-Time Inspection Program. The applicant also stated that for aluminum and copper 

alloy piping, piping components and piping elements, the aging effect is managed with 

the Water Chemistry Program and One-Time Inspection Program, or the Closed-Cycle 

Cooling Water System Program, or with the Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program. The applicant stated that the 

Closed-Cycle Cooling Water System Program includes both preventive measures 

(corrosion inhibitor addition and chemical testing) to minimize aging effects and 

component inspections to monitor for the effects of aging.

The staff compared LRA Section 3.4.2.2.7.1 against the criteria of SRP-LR 

Section 3.4.2.2.7.1, which states that loss of material due to pitting and crevice corrosion 

may 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 SRP-LR states that the existing AMP relies on monitoring and 

control of water chemistry to manage the effects of loss of material due to pitting, and 

crevice corrosion. However, 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 should be verified to ensure that corrosion 

is not occurring. The SRP-LR states that a one-time inspection of selected components 

at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring and the component’s intended function will be maintained during the period of 

extended operation.
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SRP-LR Section 3.4.2.2.7.1 invokes AMR items 6, 15 and 16 in Table 4 of the GALL 

Report, Volume 1, and GALL AMR items VIII.A-5, VIII.B1-4, VIII.C-1, VIII.D1-4, VIII.E-15, 

VIII.E-29, VIII.E-36, VIII.E-40, VIII.F-15, VIII.F-23, and VIII.G-32. The staff noted that 

components in the chemical and volume control system, the condensate system, the 

heating system, the reactor coolant system, the radiation monitoring system, steam 

generator system, plant sample system, the steam generator blowdown system, the 

auxiliary feedwater system, the containment spray system, the control room and 

miscellaneous area ventilation system, the fire protection system, the turbine generator 

and support system, and the water treatment system are included in the AMR results 

referring to LRA Section 3.4.2.2.7.1

The staff reviewed the applicant’s Water Chemistry Program. The staff’s evaluation of 

this program, which is documented in SER Section 3.0.3.2.18, determined that the 

applicant’s Water Chemistry Program, provides mitigation for loss of material due to 

general corrosion in steel components and due to pitting and crevice corrosion in 

stainless steel, copper-alloy and aluminum components. The staff reviewed the 

applicant’s One-Time Inspection Program. The staff’s evaluation of this program, which 

is documented in SER Section 3.0.3.1.18, determined that the applicant’s One-Time 

Inspection Program is consistent with the One-Time Inspection AMP XI.M32, as 

described in the GALL Report, and is adequate to detect the presence or note the 

absence of loss of material due to general, pitting, crevice, and galvanic corrosion for 

components within the scope of the program. The staff confirmed 1) that the applicant is 

crediting the AMPs recommended in GALL AMR items VIII.A-5, VIII.B1-4, VIII.C-1, 

VIII.D1-4, VIII.E-15, VIII.E-29, VIII.E-36, VIII.E-40, VIII.F-15, VIII.F-23, and VIII.G-32; 2)

that the Water Chemistry Program provides mitigation for the identified age-related

degradation, and 3) that the One-Time Inspection Program provides verification of the 

effectiveness of the Water Chemistry Program to mitigate loss of material due to 

general, pitting or crevice corrosion in steel and stainless steel tanks, piping, piping 

components, pump casings, and heat exchanger components, and in aluminum and 

copper alloy piping, piping components and piping elements exposed to treated water. 

The staff finds the applicant’s AMR results acceptable because the AMPs credited with 

aging management are consistent with the guidance in SRP-LR Section 3.4.2.2.7.1 and 

in GALL AMR items VIII.A-5, VIII.B1-4, VIII.C-1, VIII.D1-4, VIII.E-15, VIII.E-29, VIII.E-36, 

VIII.E-40, VIII.F-15, VIII.F-23, and VIII.G-32.

The staff noted that the applicant credits the Closed-Cycle Cooling Water System 

Program in lieu of the Water Chemistry and One-Time Inspection Programs for 

managing loss of material due to pitting and crevice corrosion in aluminum heat 

exchanger tubes exposed to treated water in the control room and miscellaneous area 

ventilation system and in aluminum heaters exposed to treated water in the fire 

protection system. The staff also noted that the applicant cited Generic Note E for these 

AMR results, indicating that the results are consistent with the GALL Report for material, 

environment and aging effect, but the proposed AMP is different from the one 

recommended in the GALL Report. 

The staff reviewed the applicant’s Closed-Cycle Cooling Water System Program. The 

staff’s evaluation of this program, which is documented in SER Section 3.0.3.2.2, 

determined that the Closed-Cycle Cooling Water System Program, with an 
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enhancement, is consistent with the Closed-Cycle Cooling Water System AMP XI.M21, 

as described in the GALL Report with acceptable exceptions. The staff determined that 

the applicant’s Closed-Cycle Cooling Water System Program includes preventive 

measures, such as use of corrosion inhibitors, to minimize the effects of aging due to 

corrosion; and it includes inspection activities to monitor for loss of material due to pitting 

and crevice corrosion. Based on the staff’s determination that the applicant’s ClosedCycle Cooling Water System Program provides both mitigation and detection for the 

potential aging effect, the staff finds the applicant’s proposed use of the Closed-Cycle 

Cooling Water System Program for managing loss of material due to pitting and crevice 

corrosion in aluminum heat exchanger tubes exposed to treated water in the control 

room and miscellaneous area ventilation system and in aluminum heaters exposed to 

treated water in the fire protection system to be acceptable.

The staff noted that LRA Table 3.4.2-8 includes two AMR result lines for aluminum pump 

casings in a raw water environment in the turbine generator and support system where 

the aging effect is loss of material due to crevice and pitting corrosion and the proposed 

AMP is the Inspection of Internal Surfaces in Miscellaneous Piping and Ducting 

Components. For these AMR results, the applicant referenced to LRA Table 3.4.1, AMR 

item 3.4.1-15, and GALL AMR item VIII.E-15, and cited Generic Note E. The staff noted 

that the environment corresponding to AMR item 3.4.1-15 and GALL AMR item VIII.E-15 

is treated water, not raw water. Because of the inconsistency of environments between 

the applicant’s AMR result line and the corresponding GALL AMR item, the staff 

determined that the applicant’s reference to AMR item 3.4.1-15 and use of Generic Note 

E appeared to be incorrect. 

In a January 22, 2009, telephone conference, the staff requested that the two entries for 

aluminum pump casings in raw water in LRA Table 3.4.2-8 be clarified to eliminate 

confusion over whether treated water or raw water is the applicable environment for the 

component. In a letter dated February 6, 2009, the applicant stated that the environment 

for the aluminum pump casings is raw water and that the reference to GALL AMR item 

VIII.E-15 and to LRA Table 3.4.1, AMR item 3.4.1-15, and the use of generic Note E are 

incorrect. The staff verified that in the letter of February 6, 2009, the applicant amended 

LRA Table 3.4.1, AMR item 3.4.1-15, to delete the reference to the Inspection of Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program for aging 

management. The staff also verified that the applicant amended LRA Table 3.4.2-8 for 

the two AMR items related to loss of material for the aluminum pump casings that are 

exposed to raw water and specifically amended the AMR items to delete the reference to 

GALL AMR item VIII.E-15 and to LRA AMR item 3.4.1-15, and revise these AMR items 

note from E to generic Note G, indicating that the environment is not in the GALL Report 

for this material and environment combination. The two revised AMR result lines are 

evaluated by the staff in SER Section 3.4.2.3.8.

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7 criteria. For those line items that apply to LRA Section 

3.4.2.2.7.1, the staff determines that the LRA is consistent with the GALL Report and 

that the applicant has demonstrated that the effects of aging will be adequately managed 

so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).
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 (2) LRA Section 3.4.2.2.7.2 addresses loss of material due to pitting and crevice corrosion 

for stainless steel piping, piping components, and piping elements exposed to soil and

states that this aging effect is not applicable because there are no stainless steel 

components exposed to soil in the steam and power conversion systems.

SRP-LR Section 3.4.2.2.7.2 states that loss of material due to pitting and crevice 

corrosion may occur in stainless steel piping, piping components, and piping elements 

exposed to soil. The GALL Report recommends further evaluation of a plant-specific 

AMP to ensure that the aging effect is adequately managed.

The staff reviewed the PINGP UFSAR, and verified that there are no stainless steel 

components exposed to soil in the steam and power conversion systems that are within 

the scope the license renewal and subject to an AMR.

On this basis, the staff finds that criteria in SRP-LR Section 3.4.2.2.7.2 are not 

applicable to PINGP.

 (3) The applicant stated in LRA Section 3.4.2.2.7.3 that loss of material due to pitting and 

crevice corrosion could occur for copper alloy piping, piping components, and piping 

elements exposed to lubricating oil. LRA Section 3.4.2.2.7.3 further states that: 1) this 

aging effect is managed with a combination of the Lubricating Oil Analysis Program and 

the One-Time Inspection Program; 2) the Lubricating Oil Analysis Program includes 

periodic oil sampling, analysis, and evaluation and trending of results; 3) the program 

maintains oil systems contaminants (primarily water and particulates) within acceptable 

limits, thereby preserving an environment that is not conducive to degradation; 4) the 

One-Time Inspection Program performs sampling inspections using NDE techniques 

that either verify unacceptable degradation is not occurring or trigger additional actions;

and 5) components containing hydraulic fluid and not lubricating oil are also managed by 

the Lubricating Oil Analysis Program and the One-Time Inspection Program.

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 could 

occur for copper alloy piping, piping components, and piping elements exposed to 

lubricating oil. The existing AMP relies on the periodic sampling and analysis of 

lubricating oil to maintain contaminants within acceptable limits, thereby preserving an 

environment that is not conducive to corrosion. SRP-LR Section 3.4.2.2.7.3 further 

states that the effectiveness of lubricating oil contaminant control can be verified through 

a one-time inspection of selected components at susceptible locations and one-time 

inspection is an acceptable method to ensure that corrosion is not occurring.

SRP-LR Section 3.4.2.2.7.3 invokes AMR item 18 in Table 3 of the GALL Report, 

Volume 1, and GALL AMR items VIII.G-19 (Auxiliary Feedwater System), VIII.D1-2 

(Feedwater System), VIII.A-3 (Steam Turbine System) as applicable to loss of material 

due to pitting and crevice corrosion of stainless steel and copper alloy piping, piping 

components, and piping elements exposed to lubricating oil. These components are 

identified in LRA Table 3.1.2-2: Piping/Fittings, Valve Bodies, LRA Table 3.4.2-5: 
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Piping/Fittings, Valve Bodies, LRA Table 3.4.2-1: Heat Exchanger Tubers, Valve Bodies, 

LRA Table 3.4.2-8: Filter Strainer/Housing, Piping/Fittings, Valve Bodies.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and 

B2.1.29, “One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively, 

and found that these programs: 1) provide for periodic sampling of lubricating oil to 

maintain contaminants at acceptable limits to preclude loss of material due to pitting and 

corrosion and 2) will perform one-time inspections of select copper alloy piping, piping 

components, and piping elements exposed to lubricating oil for loss of material due to 

pitting and crevice corrosion to verify the effectiveness of the Lubricating Oil Analysis 

Program in applicable Steam and Power Conversion systems. The GALL Report states 

that one-time inspection is an acceptable method to verify the effectiveness of a 

mitigative AMP such as the Lubricating Oil Analysis Program. The staff noted that the 

applicant is crediting the Lubricating Oil Analysis Program as recommended in GALL 

AMR items VIII.G-19, VIII.D1-2 and, VIII.A-3, the applicant is verifying effectiveness of 

the Lubricating Oil Analysis Program with the elements of the One-Time Inspection 

Program, which the GALL Report states is an acceptable program to verify the 

Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds that, based on 

the programs identified above, the applicant has met the criteria of SRP-LR Section 

3.4.2.2.7.3. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.7.3 criteria. For those line 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 function(s) will be maintained consistent with the CLB 

during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.2.8 Loss of Material Due to Pitting, Crevice, and Microbiologically-Influenced Corrosion 

The applicant stated in LRA Section 3.4.2.2.8 that loss of material due to pitting, crevice, and 

MIC could occur for stainless steel piping, piping components, heat exchanger components and 

tanks exposed to lubricating oil. LRA Section 3.4.2.2.8 further states that: 1) this aging effect is 

managed with a combination of the Lubricating Oil Analysis Program and the One-Time 

Inspection Program; 2) the Lubricating Oil Analysis Program includes periodic oil sampling, 

analysis, and evaluation and trending of results; the program maintains oil systems 

contaminants (primarily water and particulates) within acceptable limits, thereby preserving an 

environment that is not conducive to degradation; 3) the One-Time Inspection Program 

performs sampling inspections using NDE techniques that either verify unacceptable 

degradation is not occurring or trigger additional actions, and; 4) components containing 

hydraulic fluid and not lubricating oil are also managed by the Lubricating Oil Analysis Program 

and the One-Time Inspection Program.

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 MIC could occur in stainless steel piping, 

piping components, piping elements, and heat exchanger components exposed to lubricating 

oil. SRP-LR Section 3.4.2.2.8 further states that: 1) the existing AMP relies on the periodic 

sampling and analysis of lubricating oil to maintain contaminants within acceptable limits, 
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thereby preserving an environment that is not conducive to corrosion; and, 2) the effectiveness 

of lubricating oil contaminant control can be verified through a one-time inspection of selected 

components at susceptible locations is an acceptable method to ensure that corrosion is not 

occurring.

SRP-LR Section 3.4.2.2.8 invokes AMR item 19 in Table 3 of the GALL Report, Volume 1, and 

GALL AMR items VIII.G-29 (Auxiliary Feedwater System), VIII.G-3 (Auxiliary Feedwater 

System), VIII.D1-3 (Feedwater System) and, VIII.A-9 (Steam Turbine System) as applicable to 

loss of material due to pitting and crevice corrosion of stainless steel piping, piping components, 

and piping elements exposed to lubricating oil. These components are identified in LRA Table 

3.4.2-1: Filter / Strainer Elements, Restricting Orifices.

The staff reviewed LRA Appendix B, Sections B2.1.24, “Lubricating Oil Analysis” and B2.1.29, 

“One-Time Inspection” in SER Sections 3.0.3.1.14 and 3.0.3.1.18 respectively and found that 

these programs: 1) provide for periodic sampling of lubricating oil to maintain contaminants at 

acceptable limits to preclude loss of material due to pitting, crevice and MIC; and 2) will perform 

one-time inspections of select stainless steel piping, piping components, piping elements 

exposed to lubricating oil for loss of material due to pitting, crevice and MIC to verify the 

effectiveness of the Lubricating Oil Analysis Program in applicable Steam and Power 

Conversion systems. The GALL Report states that one-time inspection is an acceptable method 

to verify the effectiveness of a mitigative AMP such as the Lubricating Oil Analysis Program.

The staff noted that the applicant is crediting the Lubricating Oil Analysis Program as 

recommended in GALL AMR items VIII.G-29, VIII.G-3, VIII.D1-3 and, VIII.A-9, the applicant is 

verifying effectiveness of the Lubricating Oil Analysis Program with the elements of the OneTime Inspection Program, which the GALL Report states is an acceptable program to verify the 

Lubricating Oil Analysis Program effectiveness. Therefore, the staff finds that, based on the 

programs identified above, the applicant has met the criteria of SRP-LR Section 3.4.2.2.8. 

Based on the programs identified, the staff concludes that the applicant’s programs meet 

SRP-LR Section 3.4.2.2.8 criteria. For those line 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 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.4.2.2.9 Loss of Material Due to General, Pitting, Crevice, and Galvanic Corrosion 

LRA Section 3.4.2.2.9 addresses the applicant’s aging management basis for managing loss of 

material due to general, pitting, crevice, and galvanic corrosion for steel heat exchanger 

components exposed to treated water. The applicant stated that LRA Table 3.4.1, AMR 

item 3.4.1-3 was used in lieu of AMR item 3.4.1-5 for evaluation of the steel heat exchanger 

components exposed to treated water in the condensate system; and, therefore, LRA 

Table 3.4.1, AMR item 3.4.1-5, was designated as “not used.”

The staff compared LRA Section 3.4.2.2.9 against the criteria of SRP-LR Section 3.4.2.2.9, 

which states that loss of material due to general, pitting, crevice, and galvanic corrosion may 

occur in steel heat exchanger components exposed to treated water. The SRP-LR states that 

the existing AMP relies on monitoring and control of water chemistry to manage the aging effect 
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of loss of material. However, control of water chemistry does not preclude loss of material at 

locations with stagnant flow conditions. The GALL Report recommends a one-time inspection 

program of selected components and susceptible locations to ensure that corrosion is not 

occurring.

SRP-LR Section 3.4.2.2.9 invokes AMR item 5 in Table 4 of the GALL Report, Volume 1, and 

GALL AMR item VIII.E-7. In the GALL Report, Volume 1, Table 4, and in the SRP-LR, 

Table 3.4-1, AMR item 5 is designated as applicable for BWRs, only. The staff noted that for the 

GALL Report item, the recommended AMPs are Water Chemistry (GALL AMP XI.M2) and OneTime Inspection (GALL AMP XI.M32). The staff also noted that Water Chemistry and One-Time 

Inspection are the AMPs recommended in the GALL Report, Volume 1, Table 4, item 3, and in 

SRP-LR, Table 3.4-1, item 3, which refers to SRP-LR Section 3.4.2.2.2.1. The staff determined 

that the recommended AMPs are the same, no matter whether the steel heat exchanger 

components in the condensate system are included in the evaluation for LRA Table 3.4.1, AMR 

item 3.4.1-3 or are evaluated separately under LRA Table 3.4.1, AMR item 3.4.1-5.

Because the AMPs recommended for AMR item 3.4.1-3 and for AMR item 3.4.1-5 are identical, 

the staff finds it acceptable for the applicant to designate LRA Table 3.4.1, AMR item 3.4.1-5 as 

not used, and to use LRA Table 3.4.1, AMR item 3.4.1-3, for evaluation of steel heat exchanger 

components in the condensate system. The staff’s evaluation of these and other components 

included in LRA Table 3.4.1, AMR item 3.4.1-3 are provided in SER Section 3.4.2.2.2.1.

3.4.2.2.10 Quality Assurance for Aging Management of Nonsafety-Related Components 

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

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

In LRA Tables 3.4.2-1 through 3.4.2-8, 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 3.4.2-1 through 3.4.2-8, 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 
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function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.4.2.3.1 Auxiliary Feedwater System - Summary of Aging Management Review –

LRA Table 3.4.2-1 

The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the 

auxiliary feedwater system component groups.

In LRA Table 3.4.2-1, the applicant proposed to manage loss of material–selective leaching in 

cast iron pump casings, filter, and strainer housings; copper alloy heat exchanger tubes; and 

bronze valve bodies exposed to internal and external environments of hydraulic oil and 

lubricating oil, by using the Selective Leaching of Materials Program. The applicant referenced 

Footnote H for these line items indicating that the aging effect is not in the GALL Report for this 

component, material, and environment combination. The applicant also referenced a plantspecific note, which stated that for these line items loss of material due to selective leaching for 

copper alloys and gray cast iron is evaluated in a fuel oil and lubricating oil internal environment. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection program credited under the applicant’s Selective 

Leaching Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15% alloying zinc content, aluminum bronzes with greater than 8% 

aluminum alloying contents and cast irons may be susceptible to selective leaching. On this 

basis, the staff finds the Selective Leaching of Materials Program is a valid program to credit for 

the management of loss of material due to selective leaching in these copper alloy piping and 

fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which identifies 

that copper alloys with greater than 15% alloying zinc contents may be susceptible to selective 

leaching, and (2) the basis in GALL AMP XI.M33 that the one-time inspection proposed in 

Selective Leaching Program is an acceptable basis for managing loss of material in for copper 

alloy, aluminum bronze and cast iron components as a result of selective leaching.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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3.4.2.3.2 Bleed Steam System - Summary of Aging Management Review – LRA Table 3.4.2-2 

The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for the 

bleed steam system component groups.

In LRA Table 3.4.2-2, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal treated water and steam 

environment and for chrome-molybdenum alloy piping and fittings exposed to an internal steam 

environment. The applicant stated this is TLAA and must be evaluated in accordance with 

10 CFR 54.21(c)(1). The AMR line items cite Generic Note H, which indicates that the aging 

effect is not addressed in the GALL Report for this component, material and environment 

combination.

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.3 Circulating Water System - Summary of Aging Management Review –

LRA Table 3.4.2-3 

The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for the 

circulating water system component groups.

In LRA Table 3.4.2-3, the applicant proposed to manage change in material properties due to 

thermal exposure and cracking due to thermal exposure for expansion joints fabricated from 

natural rubber exposed to an internal raw water environment. The AMR line items cite Generic 

Note H, which indicates that the aging effect is not addressed in the GALL Report for this 

component, material and environment combination.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring” to include non-metallic components, 

including natural rubber, and the aging effects of change in material properties and cracking.

The staff further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant to provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 
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and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

During its review the staff notes that the applicant utilized a plant-specific note which indicates 

that this program is credited to manage aging of internal surfaces because the external surfaces 

are subject to the same environment or stressor as the internal surfaces. The staff notes that 

the applicant’s use of this program is consistent with the recommendations in the GALL Report.

However, the staff determined that additional information was needed pertaining to the internal 

and external environments of these natural rubber components. Therefore, by letter dated 

December 18, 2008, the staff issued RAI 3.3.2-08-01 requesting the applicant to clarify the 

external environment of these components, and to consider the program’s ability to manage 

aging in non-metallic components. By letter dated January 20, 2009, the applicant responded to 

RAI 3.3.2-08-01 by stating that the external environment is plant-indoor air – uncontrolled and is 

not identical to the internal environment of raw water. The applicant further stated the external 

thermal stressor (i.e., temperature) that can cause cracking and change in material properties 

for non-metallic components is the same as the internal thermal exposure stressor. The staff 

notes that the applicant’s statement is reasonable because these natural rubber flex 

connections are not insulated and, therefore, the external surface of these components will be 

representative of the temperature of the internal raw water environment. The staff further notes 

that the external surface may be subject to ultraviolet and ozone exposure which can contribute 

to the aging effects of cracking and change in material properties in non-metallic components.

Furthermore, the staff notes this additional exposure may create a more aggressive 

environment on the external surface when compared to the internal environment. On the basis 

of its review, the staff finds the applicant’s response acceptable because the external 

environment is subject to the same thermal stressor and is more aggressive than the internal 

environment because of the additional ultraviolet and ozone exposure; therefore, the applicant’s 

program which performs inspections on the external surface of these components will be 

representative of the conditions on the internal surface.

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is

documented in SER Section 3.0.3.2.5. The staff notes that this program will include periodic 

visual inspections of external surfaces performed during system walkdowns at a specified 

frequency. The staff further notes that age-related degradation of non-metallic components, 

such as change in material properties and cracking, can be detected by a visual inspection, 

coupled with a physical manipulation when appropriate, and is evidenced by surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes that the physical manipulation will 

supplement and aid the visual inspection in detecting age-related degradation because changes 

in material properties, such as hardening and loss of strength, can be detected during 

manipulation of non-metallic components, when appropriate, by the relative inflexibility of the 

component, or by the failure of the component to return to its previous shape or configuration.

On the basis of periodic visual inspections supplemented by a physical manipulation and that 

these activities will be performed during system walkdowns at a specified frequency, the staff 

finds the applicant’s use of the External Surfaces Monitoring Program acceptable.
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In LRA Table 3.4.2-3, the applicant proposed to manage change in material properties due to 

cracking for PVC piping, fittings and valve bodies exposed to an external uncontrolled plant 

indoor air environment. The AMR line items cite Generic Note F, which indicates that the 

material is not addressed in the GALL Report for this environment.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring” to include non-metallic components, 

including PVC, and the aging effects of change in material properties and cracking. The staff 

further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant to provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.5. The staff notes that this program will include periodic 

visual inspections of external surfaces performed during system walkdowns at a specified 

frequency. The staff further notes that age-related degradation of non-metallic components, 

such as change in material properties and cracking, can be detected by a visual inspection, 

coupled by a physical manipulation when appropriate, and is evidenced by surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008 to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes stated that this program will 

supplement the visual examination with a physical manipulation in order to verify aging effects 

such as hardening, embrittlement, or gross softening are not occurring. The staff notes that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation and that these activities will be performed during system walkdowns at a specified 

frequency, the staff finds the applicant's use of the External Surfaces Monitoring Program 

acceptable.

LRA Table 3.4.2-3 summarizes the results of AMRs for the circulating water system piping, 

fittings and valve bodies constructed using PVC exposed to raw water (internal). The applicant 

proposed that there is no aging effect for the material environment combination and that no 

AMR is required.

The applicant has indicated that Generic Note F is applicable for these items with plant-specific

Note 413. Generic Note F is “Material not in NUREG-1801 for this component.” Plant-specific 

Note 413 states, “Materials science evaluation for this material in this environment results in no 

aging effects." The staff confirmed that this material is not in the GALL Report for this 
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component. The staff also agrees that there will not be any aging mechanism for this 

material/environment combination and that no AMP is required. This conclusion is based on the 

fact that PVC has no aging effect when in contact with raw water (Roff, W. J., Fibres, Plastics, 

and Rubbers: A Handbook of Common Polymers, Academic Press Inc., New York, 1956.)

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 for circulating water system 

components not evaluated in the GALL Report. The staff finds that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.4.2.3.4 Condensate System - Summary of Aging Management Review – LRA Table 3.4.2-4

The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for the 

condensate system component groups.

In LRA Table 3.4.2-4, the applicant proposed to manage change in material properties due to 

thermal exposure and cracking due to thermal exposure for expansion joints fabricated from 

natural rubber exposed to an internal treated water environment. The AMR line items cite 

Generic Note H, which indicates that the aging effect is not addressed in the GALL Report for 

this component, material and environment combination.

The applicant credits PINGP AMP B2.1.14 “External Surfaces Monitoring Program” for aging 

management. The staff notes that the applicant has proposed to enhance the scope of program 

of GALL AMP XI.M36, “External Surfaces Monitoring” to include non-metallic components, 

including natural rubber, and the aging effects of change in material properties and cracking. 

The staff further notes the intent of GALL AMP XI.M36 is to perform visual inspections of steel 

components for loss of material. The staff determined that additional information was needed on 

the applicant’s proposed augmentation to PINGP AMP B2.1.14. Therefore, by letter dated 

November 5, 2008, the staff issued RAI B2.1.14-1 requesting the applicant provide an 

appropriate program that will manage the effects of aging for non-metallic components, 

including PVC. The applicant responded to RAI B2.1.14-1 by letter dated December 5, 2008, 

and the staff finds the applicant’s response acceptable as documented in the staff’s evaluation 

of RAI B2.1.14-1 in SER Section 3.0.3.2.5.

During its review the staff notes that the applicant utilized a plant-specific note which indicates 

that this program is credited to manage aging of internal surfaces because the external surfaces 

are subject to the same environment or stressor as the internal surfaces. The staff notes that 

the applicant’s use of this program is consistent with the recommendations in the GALL Report.

However, the staff determined that additional information was needed pertaining to the internal 

and external environments of these natural rubber components. Therefore, by letter dated 

December 18, 2008, the staff issued RAI 3.3.2-08-01 requesting the applicant to clarify the 

external environment of these components, and to consider the program’s ability to manage 

aging in non-metallic components. By letter dated January 20, 2009, the applicant responded to 

RAI 3.3.2-08-01 by stating that the external environment is plant-indoor air – uncontrolled and is 

not identical to the internal environment of treated water. The applicant further stated the 

external thermal stressor (i.e. temperature) that can cause cracking and change in material 
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properties for non-metallic components is the same as the internal environment. The staff notes 

that the applicant’s statement is reasonable because these natural rubber flex connections are 

not insulated and, therefore, the external surface of these components will be representative of 

the temperature of the internal treated water environment. The staff further notes that the 

external surface may be subject to ultraviolet and ozone exposure which can contribute to the 

aging effects of cracking and change in material properties in non-metallic components.

Furthermore, the staff notes this additional exposure may potentially create a more aggressive 

environment on the external surface when compared to the internal environment. On the basis 

of its review, the staff finds the applicant’s response acceptable because the external 

environment is potentially more aggressive than the internal environment; therefore, the 

applicant’s program, which performs inspections on the external surface of these components, 

will be a representative of the conditions on the external and internal surface.

The staff reviewed the applicant’s External Surfaces Monitoring Program and its evaluation is 

documented in SER Section 3.0.3.2.5. The staff notes that this program will include periodic 

visual inspections of external surfaces performed during system walkdowns at a specified 

frequency. The staff further notes that age-related degradation of non-metallic components, 

such as change in material properties and cracking, can be detected by a visual inspection, 

coupled by a physical manipulation when appropriate, and is evidenced by surface 

discontinuities that include cracking, crazing, peeling, blistering, chalking, flaking, physical 

distortion, discoloration, loss of material from wear, and signs of leakage. The applicant 

amended its LRA, by letter dated December 5, 2008, to supplement the visual inspection with a 

physical manipulation when appropriate. The staff notes stated that this program will 

supplement the visual examination with a physical manipulation in order to verify aging effects 

such as hardening, embrittlement, or gross softening are not occurring. The staff notes that the 

physical manipulation will supplement and aid the visual inspection in detecting age-related 

degradation because changes in material properties, such as hardening and loss of strength, 

can be detected during manipulation of non-metallic components, when appropriate, by the 

relative inflexibility of the component, or by the failure of the component to return to its previous 

shape or configuration. On the basis of periodic visual inspections supplemented by a physical 

manipulation and that these activities will be performed during system walkdowns at a specified 

frequency, the staff finds the applicant’s use of the External Surfaces Monitoring Program 

acceptable.

LRA Table 3.4.2-4 summarizes the results of AMRs for Condensate System flex connections 

constructed from stainless steel exposed to outdoor air – sheltered (external). The applicant 

proposed that there is no aging effect for the material environment combination and that no 

AMR is required.

The applicant has indicated that Generic Note G is applicable for these items. Generic Note G is 

“Environment not in NUREG-1801 for this component and material.” The staff confirmed that 

this environment is not in the GALL Report for this component and material. The staff also 

agrees that there will not be any aging mechanism for this material/environment combination 

and that no AMP is required. Stainless steel forms a passive film in outdoor air that is 

immediately repassivated if disturbed. Therefore, there is no aging effect for stainless steel in air 

and no AMP is required. There is a similar material/environment combination in the GALL 

Report and the aging effect is none and no AMP is required (See the GALL Report items III 

TP-5, IV RP-04, V EP-18, VII AP-17, and VIII SP-12).
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In LRA Table 3.4.2-4, the applicant proposed to manage loss of preload due to thermal, gasket 

creep loosening for carbon steel and stainless steel bolts and fasteners externally exposed to 

an outdoor air- sheltered environment using the Bolting Integrity Program. The AMR line item 

cites Generic Note G, which indicates that the environment is not addressed in the GALL Report 

for this component and material. The AMR line item also cites Plant-Specific Note 304, which 

indicates that SCC is not an applicable aging effect/mechanism since there are no bolts with a 

minimum yield strength > 150 ksi. 

The LRA credits the PINGP AMP B2.1.6 “Bolting Integrity Program” to manage this aging effect.

The staff’s evaluation of the Bolting Integrity Program is documented in SER Section 3.0.3.2.1.

The Bolting Integrity Program is an existing PINGP program that will manage the loss of preload 

due to thermal effects, gasket creep, and self loosening. As described in EPRI NP-5067, the 

loss of preload aging effect is most common in high temperature environments. However, 

thermal cycling may be experienced in outdoor environments during the change from summer to 

winter months, can also contribute to a loss of preload. The applicant clearly states in LRA 

Section AMP B2.1.6 “Bolting Integrity Program” that loss of preload (leaking or loose bolts/nuts) 

for closure and structural bolting is inspected periodically. These periodic inspections monitor for 

indications of the loss of preload. On the basis of its review, the staff finds that because these 

components will be inspected through the specifications of the Bolting Integrity Program, they 

will be adequately managed.

In LRA Table 3.4.2-4, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal treated water environment.

The applicant stated this is TLAA and must be evaluated in accordance with 10 CFR 

54.21(c)(1). The AMR line items cite Generic Note H, which indicates that the aging effect is not 

addressed in the GALL Report for this component, material and environment combination.

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.5 Feedwater System - Summary of Aging Management Review – LRA Table 3.4.2-5

The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for the 

feedwater system component groups.

In LRA Table 3.4.2-5, the applicant proposed to manage loss of material–selective leaching in 

copper alloy piping and fittings, cast iron pump casings, and brass valve bodies exposed to 

internal environments of lubricating oil by using the Selective Leaching of Materials Program.

The applicant referenced Footnote H for these line items indicating that the aging effect is not in 

the GALL Report for this components, material, and environment combination. The applicant 
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also referenced a plant-specific note, which stated that for these line items loss of material due 

to selective leaching for copper alloys and gray cast iron is evaluated in a fuel oil and lubricating 

oil internal environment. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection program credited under the applicant’s Selective 

Leaching Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15 % alloying zinc content, aluminum bronzes with greater than 8 %

aluminum alloying contents and cast irons may be susceptible to selective leaching. On this 

basis, the staff finds the Selective Leaching of Materials Program is a valid program to credit for 

the management of loss of material due to selective leaching in these copper alloy piping and 

fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which identifies 

that copper alloys with greater than 15 % alloying zinc contents may be susceptible to selective 

leaching, and (2) basis in GALL AMP XI.M33 that the one-time inspection proposed in Selective 

Leaching Program is an acceptable basis for managing loss of material for copper alloy, 

aluminum bronze and cast iron components as a result of selective leaching.

In LRA Table 3.4.2-5, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal treated water environment.

The applicant stated this is TLAA and must be evaluated in accordance with 

10 CFR 54.21(c)(1). The AMR line items cite Generic Note H, which indicates that the aging 

effect is not addressed in the GALL Report for this component, material and environment 

combination.

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.4.2.3.6 Main Steam System - Summary of Aging Management Review – LRA Table 3.4.2-6

The staff reviewed LRA Table 3.4.2-6, which summarizes the results of AMR evaluations for the 

main steam system component groups.
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In LRA Table 3.4.2-6, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal steam environment. The 

applicant stated this is TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1).

The AMR line items cite Generic Note H, which indicates that the aging effect is not addressed 

in the GALL Report for this component, material and environment combination.

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

3.4.2.3.7 Steam Generator Blowdown System - Summary of Aging Management Review –

LRA Table 3.4.2-7

The staff reviewed LRA Table 3.4.2-7, which summarizes the results of AMR evaluations for the 

steam generator blowdown system component groups.

In LRA Table 3.4.2-7, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal treated water environment.

The applicant stated this is TLAA and must be evaluated in accordance with 10 CFR 

54.21(c)(1). The AMR line items cite Generic Note H, which indicates that the aging effect is not 

addressed in the GALL Report for this component, material and environment combination.

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

3.4.2.3.8 Turbine Generator and Support System - Summary of Aging Management Review –

LRA Table 3.4.2-8

The staff reviewed LRA Table 3.4.2-8, which summarizes the results of AMR evaluations for the 

turbine generator and support system component groups.

In LRA Table 3.4.2-8, the applicant proposed to manage loss of material due to pitting and 

crevice corrosion for aluminum material for pump casings exposed to an internal raw water 

environment using the Internal Inspection of Miscellaneous Piping and Ducting Components 

Program. The AMR line items cite Generic Note G, which indicates that this environment is not 

addressed in the GALL Report for this component and material combination. The applicant 

stated that the environment for this component is evaluated as raw water and is essentially 

waste water or a potential mixture of water and oil.

The LRA credits the PINGP AMP B2.1.22 “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components” to manage this aging effect tanks in a raw water (internal) 

environment only. The staff’s review of the applicant's Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and its evaluation are documented in 

SER Section 3.0.3.1.13. The staff finds that the Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program performs periodic visual inspections of internal 

surfaces during periodic system and component surveillance activities or during maintenance 

activities when the internal surface is accessible for visual inspections to detect aging effects 
3-425

that could result in a loss of the component's intended function. The staff finds that these visual 

inspections will be capable of detecting loss of material because evidence of material wastage 

will be visible on the internal surface of these components during the inspections. On the basis 

of its review, the staff finds that because these components will be inspected periodically by

visual inspections when exposed to an internal raw water environment they will be adequately 

managed by this program.

In LRA Table 3.4.2-8, the applicant proposed to manage loss of material–selective leaching in 

copper nickel heat exchanger tubes exposed to wet air/gas external environment, and cast iron 

heat exchanger components; brass valve bodies, filters, and strainer housings; and bronze 

valve bodies exposed to internal environments of hydraulic and lubricating oil, by using the 

Selective Leaching of Materials Program. The applicant referenced Footnote H for these line 

items indicating that the aging effect is not in the GALL Report for this components, material, 

and environment combination. The applicant also referenced a plant-specific note, which stated 

that for these line items loss of material due to selective leaching for copper alloys and gray cast 

iron is evaluated in a fuel oil and lubricating oil internal environment. 

In LRA B2.1.36, the applicant stated that the Selective Leaching of Materials Program will 

include a one-time visual inspection in conjunction with a hardness measurement, or other 

suitable detection technique of selected components that may be susceptible to selective 

leaching. The staff's evaluation of the Selective Leaching of Materials Program is documented 

in SER Section 3.0.3.2.15. The staff finds that this new one-time program is consistent with 

GALL AMP XI.M33, "Selective Leaching," and includes an approved exception related to 

physical examinations.

The staff noted that the one-time inspection program credited under the applicant’s Selective

Leaching Program is consistent with the one-time inspection basis credited in GALL AMP 

XI.M33, "Selective Leaching," for component materials that are identified as being susceptible to 

selective leaching. The staff also noted that the GALL Report Table IX.C identifies that copper 

alloys with greater than 15% alloying zinc content, aluminum bronzes with greater than 8% 

aluminum alloying contents and cast irons may be susceptible to selective leaching. On this 

basis, the staff finds the Selective Leaching of Materials Program is a valid program to credit for 

the management of loss of material due to selective leaching in these copper alloy piping and 

fittings because the basis is consistent with: (1) the basis in GALL Table IX.C, which identifies 

that copper alloys with greater than 15% alloying zinc contents may be susceptible to selective 

leaching, and (2) basis in GALL AMP XI.M33 that the one-time inspection proposed in Selective 

Leaching Program is an acceptable basis for managing loss of material in for copper alloy, 

aluminum bronze and cast iron components as a result of selective leaching.

In LRA Table 3.4.2-8, the applicant proposed to manage cumulative fatigue damage due to 

fatigue for stainless steel piping and fittings exposed to an internal treated water and internal 

steam environment. The applicant stated this is TLAA and must be evaluated in accordance 

with 10 CFR 54.21(c)(1). The AMR line items cite Generic Note H, which indicates that the 

aging effect is not addressed in the GALL Report for this component, material and environment 

combination.
3-426

The staff verified that in LRA Section 4.3.2 the applicant provided its TLAA evaluation for this 

component. The staff’s evaluation of this TLAA, Non-Class 1 Fatigue, is documented in SER 

Section 4.3.2.

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 for those items with aging effects, the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 10 CFR 

54.21(a)(3). 

3.4.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion systems components within the scope 

of license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.5 Aging Management of 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:

• auxiliary and turbine buildings

• component supports

• cranes, heavy loads, fuel handling

• D5/D6 diesel generator building and underground storage vault, fuel oil transfer house, 

old service building, and new service building

• fire protection barriers

• radwaste building, old administration building, and administration building addition

• reactor containment vessels units 1 and 2

• SBO yard structures

• shield buildings units 1 and 2

• tank foundations

• water control structures – approach canal, emergency cooling water intake, intake canal, 

and screenhouse

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 Evaluations in 
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Chapters II and III of NUREG-1801 for Structures and Component Supports,” 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 CRs 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.

3.5.2 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 function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted a review of the AMR items that the applicant had identified as being 

consistent with the GALL Report to ensure the applicant’s claim that certain AMRs were 

consistent with the GALL Report. The staff did not repeat its review of the matters described in 

the GALL Report; however, the staff did verify that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s audit 

evaluation are documented in SER Section 3.5.2.1.

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.
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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 belowgrade concrete, 

and periodic 

monitoring of 

groundwater if 

environment is nonaggressive. 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

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.1.2)
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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

Concrete elements:

foundation, 

sub-foundation

(3.5.1-3)

Reduction in 

foundation 

strength, 

cracking, 

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 Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.1.2)

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 

aging management 

program 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, IWE (B2.1.4) 

and 

10 CFR Part 50, 

Appendix J

(B2.1.1)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.1.4)
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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

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 

to PINGP (See 

SER Section 

3.5.2.2.1.5)

Steel and stainless 

steel elements: 

vent line, vent 

header, vent line 

bellows; 

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 - Metal 

fatigue

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.1.6)

Stainless steel 

penetration 

sleeves, 

penetration 

bellows, dissimilar 

metal welds

(3.5.1-10)

Cracking due 

to stress 

corrosion 

cracking

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, IWE (B2.1.4) 

and 

10 CFR Part 50, 

Appendix J 

(B2.1.1)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.1.7)

Stainless steel vent 

line bellows,

(3.5.1-11)

Cracking due 

to stress 

corrosion 

cracking

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)
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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 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 TLAA Consistent with 

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 dayinch/yr) 

(NUREG-1557).

Yes Not applicable See SER 

Section 

3.5.2.2.1.9 

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 
3-432

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

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, IWE (B2.1.4) 

and 

10 CFR Part 50, 

Appendix J 

(B2.1.1)

Consistent with 

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 Technical 

Specifications

No ASME Section 

XI, IWE 

(B2.1.4), 

10 CFR Part 50, 

Appendix J 

(B2.1.1), and 

Plant Technical 

Specification 

Consistent with 

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, IWE (B2.1.4) 

and 

10 CFR Part 50, 

Appendix J 

(B2.1.1)

Consistent with 

GALL Report, 

(See SER 

Section 

3.5.2.1.2)

Steel elements: 

stainless steel 

suppression 

chamber shell 

(inner surface)

(3.5.1-19)

Cracking due 

to stress 

corrosion 

cracking

ISI (IWE) and 

10 CFR Part 50, 

Appendix J

No Not applicable Not applicable 

to PWRs

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

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
3-433

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 

to PINGP (See 

SER Section 

3.5.2.1.1)

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

(B2.1.38)

Consistent with 

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

(B2.1.38)

Consistent with 

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

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.1)
3-434

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 

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

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.1 and 

3.5.2.2.2.2.1)

All Groups except 

Group 6: 

accessible and 

inaccessible 

interior/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

(B2.1.38)

Consistent with 

GALL Report, 

(See SER 

Section 

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

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

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, 

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 

Section 

3.5.2.2.2.1 and 

3.5.2.2.2.2.3)
3-435

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 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 10 CFR 50, 

Appendix J 

(B2.1.1) or 

Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.1)

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 belowgrade concrete, 

and periodic 

monitoring of 

groundwater, if the 

environment is nonaggressive. A 

plant-specific

program is to be 

evaluated if 

environment is 

aggressive.

Yes Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

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

(B2.1.38)

Consistent with 

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

Plant-specific Yes Structures 

Monitoring 

Program

(B2.1.38) &

RG 1.127 , 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.3)
3-436

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, loss 

of material due 

to aggressive 

chemical 

attack; 

cracking, loss 

of bond, loss of 

material due to 

corrosion of 

embedded 

steel

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs and for 

inaccessible 

concrete, an 

examination of 

representative 

samples of belowgrade concrete, 

and periodic 

monitoring of 

groundwater, if the 

environment is nonaggressive. A 

plant-specific

program is to be 

evaluated if 

environment is 

aggressive.

Yes RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

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 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.4.2)
3-437

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

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 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

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 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power

Plants Program 

(B2.1.35)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.4.3)

Groups 7, 8: tank 

liners

(3.5.1-38)

Cracking due 

to stress 

corrosion 

cracking; loss 

of material due 

to pitting and 

crevice 

corrosion

A plant-specific 

aging management 

program is to be 

evaluated

Yes Water 

Chemistry 

Program 

(B2.1.40)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.5)

Support members; 

welds; bolted 

connections; 

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

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.6)
3-438

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

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, 

serviceinduced 

cracking or 

other concrete 

aging 

mechanisms

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program

(B2.1.38)

ASME Section 

XI, Subsection 

IWF Program 

(B2.1.5)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.6)

Vibration isolation 

elements

(3.5.1-41)

Reduction or 

loss of 

isolation 

function, 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory 

loading

Structures 

Monitoring Program

Yes Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report 

(See SER 

Section 

3.5.2.2.2.6)

Groups B1.1, B1.2, 

and B1.3: support 

members: anchor 

bolts, welds

(3.5.1-42)

Cumulative 

fatigue 

damage (CLB 

fatigue 

analysis exists)

TLAA, evaluated in 

accordance with 

10 CFR 54.21(c)

Yes TLAA & ASME 

Section XI, 

Subsection IWF 

Program

(B2.1.5)

Consistent with 

GALL Report 

(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 Masonry Wall 

Program 

(B2.1.25), Fire 

Protection 

Program

(B2.1.15)

Consistent with 

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

(B2.1.38)

Consistent with 

GALL Report
3-439

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: 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 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

GALL Report 

Group 5: fuel pool 

liners

(3.5.1-46)

Cracking due 

to stress 

corrosion 

cracking; loss 

of material due 

to pitting and 

crevice 

corrosion

Water Chemistry 

and monitoring of 

spent fuel pool 

water level in 

accordance with 

technical 

specifications and 

leakage from the 

leak chase 

channels

No Water 

Chemistry 

Program

(B2.1.40) / 

Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report, 

(See SER 

Section 

3.5.2.1.4)

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 RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35) /

Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report, 

(See SER 

Section 

3.5.2.1.5)

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, 

Seepage

Inspection of 

Water-Control 

Structures or 

FERC/US Army 

Corps of Engineers 

dam inspections 

and maintenance 

programs

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants Program 

(B2.1.35)

Consistent with 

GALL Report 
3-440

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

Support members; 

welds; bolted 

connections; 

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

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 Not applicable Not applicable 

to PINGP (See 

SER Section 

3.5.2.1.1)

Group B1.1: high 

strength low-alloy 

bolts

(3.5.1-51)

Cracking due 

to stress 

corrosion 

cracking; loss 

of material due 

to general 

corrosion

Bolting Integrity No Bolting Integrity

Program 

(B2.1.6)

Consistent with 

GALL Report 

Groups B2, and B4: 

sliding support 

bearings and 

sliding support 

surfaces

(3.5.1-52)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, 

fatigue due to 

vibratory and 

cyclic thermal 

loads

Structures 

Monitoring Program

No Structures 

Monitoring 

Program

(B2.1.38)

Consistent with 

GALL Report 

Groups B1.1, B1.2, 

and B1.3: support 

members: welds; 

bolted connections; 

support anchorage 

to building structure

(3.5.1-53)

Loss of 

material due to 

general and 

pitting 

corrosion

ISI (IWF) No ASME Section 

XI, IWF 

Program 

(B2.1.5)

Consistent with 

GALL Report 

Groups B1.1, B1.2, 

and B1.3: constant 

and variable load 

spring hangers; 

guides; stops;

(3.5.1-54)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, 

fatigue due to 

vibratory and 

cyclic thermal 

loads

ISI (IWF) No ASME Section 

XI, IWF 

Program 

(B2.1.5)

Consistent with 

GALL Report 
3-441

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, 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

No Boric Acid 

Corrosion

Program 

(B2.1.7)

Consistent with 

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, 

overload, 

fatigue due to 

vibratory and 

cyclic thermal 

loads

ISI (IWF) No ASME Section 

XI, IWF 

Program 

(B2.1.5)

Consistent with 

GALL Report

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, 

sustained 

vibratory 

loading

ISI (IWF) No ASME Section 

XI, IWF 

Program 

(B2.1.5)

Consistent with 

GALL Report

Galvanized steel 

and aluminum 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

exposed to air -

indoor uncontrolled

(3.5.1-58)

None None NA None Consistent with 

GALL Report 

Stainless steel 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure

(3.5.1-59)

None None NA None Consistent with 

GALL Report
3-442

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 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:

• 10 CFR Part 50, Appendix J Program

• ASME Section XI, Subsection IWE Program

• Bolting Integrity Program

• Boric Acid Corrosion Program

• Fire Protection Program

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program

• Masonry Wall Program

• RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program

• Structures Monitoring Program

• Water Chemistry Program

LRA Tables 3.5.2-1 through 3.5.2-11 summarize AMRs for the structures and component 

supports components and indicate AMRs claimed to be consistent with the GALL Report.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency with the report and for which it does not recommend further evaluation, the staff’s 

audit and review determined whether the plant-specific components of these GALL Report 

component groups were bounded by the GALL Report evaluation.

The applicant noted for each AMR line item how the information in the tables aligns with the 

information in the GALL Report. The staff audited those AMRs with Notes A through E indicating 

how the AMR is consistent with the GALL Report.

Note A indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP is consistent with the GALL AMP. 
3-443

The staff reviewed these line items to verify consistency with the GALL Report and validity of 

the AMR for the site-specific conditions.

Note B indicates that the AMR line item is consistent with the GALL Report for component, 

material, environment, and aging effect. In addition, the AMP takes some exceptions to the 

GALL AMP. The staff reviewed these line items to verify consistency with the GALL Report and 

verified that the identified exceptions to the GALL AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with the GALL AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR line item, although different from 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 AMP. This note indicates that the 

applicant was unable to find a listing of some system components in the GALL Report; however, 

the applicant identified in the GALL Report a different component with the same material, 

environment, aging effect, and AMP as the component under review. The staff 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 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 AMPs have been reviewed and accepted. The staff also 

determined whether the applicant’s AMP was consistent with the GALL AMP and whether the 

AMR was valid for the site-specific conditions.

Note E indicates that the AMR line item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff reviewed these line items 

to verify consistency with the GALL Report. The staff also determined whether the credited AMP 

would manage the aging effect consistently with the GALL AMP and whether the AMR was valid 

for the site-specific conditions.

The staff 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 

structures and components 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 
3-444

determined were in need of additional clarification and assessment. The staff’s evaluations of 

these AMRs are provided in the subsections that follows.

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 states that the 

corresponding AMR items in GALL Report are not applicable to PINGP because the AMR items 

in the GALL Report are only applicable to particular components in BWR reactor designs and 

because PINGP is a Westinghouse-designed PWR facility. The staff verified that the stated 

AMR items in the GALL Report are only applicable to BWR designed facilities and are not 

applicable to the PINGP LRA.

LRA Table 3.5.1, items 22, and 50 are identified as “Not Applicable" since the component, 

material, and environment combination does not exist at PINGP. For each of these line items, 

the staff reviewed the LRA and the applicant's supporting documents, and confirmed the 

applicant's claim that the component, material, and environment combination does not exist at 

PINGP. Since PINGP does not have the component, material, and environment combination for 

these Table 1 line items, the staff finds that these AMRs are not applicable to PINGP. 

3.5.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

In the discussion section of LRA Table 3.5.1, item 3.5.1-18, the applicant stated that ASME 

Section XI, Subsection IWE, and 10 CFR 50, Appendix J will be used to manage aging affects 

due to general, pitting, and crevice corrosion of reactor building (containment) penetration 

sleeves with dissimilar metal welds, personal airlocks, and equipment hatches. The applicant 

stated that the Fire Protection Program will also be used to manage the aging effect/mechanism 

in areas subject to loss of material due to general corrosion. The staff noted the AMR item 

3.5.1-18 included a reference to Note E and plant-specific Note 8, which states that “NUREG1801 includes the aging effect loss of material due to general, pitting, and crevice corrosion. 

Loss of material due to pitting and crevice corrosions is not applicable at PINGP since air indoor 

and air outdoor environments do not contain aggressive contaminants and are not continuously 

wetted.”

The staff reviewed the AMR results lines that referenced Note E and plant-specific Note 8. The 

staff determined, for these line items, 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 AMP XI.S1, “ASME Section XI, Subsection IWE and AMP XI.S4.

“10 CFR Part 50, Appendix J,” the applicant has additionally proposed using the Fire Protection 

Program. The GALL Report line item referenced is the steel elements and, therefore, the GALL 

Report recommends AMP XI.S1 and XI.S4. The applicant stated that the AMR result line items 

that reference LRA Table 3.5.1 item 3.5.1-18 is also located in the areas subject to general 

corrosion and, therefore, the Fire Protection Program was also credited. Since the Fire 

Protection Program, ASME Section XI, Subsection IWE, and 10 CFR Part 50, Appendix J 

require visual inspections on a periodic basis to manage loss of material due to general

corrosion. On the basis that periodic visual inspections are performed, the staff finds the 

applicant's additional use of the Fire Protection Program to be acceptable.
3-445

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 AERM adequately, as recommended by the 

GALL Report.

3.5.2.1.3 Cracking Due to Restraint Shrinkage, Creep, and Aggressive Environment 

In the discussion section of 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 Masonry Wall 

Program. The applicant stated that the Fire Protection Program will also be used to manage the 

aging effect/mechanism in areas relied upon as fire barriers. During the review, the staff noted 

that for the AMR results line pointing to Table 3.5.1, item 3.5.1-43, for four groups the applicant 

included a reference to Note E and plant-specific Note 30, which states “These masonry walls 

are not safety-related, and are relied upon to perform a function that demonstrates compliance 

with a regulated event(s).” 

.

The staff reviewed the AMR results lines referenced to Note E, plant-specific Note 30, 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 

AMP XI.S5, “Masonry Wall Program,” the applicant has additionally proposed using the Fire 

Protection Program. The GALL Report line item referenced is masonry block walls and the 

GALL Report recommends AMP XI.S5. The applicant stated that the AMR result line items that 

reference LRA Table 3.5.1 item 3.5.1-43 are also located in areas that are relied upon as fire 

barriers, and the Fire Protection Program was also credited. Since the Fire Protection Program 

and Masonry Wall Program require visual inspections on a periodic basis to manage cracking 

due to restraint shrinkage, creep, and aggressive environment, the staff finds the applicant's 

additional use of the Fire Protection 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 AERM adequately.

3.5.2.1.4 Cracking Due to Stress Corrosion Cracking; Loss of Material Due to Pitting and 

Crevice Corrosion. 

In the discussion section of LRA Table 3.5.1, item 3.5.1-46, the applicant stated that cracking 

due to SCC and loss of material due to pitting and crevice corrosion are managed by the Water 

Chemistry Program. The applicant stated that the Structures Monitoring Program will also be 

used to manage the aging effect/mechanism in areas subject to pitting and crevice corrosion. 

During the review, the staff noted that for the AMR results line pointing to Table 3.5.1, 

item 3.5.1-46, for two groups the applicant included a reference to Note E and plant-specific 

Note 16, which states, “NUREG-1801 line item material/environment combination is used to 

identify stainless steel sump liners in treated borated water. The Structures Monitoring Program 

is used to manage the aging effects cracking due to SCC and loss of material due to pitting and 

crevice corrosion for stainless steel sump liners rather then the NUREG referenced Water 

Chemistry Program since water quality in the sumps is not monitored.”
3-446

The staff reviewed the AMR results lines referenced to Note E and plant-specific Note 16. The 

staff 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 

AMP XI.M2, “Water Chemistry Program,” the applicant has additionally proposed using the 

Structures Monitoring Program. The GALL Report line item referenced is stainless steel sump 

liners, and the GALL Report recommends AMP XI.M2. The applicant stated that the AMR result 

line items that reference LRA Table 3.5.1 item 3.5.1-46 is also located in the treated borated 

water areas subject to cracking and loss of material due to pitting and crevice corrosion, and the 

Structures Monitoring Program was also credited. Since the Water Chemistry Program and 

Structures Monitoring Program are performing visual inspections on a periodic basis to manage 

cracking and loss of material due to pitting and crevice corrosion, the staff finds the applicant's 

additional use of 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 AERM adequately.

3.5.2.1.5 Loss of Material Due to General (steel only), Pitting and Crevice Corrosion. 

In the discussion section of LRA Table 3.5.1, item 3.5.1-47, the applicant stated that loss of 

material due to general (steel only)/pitting and crevice corrosion is managed by RG 1.127 

Inspection of Water Control Structures Associated with Nuclear Power Plants. The applicant 

stated that the Structures Monitoring Program will also be used to manage the aging 

effect/mechanism in areas subject to loss of material due to general (steel only)/pitting and 

crevice corrosion. During the review, the staff noted that for the AMR results line pointing to 

Table 3.5.1, item 3.5.1-47, for two groups the applicant included a reference to Note E and 

plant-specific Notes 3, 4, and 31, which state “Aging mechanism(s) not in NUREG-1801,” “The 

component is buried and inaccessible for examination. The Structures Monitoring Program 

requires examination of buried structural members whenever the surrounding soil is excavated. 

Observed condition of excavated members is used as a basis for evaluating the condition of 

inaccessible structural members," and “The Bolting Integrity Program provides preventive 

measures and maintenance practices for structural bolting.”

The staff reviewed the AMR results lines referenced to Note E, plant-specific Note 3, 4, and 31, 

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 

AMP XI.S7, “RG 1.127 Inspection of Water Control Structures Associated with Nuclear Power 

Plants,” the applicant has additionally proposed using the Structures Monitoring Program. The 

GALL Report line item referenced is steel only, and therefore, the GALL Report recommends 

AMP XI.S7. The applicant stated that the AMR result line items that reference LRA Table 3.5.1 

item 3.5.1-47 is also located in the groundwater/soil environment areas subject to loss of 

material due to general, and therefore, the Structures Monitoring Program was also credited. 

Since the RG 1.127 Inspection of Water Control Structures Associated with Nuclear Power 

Plants and Structures Monitoring Program are performing visual inspections whenever the 

surrounding soil is excavated, the staff finds the applicant's additional use of the Structures 

Monitoring Program to be acceptable.
3-447

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 AERM adequately, as recommended by the 

GALL Report.

Conclusion. 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 the recent OE and 

proposals for managing aging effects. On the basis of its review, the staff concludes that the 

AMR results, which the applicant claimed to be consistent with the GALL Report, are indeed 

consistent with its AMRs. Therefore, the staff concludes that the applicant has demonstrated 

that the effects of aging for these components will be adequately managed so that their 

intended function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

3.5.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.5.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the containments, structures, and component supports components and 

provides information concerning how it will manage aging effects in the following three areas:

PWR and BWR containments:

(1) PWR and BWR containments

• aging of inaccessible concrete areas

• cracks and distortion due to increased stress levels from settlement; reduction of 

foundation strength, cracking, and differential settlement due to erosion of porous 

concrete subfoundations if not covered by the Structures Monitoring Program

• reduction of strength and modulus of concrete structures due to elevated 

temperature

• loss of material due to general, pitting, and crevice corrosion

• loss of prestress due to relaxation, shrinkage, creep, and elevated temperature

• cumulative fatigue damage

• cracking due to SCC

• cracking due to cyclic loading

• loss of material (scaling, cracking, and spalling) due to freeze-thaw

• cracking due to expansion and reaction with aggregate and increase in porosity 

and permeability due to leaching of calcium hydroxide

 (2) safety-related and other structures and component supports:

• aging of structures not covered by the Structures Monitoring Program

• aging management of inaccessible areas
3-448

• reduction of strength and modulus of concrete structures due to elevated 

temperature

• aging management of inaccessible areas for Group 6 structures

• cracking due to SCC and loss of material due to pitting and crevice corrosion

• aging of supports not covered by the Structures Monitoring Program

• cumulative fatigue damage due to cyclic loading

 (3) QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the 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 PWR and BWR Containments

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:

Aging of Inaccessible Concrete Areas. LRA Section 3.5.2.2.1.1 states that PINGP has no ASME 

Section III, Division 2 Class CC concrete subject to IWL in-service inspection requirements. The 

free standing steel containment (i.e. Reactor Containment Vessel) is supported by unreinforced 

concrete, but this concrete does not serve a pressure retaining function. Therefore, it is not 

subject to IWL inspections. The LRA further states that aging mechanism aggressive chemical 

attack of this unreinforced concrete is managed by the Structures Monitoring Program.

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.

The staff confirmed that no PINGP containment concrete serves a pressure retaining function. 

Therefore, the concrete is not subject to IWL inspections. Aging mechanism aggressive 

chemical attack of the unreinforced containment concrete is managed by the Structures 

Monitoring Program. The staff’s review of the Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. SER Section 3.5.2.2.2.2 documents the staff’s review of the applicant’s 

evaluation of aging management of inaccessible areas, including the unreinforced concrete. 

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. LRA Section 3.5.2.2.1.2 

states that PINGP has no ASME Section III, Division 2 Class CC concrete subject to IWL in-
3-449

service inspection requirements. The free standing steel containment (i.e. reactor containment 

vessel) is supported by unreinforced concrete, but this concrete does not serve a pressure 

retaining function. Therefore, it is not subject to IWL inspections. The LRA further states that 

settlement of this unreinforced concrete is managed by the Structures Monitoring Program.

The staff reviewed LRA Section 3.5.2.2.1.2 against the criteria in SRP-LR Section 3.5.2.2.1.2 

which states that cracks and distortion due to settlement could occur in concrete and steel 

containments. Also, reduction of foundation strength and differential settlement due to erosion of 

porous concrete subfoundations could occur in all types of containments. The existing program 

relies on structures monitoring program to manage these aging effects. The GALL Report 

recommends no further evaluation if this activity is within scope of the applicant’s Structures 

Monitoring Program.

The staff confirmed that no PINGP containment concrete serves a 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 settlement in inaccessible areas, 

including the unreinforced concrete. The staff confirmed that the settlement of the unreinforced 

concrete is managed under the Structures Monitoring Program. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.17.

Reduction of Strength and Modulus of Concrete Structures Due to Elevated

Temperature. LRA Section 3.5.2.2.1.3 states the temperature of the unreinforced concrete 

beneath containment remains well below the allowable limits of the GALL Report item II.A2-1.

Since the temperature remains below the limits, the applicant stated the aging effect is not 

applicable.

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 the GALL Report item 

II.A2-1.

The staff finds acceptable the applicant’s evaluation that this aging effect is not applicable 

because the concrete remains below the allowable temperature limits.

Loss of Material due to General, Pitting and Crevice Corrosion. LRA Section 3.5.2.2.1.4 

addresses loss of material due to general, pitting and crevice corrosion for steel elements of 

accessible and inaccessible areas of containments, stating that the ASME Section XI, 

Subsection IWE and the 10 CFR 50 Appendix J Programs are recommended to manage this 

aging effect. The applicant stated that the GALL Report recommends further evaluation of plantspecific programs to manage this aging effect for inaccessible areas if corrosion is significant. 

The applicant further stated that corrosion is not significant for inaccessible steel components 

embedded in concrete because the four criteria listed in the GALL Report had been reviewed 

and satisfied.

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 further evaluation is necessary if corrosion is significant. GALL Report item 

II.A2-9 states that corrosion is not significant for inaccessible areas of steel containments

(embedded containment steel shell or liner) if the following four conditions are satisfied:
3-450

(1) Concrete meeting the requirements of ACI 318 or 349 and the guidance of ACI 201.2R 

was used for the containment concrete in contact with the embedded containment shell 

or liner.

(2) The concrete is monitored to ensure that it is free of penetrating cracks that provide a 

path for water seepage to the surface of the containment shell or liner.

(3) The moisture barrier, at the junction where the shell or liner becomes embedded, is 

subject to aging management activities in accordance with ASME Section XI, Subsection 

IWE requirements.

(4) Borated water spills and water ponding on the containment concrete floor are not 

common and when detected are cleaned up in a timely manner.

The staff reviewed the construction codes and standards for PINGP and found that the concrete 

was designed in accordance with ACI 318. Additional ASTM and ACI standards were followed 

during construction which ensure the concrete was placed in accordance with guidance in ACI 

201.2R. Further discussion of the acceptability of PINGP concrete is documented in SER 

Sections 3.5.2.2.2.2.1 and 3.5.2.2.2.2.2.

During its audit, the staff noted an ongoing issue with water seepage from the refueling cavity, 

through concrete inside containment, into the containment sumps. This is inconsistent with the 

applicant’s claim that the concrete meets the second criteria listed in the GALL Report. To 

address the issue of refueling cavity leakage, several RAIs were issued, a public meeting was 

held, and the staff performed an additional audit. A summary of these communications and the 

resolution of the issue, including the closure of OI 3.0.3.2.17-1, is discussed and documented 

under the Structures Monitoring Program in SER Section 3.0.3.2.17. During the resolution of the 

leakage issue, the applicant committed to removing concrete from an area susceptible to 

corrosion and inspecting the containment vessel and the concrete reinforcement for signs of 

degradation (Commitment 41). Any indications of degradation will be entered into the applicant’s 

Corrective Action Program and the effects on the structural integrity of the containment will be 

reviewed. This inspection will provide assurance that either corrosion is not significant for 

inaccessible areas of the containment, or any existing corrosion will be captured and evaluated 

prior to the period of extended operation. 

In the LRA, the applicant stated that aging effects for the moisture barrier are managed by the 

ASME Section XI, Subsection IWE Program. The staff’s review of the applicant’s ASME Section 

XI, Subsection IWE Program is documented in SER Section 3.0.3.1.4. The applicant also stated 

that borated water spills are managed by the Boric Acid Corrosion Program. The staff’s review 

of the applicant’s Boric Acid Corrosion Program is documented in SER Section 3.0.3.1.6.

Based on the information provided, as well as the closure of Open Item 3.0.3.2.17-1, the staff 

finds the applicant’s evaluation of the aging effect “loss of material due to general, pitting and 

crevice corrosion” acceptable. The applicant has demonstrated that SRP conditions 1, 3, and 4 

are satisfied, while the commitments related to the refueling cavity leakage provide assurance 

that any corrosion in inaccessible areas of the containment will be captured and evaluated prior 

to the period of extended operation (Commitments 41, 42, and 44).
3-451

Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.5 states that loss of prestress of concrete containments is not applicable since 

PINGP containments are free standing steel containments. 

The staff finds acceptable the applicant’s evaluation that this aging effect is not applicable on 

the basis that the PINGP containments are free standing steel containments with no 

prestressed concrete.

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.6 states that cumulative fatigue damage is 

a TLAA. SER Section 4.6. documents the staff’s review of the applicant’s evaluation of this 

TLAA.

Cracking due to Stress Corrosion Cracking (SCC). LRA Section 3.5.2.2.1.7 states that PINGP 

OE has shown no age-related issues on bellow replacement and industry OE has identified 

cracks in the bellows, but not the weld metal. The LRA further states that the penetration bellow 

assembly welds are located in a sheltered, non-corrosive environment, where temperatures are 

not expected to exceed threshold limits for SCC. Since the environment is not corrosive and the 

temperature does not exceed limits, the LRA states that the components do not require 

additional inspections and the aging effects can be adequately managed under the ASME 

Section XI, Subsection IWE and 10 CFR 50 Appendix J Programs.

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. Additional examinations or evaluations may 

need to be implemented to detect these aging effects.

GALL Report item II.A3-2 states that SCC may cause aging effects if the material is not shielded 

from a corrosive environment. Chapter IX.D of the GALL Report also states that SCC very rarely 

occurs in austenitic stainless steels below,140 oF and the observed instances of SCC below 

140 oF occurred in an environment with significant presence of contaminants. The staff is not 

clear what temperature and chemical elements these components have experienced. Therefore, 

RAI 3.5.2.2-2 dated December 18, 2008, was issued to ask the applicant to (1) provide the 

history of the highest temperature that stainless steel penetration sleeves, penetration bellows, 

and dissimilar metal welds have experienced, and (2) demonstrate that chemical elements that 

would support SCC have been monitored or measured to ensure a non-aggressive chemical 

environment. 

In its response to RAI 3.5.2.2-2, dated January 20, 2009, the applicant stated that the 

components are located inside the shield building in an air indoor environment which is not 

corrosive. The applicant further stated that the PINGP indoor environment is not corrosive 

based on the following facts: (1) the plant draws its cooling water from the Mississippi River, a 

fresh water source, so it is not exposed to a salt air/water environment, and (2) the air quality 

around the plant is better than the established National Ambient Air Quality Standards for the six 

criteria pollutants. The applicant stated that SCC requires simultaneous action of a corrosive 

environment and temperatures in excess of 140 oF, and since the environment was not 

corrosive the elements were not susceptible to SCC.
3-452

The staff reviewed the applicant’s response to RAI 3.5.2.2-2 and agreed that the components 

are not exposed to a corrosive environment. On the basis of its review, the staff determines that 

additional inspections of stainless steel penetration sleeves, penetration bellows, and dissimilar 

metal welds is not applicable to PINGP because the conditions necessary for SCC, both high 

temperature (>140 °F ) and exposure to a corrosive environment, do not exist simultaneously.

Cracking due to Cyclic Loading. The PINGP containment penetrations that experience 

significant cyclic loading have fatigue analyses that are evaluated as TLAAs. SER Section 4.6 

“Containment and Penetration Fatigue Analysis” documents the staff’s review of the applicant’s 

evaluation of these TLAAs. 

Loss of Material (Scaling, Cracking, and Spalling) Due to Freeze–Thaw. LRA Section 

3.5.2.2.1.9 states that loss of material due to freeze-thaw is not applicable to the unreinforced 

concrete below containment since the concrete is not exposed to outdoor air or groundwater/soil 

environments. 

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 acceptable the applicant’s evaluation that this aging effect is not applicable to the 

unreinforced concrete below the free standing steel containment because the concrete will not 

be subjected to freeze-thaw cycles since it is not exposed to outdoor air.

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 

PINGP has no ASME Section III, Division 2 Class CC concrete subject to IWL in-service 

inspection requirements. The free standing steel containment (i.e. Reactor Containment Vessel) 

is supported by unreinforced concrete, but this concrete does not serve a pressure retaining 

function. The LRA also states that leaching of calcium hydroxide for the unreinforced concrete 

beneath containment is not applicable since it is not exposed to flowing water or a head of 

standing water. The LRA further states that cracking due to expansion and reactions with 

aggregate of this unreinforced concrete is managed by the Structures Monitoring Program.

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.

The staff confirmed that no PINGP containment concrete serves a 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 and permeability due to leaching of calcium 

hydroxide. The staff confirmed that aggregate reaction aging effects for the unreinforced 

concrete are managed by the Structures Monitoring Program. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.17
3-453

Based on the programs and analyses discussed above, the staff concludes that the applicant 

has met the criteria of SRP-LR Section 3.5.2.2.1. For those line items that apply to LRA Section 

3.5.2.2.1, 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).

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

addresses several areas:

Aging of Structures Not Covered by Structures Monitoring Program. LRA Section 3.5.2.2.2.1 

states that PINGP concrete structures subject to the aging effects discussed below are included 

in the Structures Monitoring Program. Aging effects discussed below for structural steel items 

are also addressed by the Structures Monitoring Program. 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/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, 

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, differential settlement 

due to erosion of porous concrete subfoundation for Groups 1-3 and 5-9 structures. 

In addition, lock-up due to wear may occur for Lubrite radial beam seats in 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 ASME Code Section XI, Subsection IWF, to manage this aging effect. The GALL Report 

recommends further evaluation only for structure-aging effect combinations not within the 

Inservice Inspection (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 applicant stated in the LRA that cracking, loss of bond, and loss of material 

(spalling, scaling) due to corrosion of embedded steel for accessible concrete areas of 

Groups 1-5, 7 and 9 structures is managed by the Structures Monitoring Program. 

The staff’s reviews for the cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel for accessible and inaccessible concrete elements 

of containments and Groups 1-5, 7 and 9 structures are documented in SER Sections 
3-454

3.5.2.2.1.1 and 3.5.2.2.2.2.4, respectively. The staff’s review of the Structures Monitoring 

Program is documented in SER Section 3.0.3.2.17. The staff confirmed that groups 1-5, 

7, and 9 structures subject to this AMR are all in-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.

(2) Increase in Porosity and Permeability, Cracking, Loss of Material (Spalling, Scaling) Due 

to Aggressive Chemical Attack for Groups 1-5, 7, and 9 Structures

The applicant stated in the LRA that increase in porosity and permeability, cracking, 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’s reviews for the increase in porosity and permeability, cracking, loss of 

material (spalling, scaling) due to aggressive chemical attack for accessible and

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. The staff’s 

review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.17.

The staff confirmed that Groups 1-5, 7 and 9 structures subject to this AMR are all inscope 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. 

(3) Loss of Material Due to Corrosion for Groups 1-5, 7, and 8 Structures

The applicant stated in the LRA that loss of material due to corrosion for structural steel 

components is managed by the Structures Monitoring Program. 

The staff’s review for the loss of material due to general, pitting and crevice corrosion for 

steel elements of containments is documented in SER Section 3.5.2.2.1.4. The staff’s 

review of the Structures Monitoring Program is documented in SER Section 3.0.3.2.17.

The staff confirmed that Groups 1-5, 7, 8 structures subject to this AMR are all in-scope 

of the Structures Monitoring Program. Therefore, the staff finds that the criteria of SRPLR Section 3.5.2.2.2.1 have been met, and no further evaluation is required.

(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’s reviews for the loss of material (spalling, scaling) and cracking due to freezethaw for concrete elements of containments, below–grade inaccessible concrete areas 

of Groups 1-3, 5, 7- 9 structures, and below–grade inaccessible concrete areas of 

Groups 6 Structures are documented in SER Sections 3.5.2.2.1.9, 3.5.2.2.2.2.1 and 

3.5.2.2.2.4.2, respectively. The staff’s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.17. The staff confirmed that Groups 1-3, 5, 7- 9 
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structures subject to this AMR are all in-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.

(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, 7, and 9 structures is managed 

by the Structures Monitoring Program. 

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.

The staff’s review of the Structures Monitoring Program is documented in SER Section 

3.0.3.2.17. The staff confirmed that Groups 1-5, 7- 9 structures subject to this AMR are 

all in-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.

(6) Cracks and Distortion Due to Increased Stress Levels from Settlement for Groups 1-3 

and 5-9 Structures

The applicant stated in the LRA that cracks and distortion due to increased stress levels 

from settlement of groups 1-3 and 5-9 structures are managed by the Structures 

Monitoring Program. 

The staff’s reviews for cracks and distortion due to increased stress levels from 

settlement for concrete elements of containments and inaccessible areas of Groups 1-3 

and 7-9 structures are documented in SER Sections 3.5.2.2.1.2 and 3.5.2.2.2.2.3, 

respectively. The staff’s review of the Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. The staff confirmed that Groups 1-3, 7- 9 structures subject to 

this AMR are all in-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.

(7) Reduction in Foundation Strength, Cracking, and Differential Settlement Due to Erosion 

of Porous Concrete Subfoundation for Groups 1-3 and 5-9 Structures

The 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 PINGP does not have porous 

subfoundations. 

Based on the review of documents supporting the LRA, the staff agrees this aging affect 

is not applicable because PINGP has no porous concrete subfoundations.
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(8) Lockup Due to Wear for Lubrite® Radial Beam Seats in RPV Support Shoes for PWRs 

with nozzle supports and Other Sliding Support Surfaces

The applicant stated in the LRA that lockup due to wear for sliding support surfaces of 

the RPV support shoes is managed by the ASME Section XI, Subsection IWF Program.

The LRA further states that the steam generator supports do not incorporate sliding 

surfaces.

The staff finds that RPV support shoes are all in-scope of the applicant’s ASME Section 

XI, Subsection IWF Program. The staff’s review of the ASME Section XI, Subsection 

IWF Program is documented in SER Section 3.0.3.1.5. The applicant stated in LRA 

Section 3.5.2.2.2.1 that the ASME Section XI, Subsection IWF Program will perform 

inspections to confirm the absence of lock-up due to wear aging effect for these 

components. 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.

Based on the programs and analyses discussed above, the staff concludes that the applicant 

has met the criteria of SRP-LR Section 3.5.2.2.2.1. For those line items that apply to LRA 

Section 3.5.2.2.2.1, the staff determines that the LRA is consistent with the GALL Report and 

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).

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 belowgrade inaccessible concrete areas of Groups 1-3, 5 and 7-9 structures.

In LRA Section 3.5.2.2.2.2.1 the applicant stated that PINGP is located in a severe 

weathering area and therefore an evaluation must be done to determine if freeze-thaw 

cycles will have an effect on concrete structures. The applicant stated that the concrete 

design conforms to ACI 318, the entrained air content of the concrete was specified 

between 4% and 8%, and the water-to-cement ratio was specified not to exceed 0.46.

The applicant also stated that the Structures Monitoring Program will examine 

accessible areas of concrete structures for evidence of freeze-thaw induced

degradation. These inspections will be used to assess the impact of freeze-thaw on 

inaccessible areas. The applicant further stated that compliance with industry code 

requirements and the absence of any significant freeze-thaw degradation shows that this 

aging affect is not significant.

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 groups of structures for plants located 

in moderate to severe weathering conditions.

The GALL Report suggests a water-to-cement ratio between 0.35 and 0.45. Although 

the PINGP water-to-cement ratio specification value is not to exceed 0.46, the staff finds 
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this value acceptable because the 0.01 difference between upper bounds is negligible. 

The ‘not to exceed’ portion of the PINGP specification is also acceptable because, per 

ACI codes, the strength and durability of concrete increases as the water-to-cement ratio 

decreases. According to ACI 318 and ACI 201.2R, the maximum water-to-cement ratios 

of 0.40 to 0.50 that may be required for concretes exposed to aggressive environments 

will typically be equivalent to requiring compressive strengths of 5000 to 4000 psi, 

respectively. Therefore, as long as the workability of the concrete is maintained, a lower 

water-to-cement ratio provides a more durable concrete with a higher compressive 

strength. 

The GALL Report suggests an air content of 3% to 6%. The staff finds the 4% to 8% 

value specified at PINGP acceptable because the recommended air content for concrete 

resistance to freezing and thawing by ACI 201.2R is 4.5% to 7.5 % for severe exposure 

and 3.5% to 6% for moderate exposure with a ±1.5% tolerance. PINGP is located in a 

severe weathering region so the 4% to 8% air content falls within the ACI 

recommendations when the available tolerance is taken into consideration. The sufficient 

concrete air content creates a large number of closely spaced, small air bubbles in the 

hardened concrete. The air bubbles relieve the pressure build-up caused by ice 

formation by acting as expansion chambers. The staff found that the PINGP concrete 

mix design adequately addressed freeze-thaw damage potential by using entrained air 

and aggregate soundness for structures subject to freezing in the subgrade freeze zone 

and in water-tight structures. In addition, potential freeze-thaw effects on the 

inaccessible concrete are assessed by monitoring the accessible concrete under the 

Structures Monitoring Program. The staff’s review of the Structures Monitoring Program 

is documented in SER Section 3.0.3.2.17.

On the basis of its review, the staff finds that the 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 is not significant. Therefore, no additional plant-specific program is 

required. 

(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. 

In LRA Section 3.5.2.2.2.2.2 the applicant states that cracking due to reaction with 

aggregates is not significant because tests in accordance with ASTM C289 verified that 

non-reactive aggregates were used. 

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.

The staff issued RAI 3.5.2.2-1 in a letter dated December 18, 2008, asking the applicant 

to provide a discussion and basis for the determination that ASTM C289 satisfies the 

requirements of ASTM C227 and C295 as suggested by GALL Report item III.A1-2. 
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In its response to RAI 3.5.2.2-1, dated January 20, 2009, the applicant stated that ASTM 

Specification C295 is included in the PINGP UFSAR Section 12.2.3.2 on a list of 

standards and specifications for concrete materials, and should have been included in 

LRA Section 3.5.2.2.2.2. The staff verified that ASTM C295 was included in the UFSAR

list, and found that ASTM C227 was also on the list of standards and specifications. 

Since both GALL recommended ASTM standards were used to verify that PINGP 

aggregates were non-reactive, the staff’s concern is resolved.

The staff also reviewed the construction codes and standards for PINGP and found that 

the concrete was designed in accordance with ACI 318. Additional ASTM and ACI 

standards were followed during construction which ensures the concrete was placed in 

accordance with guidance in ACI 201.2R-77.

On the basis of its review, the staff finds that the aggregates used at PINGP are nonreactive, and the concrete was constructed in accordance with the recommendations in 

ACI 201.2R-77. Therefore, cracking due to expansion and reaction with aggregate in 

below-grade inaccessible concrete areas for Groups 1-5 and 7-9 structures are not 

aging effects for concrete elements and no aging management is necessary.

(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.

In LRA Section 3.5.2.2.2.2.3 the applicant stated that the auxiliary building, turbine 

building and shield buildings were constructed on a continuous mat foundation which 

was built on a 30 foot layer of densely compacted materials. The LRA further states that 

de-watering systems are not used at PINGP and are not credited in the CLB. Operating 

experience shows no evidence of significant building settlement, and to ensure 

unexpected settlement does not occur, the Structures Monitoring Program manages 

cracks due to settlement. The LRA further states that PINGP does not have porous 

concrete subfoundations.

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 belowgrade 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. PINGP does not use a dewatering system, and there are no porous subfoundations on the site. In addition, the 

applicant elected to monitor the above-grade exposed containment concrete for the 

aging effect of cracking due to settlement with the Structures Monitoring Program. The 
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staff reviewed the Structures Monitoring Program, and the evaluation is documented in 

SER Section 3.0.3.2.17. The staff finds that this program is consistent with the 

recommendations in the GALL Report, and is 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.

(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.

In LRA Section 3.5.2.2.2.2.4 the applicant stated that the above aging effect does not 

require further evaluation since the groundwater was found to be non-aggressive. The 

LRA also included chemistry test results for groundwater over the last 22 years: pH 

ranging from 7.6 to 8.5, maximum chloride concentration of 89.4 ppm, and maximum 

sulfate concentration of 119 ppm. 

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 groundwater inspection program is under the applicant’s Structures 

Monitoring Program. RAI B2.1.38-1 was issued to ask the applicant to specify the 

location(s) where tests samples were/are taken relative to the safety-related and 

important-to-safety embedded concrete and to explain the technical basis for concluding 

that sampling a single well is sufficient to ensure the embedded concrete is not exposed 

to aggressive groundwater. The staff’s review of the applicant’s Structures Monitoring 

Program including responses to RAI B2.1.38-1 is documented in SER Section 

3.0.3.2.17. The basis document for the Structural Monitoring Program indicated a five 

year interval for monitoring the below-grade water chemistry. The staff agreed that this 

sampling period is in accordance with the industry’s standard. The staff also verified that 

the historic results were within the GALL Report limits, which are greater than 5.5 for pH; 

less than 500 ppm for chlorides; and less than 1500 ppm for sulfates. The staff also 

noted that the applicant’s Structures Monitoring Program includes examinations of 

below-grade concrete when exposed for any reason.

On the basis of its review, the staff finds that the 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 Groups 1-3, 5 and 7-9 

structures requires no further evaluation because the environment is not aggressive and 

the groundwater chemistry inspection under the applicant’s Structures Monitoring 

Program agrees with the recommendation of the GALL Report.
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(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

In LRA Section 3.5.2.2.2.2.5 the applicant stated that PINGP documents confirm that the 

concrete was constructed in accordance with the recommendations in ACI 201.2R-77, 

and therefore aging management due to leaching of calcium hydroxide is not necessary. 

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 – 6%), and thorough consolidation. The staff’s 

discussion and review of the equivalence of PINGP 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.

On the basis of its review, 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 aging effect 

requiring management 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, 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).

Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. In 

LRA Section 3.5.2.2.2.3 the applicant addresses reduction of concrete strength and modulus 

due to elevated temperatures that may occur in PWR and BWR Groups 1-5 concrete structures. 

The applicant stated that three locations at PINGP require further evaluation due to elevated 

temperatures. These include the shield building walls adjacent to hot piping penetrations, 

screenhouse and diesel generator building concrete adjacent to non-insulated exhaust lines, 

and the reactor biological shield wall. The PINGP LRA states that the maximum concrete 

temperature in the shield building walls is 158 °F. The applicant states that this temperature is 

localized and falls below the 200 °F limit, therefore no further evaluation is necessary. The LRA 

also states that no concrete temperatures have been measured at the diesel exhaust lines.

Since the temperature may exceed the limits, aging management is provided by examinations 

under the RG 1.127, Inspection of Water-Control Structures and the Structures Monitoring 

Programs. The PINGP LRA further states that the maximum calculated concrete temperature in 

the biological shield wall is 195 °F. The applicant performed an evaluation to ensure that the 

elevated temperatures would not affect structural integrity.

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 
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may occur in PWR and BWR Groups 1-5 concrete structures. For concrete elements that 

exceed specified temperature limits, further evaluations are recommended. Appendix A to 

ACI 349-85 specifies the concrete temperature limits for normal operation or any other longterm period. Temperatures shall not exceed 150 °F except for local areas allowed to have 

temperatures not to exceed 200 °F.

During its review, the staff verified that the 158 °F temperature in the shield building walls is a 

localized temperature which falls below the 200 °F limit, therefore the staff agrees no further 

evaluation is necessary. GALL Report item III.A3-1 specifies temperature limits (150 °F general 

and 200°F local) for normal operation or any other long-term period (30 or more days) per ACI 

349-85. The diesel generators are only run periodically or during accident conditions, so the 

concrete surrounding the exhaust lines will not exceed the temperature limits for a long-term 

period; therefore, the staff believes no further evaluation is necessary. Conservatively the 

applicant proposed to examine the concrete adjacent to the non-insulated diesel exhaust lines 

under the Structures Monitoring and RG 1.127, Inspection of Water-Control Structures 

Programs. The staff’s reviews of the applicant’s RG 1.127, Inspection of Water-Control 

Structures and Structures Monitoring Programs are documented in SER Sections 3.0.3.2.14 

and 3.0.3.2.17, respectively. During the audit, the applicant explained, and the staff agreed, that 

the 195 °F temperature in the biological shield wall is considered to be a localized temperature 

and therefore falls below the 200 °F limit. However, the applicant performed an evaluation to 

ensure that the elevated temperatures would not affect structural integrity. The staff reviewed 

the analysis and confirmed that the biological shield wall could support the applied stresses with 

the reduced concrete strength due to high temperatures. The staff also confirmed that the 

increased deflections due to the reduced modulus of elasticity would not affect the structural 

stability. In addition, aging management of the biological shield wall is provided by examinations 

under the Structures Monitoring Program.

The staff also noted there are nine Table 3.5.2 line items, which cite neither an AERM nor AMP, 

which refer to the GALL Table 3.5.1-33 item which claims reduction of strength and modulus 

due to elevated temperature as the aging effect. The staff also noted that Note E is used by the 

applicant for these nine line items. Note E states “Consistent with NUREG-1801 item for 

material, environment and aging effect, but a different AMP is credited or NUREG-1801 

identifies a plant-specific aging management program.” The GALL Table 3.51-33 item suggests 

further evaluation of plant-specific AMP if temperature limits are exceeded. GALL Report 

specifies temperature limits (150°F general and 200°F local) per ACI 349-85. The staff 

confirmed that the components of these nine line items do not experience normal operating 

temperatures in excess of threshold levels. Therefore, the staff agrees there is no AERM for 

these components because the necessary condition does not exist.

Based on the programs and analyses discussed above, the staff concludes that the applicant 

has met the criteria of SRP-LR Section 3.5.2.2.2.3. For those line items that apply to LRA 

Section 3.5.2.2.2.3, the staff determines that the LRA is consistent with the GALL Report and 

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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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 

aggressive chemical attack; and cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel could occur in accessible and below-grade 

inaccessible concrete areas of Group 6 structures. 

In LRA Section 3.5.2.2.2.4.1 the applicant stated that the above aging effects for 

concrete in accessible areas are managed by the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program. The LRA also states that the 

aging effects are not significant for inaccessible concrete as discussed in LRA Section 

3.5.2.2.2.2.4.

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 RG 1.127, Inspection 

of Water-Control Structures Associated with Nuclear Power Plants Program is 

documented in SER Section 3.0.3.2.14. The staff confirmed that Group 6 structures 

subject to this AMR are in-scope of the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program.

Since the environment is non-aggressive and the applicant has enhanced the Structures 

Monitoring Program to include periodic sampling of groundwater to ensure the 

environment remains non-aggressive, the staff finds that the criteria of SRP-LR Section 

3.5.2.2.2.4.1 have been met.

(2) Loss of material (spalling, scaling) and cracking due to freeze-thaw could occur in belowgrade inaccessible concrete areas of Group 6 structures.

In LRA Section 3.5.2.2.2.4.2 the applicant stated that loss of material (spalling, scaling) 

and cracking due to freeze-thaw for accessible concrete areas of Group 6 structures is 

managed by the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program. The LRA also states that the aging effects are not 

significant for inaccessible concrete as discussed in LRA Section 3.5.2.2.2.2.1. To 

assure against degradation, the potential effects on inaccessible concrete are assessed 

by monitoring accessible concrete.

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. 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 
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RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program is documented in SER Section 3.0.3.2.14. The staff confirmed that Group 6 

structures subject to this AMR are in-scope of the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program.

Since the applicant’s concrete contains the appropriate air content and water-to-cement 

ration, as discussed in SER Section 3.5.2.2.2.2.1, the staff finds that the criteria of 

SRP-LR Section 3.5.2.2.2.4.2 have been met.

(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.

In LRA Section 3.5.2.2.2.4.3 the applicant stated that cracking due to expansion and 

reaction with aggregates for accessible concrete areas of Group 6 structures is 

managed by the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Program. The LRA also states that the aging effects are not 

significant for inaccessible concrete as discussed in LRA Section 3.5.2.2.2.2.2.

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 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program is documented in SER Section 3.0.3.2.14. The staff confirmed that 

Group 6 structures subject to this AMR are in-scope of the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program.

Since the applicant’s concrete was constructed in accordance with ACI 201.2R-77, 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.

In LRA Section 3.5.2.2.2.4.3 the applicant further stated that an increase in porosity and 

permeability, and loss of strength due to leaching of calcium hydroxide for accessible 

concrete areas of Group 6 structures is managed by the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program. The LRA also 

stated that the aging effects are not significant for inaccessible concrete as discussed in 

LRA Section 3.5.2.2.2.2.5.

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 RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program is documented 

in SER Section 3.0.3.2.15. The staff confirmed that Group 6 structures subject to this 

AMR are in-scope of the RG 1.127, Inspection of Water-Control Structures Associated 
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with Nuclear Power Plants Program. Since the applicant’s 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 identified above, 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).

Cracking due to Stress Corrosion Cracking and Loss of Material due to Pitting and

Crevice Corrosion. LRA Section 3.5.2.2.2.5 states that liners for concrete and steel tanks are 

evaluated as mechanical components under Table I line items 3.2.1-49 and 3.2.1-53.

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 cracking due to SCC and loss of material due to pitting and crevice corrosion could 

occur for Group 7 and 8 stainless steel tank liners exposed to standing water. The GALL Report 

recommends further evaluation of plant-specific programs to manage these aging effects.

The staff confirmed that the PINGP refueling water storage tank liners are evaluated under 

Table I line items 3.2.1-49 and 3.2.1-53. The staff verified that the aging effects are managed by 

the Water Chemistry Program. The staff’s review of the Water Chemistry Program is 

documented in SER Section 3.0.3.2.19.

Based on the program identified above, the staff concludes that the applicant has met 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).

Aging of Supports Not Covered by Structures Monitoring Program. LRA Section 3.5.2.2.2.6 

states that all the component/aging effect combinations mentioned in SRP-LR Section 

3.5.2.2.2.6 are covered by the Structures Monitoring Program with one exception; Class 1 and 

Class 2 and Class 3 supports are managed by the ASME Section XI, Subsection IWF Program.

The staff reviewed LRA Section 3.5.2.2.2.6 against the following criteria in SRP-LR Section 

3.5.2.2.2.6, which recommends further evaluation of certain component support/aging effect 

combinations if they are not covered by the Structures Monitoring Program. The staff confirmed 

that the component support/aging effect combinations of loss of material due to general and 

pitting corrosion, for Groups B2-B5 supports; reduction in concrete anchor capacity due to 

degradation of the surrounding concrete, for Groups B1-B5 supports; and reduction/loss of 

isolation function due to degradation of vibration isolation elements, for Group B4 supports; are 

managed by the Structures Monitoring Program, with the exception of Class 1 – 3 supports, 

which are managed by the ASME Section XI, Subsection IWF Program. The staff’s review of the 
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Structures Monitoring and ASME Section XI, Subsection IWF Programs are documented in SER 

Sections 3.0.3.2.17 and 3.0.3.1.5, respectively.

Based on the programs and analysis identified above, the staff concludes that the applicant has 

met the criteria of SRP-LR Section 3.5.2.2.2.6. For those line items that apply to LRA Section 

3.5.2.2.2.6, the staff determines that the LRA is consistent with the GALL Report and 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).

Cumulative Fatigue Damage due to Cyclic Loading. LRA Section 3.5.2.2.2.7 states that fatigue 

of metal Class 1 component supports for the reactor pressure vessels and pressurizers is a 

TLAA and is addressed in Section 4.3. The LRA further states that the remaining Class 1 – 3 

component supports do not include a fatigue analysis and are managed for aging by the ASME 

Section XI, Subsection IWF Program.

The staff’s evaluation of the Class 1 component supports metal fatigue TLAA is documented in 

SER Section 4.3.

3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

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

In LRA Tables 3.5.2-1 through 3.5.2-11, the staff reviewed additional details of the AMR results 

for material, environment, AERM, and AMP combinations not consistent with or not addressed 

in the GALL Report.

In LRA Tables 3.5.2-1 through 3.5.2-11, the applicant indicated, via Notes F through J that the 

combination of component type, material, environment, and AERM does not correspond to a 

line item in the GALL Report. The applicant provided further information about how it will 

manage the aging effects. Specifically, Note F indicates that the material for the AMR line item 

component is not evaluated in the GALL Report. Note G indicates that the environment for the 

AMR line item component and material is not evaluated in the GALL Report. Note H indicates 

that the aging effect for the AMR line item component, material, and environment combination is 

not evaluated in the GALL Report. Note I indicates that the aging effect identified in the GALL 

Report for the line item component, material, and environment combination is not applicable. 

Note J indicates that neither the component nor the material and environment combination for 

the line item is evaluated in the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.
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3.5.2.3.1 Auxiliary and Turbine Buildings - Summary of Aging Management Review –

LRA Table 3.5.2-1 

The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for the 

auxiliary and turbine buildings component groups.

In LRA Table 3.5.2-1, the applicant identified 54 unique component/material/environment/aging 

effect/AMP groups for the Auxiliary and Turbine Buildings. Forty nine have AMR results 

consistent with the GALL Report, as identified by reference to Notes A through E. The staff 

confirmed that the references to Table 1 and GALL Report line items are applicable.

For two component types, the applicant proposed to assign aluminum and stainless steel Table 

1 line item 3.5.1-50 (III.B2-7) material, to the aging affect none and aging management program 

none. These line items reference Note I and plant-specific Note 13 and Note 14, which state 

“Aluminum roof hatch (hatch over concrete roof plug) is not susceptible to aging since the 

PINGP air outdoor environment is non-aggressive and dissimilar metal hatch connections are 

not used,” and “NUREG-1801 line item includes the aging effect loss of material due to pitting 

and crevice corrosion where applicable. Loss of material due to pitting and crevice corrosion is 

not applicable at PINGP since the air outdoor environment does not contain aggressive 

contaminants and is not continuously wetted,” respectively. The staff reviewed the LRA, license 

design basis documents, EPRI 1002950 Structural Tools, Revision 1, August 2003, and the 

GALL Report and found that these materials do not perform or support any license renewal 

intended functions that satisfy the scoping criteria of 10 CFR 54.4(a). Therefore, aging 

management for these materials is not required.

For one component type, the applicant proposed not to manage roofing material, aging affect 

separation, environmental degradation, water in-leakage/weathering, by using the Structures 

Monitoring Program. The staff’s review of the Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. This line items references Note J and plant-specific Note 6, which 

states “Roofing components are not provided in NUREG-1801. PINGP plant-specific evaluation 

source document ACI 349.3R provided aging effects for roofing to include separation, 

environmental degradation, water in-leakage due to weathering.“ The staff finds that the 

credited AMP is appropriate because the Structures Monitoring Program performs visual 

inspections on a periodic basis to manage roofing material, aging affect separation, 

environmental degradation, and water in-leakage/weathering. Since the applicant has 

committed to an appropriate AMP for the period of extended operation, the staff finds these 

AMR results to be acceptable.

For one component type, the applicant proposed to manage ceramic (breakaway door pins) 

material, aging affect none and none for aging management. These line items reference Note J 

and plant-specific Note 9, which states “PINGP plant-specific evaluation did not identify any 

aging effect or mechanism for this material/environment combination.” The staff reviewed the 

LRA, license design basis documents, EPRI 1002950 Structural Tools, Revision 1, August 

2003, and the GALL Report and found that these materials do not perform or support any 

license renewal intended functions that satisfy the scoping criteria of 10 CFR 54.4(a). Therefore, 

aging management for these materials is not required.
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For the remaining one component type, the applicant proposed to manage wood (new fuel rack 

base support system) material, aging affect none and none for aging management. These line 

items reference Note J and plant-specific Note 12, which states “The PINGP new fuel pit bottom 

contains a layer of sand approximately 2 feet 3 inches thick topped with a 9 inches thick 

concrete slab that incorporates water stops. Wood planking is placed on top of the concrete slab 

at locations that correspond with the fuel racks. A concrete enclosure covers the new fuel pit. 

Since the wood planking is treated wood and is located in an air indoor environment, no aging 

effects are applicable.” The staff reviewed the LRA, license design basis documents, EPRI 

1002950 Structural Tools, Revision 1, August 2003, and the GALL Report and found that these 

materials do not perform or support any license renewal intended functions that satisfy the 

scoping criteria of 10 CFR 54.4(a). Therefore, aging management for this material is not 

required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.2 Component Supports - Summary of Aging Management Review – LRA Table 3.5.2-2 

The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for the 

component supports component groups.

In LRA Table 3.5.2-2, the applicant identified 104 unique component/material/environment/aging 

effect/AMP groups for the Component Supports. Seventy seven have AMR results consistent 

with the GALL Report, as identified by reference to Notes A through E. The staff confirmed that 

the references to Table 1 and GALL Report line items are applicable.

For one component type, the applicant proposed to manage reinforced concrete material, aging 

affect reduction in concrete anchor capacity due to local concrete degradation/service-induced 

cracking or other concrete aging mechanisms, by using the RG 1.127, Inspection of Water 

Control Structures Associated with Nuclear Power Plants Program. The staff’s review of the RG 

1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants Program is 

documented in SER Section 3.0.3.2.14. This line item references Note G and plant-specific 

Note 5, which states “SSC submerged in river (raw) water and accessible for diver examinations 

are identified as being in groundwater/soil (accessible) environment.” The staff finds that the 

credited AMP is appropriate because the RG 1.127, Inspection of Water Control Structures 

Associated with Nuclear Power Plants Program performs visual inspections on a periodic basis 

to manage reinforced concrete material, aging affect reduction in concrete anchor capacity due 

to local concrete degradation/service-induced cracking or other concrete aging mechanisms. 

Since the applicant has committed to an appropriate AMP for the period of extended operation, 

the staff finds these AMR results to be acceptable.

For two component types, the applicant state that aluminum, stainless steel (conduits, lighting 

fixtures, etc.) material have no aging affect and require no aging management. These line items 

reference Note J and plant-specific Note 14, which states “NUREG-1801 line item includes the 

aging effect loss of material due to pitting and crevice corrosion where applicable. Loss of 
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material due to pitting and crevice corrosion is not applicable at PINGP since the air outdoor 

environment does not contain aggressive contaminants and is not continuously wetted.” The 

staff reviewed the LRA, license design basis documents, EPRI 1002950 Structural Tools, 

Revision 1, August 2003, and the GALL Report and found that these materials do not perform or 

support any license renewal intended functions that satisfy the scoping criteria of 

10 CFR 54.4(a). Therefore, aging management for these materials is not required.

For the remaining twenty four component types, the applicant states that aluminum, stainless 

steel, and other insulation materials have no aging affect and require no aging management. 

These line items reference Note J and plant-specific Note 32, which states, “A review of PINGP 

operating experience confirms that insulation failures have not adversely impacted the 

satisfactory accomplishment of a safety-related intended function. Therefore, based upon the 

material, environment, and OE, the insulation is not expected to degrade, and an AMP is not 

required.” The staff reviewed the LRA, license design basis documents, EPRI 1002950 

Structural Tools, revision 1, August 2003, and the GALL Report and found that these materials 

do not perform or support any license renewal intended functions that satisfy the scoping criteria 

of 10 CFR 54.4(a). Therefore, aging management for these materials is not required.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.3 Cranes, Heavy Loads, Fuel Handling - Summary of Aging Management Review –

LRA Table 3.5.2-3 

The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for the 

cranes, heavy loads, and fuel handling component groups.

In LRA Table 3.5.2-3, the applicant identified 8 unique component/material/environment/aging 

effect/AMP groups for the Cranes, Heavy Loads, Fuel Handling. All eight have AMR results 

consistent with the GALL Report, as identified by reference to Notes A through E. The staff 

confirmed that the references to Table 1 and GALL Volume II line items are applicable.

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 for the Cranes, Heavy Loads, 

Fuel Handling not evaluated in the GALL Report. The staff finds that the applicant has assured 

that the effects of aging will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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3.5.2.3.4 D5/D6 Diesel Generator Building and Underground Storage Vault, Fuel Oil Transfer 

House, Old Service Building, and New Service Building – Summary of Aging Management

Review - LRA Table 3.5.2-4

The staff reviewed LRA Table 3.5.2-4 which summarizes the results of AMR evaluations for the 

D5/D6 diesel generator building and underground storage vault, fuel oil transfer house, old 

service building, and new service building component groups.

In LRA Table 3.5.2-4, the applicant identified 39 unique component/material/environment/aging 

effect/AMP groups for the D5/D6 Diesel Generator Building and Underground Storage Vault, 

Fuel Oil Transfer House, Old Service Building, and New Service Building. Thirty six have AMR 

results consistent with the GALL Report, as identified by reference to Notes A through E. The 

staff confirmed that the references to Table 1 and GALL Volume II line items are applicable.

For one component type, the applicant proposed to manage aluminum (seismic gap covers at 

NSB and DGB) material, in an air-outdoor environment with an aging affect of loss of 

material/galvanic corrosion, by using the Structures Monitoring Program. The staff’s review of 

the Structures Monitoring Program is documented in SER Section 3.0.3.2.17. This line item 

references Note H and plant-specific Note 18, which states “Plant-specific review determined 

the potential use of dissimilar metal connections and therefore loss of material due to galvanic 

corrosion for aluminum is possible. In an outdoor environment that does not contain aggressive 

contaminants and is not continuously wetted, pitting and crevice corrosion are not applicable for 

aluminum." The staff finds that the credited AMP is appropriate, because the Structures 

Monitoring Program performs visual inspections on a periodic basis to manage aluminum 

(seismic gap covers at NSB and DGB) material, aging affect loss of material/galvanic corrosion. 

Since the applicant has committed to an appropriate AMP for the period of extended operation, 

the staff finds these AMR results to be acceptable.

For one component type, the applicant proposed to manage roofing material, aging affect 

separation, environmental degradation, water in-leakage/weathering, by using the Structures 

Monitoring Program. The staff’s review of the Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. These line items reference Note J and plant-specific Note 6, which 

states “Roofing components are not provided in NUREG-1801. PINGP plant-specific evaluation 

source document ACI 349.3R provided aging effects for roofing to include separation, 

environmental degradation, and water in-leakage due to weathering.“ The staff finds that the 

credited AMP is appropriate, because the Structures Monitoring Program performs visual 

inspections on a periodic basis to manage roofing material, aging affects separation, 

environmental degradation, water in-leakage/weathering. Since the applicant has committed to 

an appropriate AMP for the period of extended operation, the staff finds these AMR results to be 

acceptable.

For the remaining one component type, the applicant proposed to manage reinforced concrete 

material, aging affect cracking and spalling/fatigue due to low level repeated load, by using the 

Structures Monitoring Program. The staff’s review of the Structures Monitoring Program is 

documented in SER Section 3.0.3.2.17. These line items reference Note J and plant-specific 

Note 19, which states “It is possible that vibratory motion of the fuel oil storage vault roof slab 

during its use as an access roadway could cause gradual weakening and spalling in stress 
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concentration areas. The Structures Monitoring Program is used to manage cracking and 

spalling due to fatigue due to low level repeated load.” The staff finds that the credited AMP is 

appropriate because the Structures Monitoring Program performs visual inspections on a 

periodic basis to manage reinforced concrete material, aging affect cracking and spalling/fatigue 

due to low level repeated load. Since the applicant has committed to an appropriate AMP for the 

period of extended operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.5 Fire Protection Barriers - Summary of Aging Management Review –

LRA Table 3.5.2-5 

The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for the 

fire protection barriers component groups.

In LRA Table 3.5.2-5, the applicant identified 17 unique component/material/environment/aging 

effect/AMP groups for the Fire Protection Barriers. Fourteen have AMR results consistent with 

the GALL Report, as identified by reference to Notes A through E. The staff confirmed that the 

references to Table 1 and GALL Volume II line items are applicable.

For three component types, the applicant proposed to manage cementitious fireproofing and fire 

rated caulks and putties with smooth hard surface, rigid non-shrink mineral fiber board, fibrous 

fire rated, and rough surface (sprayed on or troweled) material, in an air indoor environment with 

an aging affect of loss of material/flaking, abrasion; cracking/vibration and movement; 

separation/vibration and movement, by using the Fire Protection Program. The staff’s review of 

the Fire Protection Program is documented in SER Section 3.0.3.2.6. These line items 

reference Note J. The staff finds that the credited AMP is appropriate, because the Fire 

Protection Program performs visual inspections on a periodic basis to manage cementitious 

fireproofing and fire rated caulks and putties with smooth hard surface, rigid non-shrink mineral 

fiber board, fibrous fire rated, and rough surface (sprayed on or troweled) material, aging affect 

loss of material/flaking, abrasion; cracking/vibration and movement; separation/vibration and 

movement. Since the applicant has committed to an appropriate AMP for the period of extended 

operation, the staff finds these AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).
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3.5.2.3.6 Radwaste Building, Old Administration Building, and Administration Building Addition -

Summary of Aging Management Review – LRA Table 3.5.2-6

The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for the 

radwaste building, old administration building, and administration building addition component 

groups.

In LRA Table 3.5.2-6, the applicant identified 29 unique component/material/environment/aging 

effect/AMP groups for the Radwaste Building, Old Administration Building, and Administration 

Building Addition. All twenty nine have AMR results consistent with the GALL Report, as 

identified by reference to Notes A through E. The staff confirmed that the references to Table 1 

and GALL Volume II line items are applicable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.7 Reactor Containment Vessels Units 1 and 2 - Summary of Aging Management 

Review – LRA Table 3.5.2-7

The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for the 

reactor containment vessels Units 1 and 2 component groups.

In LRA Table 3.5.2-7, the applicant identified 42 unique component/material/environment/aging 

effect/AMP groups for the Reactor Containment Vessels Units 1 and 2. Thirty eight have AMR 

results consistent with GALL, as identified by reference to Notes A through E. The staff 

confirmed that the references to Table 1 and GALL Volume II line items are applicable.

For one component type, the applicant proposed to manage steel for reactor containment 

vessel material, in an air indoor environment with an aging affect of cumulative fatigue 

damage/fatigue, by using the TLAA Section 4.6.1. The staff’s review of the TLAA is documented 

in SER Section 4.6.1. This line item references Note H. The staff finds that the credited TLAA is 

appropriate because the TLAA Section 4.6.1 evaluated the aging affect cumulative fatigue 

damage / fatigue. Since the applicant has committed to an appropriate TLAA for the period of 

extended operation, the staff finds these AMR results to be acceptable.

For the remaining three component types, the applicant proposed to manage unreinforced 

concrete material, in an air indoor environment with an aging affects of cracking, distortion, 

increase in porosity and permeability, loss of material (spalling/scaling), by using the Structures 

Monitoring Program. The staff’s review of the Structures Monitoring Program is documented in 

SER Section 3.0.3.2.17. These line items reference Note F and plant-specific Note 23, which 

states “This line item addresses the unreinforced concrete placed between the Shield Building 

base mat/wall and the elliptical bottom head of the Reactor Containment Vessel. The top of the 

unreinforced concrete, which extends across the annular space between the Containment and 

Shield Building, is exposed to an indoor air environment. Elsewhere the unreinforced concrete is 

in contact with either the containment bottom head or the reinforced concrete Shield Building. 
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The reinforced concrete base mat below the unreinforced concrete is an integral part of the 

Shield Building and is evaluated with the Shield Building. Since the unreinforced concrete is 

exposed to air indoor and embedded in concrete environments, the aging mechanisms 

settlement, reactions with aggregate and aggressive chemical attack are applicable, while 

elevated temperature, corrosion of embedded steel, leaching of calcium hydroxide, erosion of 

porous concrete subfoundation and freeze-thaw do not apply.” The staff finds that the credited 

AMP is appropriate because the Structures Monitoring Program performs visual inspections on 

a periodic basis to manage unreinforced concrete material, aging affect cracking, distortion, 

increase in porosity and permeability, loss of material (spalling/scaling). Since the applicant has 

committed to an appropriate AMP for the period of extended operation, the staff finds these 

AMR results to be acceptable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.8 SBO Yard Structures - Summary of Aging Management Review – LRA Table 3.5.2-8 

The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for the 

SBO yard structures component groups.

In LRA Table 3.5.2-8, the applicant identified 27 unique component/material/environment/aging 

effect/AMP groups for the SBO Yard Structures. All twenty seven have AMR results consistent 

with the GALL Report, as identified by reference to Notes A through E. The staff confirmed that 

the references to Table 1 and GALL Volume II line items are applicable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.9 Shield Buildings Units 1 and 2 - Summary of Aging Management Review –

LRA Table 3.5.2-9

The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for the 

shield buildings Units 1 and 2 component groups.

In LRA Table 3.5.2-9, the applicant identified 39 unique component/material/environment/aging 

effect/AMP groups for the Shield Buildings Units 1 and 2. All thirty nine have AMR results 

consistent with GALL, as identified by reference to Notes A through E. The staff confirmed that 

the references to Table 1 and GALL Volume II line items are applicable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 
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adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.10 Tank Foundations - Summary of Aging Management Review – LRA Table 3.5.2-10 

The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations for 

the tank foundations component groups.

In LRA Table 3.5.2-10, the applicant identified 19 unique component/material/environment/aging 

effect/AMP groups for the Tank Foundations. All 19 have AMR results consistent with GALL, as 

identified by reference to Notes A through E. The staff confirmed that the references to Table 1 

and GALL Volume II line items are applicable.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the GALL 

Report. The staff finds that the applicant has demonstrated that the effects of aging will be 

adequately managed so that the intended function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.11 Water Control Structures–Approach Canal, Emergency Cooling Water Intake, Intake 

Canal, and Screenhouse - Summary of Aging Management Review – LRA Table 3.5.2-11 

The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations for 

the water control structures component groups.

In LRA Table 3.5.2-11, the applicant identified 49 unique component/material/environment/aging 

effect/AMP groups for the Water Control Structures, Approach Canal, Emergency Cooling 

Water Intake, Intake Canal, and Screenhouse. Forty eight have AMR results consistent with the 

GALL Report, as identified by reference to Notes A through E. The staff confirmed that the 

references to Table 1 and GALL Volume II line items are applicable.

For one component type the applicant proposed to manage roofing material, in an air-outdoor 

environment with in aging affect of separation, environmental degradation, and water inleakage/weathering, by using the Structures Monitoring Program. The staff’s review of the 

Structures Monitoring Program is documented in SER Section 3.0.3.2.17. These line items 

reference Note J and plant-specific Note 6, which states “Roofing components are not provided 

in NUREG-1801. PINGP plant-specific evaluation source document ACI 349.3R provided aging 

effects for roofing to include separation, environmental degradation, water in-leakage due to 

weathering.“ The staff finds that the credited AMP is appropriate because the Structures 

Monitoring Program performs visual inspections on a periodic basis to manage roofing material, 

aging affects separation, environmental degradation, and water in-leakage/weathering. Since 

the applicant has committed to an appropriate AMP for the period of extended operation, the 

staff finds these AMR results to be 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 function(s) will be maintained consistent with the CLB 

for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the structures and component supports components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls System

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 (insulation), includes splices, terminations, fuse blocks and 

connectors

• cables and connections used in instrumentation circuits (insulation), sensitive to 

reduction in conductor insulation resistance

• inaccessible medium voltage cables and connections (insulation), underground, buried 

• electrical connector contacts (metallic connector pins exposed to borated water) 

• Electrical Penetrations (electrical insulation portions)

• metal enclosed bus and connections (bus/connections, enclosure assemblies, 

insulation/insulators) 

• fuse holders (metallic parts), not part of a larger active assembly 

• cable connections (metallic parts) 

• switchyard bus and connections 

• transmission conductors and connections 

• high-voltage Insulators 

3.6.1 Summary of Technical Information in the Application 

LRA Section 3.6 provides AMR results for the electrical and I&C components and component 

groups. LRA Table 3.6.1, “Summary of Aging Management Programs for Electrical and I&C 

Component Evaluated in Chapter VI of the GALL Report,” 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.
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3.6.2 Staff Evaluation 

The staff reviewed LRA Section 3.6 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the electrical and I&C components within 

the scope of license renewal and subject to an AMR will be adequately managed so that the 

intended function(s) will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

The staff reviewed AMRs to ensure the applicant’s claim that certain AMRs were consistent with 

the GALL Report. The staff did not repeat its review of the matters described in the GALL 

Report; however, the staff did verify that the material presented in the LRA was applicable and 

that the applicant has identified the appropriate GALL 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 AMRs consistent with the GALL Report and for which further evaluation 

is recommended. The staff confirmed that the applicant’s further evaluations were consistent 

with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s 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 evaluated whether all plausible aging effects have been 

identified and whether the aging effects listed were appropriate for the material-environment 

combinations specified. The staff’s evaluations are documented in SER Section 3.6.2.3.

Table 3.6-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.6 and addressed in the GALL Report.

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

Report

Component Group

(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

Environmental 

Qualification of 

Electrical 

Components (B3.1)

Consistent with 

the GALL Report 

(See Section 

3.6.2.2.1)
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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

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 Visual 

Inspection Program

(B2.1.12)

Consistent with 

the GALL Report 

(See Section 

3.6.2.1)

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 Cables and 

Connections Used in 

Low-Current 

Instrumentation 

Circuits Program 

(B2.1.13)

Consistent with 

the GALL Report 

(See Section 

3.6.2.1)

Conductor insulation 

for inaccessible 

medium voltage 

(2 kV to 35 kV) 

cables (e.g., installed 

in conduit or direct 

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 

trees

Inaccessible Medium 

Voltage Cables Not 

Subject to 

10 CFR 50.49 

EQ Requirements

No Inaccessible 

Medium-Voltage 

Cables Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Program (B2.1.21)

Consistent with 

the GALL Report 

(See Section 

3.6.2.1)

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage (3.6.1-5) 

Corrosion of 

connector 

contact surfaces 

Boric Acid Corrosion No Boric Acid Corrosion 

(B2.1.7) 

Consistent with 

the GALL Report

(See Section 

3.6.2.1)
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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

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 Fuse Holders 

Program (B2.1.20)

Consistent with

the GALL Report

(See Section 

3.6.2.1)

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 (B2.1.26)

Consistent with 

the GALL Report

(See Section 

3.6.2.1)

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

(B2.1.26)

Consistent with

the GALL Report 

(See Section 

3.6.2.1)

Metal enclosed bus -

enclosure 

assemblies

(3.6.1-9)

Loss of material 

due to general 

corrosion

Structures Monitoring 

Program

No Structures Monitoring 

Program (B2.1.38)

Consistent with

the GALL Report

(See Section 

3.6.2.1)

Metal enclosed bus -

enclosure 

assemblies

(3.6.1-10)

Hardening and 

loss of strength 

due to 

elastomers 

degradation

Structures Monitoring 

Program

No Structures Monitoring 

Program (B2.1.38)

Consistent with

the GALL Report

(See Section 

3.6.2.1)
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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

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 aging 

management 

program is to be 

evaluated

Yes None Further 

evaluation (See 

SER Section 

3.6.2.2.2)

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 aging 

management 

program 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 Electrical Cable 

Connections Not 

Subject to 10 CFR 

50.49 Environmental 

Qualification 

Requirements 

Program (B2.1.11)

Consistent with 

the GALL Report

for the 

component, 

material, 

environment, 

and aging effect. 

AMP take some 

exception to 

GALL AMP (See 

Section 3.6.2.1)

Fuse Holders

(Not Part of a Larger 

Assembly) -

insulation material

(3.6.1-14)

None None No Not applicable Consistent with

the GALL report

(See Section 

3.6.2.1)

The staff’s review of the electrical and I&C component groups followed one of several 

approaches. In one approach, documented in SER Section 3.6.2.1, the staff reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 
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require no further evaluation. In the second approach, documented in SER Section 3.6.2.2, the 

staff reviewed AMR results for components that the applicant indicated are consistent with the 

GALL Report and for which further evaluation is recommended. In the third approach, 

documented in SER Section 3.6.2.3, the staff reviewed AMR results for components that the 

applicant indicated are not consistent with or not addressed in the GALL Report. The staff’s 

review of AMPs credited to manage or monitor aging effects of the electrical and I&C 

components is documented in SER Section 3.0.3.

3.6.2.1 AMR Results Consistent with the GALL Report 

LRA Section 3.6.2.1 identifies the materials, environments, aging effects requiring management, 

and the following programs that manage aging effects for the electrical and I&C components:

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirement Program

• Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental

Qualification Requirements Used in Instrumentation Circuit

• Inaccessible Medium Voltage Cables Not Subject to 10 CFR 50.49 Environmental 

Qualification Requirement Program

• Boric Acid Corrosion Program

• Metal Enclosed Bus Program

• Structure Monitoring Program

• Fuse Holder Program

• Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements Program

In LRA Table 3.6.2-1, the applicant summarizes AMRs for the electrical and instrumentation and 

controls components.

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.

For each AMR line item, the applicant stated how the information in the tables aligns with the 

information in the GALL Report. The staff reviewed those AMRs including Notes A through E, 

which indicate 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 is applicable and that the applicant identified the appropriate GALL Report AMRs. The staff 

evaluation follows.
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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 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 evaluated the applicant’s claim of consistency with the GALL Report. The staff also 

reviewed information pertaining to the applicant proposals for managing aging effects. On the 

basis of its review, the staff concludes that the AMR results, which the applicant claimed to be 

consistent with the GALL Report, are indeed consistent. Therefore, the staff concludes that the 

applicant has demonstrated that the effects of aging for these components will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB during the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

3.6.2.2 AMR Results Consistent with the GALL Report for Which Further Evaluation is 

Recommended 

In LRA Section 3.6.2.2, the applicant further evaluates aging management, as recommended by 

the GALL Report, for the electrical and I&C components and provides information concerning 

how it will manage the following aging effects:

• electrical equipment subject to EQ

• degradation of insulator quality due to salt deposits or surface contamination, loss of 

material due to mechanical wear

• loss of material due to wind induced abrasion and fatigue, loss of conductor strength due 

to corrosion, and increased resistance of connection due to oxidation or loss of pre-load

For component groups evaluated in the GALL Report, for which the applicant claimed 

consistency with the report and for which the GALL Report recommends further evaluation, the 

staff reviewed the corresponding AMR line items 3.6.1-1, 3.6.1-11 and 3.6.1-12 in Table 3.6.1 of 

the LRA. The staff also reviewed the applicant’s evaluation to determine whether it adequately 

addressed the issues. In addition, the staff reviewed the applicant’s evaluations against the 

criteria contained in SRP-LR Section 3.6.2.2. The staff’s review is as follows.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification 

LRA Section 3.6.2.2.1 states that EQ of electrical equipment (Table 3.6.1, Item 3.6.1-1) is a 

TLAA, as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 

10 CFR 54.21(c)(1). SER Section 4.4 documents the staff’s review of the applicant’s evaluation 

of this TLAA.

3.6.2.2.2 Degradation of Insulator Quality Due to Salt Deposits or Surface Contamination, and

Loss of Material Due to Mechanical Wear 

In LRA Section 3.6.2.2.2 the applicant addressed degradation of insulator quality due to salt 

deposits or surface contamination and loss of material due to mechanical wear. The applicant 
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stated that the high-voltage insulators subject to an AMR (1) are constructed of porcelain, 

galvanized metal, and cement, (2) are exposed to an outdoor weather environment consisting of 

temperatures up to 40 oC (104 oF), precipitation, and negligible radiation, (3) insulate and 

support an electrical conductor, and (4) require no AMP. The applicant also stated that that it did 

not identify any aging effects from the outside environment (consisting of temperatures up to 

40 oC (104 oF) and precipitation) that would cause the loss of the capability to insulate or 

support its associated electrical conductor.

Regarding the potential for contamination of insulators, the applicant states that buildup of 

surface contamination is gradual and is washed away by rain; the glazed insulator surface aids 

this contamination removal. A large buildup of contamination enables the conductor voltage to 

track along the surface more easily and can lead to insulator flashover. Surface contamination 

can be a problem in areas where there are greater concentrations of airborne particles such as 

near facilities that discharge soot or near the seacoast where salt spray is prevalent. The 

applicant also states that PINGP is located in an area with moderate rainfall where airborne 

particle concentrations are comparatively low; consequently, the rate of contamination buildup 

on the insulators is not significant and, at PINGP, contamination build-up on insulators is not a 

problem due to rainfall periodically "washing" the insulators. Additionally, the applicant states 

that there is no nearby heavy industry or other producers of industrial effluents, which could 

cause excessive contamination. There is no salt spray at PINGP as the plant is far from any 

ocean. Therefore, the applicant concludes that surface contamination is not an applicable aging 

effect for the insulators in the service conditions they are exposed to at PINGP.

Regarding mechanical wear, the applicant states that this is an aging effect for strain and 

suspension insulators (structural metallic portions) 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 swinging is frequent enough, it could 

cause wear in the metal contact points of the insulator string and between an insulator and the 

supporting hardware. The applicant also states that although this mechanism is possible, 

experience has shown that the transmission conductors do not normally swing and that when 

they do, due to a substantial wind, the transmission conductors do not continue to swing 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. The applicant further states that the loss of 

material due to wear concern will be conservatively managed under a structural AMP. 

The applicant states that it reviewed OE to validate aging effects for switchyard insulators 

(electrical insulation portion). This review included corrective action documents for any 

documented instances of switchyard insulator aging. The applicant uncovered no instance of 

aging related problems with in-scope switchyard insulators due to contaminants, cracking, or 

cement growth.

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 highvoltage insulators. The GALL Report recommends further evaluation of plant-specific AMPs for 

plants at locations of potential salt deposits or surface contamination (e.g., in the vicinity of salt 

water bodies or industrial pollution). Loss of material due to mechanical wear caused by wind on 

transmission conductors may occur in high-voltage insulators. The GALL Report recommends 
3-482

further evaluation of a plant-specific AMP to ensure that these aging effects are adequately 

managed.

The staff noted that although loss of material of insulators due to mechanical wear is possible, 

industry OE has shown that the transmission conductors do not normally swing significantly. 

When they do swing as a result of a substantial wind, they do not swing very long once the wind 

has subsided. Wind loading that can cause a transmission line and insulators to vibrate or sway 

is typically considered during the design and installation. Transmission conductors within the 

scope of license renewal are typically short spans and the surface area exposed to wind loads 

are not significant. However, the applicant will conservatively manage the loss of material due to 

wear under the Structures Monitoring Program. The staff evaluation of this program is provided 

in Section 3.0.3.2.17 of SER.

The staff also noted surface contamination can be a problem in areas where the greatest 

concentration of airborne particles such as near facilities that discharge soot or near the sea 

coast where salt spray is prevalent. PINGP is not located near facilities that discharge soot or 

near the sea coast. The rate of contamination buildup on the insulators is not significant. The 

buildup of surface contamination is gradual and is washed away by periodic rain; the glazed 

insulator surface aids this contamination removal. Based on this information, the staff 

determines that surface contamination is not an applicable AERM for the insulators in the 

service conditions they are exposed to at PINGP.

Based on the programs identified above, the staff concludes that the applicant has met the 

SRP-LR Section 3.6.2.2.2 criteria. For those line items that apply to LRA Section 3.6.2.2.2, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

3.6.2.2.3 Loss of Material Due to Wind-Induced Abrasion and Fatigue, Loss of Conductor 

Strength Due to Corrosion, and Increased Resistance of Connection Due to Oxidation or Loss 

of Pre-Load 

In LRA Section 3.6.2.2.3, the applicant addressed loss of material due to wind-induced abrasion 

and fatigue, loss of conductor strength due to corrosion, and increased resistance of connection 

due to oxidation or loss of pre-load. The applicant states that corrosion in aluminum core steel 

reinforced (ACSR) conductors is a slow acting mechanism. Corrosion rates are dependent on 

air quality. The applicant also states that PINGP is located in an agricultural area with no nearby 

industries that could contribute to corrosive air quality. The applicant further states that 

corrosion testing of transmission conductors at Ontario Hydroelectric showed a 30% loss of 

composite conductor strength of an 80-year-old ACSR conductor. The Institute of Electrical and 

Electronic Engineers National Electrical Safety Code (NESC) requires that tension on installed 

conductors be a maximum of 60% of the ultimate conductor strength. Therefore, assuming a 

30% loss of strength, the applicant states there is margin remaining over what is required by the 

NESC and the existing actual conductor strength. The applicant states that in determining actual 

conductor tension, the NESC considers various loads imposed by ice, wind, and temperature as 

well as length of conductor span. The applicant states that PINGP transmission conductors inscope for license renewal are short spans located within the PINGP site, and are designed for 
3-483

heavy loading; therefore, the Ontario Hydroelectric heavy loading zone study is aligned with 

respect to loads imposed by weather conditions.

The applicant also states that 636 kilo circular mil (MCM) ACSR transmission conductor is used 

in the PINGP switchyard. The ultimate strength of a 636 MCM (24/7 strands) ACSR conductor is 

22,600 lbs and the maximum design tension for this conductor is 3,500 lbs. The margin between 

the maximum design tension and the ultimate strength is 19,100 lbs. Therefore, there is an 

84.5% ultimate strength margin (19,100/22,600). The Ontario Hydroelectric study showed a 

30% loss of composite conductor strength in an 80-year old conductor. The applicant states that 

since the margin for the PINGP conductors is greater than the margin loss due to aging, 

remaining safety margin exists on the aged conductors. The applicant further states that the 

Ontario Hydroelectric test results demonstrate that the expected material loss that would be 

incurred on the PINGP ACSR transmission conductors is acceptable for the period of extended 

operation. Therefore, no aging management is required for loss of material and loss of strength 

on the ACSR transmission conductors at PINGP.

In LRA Section 3.6.2.2.3, the applicant states that the switchyard bus and connections subject 

to an AMR (1) are constructed of aluminum and aluminum alloy (bolting), (2) are exposed to an 

atmosphere/weather (same as Air-Outdoor) environment consisting of temperatures up to 

40 oC (104 oF), precipitation, and negligible radiation, (3) provide electrical connections to 

specific sections of an electrical circuit to deliver voltage, current or signals, and (4) require no 

AMP. The applicant also states that there are no aging effects from the outdoor environment 

(consisting of temperatures up to 40 oC (104 oF) and precipitation) that would cause the loss of 

the capability to provide electrical connections to specified sections of an electrical circuit to 

deliver voltage, current, or signals. The applicant further states that PINGP currently performs 

periodic thermography and visual inspection of switchyard connections.

The applicant states that it determined that an environment consisting of temperatures up to 

40 oC (104 oF) and precipitation has no significant aging effect on aluminum and aluminum 

alloy. The applicant further states that it already maintains an existing inspection program on 

switchyard connections, and does not require a license renewal program; therefore, no license 

renewal AMP is required for high-voltage switchyard bus and connections. The applicant also 

states that it reviewed industry OE and NRC generic communications related to the aging of 

transmission conductors in order to ensure that no additional aging effects exist beyond those 

identified above. The applicant further states that PINGP also reviewed plant-specific OE, 

including nonconformance reports, licensee event reports, and CRs. PINGP's review did not 

identify unique aging effects for transmission conductors beyond those identified above. The 

applicant concludes that no license renewal AMP is required for the PINGP transmission 

conductors and connections aging effects of loss of conductor strength and loss of material 

(mechanical wear).

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 pre-load 

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.
3-484

The staff finds that corrosion of an ACSR conductor is a very slow acting mechanism and 

insignificant during the period of extended operation. The conductor strength of a 636 MCM 

ACSR conductor is 22,600 lbs. and the maximum design tension for this conductor is 3500 lbs. 

The heavy load tension is 15.5 % of the conductor strength (3500 lbs./22600 lbs.) The Ontario 

Hydroelectric study showed a 30% loss of conductor strength after 80 years in service for an 

ACSR transmission conductor. A 30% loss of conductor strength would mean the heavy load 

tension is 22% of the ultimate conductor strength (3500 lbs./22600 lbs. x 70%) which is within 

the 60% NESC requirement. This illustrates that the transmission conductor will have ample 

strength through the period of extended operation. Based on this information, the staff 

concludes that loss of conductor strength is not a significant aging effect requiring management 

at PINGP.

The staff noted that increased resistance of connections due to oxidation could occur in 

transmission conductors and connections, and in switchyard bus and connections. The 

applicant stated in LRA Section 3.6.2.2.3 that there are no aging effects from the outdoor 

environment that would cause the loss of the capacity to provide electrical connections to 

specified sections of an electrical circuit to deliver voltage, current, or signals. SRP-LR Section 

3.6.2.2.3 recommends a plant-specific AMP for the management of increase resistance of 

connections due to oxidation or loss of pre-load in transmission conductors and connections 

and in switchyard bus and connections. The applicant did not explain why increased resistance 

of connections due to oxidation or loss of pre-load in transmission conductors and connections, 

and in switchyard bus and connections is not an AERM. By letter dated December 18, 2008, in 

RAI 3.6-1, the staff asked the applicant to explain why increased resistance of connections of 

transmission connections and switchyard bus connections due to oxidation or loss of pre-load is 

not identified as an AERM. In response to the staff’s request, in a letter dated January 20, 2009, 

the applicant stated that the switchyard bus connections within the component boundaries are 

bolted, welded and crimped aluminum connections for cables. The PINGP OE review has not 

identified aging problems with the high-voltage switchyard bus and connections that resulted 

from loss of material, wind induced abrasion and fatigue loss of conductor strength, corrosion 

increased resistance of connections, oxidation or loss of pre-load. Bellville washers are also 

used at PINGP to minimize the effects of loose connections from loss of pre-load. Failures of 

Bellville washers (causing loose connections) were noted from industry OE, whereby hydrogen 

entrapment with plated steel washers caused embrittlement and stress cracking of the plated 

washer leading to loose connections. Action has been taken by the industry to correct this issue.

The PINGP design includes the use of stainless steel Bellville washers. The issue of hydrogen 

entrapment causing failures is not an issue for stainless steel Bellville washers used at PINGP.

The applicant also stated that surface oxidation does initially occur on aluminum switchyard bus 

and connection portions exposed to air-outdoor environments, but the oxidation levels do not 

adversely impact the bus and connections from appreciable losses of material. This initial 

oxidation of exposed aluminum actually provides a protective layer, whereby further oxidation is 

progressively slowed to negligible levels. The internal contact surfaces of the switchyard bolted 

connections are not exposed to a moisture environment that would contribute to corrosion of the 

connection contact surface area. A loose connection (from any other cause, such as inadequate 

tightening during maintenance) is required to provide an environment for the onset of corrosion 

of the internal connection surfaces to occur.
3-485

The applicant further stated that for the ambient environmental conditions at the PINGP

substation, no aging effects have been identified for switchyard bus and connections that could 

cause a loss of intended function for the extended period of operation. Therefore, the applicant 

believes there are no applicable or significant aging effects for the aluminum bus and aluminum 

alloy connections that require aging management. As a result, no plant-specific license renewal 

AMP is required for transmission cables and conductors, and switchyard bus and connections.

In reviewing the applicant’s response to the staff request for additional information, the staff 

noted that the applicant did explain why increased resistance of switchyard bus connections is 

not an AERM. However, the applicant did not explain why increased resistance of transmission 

conductor connections due to oxidation or loss of pre-load is not identified as an AERM.

Increased resistance of connections due to oxidation could occur in transmission connections.

In a January 28, 2009 telephone conference, the staff requested the applicant to explain why 

PINGP transmission connections are not subject to aging effects. In response to the staff’s 

request, in a letter dated February 6, 2009, the applicant stated that the high-voltage 

transmission conductors and connections are bolted, welded and crimped aluminum 

connections. The applicant reviewed the PINGP OE and did not identify loss of material or 

corrosion causing increase resistance of connection in the high-voltage switchyard bus and 

connections.

The staff noted that for switchyard bus and connections, and transmission conductor and 

connections, the connections are bolted, welded and crimped aluminum alloy. The initial 

oxidation of aluminum provides a protective layer and further oxidation is negligible. Therefore, 

there is no significant aging effect of oxidation on aluminum alloy. In addition, Bellville washers 

are used at PINGP to minimize the effects of loose connections from loss of pre-load. Since 

PINGP uses stainless steel Bellville washers, hydrogen embrittlement issue with electroplated 

Belleveville washers is not applicable to PINGP. Furthermore, the applicant has reviewed 

PINGP OE, and has not identified any aging problems with the high-voltage switchyard 

connections that resulted from loss of material, corrosion increased resistance of connections, 

oxidation or loss of pre-load. Based on this information, the staff concludes that increased 

resistance of connections due to oxidation or loss of pre-load in switchyard bus and 

connections, and transmission conductor and connections is not a significant AERM at PINGP.

Based on the programs identified above, the staff concludes that the applicant has met the 

SRP-LR Section 3.6.2.2.3 criteria. For those line items that apply to LRA Section 3.6.2.2.3, the 

staff determines that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended operation, 

as required by 10 CFR 54.21(a)(3).

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

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations not consistent with or not addressed in the GALL 

Report.

In LRA Table 3.6.2-1, the applicant indicated, via Notes F through J that the combination of 

component type, material, environment, and AERM does not correspond to a line item in the 
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GALL Report. The applicant provided further information about how it will manage the aging 

effects. 

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

In some plants, tie wraps may be taken credit for in seismic analysis and in plant design 

specifications primary for separation to preclude ampacity degrading. OE has identified issues 

with tie wraps including brittleness, degradation, or missing tie wraps, and tie wraps failures

(debris considerations) affected safety functions of other system/components (e.g., blocking the 

safety-related sump pumps). The PINGP LRA does not discuss tie wraps as requiring AMRs. By 

letter dated December 18, 2008, the staff issued RAI 3.6.2, which asked the applicant to explain 

why tie wraps do not require an AMR. In particular, the staff asked the applicant to address if tie 

wraps are credited for seismic analysis in the CLB and the effects of tie wraps (debris 

considerations) for 10 CFR 54.4 (a)(2) over 10 CFR 54.4 (a)(1), non safety components whose 

failure could affect safety-functions. The staff also asked the applicant, if tie wraps are 

considered in plant design specifications, provide a quantitative analysis of the cable spacing 

not maintained per the original design specifications (due to tie wraps failures). By letter dated 

January 20, 2009, the applicant responded that it has reviewed the use of tie wraps at PINGP 

and confirmed that tie wraps are not within the scope of license renewal and not subject to an 

AMR. For debris considerations, the applicant stated that it reviewed industry and PINGP OE.

Foreign material debris, such as broken tie wraps, can cause equipment functional failures.

PINGP equipment that is sensitive to debris, such as broken tie wraps, is designed to be 

protected by enclosures. The applicant further stated that maintenance-induced failures from 

inadequate foreign material exclusion practices involving tie wraps does not bring tie wraps inscope and does not require AMRs for license renewal purposes. Its analysis of the containment 

sump for the safety-related recirculation mode of post-accident operation, considered the effects 

of debris, including tie wraps. The applicant did not identify any occurrences involving a 

nonsafety-related tie wrap failure affecting safety-related intended functions at PINGP. For 

seismic support considerations, the applicant stated that tie wraps are used to assist in the 

orderly installation of cables in trays at PINGP. Tie wraps are not credited for support in the 

PINGP seismic analyses. For ampacity considerations, the applicant stated that the PINGP 

UFSAR Section 8.7 states "Power cables are installed with only a single layer of cables per tray 

and clamped in the ladder to ensure that a specified spacing exists between these cables to 

ensure that air cooling is available."

The applicant also stated that PINGP conducted a cable insulation aging assessment for the 

hypothetical configuration of un-spaced single layer power cables in trays with continuous heavy 

current loading for motors credited to start and run during a design basis accident. For the 

continuous heavy current loaded power cables, the applicant based the free-air rating on 

Insulated Power Cable Engineered Association (IPCEA) P-46-426, Insulated Cable Power 

Association (ICPA) P-54-440, and the National Electric Code (NEC). For each of the continuous

heavy current loaded power cables, the applicant obtained full load amps or actual amps value.

The applicant applied an aging assessment screening de-rating factor of 50% to the power 

cables’ free air allowable ampacity value. The applicant did not identify any continuous heavily 
3-487

loaded power cables with in-scope of license renewal to be operating at or above 50% of free 

air allowable ampacity. The applicant’s aging assessment concluded that power cables have 

adequate design margin to accommodate a hypothetical not spaced configuration, 60 years of 

operational aging, and to start and run credited motors during a design basis accident.

The applicant further stated that following example illustrates the process used for aging 

assessments. A power cable to a Charging Pump Motor, 125 HP (460V), operates at 145 amps 

full load name plate. The (3/C 4/0 copper) cable allowable ampacity for free air is 359 amps.

The 145 full load amps drawn by the motor is 40% of the free air allowable ampacity of the 

cable. (The free air allowable ampacity values, as well as derating criteria, reside in 

IPCEA P-46-426, ICPA P-54-440, and the NEC.)

In reviewing the applicant’s response, the staff noted that the applicant did not address the 

effects of cable spacing for the motor to start. This current is typically 2 to 3 time the continuous 

run current. In a January 28, 2009, telephone conference; the staff asked the applicant to 

explain why starting current is not an issue for aging of un-spaced power cables. By letter dated 

February 6, 2009, the applicant responded that the starting of motors does result in a current 

inrush (current surge) above the motor's full load current, but this starting current surge has only 

a momentary duration that does not contribute to cable aging effects. Cable aging is dependent 

on the average temperature exposure of cable insulation over the 60-year service duration.

The staff finds the applicant’s response is acceptable because tie wraps are not credited in 

seismic analyses and failures of tie wraps will not affect safety components to perform their 

intended function(s) during license renewal. Furthermore, the applicant did not identify any 

occurrences involving a nonsafety-related tie wrap failure affecting safety-related intended 

functions at PINGP. The applicant provided a quantitative analysis of the effects of cables 

spacing not being maintained as original design (due to tie wraps failure). This analysis 

demonstrated that with ampacity reduction of 50%, power cable have adequate design margin 

for motors to run during the design basis accident. The starting of motors has only a momentary 

duration that would not be affected by cable spacing because cable thermal resistance is 

insignificant during moments of starting current. Therefore, the staff found that tie wraps are not 

in-scope of license renewal.

3.6.3 Conclusion 

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the electrical and I&C components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended function(s) will be 

maintained consistent with the CLB for the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.7 Conclusion for Aging Management Review Results

The staff reviewed the information in LRA Section 3, “Aging Management Review Results,” and 

LRA Appendix B, “Aging Management Programs and Activities.” On the basis of its review of the 

AMR results and AMPs, the staff concludes, with the exception of OIs 3.0.3.1.21-1 and 

3.0.3.2.17-1, that the applicant has demonstrated that the aging effects will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 
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period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 

applicable UFSAR supplement program summaries and concludes that the supplement 

adequately describes the AMPs credited for managing aging, as required by 10 CFR 54.21(d).

With regard to these matters, the staff concludes that there is reasonable assurance that the 

applicant will continue to conduct the activities authorized by the renewed licenses and will 

continue to be conducted in accordance with the CLB, and any changes made to the CLB, in 

order to comply with 10 CFR 54.21(a)(3), are in accordance with the Atomic Energy Act of 1954, 

as amended, 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 4.7 of the license renewal application (LRA), 

Northern States Power, a Minnesota Corporation (NSPM or the applicant) addressed the TLAAs 

for Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2. SER Sections 4.2 through 

4.8 document the review of the TLAAs by the staff of the United States (US) Nuclear Regulatory 

Commission (NRC) (the staff).

TLAAs are certain plant-specific safety analyses that involve time-limited assumptions defined 

by the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of Federal 

Regulations (10 CFR 54.21(c)(1)), applicants must list and evaluate. TLAAs as defined in 

10 CFR 54.3. In addition, pursuant to 10 CFR 54.21(c)(2), applicants must list plant-specific 

exemptions granted under 10 CFR 50.12 based on TLAAs. For any such exemptions, the 

applicant must evaluate and justify the continuation of the exemptions for the period of extended 

operation.

4.1.1 Summary of Technical Information in the Application 

To identify the TLAAs, the applicant evaluated calculations for PINGP Units 1 and 2 against the 

six criteria specified in 10 CFR 54.3. The applicant indicated that it has identified the 

calculations that met the six criteria by searching the current licensing basis (CLB). The CLB 

includes the updated final safety analysis report (UFSAR), NRC Safety Evaluation Reports 

(SERs), licensing correspondence, and NRC Regulatory Commitments. In addition, the staff 

also reviewed engineering calculations, technical reports, engineering work requests, and 

applicable vendor reports. In LRA Table 4.1-1, “Time-Limited Aging Analyses,” the applicant 

listed the applicable TLAAs:

• reactor vessel neutron embrittlement 

• metal fatigue 

• environmental qualification of electrical equipment

• containment and penetration fatigue analyses

• reactor coolant system piping leak-before-break analyses

• reactor vessel underclad cracking

• reactor coolant pump flywheel

• fatigue analysis of cranes

• probability of damage to safeguards equipment from turbine missiles
4-2

Pursuant to 10 CFR 54.21(c)(2), the applicant stated that it did not identify exemptions 

applicable to the period of extended operation granted under 10 CFR 50.12 based on TLAAs as 

defined in 10 CFR 54.3.

4.1.1.1 Amendment of LRA Section 4.7.5, Probability of Damage to Safeguards 

Equipment from Turbine Missiles

In NSPM Letter No. L-PI-09-047, dated April 6, 2009, the applicant amended its LRA to delete 

the probabilistic turbine rotor failure analysis associated with LRA Section 4.7.5, “Probability of 

Damage to Safeguards Equipment from Turbine Missiles” (henceforth Turbine Missile Analysis), 

as an analysis that meets the definition of a TLAA under the TLAA identification criteria of 

10 CFR 54.3. In this letter, the applicant stated that, upon reassessment of this analysis, the 

Turbine Missile Analysis was not a TLAA for the LRA because the time frame for the analysis 

was not based on time-limited assumptions defined by the current operating period. Thus, in this 

letter, the applicant made the following LRA changes in order to delete the Turbine Missile 

Analysis:

• In LRA Section 3.4.2.3 on Page 3.4-21, the last bullet, Probability of 

Damage to Safeguards Equipment from Turbine Missiles, is deleted in its 

entirety.

• In LRA Table 4.1-1 on Page 4.1-7, the last line item, Probability of 

Damage to Safeguards Equipment from Turbine Missiles, is deleted in its 

entirety.

• In LRA Section 4.7 on Page 4.7-1, the sentence is revised in its entirety to 

read:

• Other PINGP-specific TLAAs include leak-before-break (LBB) analyses, 

underclad cracking, RCP flywheel, and fatigue analysis of cranes.

• LRA Section 4.7.5 on Pages 4.7-4 through 4.7-6 is deleted in its entirety.

• LRA Section A4.9 on Pages A-25 and A-26 is deleted in its entirety.

In NSPM Letter No. L-PI-09-059, dated April 17, 2009, the applicant supplemented the 

information in the letter of April 6, 2009, in order to clarify why the Turbine Missile Analysis did 

not meet the Criterion (3) of 10 CFR 54.3 – the analysis must be based on time-limited 

assumptions defined by the current operating period. This supplemental information is 

discussed and evaluated in SER Section 4.1.2.1 to support the staff’s basis for concluding that 

the Turbine Missile Analysis does not meet the definition of a TLAA defined in 10 CFR 54.3.

4.1.2 Staff Evaluation 

LRA Section 4.1 lists the PINGP TLAAs. The staff reviewed the information to determine 

whether the applicant has provided sufficient information pursuant to 10 CFR 54.21(c)(1) and 

10 CFR 54.21(c)(2). As defined in 10 CFR 54.3, TLAAs meet the following six criteria:

 (1) involve systems, structures, and components within the scope of license renewal, as 

described in 10 CFR 54.4(a)

 (2) consider the effects of aging
4-3

 (3) involve time-limited assumptions defined by the current operating term (40 years)

 (4) are determined to be relevant by the applicant in making a safety determination

 (5) involve conclusions, or provide the basis for conclusions, related to the capability of the 

system, structure, and component to perform its intended functions, as described in 

10 CFR 54.4(b)

 (6) are contained or incorporated by reference in the CLB

The applicant reviewed the list of common TLAAs in NUREG-1800, Revision 1, “Standard 

Review Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR), 

dated September 2005. The applicant listed TLAAs applicable to PINGP in LRA Tables 4.1-1 

and 4.1-2.

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 evaluated and justified 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 did not identify any TLAA-based 

exemptions applicable to the period of extended operation. Based on the information provided 

by the applicant regarding the process used to identify these exemptions and its results, the 

staff concludes, in accordance with 10 CFR 54.21(c)(2), that there are no TLAA-based 

exemptions justified for continuation through period of extended operation. 

4.1.2.1 Staff Evaluation of the Applicant’s LRA Amendment to Delete LRA Section 4.7.5, 

Probability of Damage to Safeguards Equipment from Turbine Missiles, from the Scope 

of the LRA

LRA Section 4.7.5, Probability of Damage to Safeguards Equipment from Turbine Missiles, 

provides the applicant’s original TLAA assessment for the PINGP probabilistic failure analysis 

for the turbine rotors and blades (henceforth Turbine Missile Analysis). The staff noted that in 

this section of the LRA, the applicant referred to the following documents in the CLB to support 

its TLAA basis under TLAA acceptance criterion in 10 CFR 54.21(c)(1)(i): (1) NUREG-0800 

Chapter 3.5.3, “Barrier Design Procedures,” (2) UFSAR Section 12.2.7, (3) UFSAR Section 

11.2.3.2, (4) UFSAR Figure 12.2-38, and (5) WCAP-11525, (6) the staff’s safety evaluation on 

PINGP turbine stop valve, governor valve, and intercept valves testing frequencies and safety 

evaluation on WCAP-11525, which were issued in License Amendment 86 for Unit 1 Operating 

License DPR-42 and License Amendment 79 for Unit 2 Operating License DPR-50, dated 

February 7, 1989. 

Chapter 3.5.1.3 of the Standard Review Plan for the Review of Safety Analysis Results for 

Nuclear Power Plants (SRP-SAR), Revision 3, provides the NRC most recent guidance for 

performing probabilistic turbine missile analysis for turbine rotor and blade failure that are used 

to demonstrate compliance with the requirements of 10 CFR Part 50, Appendix A, “General 

Design Criteria” (GDC), GDC No. 4, Environmental and Dynamic Effects Design Bases, or 

similar design bases for plants that were licensed prior to the staff’s development of the GDC. 
4-4

The staff noted that, consistent with this guidance, the applicant established that the 

probabilistic analysis for these components is calculated in accordance with the following 

equation:

P4 = P1 × P2 × P3

Where

P1 = the probability of turbine failure resulting in the ejection of turbine rotor (or internal 

structure) fragments through the turbine casing.

P2 = the probability of ejected missiles perforating intervening barriers and striking safety-related 

structures, systems, or components.

P3 = the probability of struck structures, systems, or components failing to perform their safety 

function 

The staff noted that Chapter 3.5.1.3 of the SRP-SAR establishes that these probabilistic failure 

analyses must demonstrate an acceptably low risk of damage from postulated turbine missiles 

so long as the overall P4 probability failure remains less than 1 x 10-7

. The staff also noted that 

this SRP chapter establishes that the combined product of the P2 × P3 probability factors 

should be set in the range of 1.0 x 10-2 to 1.0 x 10-3 for unfavorably oriented turbines. The staff 

noted that the applicant has conservatively set the product of the P2 × P3 probability factors to a 

value of 1.0 x 10-2 consistent with the SRP-SAR recommendations. Thus, the staff noted that 

applicant’s probability of failure analysis for the turbine rotors would remain valid so long as the 

P1 probability factor value for turbine rotor or blade ejections remains less than or equal to a 

value of 1.0 x 10-5

.

The staff noted that in NPSM Letter No. L-PI-09-047 (dated April 6, 2009), and as amended in 

NPSM Letter No. L-PI-09-059 (dated April 17, 2009), the applicant amended its LRA to delete 

the Turbine Missile Analysis as an analysis that meets the definition of a TLAA according to

10 CFR 54.3. The applicant’s basis for deleting the Turbine Missile Analysis as a TLAA for the 

LRA has been summarized in SER Section 4.1.1.1. 

The staff reviewed the information given in LRA Section 4.7.5, and as amended by the relevant 

information in the applicant’s letters of April 6, 2009 and April 17, 2009, in order to determine 

whether the applicant had a valid basis for deleting the Turbine Missile Analysis as an analysis 

that meet the definition of a TLAA in 10 CFR 54.3. 

The staff assessed the Turbine Missile Analysis against the six TLAA definition criteria in 

10 CFR 54.3. The staff determined that the Turbine Missile Analysis meets Criteria 1, 2, 4, 5, 

and 6 as defined below:

 (1) The analysis meets Criterion (1) - the analysis must involve systems, structures, and 

components within the scope of license renewal - because the generation of postulated 

turbine missiles is relevant to the integrity of passive, long-lived safeguards equipment 

that are within the scope of license renewal and that are subject to an AMR.
4-5

 (2) The analysis meets Criterion (2) - the analysis must consider the effects of aging -

because the generation of postulated turbine missiles is initiated by a fatigue induced 

failure of a turbine rotor or blade.

 (4) The analysis meets Criterion (4) - the analysis must be determined to be relevant by the 

applicant in making a safety determination - because the analysis is performed to ensure 

the structural integrity of safeguards equipment against the generation of postulated 

turbine missiles in order to satisfy the design requirement in 10 CFR Part 50, Appendix 

A, “General Design Criteria” (GDC), under GDC No. 4, “Environmental and Dynamic 

Effect Design Bases.

 (5) The analysis meets Criterion (5) - the analysis must involve conclusions, or provide the 

basis for conclusions, related to the capability of the system, structure, and component 

to perform its intended functions, as described in 10 CFR 54.4(b) - because the analysis 

is relevant to the ability of passive-longed safeguard equipment to perform their intended 

10 CFR 54.4(a)(1) safety functions during the period of extended operation.

 (6) The analysis meets Criterion (6) - the analysis must be contained or incorporated by 

reference in the CLB - because the analysis is relevant to compliance with the design 

requirements for the CLB, as established in GDC No. 4. 

Thus, the staff noted that whether the Turbine Missile Analysis meets the definition of a TLAA 

depends on whether the analysis conformed to TLAA definition Criterion (3) – the analysis must 

involve time-limited assumptions defined by the current operating term. Thus, the staff 

determined that the Turbine Missile Analysis would only meet TLAA definition Criterion (3) if the 

validity of the analysis was performed for a period equal to the currently licensed life of the plant 

or more than the time frame established at the expiration of the period of extended operation.

The applicant determined that the Turbine Missile Analysis does not meet the TLAA definition 

Criterion (3) for a TLAA because it stated the probabilistic analysis was used to support an 

approximate 10-year inservice inspection (ISI) interval for the turbine rotors and blades and a 

12 month inservice testing surveillance frequency for the turbine governor valves, stop valves, 

and intercept valves (which are implemented in accordance with the applicant’s Technical 

Requirements Manual (TRM)).

The staff noted that in the applicant’s letter of April 17, 2009, the applicant clarified that TRM 

Section 3.7.3 requires the applicant to maintain the probability of a turbine rotor or blade 

ejection event at a probability of 1.0 x 10-5 or less. In this letter the applicant clarified that the 

TRM section identifies that the probabilistic turbine rotor and blade ejection analysis was done 

in WCAP-11525, which was approved in an NRC safety evaluation date February 7, 1989, and 

that the validity of the turbine rotor or blade ejection probability is to be re-verified by performing 

required TRM Section 3.7.3 periodic surveillance testing of the turbine stop valves, intercept 

valves, and governor valves at a frequency of at least once every 12 months. The applicant also 

clarified that, although the scope of the requirements in TRM Section 3.7.3 do not include 

required inservice inspections of the turbine rotors and blades, WCAP-11525 does recommend 

that such inservice inspections of the turbine rotors and blades be implemented at the facility. 

The applicant also clarified that the applicant implements inservice inspections of the turbine 

rotors and blades at a current frequency of once every 100,000 operating hours (i.e., at a 

frequency of approximately once every 11.4 years) in order to meet the recommendations in the 
4-6

WCAP-11525. The applicant clarified that the results of the inspections are also used to 

reestablish the validity of the turbine rotor and blade probability of ejection value.

The staff noted that the result of the surveillance tests of the turbine stop valves, intercept 

valves, and governor valves and the inservice inspections of the turbine rotors and blades is 

used to reestablish the validity of the Turbine Missile Analysis. Since the surveillance tests are 

performed at a minimum frequency of once every 12 months and the inservice inspections are 

performed at a minimum frequency of approximately once every 11.4 years, the staff finds that 

the time interval for re-establishing the validity of the Turbine Missile Analysis is based on a 

period that is less than the current life of the plant. Based on this review, the staff finds that the 

Turbine Missile Analysis does not need to be identified as a TLAA for the LRA because the 

probabilistic failure analysis for the PINGP turbine rotors and blades (as given in WCAP-11525) 

is not based on an analysis that is defined by the life of the plant. The staff verified that in the 

applicant’s letter of April 6, 2009, the applicant made the appropriate amendments of the LRA,

including the deletion of LRA Section 4.7.5 and UFSAR Section A4.9 from the scope of the LRA 

and appropriate changes to Sections 3.4, 4.1 and 4.7 of the application. Based on this review, 

the staff concludes that the applicant has provided an acceptable basis for concluding that the 

Turbine Missile Analysis does not need to be identified as a TLAA for this LRA and for deleting 

this analysis from the scope of the LRA.

4.1.3 Conclusion 

On the basis of its review, the staff concludes that the applicant has provided an acceptable list 

of TLAAs, as required by 10 CFR 54.21(c)(1). The staff confirmed, as required by 

10 CFR 54.21(c)(2), that no exemption to 10 CFR 50.12 applicable to the period of extended 

operation had been granted based on a TLAA.

4.2 

Neutron embrittlement is a significant aging mechanism for all reactor pressure vessel (RPV) 

steels that are exposed to neutron fluence greater than 1017 n/cm2 (E>1.0 MeV). During plant 

operation, neutrons from the fuel in the core irradiate the RPV walls and consequently change 

the material properties of the RPV steel. The most pronounced changes are observed in the 

fracture toughness of the RPV steel. Fracture toughness is a measure of a material’s resistance 

to crack propagation in response to stress fields. A reduction in fracture toughness of the steel 

due to irradiation is referred to as neutron embrittlement. As the neutron fluence level 

experienced by the RPV increases over time, the RPV steel fracture toughness decreases. The 

most significant level of neutron embrittlement typically occurs around the section of the RPV 

wall that is closest to the fuel assemblies and is exposed to neutron fluence greater than 

1017 n/cm2 (E>1.0 MeV). This section of the RPV wall is referred to as the RPV beltline region. 

Reactor Vessel Neutron Embrittlement

Pursuant to 10 CFR 54.21(c)(1)(ii), the applicant has updated the analyses for the RPV neutron 

embrittlement TLAAs from the initial 40-year license to address the additional 20 years of 

operation (i.e., 60 years) of both PINGP, Units 1 and 2. 
4-7

4.2.1 Reactor Vessel Fluence 

4.2.1.1 Summary of Technical Information in the Application 

LRA Section 4.2.1 summarizes the evaluation of reactor vessel fluence for the period of 

extended operation. The applicant stated that the fast neutron exposure parameters were 

determined for PINGP using the methodologies discussed in WCAP-14040-NP-A, Revision 4, 

“Methodology Used to Develop Cold Overpressure Mitigating Systems Setpoints and RCS 

Heatup and Cooldown Limit Curves” (Reference 95). 

The applicant stated that the present fluence values are based on 54 effective full-power years 

(EFPY) of operation, incorporate the operating history of the plant, and project the 

implementation of a measurement uncertainty recapture power uprate. The 54 EFPY projection 

is expected to bound the plant operation at a capacity factor for both units of 90 percent, which 

the applicant stated is conservative based on operating history at both units. In 2006, the 

historical capacity factor for Unit 1 was 84.5 percent and for Unit 2 was 87 percent.

4.2.1.2 Staff Evaluation 

The guidance provided in Regulatory Guide (RG) 1.190 indicates that the following comprises 

an acceptable fluence calculation: 

  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 

As noted in an NRC staff safety evaluation dated February 27, 2004, (Reference 23) 

WCAP14040-A (Reference 95) acceptably addressed the analytic uncertainty analysis, 

benchmark comparisons, and extensive, generic qualification based on comparison of 

calculations with measurements obtained from a large number of surveillance capsules 

withdrawn from a variety of pressurized water reactors. 

As described in Reference 95, the PINGP fluence calculations were performed using the twodimensional discrete ordinates code, DORT (Reference 85), with the BUGLE-96 cross-section 

library (Reference 55), which was derived from the Evaluated Nuclear Data File (ENDF/B-VI) 

(Reference 84). Approximations include a P5 Legendre expansion for anisotropic scattering and 

a 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 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 in a manner consistent 

with the guidance set forth in RG 1.190. 
4-8

Reference 23 also contains an analytic uncertainty analysis that statistically combines 

uncertainties associated with individual components of benchmark transport calculations. The 

calculations were compared with the benchmark measurements from the Poolside Critical 

Assembly (PCA) simulator at the Oak Ridge National Laboratory (ORNL), and with surveillance 

capsule and reactor cavity measurements from the H.B. Robinson power reactor benchmark 

experiment. These constitute acceptable test facilities. 

Reference 95 also requires that each subsequent application of the methodology make 

comparisons with plant-specific dosimetry results to demonstrate that the plant-specific 

transport calculations are consistent with the uncertainties derived from the methods 

qualification. The fluence calculations for PINGP are supported by comparison to four dosimetry 

capsules withdrawn from each unit (Reference 54), and hence by adherence to this aspect of 

the approved WCAP-14040-A method, are acceptably qualified with plant-specific dosimetry.

The applicant’s fluence projections assume a 90 percent capacity factor at both units. Given the 

historic capacity factors listed in the application, the NRC staff agrees that the 90 percent 

capacity factor is conservative, such that 54 EFPY will bound the 20-year period of extended 

operation.

In summary, the staff finds the applicant has discussed 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 NSPM has 

followed the guidance in RG 1.190, and the neutron exposures reported in the PINGP LRA are, 

therefore, acceptable. The staff also concludes that, because the applicant has used actual past 

operating history in its fluence calculations, accounted for a power uprate, and assumed a 

reasonably conservative capacity factor, the fluence projections account adequately for the 

period of extended operation.

4.2.1.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the reactor vessel neutron fluence in LRA Appendix A4.1. On the basis of its review of the 

UFSAR supplement, the staff concludes that the summary description of the applicant’s actions 

to address the reactor vessel neutron fluence TLAA is adequate.

4.2.1.4 Conclusion 

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the reactor vessel neutron 

fluence analysis has been projected to the end of the period of extended operation. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).
4-9

4.2.2 Charpy Upper-Shelf Energy 

4.2.2.1 Summary of Technical Information in Application

Charpy V-notch tests indirectly estimate fracture toughness, and Charpy V-notch test results are 

measured in ft-lbs or joules of absorbed energy. Higher fracture toughness values directly 

correlate to greater absorbed energy to fracture during Charpy V-notch tests. Plots of

Charpy V-notch absorbed energy vs. the test temperature produce a relationship that is 

described by a hyperbolic tangent function. Plots of Charpy V-notch energy vs. temperature 

reveal three distinct energy-temperature regions; a low temperature plateau (lower-shelf region), 

a region of rapidly increasing absorbed energy with temperature (transition region), and a high 

temperature plateau (upper-shelf region). 

LRA Section 4.2.2 summarizes the evaluation of the Charpy Upper-Shelf Energy (USE) 

analyses for the period of extended operation. The applicant provided its USE assessments for 

the RPV beltline materials of PINGP, Units 1 and 2 in LRA Tables 4.2-2 and 4.2-3, respectively. 

The applicant implemented the positions of RG 1.99, Revision 2, “Radiation Embrittlement of 

Reactor Vessel Materials,” to obtain the end of license (EOL) USE values for PINGP, Units 1 

and 2. Footnotes were provided by the applicant for Tables 4.2-2 and 4.2-3 to clarify which 

RG 1.99, Rev. 2 position was used to determine the predicted percent drop in USE at EOL. 

The applicant determined that all beltline materials exhibited USE of greater than 50 ft-lb (68 

joules) through the end of the extended period of operation.

4.2.2.2 Staff Evaluation

The staff reviewed LRA Section 4.2.2 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the USE 

TLAA has been projected to the end of the period of extended operation.

Appendix G to 10 CFR Part 50 requires that RPV beltline materials have USE values in the 

transverse direction for the base metal and along the weld for the weld material of no less than 

75 ft-lb (102 joules) initially, and must maintain USE values throughout the life of the vessel of 

no less than 50 ft-lb (68 joules). However, in accordance with paragraph IV.A.1.a of 

10 CFR Part 50 Appendix G, USE values below these criteria may be acceptable if it is 

demonstrated, in a manner approved by the Director, Office of Nuclear Reactor Regulation, that 

the lower values of USE will provide margins of safety against fracture equivalent to those 

required by Appendix G of Section XI of the American Society of Mechanical Engineers Code 

(ASME Code). 

RG 1.99, Rev. 2 provides an expanded discussion regarding the calculations of USE values and 

describes two methods (positions 1.2 and 2.2) for determining USE values for RPV beltline 

materials. Position 1.2 is to be used for the calculation of USE if credible surveillance data from 

the RPV in question is not available. Position 2.2 is to be used in the calculation of USE if there 

are two or more credible surveillance data sets available for the RPV in question. Since the 

analyses performed in accordance with Appendix G to 10 CFR Part 50 are based on a flaw with

a depth equal to one-quarter of the vessel wall thickness (1/4T), the neutron fluence used in the 

USE analyses is the neutron fluence at the 1/4T depth location. 
4-10

The applicant provided its USE assessments for the RPV beltline materials of PINGP, Units 1 

and 2, in LRA Tables 4.2-2 and 4.2-3, respectively. The USE assessments were based on the 

1/4T neutron fluence values listed in LRA Tables 4.2-2 and 4.2-3. These neutron fluence values 

are based on the projected values at the end of the extended period of operation (i.e., at 54 

EFPY, where the 54 EFPY was calculated by assuming a conservative 0.9 capacity factor 

applied over 60 calendar years of operation). The applicant correctly used the guidance in 

RG 1.99, Rev. 2, positions 1.2 and 2.2 to determine the predicted percentage decrease in USE. 

The percentage decrease in USE was applied to the initial USE values listed in Tables 4.2-2 

and 4.2-3 to arrive at the predicted EOL USE values for all the beltline materials. The most 

limiting beltline material was determined to be the Circumferential Weld-Nozzle Shell Forging Bto-Intermediate Shell Forging C, for both Units 1 and 2. The applicant determined this limiting 

beltline material to have a predicted EOL USE of 59 and 57 ft-lb for PINGP, Units 1 and 2, 

respectively. The staff was unclear as to whether this particular limiting beltline identification 

referred to the circumferential weld between shell forgings B and C or the circumferential weld 

around a small line nozzle penetration in shell forging B. Therefore, the staff issued RAI 4.2.2 in 

a letter dated November 4, 2008, requesting the applicant to confirm this detail regarding the 

circumferential weld-nozzle shell forging B-to-intermediate shell forging C beltline material. The 

applicant submitted a response to RAI 4.2.2 in a letter dated November 12, 2008. Based on the 

response, the staff confirmed that circumferential weld-nozzle shell forging B-to-intermediate 

shell forging C is indeed a circumferential weld between shell forging B and shell forging C and 

that there is no small line nozzle penetration in the beltline region of the RPV.

The staff confirmed the appropriateness of the initial USE values listed in Tables 4.2-2 and 4.2-3 

by comparison to the applicant’s previous response to Generic Letter (GL) 92-01, “Reactor 

Vessel Structural Integrity, 10 CFR 50.54(f).” The staff also independently verified the reduction 

in the USE values resulting from neutron irradiation using the methodology prescribed in 

RG 1.99, Rev. 2 and finds that all the beltline materials listed in Tables 4.2-2 and 4.2-3 meet the 

EOL USE requirements of 10 CFR Part 50, Appendix G.

Based on the technical assessments stated above, the staff determined that the RPVs at 

PINGP, Units 1 and 2, will maintain an acceptable level of USE throughout the expiration of the 

period of extended operation. The staff therefore concludes that the applicant’s TLAA for USE, 

as given in Section 4.2.2 of the LRA, is in compliance with requirements of 10 CFR Part 50, 

Appendix G and, therefore, is acceptable. 

4.2.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the RPV USE in LRA Appendix A4.1. On the basis of its review of the UFSAR supplement, the 

staff concludes that the summary description of the applicant’s actions to address the RPV USE 

TLAA is adequate.

4.2.2.4 Conclusion

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the RPV USE TLAA has 

been projected to the end of the period of extended operation. The staff also concludes that the 
4-11

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.2.3 Pressurized Thermal Shock 

4.2.3.1 Summary of Technical Information in Application

The applicant performed a pressurized thermal shock (PTS) TLAA for PINGP, Units 1 and 2, 

using the criteria of 10 CFR 50.61. PTS reference temperature (RTPTS) values were calculated 

for the inside surface of the beltline region materials for both unit's RPV using Charpy-based 

evaluations in accordance with the methods of 10 CFR 50.61 for a 54 EFPY operating period. 

The fluence values at 54 EFPY for PINGP, Units 1 and 2, were obtained using the method 

described in Section 4.2.1 of the LRA. The applicant states that the methodology used to 

calculate RPV vessel fluence meets the uncertainty requirements of Regulatory Guide 1.190, 

“Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.” LRA 

Section 4.2.3 summarizes the results of this PTS TLAA for PINGP, Units 1 and 2 in Tables 4.2-4 

and 4.2-5, respectively. The RTPTS values for all the beltline materials of the PINGP, Unit 1 and 

2 RPVs, at the end of the extended period of operation (54 EFPY) were calculated by the 

applicant to be lower than the applicable screening criteria values established in 10 CFR 50.61 

and were, therefore, acceptable.

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 PTS 

TLAA has been projected to the end of the period of extended operation.

10 CFR Part 50.61 provides the fracture toughness requirements for protecting the RPV of 

pressurized water reactors against the consequences of PTS events. The rule requires each 

licensee to calculate the EOL RTPTS value for each material located within the beltline of the 

RPV. The RTPTS value for each beltline material is the sum of the unirradiated nil ductility 

reference temperature (RTNDT) value, a shift in the RTNDT value of the material caused by 

exposure to neutron irradiation (i.e., ∆ RTNDT value), and an additional margin term (M value) to 

account for uncertainties in the values of initial RTNDT, copper and nickel contents, neutron 

fluence, and calculation procedures. 10 CFR 50.61 also provides screening criteria against 

which the calculated RTPTS values are to be evaluated. RPV beltline base metal materials 

(forging or plate materials) and longitudinal (axial) weld materials are considered to be 

adequately protected against PTS events if the calculated EOL RTPTS values are less than 

270°F. RPV beltline circumferential weld materials are considered to be adequately protected 

against PTS events if the calculated EOL RTPTS values are less than 300 °F. 10 CFR 50.61 

provides a detailed quantitative discussion regarding the calculations of the shift in the RTNDT

value caused by exposure to neutron irradiation and the margin term to account for 

uncertainties. According to 10 CFR 50.61, the shift in the RTNDT value caused by exposure to 

neutron irradiation is the product of a chemistry factor (CF) and a fluence factor. The fluence 

factor is dependent upon the neutron fluence, which in the evaluation of PTS is taken as the 

EOL fluence. The CF may be determined from surveillance material or from the tables in 

10 CFR 50.61. If the RPV beltline material is not represented by surveillance material for which 

there is "credible" surveillance data (in accordance with 10 CFR 50.61(c)(2)(i), the CF and the 

shift in the RTNDT value caused by irradiation may be determined using the corresponding tables 
4-12

of 10 CFR 50.61. The CFs determined from the tables in 10 CFR 50.61 depend upon the 

amount of copper and nickel in the beltline materials. If the RPV beltline material is represented 

by surveillance material with "credible" surveillance data (in accordance with 

10 CFR 50.61(c)(2)(i)), its CF must be determined from the surveillance data using equation 5 

as described in 10 CFR 50.61. 

LRA Section 4.2.3 summarizes the results of this PTS TLAA. According to Tables 4.2-4 and 

4.2-5 of LRA Section 4.2.3, the RTPTS values for all the RPV beltline materials of PINGP, Units 1 

and 2, at the end of the extended period of operation (54 EFPY) were calculated by the 

applicant to be lower than the applicable screening criteria values established in 10 CFR 50.61. 

The limiting beltline material for PINGP, Unit 1 is the circumferential weld-nozzle shell forging Bto- intermediate shell forging C, with an EOL RTPTS of 157 oF calculated using the CF tables 

from 10 CFR 50.61. The limiting beltline material for PINGP, Unit 2 is the circumferential weldnozzle shell forging B-to-intermediate shell forging C, with an EOL RTPTS of 136 oF calculated 

using equation 5 of 10 CFR 50.61. 

The staff performed independent calculations to verify the validity of the applicant’s calculations 

of the EOL RTPTS for all beltline materials using the methodology prescribed in 10 CFR 50.61. 

During the staff’s calculation of the EOL RTPTS values, a discrepancy between the initial RTNDT

value reported in Table 4.2-5 of the LRA for PINGP, Unit 2 lower shell forging D (22642) and the 

corresponding value listed in Reactor Vessel Integrity Database (RVID) was identified. The 

initial RTNDT value reported in Table 4.2-5 of the LRA was -4 oF for PINGP, Unit 2 lower shell 

forging D (22642) and the corresponding value in RVID is listed as 2 oF . Therefore, the staff 

issued RAI 4.2.3 in a letter dated November 4, 2008, requesting the applicant to provide 

information which documents where the value of -4 oF comes from and demonstrate that it is 

applicable to this forging. In a letter to the NRC dated November 12, 2008, the applicant 

referenced documents that state -4 oF is the initial RTNDT. The applicant stated that the initial 

RTNDT (u) of -4 oF for PINGP, Unit 2 lower shell forging D (22642) is consistent with the RTNDT (u)

value used in the current "PINGP Units 1 and 2 Pressure and Temperature Limits Report,” 

Revision 3 (effective until 35 EFPY) and reported in WCAP-14637, "Prairie Island Unit 2 Heatup 

and Cooldown Limit Curves for Normal Operation,” Revision 3, December 1999 (ML023230354 

and ML003703560, respectively). 

Furthermore, the applicant stated that the initial RTNDT (u) of -4 oF for PINGP, Unit 2 lower shell 

forging D (22642) is obtained from the PINGP UFSAR, Table 4.7-9 which references, as a data 

source, Structural Integrity Report SIR-99-075, Revision 2, "Update of the Response to Generic 

Letter 92-01 Reactor Vessel Structural Integrity for Prairie Island Units 1 and 2,” November 

1999 (ML993410414). This report was previously transmitted from the applicant to the NRC via 

letter entitled "Comprehensive Revised Response to Generic Letter 92-01,” dated 

November 10, 1999 (ML993330371). The initial RTNDT (u) of -4 oF for lower shell forging D 

(22642) is documented as a change on page viii, Table 2-4 and Table 2-5 of SIR-99-075, 

Revision 2. Section 7.0 of SIR-99-075 provided a summary of the PINGP information in the 

RVID, and proposed a number of revisions to the database. Table 7-3 (page 7-4) of SIR-99-075 

proposed changes to include a correction in RTNDT (u) from 2 oF to -4 oF for lower shell forging D 

(22642). Based on the information provided by the applicant as described above, the staff finds 

the use of -4 oF applicable as the RTNDT (u) for PINGP, Unit 2 lower shell forging D (22642)

acceptable. The staff also notes that RVID should be updated to reflect the correct RTNDT (u)

value of -4 oF for PINGP, Unit 2 lower shell forging D (22642). 
4-13

The staff’s independently calculated EOL RTPTS values are in agreement with the applicant’s 

values presented in Tables 4.2-4 and 4.2-5 of LRA Section 4.2.3. The staff concurs that all RPV 

beltline materials for both PINGP, Units 1 and 2 have EOL RTPTS values that are below the 

threshold criterion specified in 10 CFR 50.61. Therefore, the staff finds the EOL RTPTS values for 

all the RPV beltline materials of PINGP, Units 1 and 2 to be acceptable.

Based on the technical assessments stated above, the staff determined that the RPVs at 

PINGP, Units 1 and 2 will maintain acceptable RTPTS values for all beltline materials throughout 

the extended period of operation. The staff therefore concludes that the applicant’s TLAA for 

RPV PTS, as given in Section 4.2.3 of the LRA is in compliance with requirements of 

10 CFR 50.61 and, therefore, is acceptable. 

4.2.3.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the RPV PTS in LRA Appendix A4.1. On the basis of its review of the UFSAR supplement, the 

staff concludes that the summary description of the applicant’s actions to address the RPV PTS 

TLAA is adequate.

4.2.3.4 Conclusion

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the RPV PTS TLAA has 

been projected to the end of the period of extended operation. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.2.4 Pressure-Temperature Limits and Low Temperature Overpressure Protection 

Analyses 

4.2.4.1 Summary of Technical Information in Application

Section 4.2.4 of the LRA addresses the Pressure-Temperature (P-T) limit curves and the Low 

Temperature Overpressure Protection System (OPPS) TLAAs. P-T limit curves are generated to 

satisfy the requirements of 10 CFR Part 50, Appendix G. 10 CFR Part 50, Appendix G requires 

RPV thermal limit analyses to determine operating P-T limits for boltup, hydrotest, pressure 

tests, and normal operating and anticipated operational occurrences. From these thermal limit 

analyses, P-T limit curves are developed for the RPV flange region and the core beltline region. 

Irradiation embrittlement effects are included in the development of the P-T limit curves. The 

effects of embrittlement on the P-T limit curves are determined using the Adjusted Reference 

Temperature (ART) of the RPV core beltline materials. The value of the ART for a particular 

material is a function of RPV 1/4T fluence, 3/4T fluence, and the beltline material chemistry and 

is calculated using the methodology of RG 1.99, Rev 2. 

The PINGP Pressure and Temperature Limit Report (PTLR), Revision 3, contains P-T limit 

curves for PINGP, Units 1 and 2. These P-T limit curves were determined following the methods 

prescribed in the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Appendix G, 1992 Edition. The applicant referenced the staff SER dated April 29, 1998, of the 
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PINGP 35 EFPY PTLR as justification for the validity of the current PINGP, Units 1 and 2, P-T 

limits. The applicant states that the P-T limit curves will continue to be updated, as required by 

10 CFR Part 50, Appendix G, or as operational needs dictate. These required updates of the 

P-T limit curves will be adequately managed for the period of extended operation by the Reactor 

Vessel Surveillance Program and this updating will assure that the operational limits remain 

valid through the period of extended operation. In addition, the applicant has estimated that 

there will be sufficient operating margin to conduct plant heatups and cooldowns at 60 years 

based on a comparison of 54 EFPY and 35 EFPY ART values for limiting RPV beltline materials 

at 1/4T below the vessel clad/base metal interface. 

Each time the P-T limit curves are revised, the OPPS limits must be re-evaluated to ensure its 

functional requirements continue to be met. The applicant has established an OPPS enable 

temperature using the NRC-approved methodology presented in Topical Report 

WCAP-14040-NP-A, Revision 2, “Methodology Used to Develop Cold Overpressure Mitigating 

System Setpoints and RCD Heatup and Cooldown Limit Curves,” with the provision permitted 

by ASME Code Case N-514. Calculation of new OPPS limits is considered part of the 

development of P-T limit curves, therefore the OPPS limits, will be adequately managed for the 

period of extended operation by the Reactor Vessel Surveillance Program. 

4.2.4.2 Staff Evaluation

The staff reviewed LRA Section 4.2.4 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis has been projected to the end of the period of extended operation.

10 CFR 50.60 provides acceptance criteria for fracture prevention measures for light water 

nuclear power reactors for normal operation by invoking the application of Appendices G and H 

of 10 CFR Part 50. Appendix G of 10 CFR Part 50 provides the P-T limit requirements and 

references ASME Code, Section XI, Appendix G as the methodology adopted to obtain 

minimum acceptable values for P-T limits. Calculated P-T limits for a given RPV must be at 

least as conservative as the limits obtained by following the methods of analysis and margins of 

safety of Appendix G of Section XI of the ASME Code. RPV P-T limits and minimum 

temperature requirements in accordance with 10 CFR Part 50, Appendix G are defined by 

operating condition, vessel pressure, presence of fuel in the vessel, and core criticality. The 

minimum temperature requirements pertain to the limiting material, which is the material in 

either the closure flange or the beltline region with the highest ART.

Calculation of ART values for the RPV beltline materials is accomplished by following the 

guidance in RG 1.99, Rev 2. The calculated ART value is the sum of the initial RTNDT, predicted 

radiation-induced Δ RTNDT, and a margin term to account for uncertainties in the values of initial 

RTNDT, copper and nickel contents, fluence, and the calculation procedures. The evaluation for 

the ART values are performed at the 1/4T and 3/4T wall locations of each beltline material using 

the neutron values at the 1/4 T and 3/4 T wall locations along respectively, with CFs determined 

from Tables 1 and 2 in RG 1.99, Revision 2. The applicant did not provide ART values for all 

beltline materials in their LRA. Therefore, the staff issued RAI 4.2.4 in a letter dated

November 4, 2008, which requested the applicant to provide ART values for all the RPV beltline 

materials for PINGP, Units 1 and 2. 
4-15

In a letter dated November 12, 2008, the applicant submitted to the NRC the ART values of all 

the beltline materials as requested in RAI 4.2.4. The ART values were calculated using the 

methodology prescribed in RG 1.99, Rev 2. These results show that the RPV limiting beltline 

material is the circumferential weld–nozzle shell forging B-to-intermediate shell forging C for 

PINGP, Unit 1 and circumferential weld–nozzle shell forging B-to-intermediate shell forging C for 

PINGP, Unit 2. The staff verified the calculated ART values submitted by the applicant and 

confirmed the appropriateness of these calculated values. The staff also compared the 

calculated 54 EFPY ART values for the above RPV limiting materials for PINGP, Unit 1 and 2, 

respectively, to the corresponding PINGP PTLR 35 EFPY ART values. Based on this 

comparison, the staff finds the applicant’s estimation that there will be sufficient margin to 

conduct plant heatups and cooldowns through the extended period of operation to be 

acceptable. In addition, the applicant states that the P-T limit curves for PINGP, Units 1 and 2 

will continue to be updated, as required by Appendix G of 10 CFR Part 50 or as operational 

needs dictate. Also, these required updates of the P-T limit curves will be adequately managed 

for the period of extended operation, by the Reactor Vessel Surveillance Program, consistent 

with 10 CFR 54.21 (c)(1)(iii). 

With each revision of the P-T limit curves, the OPPS limits must also be re-evaluated because 

calculation of new OPPS limits are considered part of the development of the P-T limit curves. 

The applicant has determined that the PINGP, Unit 1 and 2 OPPS enable temperatures used 

using the NRC-approved methodology presented in Topical Report WCAP-14040-NP-A, Rev. 2 

with the provision permitted by ASME Code Case N-514. ASME Code Case N-514 allows for 

the OPPS system to limit the maximum pressure in the RPV to 110 percent of the pressure as 

determined from the P-T limit curve using the methodology described in ASME Code, Section 

XI, Appendix G. The applicant stated that the OPPS limits will be concurrently updated with the 

P-T limits update for PINGP, Units 1 and 2. In addition, the OPPS limits will be managed by the 

Reactor Vessel Surveillance Program for the extended period of operation. The staff finds the 

applicant’s analysis and management of OPPS limits through the period of extended operation

using the staff-approved methodology in WCAP-14040-NP-A, Rev. 2 to be acceptable and 

consistent with the requirements of 10 CFR 54.21(c)(1)(iii). 

4.2.4.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the RPV P-T limits and OPPS limits in LRA Appendix A4.1. On the basis of its review of the 

UFSAR supplement, the staff concludes that the summary description of the applicant’s actions 

to address the RPV P-T limits and OPPS limits TLAA is adequate.

4.2.4.4 Conclusion

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the RPV P-T limits and 

OPPS limits TLAA will be adequately managed through the end of the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).
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4.3 

The staff notes that fatigue may cause a metal component that is subjected to cyclic loads to fail 

at load levels lower than its design load carrying capacity. Fatigue failure involves crack 

initiation and propagation. The fatigue life of a structural component depends on the material 

used for the structure, the environment to which the structural component is exposed, the 

number of applied loads occurrences, and magnitude of the applied fluctuating loads. 

Metal Fatigue 

Fatigue analyses are TLAAs if they meet all six elements of the definition in 10 CFR 54.3(a). If 

the analyses are based on a number of cycles estimated for the current license term, they may 

be considered to meet criterion 54.3(a)(3) of being based on the current operating term. The 

staff evaluates the TLAA, per 10 CFR 54.21(c)(1), to determine whether:

• The analyses remain valid for the period of extended operation;

• The analyses have been projected to the end of the period of extend operation; or

• The effects of aging on the intended function(s) will be adequately managed for the 

period of extended operation.

LRA Section 4.3 states that PINGP Class 1 and non-Class 1 components that are potentially 

susceptible to fatigue damage have been reviewed for TLAAs and evaluated where applicable. 

The applicant indicates that the PINGP Class 1 boundary includes the components within the 

ASME Code Section XI, Subsection IWB inspection boundary as well as the steam generator 

items designed to ASME Code Section III, Class A or Class 1. The LRA also states that the 

design transients and fatigue analysis results were reviewed to assess the impact of the 

measurement uncertainty recapture power uprate (MUR-PU) project, which has been planned, 

and concluded that impact due to the MUR-PU would be negligible.

The applicant states that when a flaw is detected during inservice inspections, either the flaw 

must be repaired or the component that contains the flaw can be evaluated for continued 

service in accordance with ASME Code Section XI. The applicant further states that the fracture 

mechanics analyses of the detected flaws may be TLAAs if the analyses are based on timelimited assumptions defined by the current operating term.

4.3.1 Class 1 Fatigue 

LRA Section 4.3.1 indicates that the PINGP Class 1 boundary includes components within the 

ASME Code Section XI, Subsection IWB inspection boundary and the steam generator items. 

Specifically, these include the reactor vessels, control rod drive mechanism housings, 

pressurizers, and steam generators. The applicant indicates that the Class 1 non-piping 

components are designed in accordance with ASME Code Section III, whereas the Class 1 

piping components are designed based on American Standards Association (ASA) B31.1 for 

Unit 1 and United States of America Standards (USAS) B31.1.0 for Unit 2 in the original design. 

However, the LRA states that subassemblies of pipes were later replaced and redesigned to 

ASME III Subsection NC because their nominal pipe size (NPS) is less than one inch. 

LRA Section 4.3.1 consists of seven subsections, six of which are organized according to the 

type and functionality of the structural components and the seventh is used for discussing the 
4-17

design transients and 60-year cycle projections. This section does not consider the effects of 

the reactor water environment, which are addressed in Section 4.3.3.

4.3.1.1 Transient Cycles

4.3.1.1.1 Summary of Technical Information in the Application

Portions of LRA Section 4.3.1 (first four pages of LRA Section 4.3.1) discusses the transients 

that were used for the design analyses. The applicant indicates that the PINGP Metal Fatigue of 

Reactor Coolant Pressure Boundary Program monitors and tracks the transients during the 

plant operation, performs analysis, and tracks the cycles accrued for each transient type. The 

applicant indicates that PINGP documents the results of the transient monitoring for both units. 

LRA Table 4.3-1 shows the cycles accrued through September 30, 2006. LRA Table 4.3-1

indicates that by September 30, 2006, Unit 1 logged 33 years of operation and Unit 2 logged 32 

years. LRA Table 4.3-1 shows that for each transient type, the larger of the cycles accrued from 

the two units and the reported cycles are conservatively credited for 30 years of operation 

instead of 32. Therefore, for each transient, the projected 60-year cycles are exactly two times 

the cycles under the column labeled “Actual Number of Occurrences through 9/30/2006 

(Maximum of Units 1 or 2)” of LRA Table 4.3-1.

The applicant argues that the cycle projection method used is valid because the monitoring 

logging record indicates a higher frequency of occurrence for the first 10 to 15 years of 

operation than for the most recent 10 to 15 years, and because PINGP has aging management 

programs (AMPs) which will ensure that both plants operate at the transient rates experienced 

over the most recent 10-15 years of operation. 

Based on the results shown in LRA Table 4.3-1, the applicant concludes that the original 

number of design transient cycles will remain valid through the period of the extended operation 

in accordance with 10 CFR 54.21(c)(1)(i). The applicant also states that the PINGP Metal 

Fatigue of Reactor Coolant Pressure Boundary Program will continue to assure that the 

accumulated numbers and severity of transients experienced by PINGP remain within design 

limits in accordance 10 CFR 54.21(c)(1)(iii). 

4.3.1.1.2 Staff Evaluation

The staff reviewed the first four pages of LRA Section 4.3.1 to verify that the original 40-year 

design transient cycles will remain valid for the period of extended operation.

The staff reviewed the transients shown in LRA Table 4.3-1 and verified that they are the same 

as those shown in the PINGP UFSAR Table 4.1-8. During the audit, the staff reviewed the 

transient cycle monitoring records and confirmed that the monitoring procedures were 

appropriate. The staff determined that the applicant took a conservative approach by crediting 

only 30 years of operation for the records instead of the 32 years that were actually covered. 

Therefore, the staff found the applicant’s conclusion that the original number of design transient 

cycles will remain valid through the period of extended operation acceptable. The staff also 

reviewed Metal Fatigue of Reactor Coolant Pressure Boundary Program, which is used to 

monitor and track the transients. 
4-18

The staff notes that Metal Fatigue of Reactor Coolant Pressure Boundary Program has two 

objectives: (1) to characterize and validate the thermal events captured; and (2) to log and count 

the occurrences (cycles) for each well-defined thermal event. While the applicant has achieved 

the second objective and used it to demonstrate that the projected 60-year cycles would remain 

bounded within the design transient cycles, the first objective has not been discussed. With this 

concern, the staff issued RAI 4.3.1-1, in a letter dated February 20, 2009. The staff asked the 

applicant to: 

 (A) Describe the procedures that PINGP has been using for tracking thermal 

activities so the staff can confirm that the PINGP aging management program will 

ensure that P-T characteristics, including their values, ranges, and rates remain 

bounded within the range defined in the design specifications during the renewed 

license term. 

 (B) Provide a histogram (cycle accumulating charts) of heatup transient tracking 

history, and a histogram for the cooldown transient as well.

In its response to RAI 4.3.1-1, dated February 26, 2009, the applicant states that the number of 

occurrences of design cycles is tracked by the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program as described in Section B3.2 of the PINGP LRA and that PINGP Technical 

Specifications Section 5.5.5 contains the requirement to track the transient cycles to ensure that 

components are maintained within the design limits. 

The applicant states that this requirement is implemented by a PINGP surveillance procedure, 

which requires that applicable thermal and pressure transients records be kept and these 

records are maintained as on-going transient summary sheets contained in the procedure itself.

The applicant also states that the PINGP surveillance procedure lists the UFSAR Section 4.1.4 

design pressure and temperature transients, and contains a summary sheet for each design

transient that lists every cycle counted for that transient. The applicant further states that at least 

once each quarter, the program owner conducts a review of plant operating records to 

determine if an “operating cycle” has occurred for any of the design pressure or temperature 

transients. If a cycle has occurred, the program owner adds the event to the proper cycle 

summary sheet along with a brief description of the transient cycle. 

The applicant states that the majority of transient cycles logged to date have been associated 

with heatup, cooldown and reactor trip events. The applicant also states that review of the past 

plant data revealed that the average plant heatup temperature rate and the average plant 

cooldown temperature rate were approximately 40 o

F/hr and 70 oF/hr, respectively. Therefore, 

the applicant indicates that the heatup/cooldown temperature rates experienced by the PINGP 

components are bounded by the temperature rates indicated in the design specifications, 100 

o

F/hr. 

As for the reactor trip events, the applicant states that approximately 65% of the reported 

reactor trip events in both units have occurred from an initial power level between 75% and 

100% power. The remaining 35% of reactor trip events occurred from an initial power level 

lower than 75% of full power. For design purposes, the reactor trip transient is based on a trip 

from 100% power conditions. Therefore, the applicant states that the actual plant reactor trip 

events are bounded by the design transient.
4-19

The applicant further states that if a design limit for the number or severity of a transient were 

exceeded (e.g., RCS temperature change exceeds 100 o

F/hr during heatup or cooldown), a 

Corrective Action Program (CAP) entry would be initiated, and the procedure requires that an 

analysis be performed to determine the effect on system components. The applicant indicates 

that the CAP would determine appropriate actions, potentially including reanalysis, repair, or 

replacement of the affected components, and assessment of additional pressure boundary 

locations that may be affected.

The applicant also states that since the surveillance procedure does not explicitly state that 

action should be initiated before a design limit is exceeded (see LRA Section B3.2 under the 

enhancement provision), the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

acceptance criteria will be revised to clarify that corrective action is to be taken before any 

monitored location exceeds either a cumulative fatigue usage factor of 1.0 or a design basis 

transient cycle limit.

Based on its review, the staff finds the applicant’s response to Part (a) of RAI 4.3.1-1 acceptable 

for the following reasons:

 (1) PINGP has developed the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program (as described in Section B3.2 of the LRA) to track the number of occurrences 

of design cycles.

 (2) PINGP has developed Technical Specifications and a surveillance procedure to ensure 

that components are maintained within the design limits.

 (3) PINGP has acquired records of major thermal events such as heatup, cooldown and 

reactor trip transients confirming that the P-T values experienced by the PINGP 

structural components are bounded by those of the design transients.

 (4) PINGP has developed a CAP which initiates and determines appropriate actions to be 

taken if abnormal situations should occur. 

 (5) The operational procedures that PINGP adopts for the transient events tracking are 

consistent with the GALL Report and conservative to ensure a valid cycle-based fatigue 

management program. 

Therefore, the staff’s concern described in Part (a) of RAI 4.3.1-1 is resolved. Part (b) of RAI 

4.3.1-1 requested the applicant to provide the histograms of the PINGP heatup and cooldown 

transients. The applicant provided the histograms for these two transients, as shown in the 

following pages. 

The staff reviewed these histograms and found that the transient occurrence rates (both heatup 

and cooldown) are quite constant for Unit 1 since 1980 and for Unit 2 since 1983. This means 

that for the past 25 years, the PINGP (Units 1 and 2) plant operation has been quite steady. 

The applicant made its cycle projections by doubling the actual number of cycles accrued as of 

September 30, 2006, using the maximum from either unit. The staff notes that cycle projection 

can be graphically represented, based on Figure 4.3-1 by drawing a straight line from the 

intersection of the x and y axes to the 2003 data point, boosted to the cycle value accrued by 

September 30, 2006, using the maximum from either unit. It is clear from Figures 4.3-1 and 
4-20

4.3-2, that the slope used by the applicant for making cycle projections is significantly greater 

than that of the average of the past 25 years. As expected, the slopes of event occurrence (i.e., 

the rates) during the first few years (5 to 7 years) are higher than the averages for both heatups 

and cooldowns. This means that the basis of projections that the applicant used is conservative 

and therefore, the staff found it to be acceptable.

Based on its review, the staff’s concern on the transient event monitoring is resolved because 

the applicant provided the information requested and the information validates the PINGP 

fatigue management program and the applicant's assumption for the number and severity of 

transients. 
4-21

Figure 4.3-1

Figure 4.3-2
4-22

4.3.1.1.3 UFSAR Supplement

LRA Section A4.2 summarizes the design transients data and 60-year transient cycle 

projections. On the basis of the review of the UFSAR supplement, the staff concludes that the 

summary description of the applicant’s actions to address fatigue analyses for Class 1 

components is adequate.

4.3.1.1.4 Conclusion

Based on its review of the LRA, the staff concluded that the applicant has demonstrated that the 

original design cycles remain bounding. 

The staff concludes that the UFSAR supplement contains an appropriate summary description 

of the activities for managing the effects of aging and the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program and TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.1.2 Reactor Pressure Vessel and CRDM Housings

4.3.1.2.1 Summary of Technical Information in the Application

LRA Section 4.3.1.1 discusses the fatigue evaluation for the Reactor Pressure Vessel (RPV)

and control rod drive mechanism (CRDM) housing of Units 1 and 2. The applicant indicates that 

the fatigue usage calculations supporting the original license were based on ASME Boiler and 

Pressure Vessel Code, Section III, 1968 edition. The applicant also indicates that the PINGP 

RPV heads, including the CRDMs, at Units 1 and 2 were replaced in 2006 and 2005, 

respectively, and the new RPV heads were re-evaluated based on the ASME Code Section III, 

NB-3200 guidelines, 1998 Edition. The applicant reports the CUF values at the limiting locations 

of the RPV and CRDM housings in LRA Tables 4.3-2 and 4.3-3, respectively.

The applicant indicates that these usage factor calculations are considered TLAAs because 

they are based on the design transients intended to represent 40 years of operation. The 

applicant also indicates that since the number of design transients cycles used in this fatigue 

analysis will not be exceeded in 60 years of operation, this TLAA will remain valid through the 

period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). The applicant also 

indicates that the cumulative numbers of design transients experienced by the CRDM housings 

will continue to be managed by the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analysis remains valid for the period of extended operation.

Based on its review, the staff found the applicant’s disposition of the RPV and CRDM housing 

TLAAs, pursuant to 10 CFR 54.21(c)(1)(i), is acceptable because the projected 60-year cycles 

are less than the 40-year design cycles, which were used in the plant design. 
4-23

It should be noted that, the applicant’s claim and conclusion shown herein do not reflect 

environmental effects on fatigue. NUREG/CR-6260 evaluated certain components of different 

vintage reactor designs for their fatigue effects due to reactor water environment. According to 

NUREG/CR-6260, the corresponding components for PINGP (being an older vintage 

Westinghouse plant) are the reactor vessel inlet and outlet nozzles, and the RV Lower Head to 

Shell locations (three components), which are covered in LRA 4.3.1.1. The staff notes that 

environmental effects on fatigue for these three components and the remainder of the 

NUREG/CR-6260 applicable to PINGP are evaluated in LRA Section 4.3.3.

During the audit, the staff noticed that there are many places in the PINGP license renewal 

aging management program basis document that indicate that the applicant has used 

FatiguePro to perform stress-based fatigue monitoring. The phrase “stress-based fatigue 

monitoring” also appears multiple times in the LRA. The staff notes that FatiguePro is not 

endorsed by NRC staff, since it does not produce all six individual components of a transient 

stress tensor (Sxx, Syy, Szz, Sxy, Syz, Szx) needed to support the ASME Code Section III 

fatigue analysis method. FatiguePro produces only one stress component and uses that single 

stress component to perform fatigue evaluations. 

Therefore, the staff issued RAI 4.3.1.1-1 in a letter dated December 10, 2008. The staff 

requested the applicant to identify any items, from LRA Tables 4.3-2 through 4.3-8, whose CUF 

values were calculated without using all six components of the transient stress tensors and reevaluate those components using all six individual stress components in accordance with the 

ASME Code Section III guidelines. This is so that the fatigue results are valid and applicable to 

the period of extended operation. 

In its response to RAI 4.3.1.1-1, dated January 9, 2009, the applicant states that the CUFs 

reported in LRA Tables 4.3-2 through 4.3-7 are all calculated in accordance with ASME Code 

Section III using the values of six stress components versus time for the complete stress cycle, 

taking into account both the gross and local structural discontinuities, as well as the thermal 

effects which vary during the cycle.

The applicant states that the calculations of Environmentally-Assisted Fatigue in Table 4.3-8 are 

based on ASME Code Section III CUFs with the exception of the pressurizer surge line hot leg 

nozzle safe end and the charging system nozzle for both units. The applicant also states that 

the unadjusted CUFs at both of these locations are based on FatiguePro stress-based fatigue 

analyses and that NSPM is in the process of performing ASME Code (Subsection NB) 

compliant fatigue calculations for the pressurizer surge line hot leg nozzle and the charging 

nozzle and will report the revised CUFs and CUFs adjusted for environmental effects at these 

locations as an amendment to the PINGP LRA. The applicant further states that amendment will 

also include changes to LRA Section 4.3.3, “PINGP EAF Results,” that reflect analysis results 

and remove references to stress-based fatigue monitoring. 

The applicant also provided its commitment to evaluate the effects of insurge/outsurge 

transients on the lower head of the pressurizer and to eliminate references to stress-based 

fatigue monitoring by making changes to the LRA. In addition, the applicant also included the 

following change to the LRA: 
4-24

In LRA Section 4.3.1.3, the last paragraph on Page 4.3-10 and the first 

paragraph on Page 4.3-11 are deleted and replaced in their entirety with the 

following:

NSPM will perform an ASME Code Section III fatigue evaluation of the lower 

head of the pressurizer to account for effects of insurge/outsurge transients. The 

evaluation will determine the cumulative fatigue usage of limiting pressurizer 

component(s) through the period of extended operation. The analyses will 

account for periods of both “Water Solid” and “Standard Steam Bubble” operating 

strategies. Analysis results will be incorporated, as applicable, into the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program. This analysis and any 

associated program enhancements will be completed prior to the period of 

extended operation. The Metal Fatigue of Reactor Coolant Pressure Boundary 

Program will manage metal fatigue of the pressurizer due to insurge/outsurge 

transients in accordance with 10 CFR 54.21(c)(1)(iii).

The following additional LRA changes are also being made to eliminate 

references to stress-based fatigue monitoring: 

In LRA Section A3.2, on Page A-17, the third sentence of the first paragraph is 

deleted and replaced in its entirety with the following: "The program also tracks 

fatigue usage in critical high-usage components."

In LRA Section B3.2, Program Description, on page B-84, the third sentence of the first 

paragraph is deleted and replaced in its entirety with the following: "The program also tracks 

fatigue usage in critical high-usage components."

In LRA Section B3.2, Enhancements, on page B-85, the first bulleted enhancement is deleted 

and replaced in its entirety with the following: 

Scope of Program, Preventive Actions, Parameters Monitored/Inspected, 

Detection of Aging Effects, Monitoring and Trending

The program will monitor the six component locations identified in NUREG/CR-6260 for older 

vintage Westinghouse plants, either by tracking the cumulative number of imposed stress cycles 

using cycle counting, or by tracking the cumulative fatigue usage, including the effects of 

coolant environment. The following locations will be monitored:

NUREG/CR-6260 Location

RPV Inlet and Outlet Nozzles

RPV Shell to Lower Head

RCS Hot Leg Surge Line Nozzle

RCS Cold Leg Charging Nozzle

RCS Cold Leg Safety Injection Accumulator Nozzle

RHR-to-Accumulator Piping Tee
4-25

In addition, the applicant provided its updated Commitment No. 33 and 35 to reflect the changes 

described above for this program. 

The staff reviewed the response provided by the applicant, and found it acceptable. This is 

because the applicant has confirmed that the CUF values in the LRA are all calculated in 

accordance with ASME Code Section III using the values of six stress components except for 

those of the surge line hot leg nozzle safe end and the charging nozzles. For these two 

locations, the applicant indicates that new analyses in accordance with ASME NB procedures 

are in the process and the new results will be reported as an amendment to the PINGP LRA. As 

a result of this RAI, the applicant added Commitment No. 36 to its License Renewal 

Commitment List. The staff notes that the corrective actions taken by the applicant in response 

to this RAI are consistent with the aging management program requirements described in the 

GALL Report. Therefore, the staff's concern in RAI 4.3.1.1-1 is resolved. 

The staff reviewed Commitment No. 36, and updated Commitment Nos. 33 and 35 as described 

below. The LRA states that upon the staff review and approval, the final commitments will be 

incorporated into the UFSAR.

The staff noted that pursuant to Commitment No. 36, (1) PINGP will re-evaluate fatigue usage 

using the well-established ASME III NB guidelines for the pressurizer surge line hot leg nozzle 

and the charging nozzle which were previously evaluated using the simplified method in 

FatiguePro; and (2) PINGP will remove any reference to “stress-based fatigue monitoring.” The 

staff found the commitment acceptable because this commitment will ensure that all PINGP 

fatigue analyses will use six stress components and therefore consistent with ASME Code 

Section III. This commitment was completed and provided to the staff by letter dated April 28, 

2009. The staff's review of the applicant's April 28, 2009 submission is discussed in Section 

4.3.3.1 and 4.3.3.2.

The staff reviewed the updated Commitment No. 33 and found it acceptable because, pursuant 

to the SRP-LR and GALL Reports, it commits to address the effects of the coolant environment 

on component fatigue life for the six NUREG/CR-6260 locations (or components) applicable to 

PINGP. License Renewal Commitment No. 33 also includes a provision stating that corrective 

action will be taken before a cumulative fatigue usage factor exceeds 1.0 or a design basis 

transient cycle limit is exceeded. Based on its review, the staff found Commitment No. 33 

acceptable because it is consistent with the SRP-LR, the GALL Reports and 10 CFR 50 

Appendix B. License Renewal Commitment 33 also implements the well-established ASME 

Code III NB-3200 method to perform fatigue evaluation in lieu of the simplified method indicated 

in the original version of the commitment. Therefore, Commitment No. 33 is acceptable.

The staff reviewed the updated Commitment No. 35 and found it acceptable because it is a 

direct response to a Westinghouse Owner’s Group Program discussed in WCAP-14574-A,

which deals with aging management for pressurizers. Commitment No. 35 also implements the 

well-established ASME Code III NB-3200 method to perform fatigue evaluation in lieu of the 

simplified method indicated in the original version of the commitment. Therefore, Commitment 

No. 35 is acceptable. 
4-26

4.3.1.2.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles and 60-year cycle projections, and concluded that the CUF for the Class 1 components 

based on those transients will remain valid for the period of the extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for Class 1 components is 

adequate.

4.3.1.2.4 Conclusion

Based on its LRA review, the staff found that the applicant has demonstrated that the TLAA for 

the Reactor Vessels and the CRDM Housing locations will remain valid for the period of 

extended operation in accordance with 10 CFR 54.21(c)(1)(i). The applicant also indicates that 

the cumulative numbers of design transients experienced by the reactor vessels and the CRDM 

housings will continue to be managed by the Metal Fatigue of Reactor Coolant Pressure 

Boundary Program in accordance with 10 CFR 54.21(c)(1)(iii). This is acceptable because it 

provides additional assurance. The staff also concludes that the UFSAR supplement contains 

an appropriate summary description of the activities for managing the effects of aging and the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program and TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.1.3 Reactor Vessel Internals 

4.3.1.3.1 Summary of Technical Information in the Application

LRA Subsection 4.3.1.2 discusses the fatigue evaluation for the RV internal components. The 

applicant notes that the PINGP reactor vessel internals were designed prior to incorporation of 

design codes for RV internals into ASME Code Section III. As such, the applicant indicates that 

a plant-specific stress report for the RV internals was not required. The applicant also indicates 

that the upper internals of both Units 1 and 2 were replaced in the mid-1980s due to concerns of 

aging on split pins and the replacement upper internals were evaluated and constructed in 

accordance with ASME Code Section III, Subsection NG, 1974 Edition through summer 1976 

Addenda. The applicant reports the CUF values at selected locations of the replacement RV 

upper internals in LRA Table 4.3-4.

The applicant notes that the fatigue analysis for the PINGP RV lower internals was not included 

in the CLB and new fatigue evaluations for the RV lower internals were performed based on the 

design transients shown in LRA Table 4.3-1. The applicant indicates that the CUF values are 

acceptable for all locations considered in the RV lower internals fatigue evaluations except for 

the baffle bolts. For the RV lower internal baffle bolts to meet the fatigue requirements during 

the period of the extended operation, the applicant reduced the cycles of the plant loading and 

unloading (at 5 percent of full power per minute) transients for its TLAA fatigue evaluation from 

the original design cycles of 18,300 to a new value of 1835. As such, the applicant claims that 

the TLAA for the baffle bolts satisfy the fatigue requirements during the period of the extended 

operation, pursuant to 10 CFR 54.21(c)(1)(ii).
4-27

The applicant also documents the cycle adjustment for the plant loading and unloading (at 

5 percent of full power per minute) transients in LRA Section B3.2, and Commitment No. 34, 

states that the PINGP Metal Fatigue of Reactor Coolant Pressure Boundary Program and 

UFSAR Table 4.1-8 will be enhanced to include this additional cyclic limit for baffle bolt fatigue. 

The applicant closes this subsection of the LRA with a note stating that the TLAA for the 

remaining reactor vessel upper and lower internals items continue to be based on the same 

transients as the reactor vessel, and concludes that the TLAA for these parts/locations is valid 

for the period of the extended operation per 10 CFR 54.21(c)(1)(i). The applicant also indicates 

that the cycles of the applicable design transients experienced by the reactor vessel internals, 

including the baffle bolts, will continue to be managed by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.2, pursuant to 10 CFR 54.21(c)(1)(i) and 10 CFR 

54.21(c)(1)(ii), to verify that the analysis remains valid for the period of the extended operation

or has been projected to the end of the period of extended operation.

The staff found that the applicant’s conclusion that the fatigue requirements for the RV upper 

internals are satisfied in accordance with 10 CFR 54.21(c)(1)(i) is acceptable because the 

design CUF values are all less than 1.0 and the 60-year projected transient cycles are bounded 

within the design transient cycles. 

For the RV lower internals, the applicant performed new fatigue evaluations because PINGP did 

not perform fatigue evaluations in the plant design phase. The applicant obtained acceptable 

fatigue results for all lower RV internal locations except the baffle bolts. By reducing the cycles 

of the plant loading and unloading (at 5 percent of full power per minute) transients from 18,300 

to 1,835, the applicant stated that the baffle bolts will meet the fatigue requirements during the 

period of extended operation. All design transients that are in LRA Table 4.3-1 were used for the 

analysis.

The staff found the approach that the applicant used to reach the goal of meeting the fatigue 

requirement for the lower RV internal baffle bolts acceptable because the 60-year cycles 

projected for the plant loading and unloading (at 5 percent of full power per minute) transients, 

970, is far less than the new limit that the applicant established, 1,835 cycles. In addition, 

consistent with the GALL Report, the applicant has committed (Commitment No. 34) to enhance 

the PINGP Metal Fatigue of Reactor Coolant Pressure Boundary Program to include this 

additional cyclic limit, 1835, for baffle bolt fatigue. Based on these considerations, the staff finds 

that the applicant’s disposition of the TLAA for the RV internal baffle bolts to 

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

The staff reviewed License Renewal Commitment No. 34 and found it acceptable because of 

the following reasons:

It clearly states that the new cycle limit, 1835, is for both the plant loading at 5 percent of full 

power per minute and the plant unloading at 5 percent of full power per minute transients and is 

applicable to the lower RV Internal baffle bolts only. 
4-28

The new cycle limit mentioned above will be incorporated into the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program and UFSAR Table 4.1-8. 

Resetting the cycle limit for the plant loading and plant unloading (at 5 percent of full power per 

minute) transients is a necessary adjustment to allow the lower RV internal baffle bolts to meet

the fatigue requirements. The new cycle limit, 1835, still bounds the 60-year projected cycles 

(970) for this particular pair of transients, with sufficient margin.

4.3.1.3.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles and 60-year projections, and stated that the CUF for the Class 1 components based on 

those transients will remain valid for the period of extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for Class 1 components is 

adequate.

4.3.1.3.4 Conclusion

Based on its review of LRA Section 4.3.1.2, the staff found the applicant’s claim that the TLAA 

for all parts of the RV internals except for the baffle bolts satisfy 10 CFR 54.21(c)(1)(i). For the 

RV internals baffle bolts, the TLAA satisfies 10 CFR 54.21(c)(1)(ii) by reducing design cycle limit 

to 1,835 cycles for the plant loading and unloading (at 5 percent of full power per minute) 

transients. The applicant indicates that the cycles of the applicable design transients 

experienced by the reactor vessel internals, including the baffle bolts, will continue to be 

managed by the Metal Fatigue of Reactor Coolant Pressure Boundary Program in accordance 

with 10 CFR 54.21(c)(1)(iii). This is acceptable since it provides additional assurance. The staff 

also concludes that the UFSAR supplement contains an appropriate summary description of the 

activities for managing the effects of aging and the TLAA evaluation, as required by 

10 CFR 54.21(d).

4.3.1.4 Pressurizers

4.3.1.4.1 Summary of Technical Information in the Application

The applicant presents the results of the fatigue usage analysis of the pressurizers in LRA Table 

4.3-5, in LRA Section 4.3.1.3. The applicant notes that the fatigue analyses for Units 1 and 2 

were performed in accordance with the requirements of the ASME Boiler and Pressure Vessel 

Code, Section III, 1965 Edition and addenda including Summer of 1966 for Unit 1 and 

Winter 1966 for Unit 2, respectively. The applicant also notes that both pressurizers are 

cylindrical vessels with cast upper and lower heads. 

The applicant states that these usage factor calculations are considered TLAAs because they 

are based on design transients intended to represent 40 years of operation. The applicant 

concludes that these TLAAs will remain valid through the period of the extended operation in 

accordance with 10 CFR 54.21(c)(1)(i) because, Table LRA 4.3-1 indicates the cycles projected 

to occur for 60 years are bounded by those used in the original design analyses. 
4-29

The applicant notes that the CUF results shown in Table 4.3-5 do not include the effects of 

insurge/outsurge and thermal stratification. The staff notes that these thermal events are 

associated with PWR pressurizers, but were not known to the nuclear industry until NRC issued 

Bulletins 88-08 and 88-11 in 1988. 

The applicant indicates that license renewal applicants are expected to demonstrate that 

pressurizer components have been analyzed for cumulative fatigue usage through the period of 

extended operation, and that the analyses include insurge/outsurge and other transient loads 

not considered in the current licensing basis. 

The applicant notes that the current plant operating practices mitigate insurge/outsurge effects 

in the pressurizer through continuous spray during heatup and cooldown transients. The 

applicant notes that this method maintains a small flow from the pressurizer to the hot leg during 

these transients, thus resulting in a uniform fluid temperature below the pressurizer heaters and 

in the upper portion of the surge line that prevent thermal stratification. The applicant further 

notes that, plant heatup and cooldown procedures have adopted, in 1991, the Westinghouse 

Modified Operating Procedure (MOP). This procedure uses the "Water Solid" method for 

heatups and cooldowns to reduce the magnitude of resulting insurge/outsurge temperature 

transients at the pressurizer. The applicant also notes that prior to 1991, heatups and 

cooldowns used the "Standard Steam Bubble" method, which have resulted in larger 

temperature transients and higher fatigue usage.

4.3.1.4.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.3, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that metal 

fatigue in the pressurizer lower head region will be adequately managed during the period of

extended operation. The staff reviewed LRA Section 4.3.1.3, pursuant to 10 CFR 54.21(c)(1)(i), 

to verify that metal fatigue in the region above the pressurizer lower head will be adequately 

managed during the period of extended operation.

The applicant lists the CUF values of the PINGP Units 1 and 2 pressurizers in LRA Table 4.3-5 

and claims that the fatigue requirements for these components will be satisfied during the period 

of the extended operation pursuant to 10 CFR 54.21(c)(1)(i). The applicant determined this

because according to LRA Table 4.3-1, the projected 60-year transient cycles are bounded by 

the cycles used in the original design calculations. The staff found this claim to be premature 

because, per Note 1 associated with LRA Table 4.3-5, neither the effects of LWR environment 

nor the effects of insurge/outsurge and thermal stratification have been included in the CUF 

results shown in LRA Table 4.3-5. Therefore, the LRA Table 4.3-5 CUF values for the 

pressurizer lower head and surge nozzle region do not remain valid for the period of extended 

operation. Analysis of the surge line piping is discussed in LRA Section 4.3.1.6 and SER 

4.3.1.7.

LRA Section 4.3.1.3 describes common practices that the current operating plants used to 

mitigate the effects of the insurge/outsurge transients on the pressurizer and the surge line. 

Although pressurizer is identified in NUREG/CR-6260 as one of the sample components 

considered for reactor water environment effects on fatigue life, evaluation of the 

environmentally-assisted fatigue is separately reported in LRA Section 4.3.3. 
4-30

The staff notes that since thermal events on the pressurizer and the surge line were unknown to 

the nuclear industry until issuance of NRC Bulletins 88-08 and 88-11, the likelihood that 

associated data be available to support fatigue evaluations on stratification and 

insurge/outsurge events prior to the Bulletin 88-08 issuance seems quite low. Therefore, the 

staff issued RAI 4.3.1.3-1 in a letter dated December 10, 2008. The staff asked the applicant 

how did it reconstruct the cycles that occurred before the date of issuance of Bulletin 88-11 to 

support its TLAA calculations, and to provide the dates when events tracking began.

In its response to RAI 4.3.1.3-1, dated January 9, 2009, the applicant states that the dominant 

event cycles that contribute to fatigue in the surge line analyses are the heatups and cooldowns 

that include stratification and striping in the pressurizer surge line. The applicant also states that 

surge line temperature transients during heatup and cooldown are characterized in 

WCAP-12839 and WCAP-12639 by maximum system differential temperatures between the 

pressurizer water and RCS hot leg that occur over five RCS temperature ranges. The applicant 

states that the system differential temperature ranges were used to define the stratification and 

the insurge/outsurge events for the purpose of the analyses. 

The applicant states that the PINGP Pressurizer-water-to-RCS-hot-leg differential temperature 

data were recorded since the initial plant operation (1973 for Unit 1, and 1974 for Unit 2). The 

applicant also states that upon completion of the pressurizer surge line thermal stratification 

analyses in the early 1990s, PINGP continued to monitor temperature differentials between the 

pressurizer water and RCS hot leg as required by the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program to ensure that plant operation is within the bounds of the 

pressurizer surge line transient definitions contained in WCAP-12839 and WCAP-12639. 

In the RAI response, the applicant also indicates the number of plant heatups and cooldowns 

are limited to 200 by design and the 60-year projection is approximately 125 cycles, as shown in 

LRA Table 4.3-1.

The staff summarizes its review of the applicant’s response to RAI 4.3.1.3-1, as follows:

 • The surge line stratification and the insurge/outsurge events are predominated by the 

plant heatups and cooldowns.

 • The surge line stratification and the insurge/outsurge events are defined by the system 

differential temperature ranges.

 • The surge line temperature transients during heatup and cooldown are characterized in 

WCAP-12839 and WCAP-12639 by the maximum system differential temperatures 

between the pressurizer water and the RCS hot leg that occur over five RCS 

temperature ranges.

 • PINGP has conducted transient monitoring and collecting the pressurizer-water-to-RCShot-leg differential temperature data since initial plant startup (1973 for Unit 1, and 1974 

for Unit 2). 

 • PINGP has the monitored plant data in its possession to support evaluation of the 

stratification and insurge/outsurge effects – no backward projection is necessary. 
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On the basis of its review described above, the staff’s concern about the possibility of lack of 

data to support the fatigue evaluation involving stratification and insurge/outsurge thermal 

events in the pressurizers, surge lines, and surge line nozzles was resolved based on the 

following reasons:

 • The applicant has collected the necessary plant data, in the form of Pressurizer-waterto-RCS-hot-leg temperature differentials, ever since the plant’s startup. 

 • With the monitored data of temperature differentials, stresses and the stress variations 

during the insurge/outsurge thermal events can be calculated to support fatigue 

assessment. 

 • Since the records of pressurizer-water-to-RCS-hot-leg differential temperature data are 

available for the entire plant’s operating history to date, the fatigue results involve no 

backward projections for better accuracy, ensuring the effects of aging being managed 

in accordance with a proper disposition to one of the 3 options of 10 CFR 54.21(c)(1). 

As a result of RAI 4.3.1.1-1, the applicant also made changes to LRA Section 4.3.1.3, as 

follows: 

In LRA Section 4.3.1.3, the last paragraph on Page 4.3-10 and the first 

paragraph on Page 4.3-11 are deleted and replaced in their entirety with the 

following:

NSPM will perform an ASME Section III fatigue evaluation of the lower head of 

the pressurizer to account for effects of insurge/outsurge transients. The 

evaluation will determine the cumulative fatigue usage of limiting pressurizer 

component(s) through the period of extended operation. The analyses will 

account for periods of both “Water Solid” and “Standard Steam Bubble” operating 

strategies. Analysis results will be incorporated, as applicable, into the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program. This analysis and any 

associated program enhancements will be completed prior to the period of 

extended operation. The Metal Fatigue of Reactor Coolant Pressure Boundary 

Program will manage metal fatigue of the pressurizer due to insurge/outsurge 

transients in accordance with 10 CFR 54.21(c)(1)(iii).

The staff reviewed the changes made to LRA Section 4.3.1.3 resulting from RAI 4.3.1.1-1. The 

staff found that the TLAA for the pressurizer components is consistent with GALL AMP X.M1

and 10 CFR 54.21(c)(1)(iii).

4.3.1.4.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles and 60-year projections, and concluded that the CUF for the pressurizer locations based 

on those transients will remain valid for the period of the extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for pressurizer locations is 

adequate.
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4.3.1.4.4 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 upper region of the PINGP Units 1 and 

2 pressurizer locations remain valid for the period of extended operation. For the pressurizer 

lower head locations, license renewal Commitment 35 (as discussed in Section 4.3.1.2.2 

applies. The commitment states that NSPM will perform an ASME Section III fatigue evaluation 

for the lower head of the pressurizer to account for effects of insurge/outsurge transients. The 

evaluation will determine the cumulative fatigue usage of limiting pressurizer component(s) 

through the period of extended operation. Implementation of license renewal Commitment 35 is 

scheduled to complete by 8/09/2013 for Unit 1 and 10/29/2014 for Unit 2. 

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.1.5 Steam Generators

4.3.1.5.1 Summary of Technical Information in the Application

LRA Section 4.3.1.4 discusses the fatigue usage evaluations for the steam generators. The 

applicant notes that PINGP Unit 1 steam generators (SG) were replaced in November 2004 

while the SGs of Unit 2 remain unchanged. The applicant states that fatigue analyses for both 

SG were performed in accordance with the requirements of the ASME Boiler and Pressure 

Vessel Code, Section III. The applicant also states that the primary and secondary sides are 

Class 1 and were designed in accordance with ASME Code Section III, 1995 Edition through 

1996 Addenda for Unit 1, and 1965 Edition through Winter 1966 Addenda for Unit 2. The 

applicant further states that these fatigue analyses are considered TLAAs because they are 

based on the transients and cycles expected to occur in 40 years of operation, as shown in LRA 

Section 4.3.1. The fatigue results for the PINGP Units 1 and 2 SGs are shown in 

LRA Table 4.3-6. 

Based on the fatigue results in LRA Table 4.3-6 and the results of the 60-year transient cycle 

projection in LRA Table 4.3-1, the applicant claims that the fatigue requirements for the PINGP 

SGs will remain valid for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). During that same period, the applicant states that the design transients 

actually experienced by the SGs will continue to be managed by the Metal Fatigue of Reactor 

Coolant Pressure Boundary Program in accordance with 10 CFR 54.21(c)(1)(iii).

LRA Section 4.3.1.4 also includes the experience and effort on inspecting the SG feedwater 

nozzle and repair of the flawed and eroded components as a result of the inspection. The 

applicant also performed fatigue crack growth analyses for postulated flaws in the nozzle. 

The applicant indicates that in October 1992, NMC (Nuclear Management Company) replaced 

the feedwater pipe spool pieces on all four SGs (Units 1 and 2) due to a concern of potential 

thermal fatigue damage to the weld which connects the spool piece to the feedwater nozzle. 

The applicant also indicates that for each spool piece, the weld that connected the spool piece 

to the feedwater nozzle, and part of the original feedwater nozzle were removed. The applicant 

notes that examinations of the removed items revealed minor cracks at the weld and in the base 
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metal. The applicant further notes that the maximum crack depth was 0.074 inches (in piping 

upstream of the spool piece to nozzle weld on SG 12). The applicant states that the observed 

cracking was associated primarily with repair welding performed during construction, and all 

metal (piping, weld, and nozzle base metal) that contained cracks on each steam generator was 

removed as part of the repair. 

The applicant indicates that it has examined the feedwater nozzle thermal sleeve and found 

severe erosion on its outside surface (OD). The applicant notes that the maximum erosion 

depth is approximately 0.128 inches, on SG 21. The applicant further notes that the feedwater 

nozzle bore and knuckle region for all SGs were subsequently inspected and no indications of 

degradation or cracking were found.

Because of the erosion, the applicant indicates that thermal hydraulic, fatigue, and fracture 

mechanics evaluations were performed to justify leaving the thermal sleeves in the as-found 

condition. The applicant indicates that the analysis shows that fatigue usage in the nozzle bore 

and knuckle regions, where the stresses are the highest, are well below the limit of 1.0. The 

applicant further indicates that fracture mechanics analyses were also performed for the nozzle 

bore and knuckle regions, based on a postulated flaw since there was no actual flaw found. 

In the LRA, the applicant indicates that PINGP will monitor Mode 2/3 operations for the SG FW 

nozzles with the Metal Fatigue of Reactor Coolant Pressure Boundary Program in accordance 

with 10 CFR 54.21(c)(1)(iii) to ensure that the bounds of the fracture mechanics evaluation are 

not exceeded. However, the applicant notes that the fatigue crack growth analysis does not 

apply to the Unit 1 SGs because they were replaced in 2004.

LRA Section 4.3.1.4 also presents the results of fatigue analyses for the SG tubes. The 

applicant states that to prevent the same type of fatigue cracking as that experienced at North 

Anna Unit 1 on July 15, 1987, PINGP evaluated its SG tubing and performed fatigue usage 

calculations based on the plant-specific operating conditions. The results indicate that all tubes 

have an acceptable fatigue usage factor (0.173). However, the applicant indicates that this 

evaluation is no longer applicable to Unit 1 SGs because they were replaced in 2004. 

The applicant states that to account for the MUR-PU, the CUF for the Unit 2 SG U-bend tubing 

was recalculated, projected to 60 years of operation and the revised 60-year CUF is 0.378. The 

applicant concluded that the SG tube fatigue usage for Unit 2 is acceptable, pursuant to 

10 CFR 54.21(c)(1)(ii), during the period of the extended operation. The applicant also states 

that the replacement SGs for Unit 1 use stainless steel tube support plates and thus are not 

susceptible to the denting experienced by the North Anna Unit 1 incident described in NRC 

Bulletin 88-02.

4.3.1.5.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.4, pursuant to 10 CFR 54.21(c)(1), to verify that the 

analyses remain valid for the period of the extended operation. In this evaluation, the original 

steam generator (e.g., Unit 2) is abbreviated as OSG and the replacement steam generator 

(i.e., Unit 1) is abbreviated as RSG.
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In its review of the SG fatigue results shown in LRA Table 4.3-6, the staff noticed a significant 

difference in CUFs between Unit 1 and Unit 2 at the SG primary inlet nozzle location 

(CUF=0.007 for Unit 1 and CUF=0.880 for Unit 2). The significant difference also exists at the 

SG primary outlet nozzle location (CUF=0.006 for Unit 1 and CUF=0.880 for Unit 2). The staff 

notes that it is understandable for CUF values between Units 1 and 2 will be different because 

the Unit 1 SGs are recent replacements. However, the cited differences are much larger than 

the staff's expectation. Therefore, the staff issued RAI 4.3.1.4-1, in a letter dated December 10, 

2008, in which the staff asked the applicant to explain the significant differences. 

In its response to RAI 4.3.1.4-1, dated January 9, 2009, the applicant attributed the described 

differences to one or more of the following causes: 

 (1) Differences between the Unit 1 and Unit 2 nozzle geometry and materials of 

construction. The applicant explained that the Unit 1 RSG primary inlet and outlet 

nozzles are forged with the primary head and are fabricated from low alloy steel (SA 508 

Grade 3 Class 2) whereas those for the Unit 2 OSG primary inlet and outlet nozzles are 

cast with the primary head and are fabricated from carbon steel (SA 216 Grade WCC). 

The applicant further indicated that the thickness of the Unit 1 nozzles is less than that of 

Unit 2 nozzles. The applicant explained that the differences in materials and wall

thickness allow the Unit 1 nozzles to respond quicker to temperature transients, thus 

reducing through-wall gradients, and producing lower thermal stresses than that in the 

Unit 2 nozzles for a given thermal transient.

 (2) Differences in design transients and external nozzle loads and moments used in the 

fatigue evaluations. The applicant explained that the design transients used in the 

fatigue evaluation are consistent between Units 1 and 2. The applicant also indicated 

that the external loads and moments applied to the Unit 1 nozzles are equivalent to or 

bound those used for Unit 2 analysis of the nozzles. 

 (3) Differences in methodology of CUF calculations. The applicant explained that the 

calculation for the Unit 1 RSG primary inlet and outlet nozzles CUF is based on the finite 

element method which allows the fatigue usage calculations to be performed in 

accordance with ASME III NB-3222.4 (e)(5) procedures, adding partial usage 

contributed from stress pairing among the design transients. The applicant also indicates 

that the calculation for the Unit 2 SG primary inlet and outlet nozzles CUF was based on 

the worst-case normal and upset loading conditions, and the results of the peak stress 

intensities determined from the worst loading conditions were conservatively given to 

every transient that the system will have to endure. The applicant indicates that 

altogether there are 24,000 cycles for the transients listed in Table 4.3-1 of the PINGP 

LRA. This resulted in a very conservative cumulative usage factor of 0.88 as reported in 

LRA Table 4.3-6. 

The staff evaluated the applicant’s response to RAI 4.3.1.4-1 as follows: 

For cause (1), while the thinner wall thickness in the Unit 1 RSG primary inlet and outlet nozzles 

tends to reduce the through-wall temperature gradient (as the applicant argued), the lower 

thermal diffusivity of SA-508, which is used in Unit 1 RSG primary inlet and outlet nozzles has 

the opposite effect. This is because the thermal diffusivity of low alloy steel SA-508 (used in Unit 

1 RSG) is lower than that of the SA-216 carbon steels (used in Unit 2 OSG), and substances 
4-35

with lower thermal diffusivity adjust their temperature to that of their surroundings more slowly. 

Therefore, the effects due to differences in geometry and material will cancel each other 

somewhat. In addition, thinner wall thickness in Unit 1 RSG will have higher stresses from the 

pressure and mechanical loads. 

Cause (2) obviously is a non-contributor because Unit 1 RSG primary inlet and outlet nozzles 

and Unit 2 OSG primary inlet and outlet nozzles are subject to similar thermal and piping loads. 

Cause (3) is significant because the original evaluations performed in the early 1970s are 

bounding analyses. Consequently, the results are likely very conservative. In its description of 

Cause 3, the applicant indicated that the worst-case normal and upset loading condition was 

used in the original analysis for the OSG primary inlet and primary outlet nozzles, and it was 

assumed this was the only transient that these components will be subject to, and this transient 

was repeated 24,000 times. In a teleconference held on February 10, 2009, the staff requested 

the applicant to identify “the worst-case normal and upset loading condition transient” indicated 

in the response to RAI 4.3.1.4-1 and provide the source which leads to the 24,000 number. The 

applicant responded in the same teleconference saying that the worst-case normal and upset 

loading condition transient was represented by the Loss of Flow (partial loss of flow, one pump 

only) transient, which falls in the upset condition category of Table 4.3-1 of the LRA. The staff 

found the choice reasonable, since this transient involves a near step-change temperature 

condition with a significant temperature variation, which is severe. As for the value of 24,000 for 

the number of cycles, the applicant explained that it was a round-up of the sum of the cycles of 

all the transients listed in LRA Table 4.3-1, but not double counting the paired types of 

transients such as Heatup/Cooldown, Plant Loading/Plant Unloading, Step Load Increase/Step 

Load Decrease, and not to include Steady State Fluctuations. The staff found the transient 

selected and the cycles used are both conservative and therefore are acceptable. 

On the basis of its review and evaluations as described above, the staff found that the 

applicant’s response does explain the significant differences in the CUF values as described in 

RAI 4.3.1.4-1. Among the three causes suggested by the applicant, only Cause (3) provides a 

very strong reason because the bounding analysis described in Cause (3) is meant to be 

conservative whereas the modern analysis, finite element analysis, and transient peak stress 

intensity pairing performed for Unit 1 RSG was aimed to provide a more realistic and accurate 

results. The staff’s concern is therefore resolved.

In LRA Section 4.3.1.4, the applicant discusses fracture mechanics analyses for the steam 

generator feedwater nozzle and performed fracture mechanics analyses to justify leaving the 

eroded thermal sleeves in the as-found condition. Since, as indicated in the LRA, all flawed 

parts have been removed and repaired, and the follow up inspection found no indications of 

degradation or cracking, the staff did not understand why the applicant considered fracture 

mechanics evaluation for the steam generator feedwater nozzles a time-limited aging analysis 

(TLAA). Therefore, the staff issued RAI 4.3.1.4-2, in a letter dated December 10, 2008, asking 

the applicant to explain and clarify. 

In its response to RAI 4.3.1.4-2, dated January 9, 2009, the applicant states that the Steam 

Generator Fatigue and Fracture Mechanics Evaluation of Feedwater Inlet Nozzle discussion 

was conservatively included in LRA Section 4.3.1.4 even though the analysis did not meet all six 
4-36

criteria in 10 CFR 54.3(a) for defining a TLAA. In particular, the applicant indicates that the 

analysis did not meet Criterion (3) in that it did not "involve time-limited assumptions defined by 

the current operating term, for example, 40 years." 

The applicant further states that the crack growth analysis does not provide a basis for 

demonstrating that a known flaw is acceptable for continued operation for the life of the plant, 

and the analysis simply defined an appropriate examination frequency that is based on a 

postulated flaw of a certain size. The applicant also states that since the crack growth analysis 

is not managing an actual (existing) crack and the analysis was not performed for the service 

life of the component (i.e., 40 years), this evaluation is not a TLAA. 

The applicant further states that NSPM monitors the Unit 2 feedwater nozzle to pipe transition 

forging welds for evidence of cracking using ultrasonic inspection through owner-elected 

examinations maintained within the PINGP ASME Section XI Inservice Inspection, Subsections 

IWB, IWC, and IWD Program. These periodic examinations ensure that the feedwater nozzle 

region remains free of cracks.

As a result, NSPM determined that the discussions about the flaw evaluation should be

removed from the LRA and provided the change in the January 9, 2009 response letter.

On the basis of its review described above, the staff found the applicant’s response to RAI 

4.3.1.4-2 acceptable because there was no actual flaw found in the Unit 2 SG feedwater inlet 

nozzle and the applicant made the necessary clarification that it does not meet the TLAA 

criteria. Instead, the applicant will monitor the Unit 2 SG feedwater nozzle to pipe transition 

forging welds for evidence of cracking using ultrasonic inspection through owner elected 

examinations maintained within the PINGP ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program. 

4.3.1.5.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles and 60-year projections, and concluded that the CUF for the SG locations based on 

those transients will remain valid for the period of the extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for SG locations is adequate.

4.3.1.5.4 Conclusion

Based on the review of the LRA, the staff found that the applicant has demonstrated 

conformance to 10 CFR 54.21(c)(1)(i) for the steam generators. However, for Unit 2 SG tubes, 

the TLAA is pursuant to 10 CFR 54.21(c)(1)(ii). The staff also concludes that the UFSAR

supplement contains an appropriate summary description of the activities for managing the 

effects of aging and the Metal Fatigue of Reactor Coolant Pressure Boundary Program and 

TLAA evaluation, as required by 10 CFR 54.21(d).
4-37

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the activities for managing the effects of aging and the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.1.6 Reactor Coolant Pumps

4.3.1.6.1 Summary of Technical Information in the Application

LRA Section 4.3.1.5 discusses fatigue usage analyses for the reactor coolant pump (RCP). The 

applicant states that fatigue analyses of the RCPs are considered TLAAs because they are 

based on the numbers of design cycles expected to occur in 40 years of operation. The results 

are shown in LRA Table 4.3-7.

Based on the CUF values shown in Table 4.3-7 and the results of 60-year cycles projections 

shown in Table 4.3-1, the applicant concluded that the PINGP RCP fatigue analyses will not be 

exceeded in 60 years of operation and these TLAAs will remain valid through the period of 

extended operation in accordance with 10 CFR 54.21(c)(1)(i). 

However, the applicant indicates that the design transients experienced by the reactor coolant 

pumps will continue to be managed by the PINGP Metal Fatigue of Reactor Coolant Pressure 

Boundary Program and RCP fatigue is managed in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.6.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.5, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses remain valid for the period of the extended operation.

The applicant presents the fatigue usage results of Casing, Main Flange, Main Flange Bolts, 

Thermal Barrier Flange, and Water Connections in LRA Table 4.3-7. In LRA Section 4.3.1.5, the 

applicant states that exemption from fatigue evaluation was justified for the casing feet, casing 

nozzle, and upper and lower seal housings and bolts, but did not support this statement with a 

regulatory basis. The staff issued RAI 4.3.1.5-1, in a letter dated December 10, 2008, 

requesting the applicant to provide technical and regulatory basis for exempting these 

components from being within the scope of an ASME Code Section III CUF analysis.

In its response to RAI 4.3.1.5, dated January 9, 2009, the applicant states that the RCPs were 

designed in accordance with Article 4 of ASME Code Section III through the 1970 Winter 

Addendum. Exemption from fatigue evaluation was justified in accordance with 

ASME Code Section III, Article 415.1, for the casing feet, casing nozzle, and upper and lower 

seal housings and bolts. The applicant states that the applicable RCP calculations used to show 

compliance with ASME Code Article N-415.1, (a) through (f) are based on design transients that 

bound those presented in LRA Table 4.3-1, and are intended to represent 40 years of operation. 

The staff noted that, in this part of the response to the RAI, a different set of transients must 

have been used to support the sentence “bound those presented in LRA Table 4.3-1.” 

Therefore, a teleconference was held, requesting the applicant to identify what transients were 

considered. The applicant responded in the same teleconference, indicating that they used the 

Westinghouse generic transients. The staff found this clarification acceptable because the 
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Westinghouse generic transients are intended to be conservative so they are applicable to all 

Westinghouse design PWR plants. Since the applicable RCP calculations which show 

compliance with Article N-415.1 were performed based on the bounding Westinghouse generic 

transients, exemption from fatigue evaluation for the casing feet, casing nozzle, and upper and 

lower seal housings and bolts is justified. Based on this consideration, the staff’s concern on this 

matter is resolved. 

The applicant further indicates in the response to RAI 4.3.1.5 that the numbers of analyzed 

design transients used in the RCP exemption from fatigue analyses required by Article N-415.1 

for the casing feet, casing nozzle, and upper and lower seal housings and bolts, will not be 

exceeded in 60 years of operation, and these TLAAs will remain valid through the period of 

extended operation in accordance with 10 CFR 54.21(c)(1)(i). The staff found this disposition 

acceptable because the projected 60-year cycles are bounded by the design cycles and 

ASME Code Article N-415.1 conformance is demonstrated by the bounding analyses. 

4.3.1.6.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles, and 60-year projections, and concluded that the CUF for the RCP locations based on 

those transients will remain valid for the period of the extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for RCP locations is adequate.

4.3.1.6.4 Conclusion

Based on the review of the LRA, the staff found that the applicant has demonstrated 

conformance to 10 CFR 54.21(c)(1)(i) for PINGP RCP TLAA. The staff also concludes that the 

UFSAR supplement contains an appropriate summary description of the activities for managing 

the effects of aging and the Metal Fatigue of Reactor Coolant Pressure Boundary Program and 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.1.7 Class 1 Piping

4.3.1.7.1 Summary of Technical Information in the Application

LRA Section discusses the fatigue evaluation of the Class 1 piping. The applicant indicates that 

the PINGP Class 1 boundary corresponds to all RCS pressure boundary components within the 

ASME Code Section XI, IWB inspection boundary, and that all RCS piping components, except 

a portion of the Reactor Coolant Gas Vent System (RCGVS) piping and Reactor Vessel Level 

Instrument System (RVLIS) piping attached to the RV closure head, were originally designed in 

accordance with the American Standard Code for Pressure Piping (ASA) B31.1, 1955 Edition 

(Unit 1) and USA Standard Code for Pressure Piping (USAS), B31.1.0 1967 Edition (Unit 2). 

The applicant further states that the RCGVS and RVLIS piping subassemblies have been 

replaced and the new piping subassemblies are constructed in accordance with ASME Code 

Section III, Subsection NB, 1983 Edition for the RCGVS piping subassembly and the 1998 

Edition through 2000 Addenda for the RVLIS piping subassembly. The applicant indicates that 
4-39

since these piping subassemblies are less than 1-inch nominal pipe size, they were analyzed to 

ASME III Subsection NC requirements, in accordance with NB-3630(d). 

The applicant indicates that the primary Class 1 piping fatigue evaluations were originally 

performed in accordance with USAS B31.1.0 and ASME Code Section III Subsection NC. For 

the reactor coolant piping, the analysis was performed to ensure that the stress range is within 

the limits prescribed in B31.1.0. The applicant indicates that B31.1.0 does not require fatigue 

analysis and so none was performed for reactor coolant loop piping. The applicant notes that 

stress range reduction factors are used to account for anticipated transients and further notes 

that normally, a stress range reduction factor of 1.0 is acceptable in the stress analyses for up to 

7,000 cycles. The applicant indicates that the stress analysis of the primary coolant piping is 

considered a TLAA since the stress range reduction factor is dependent on the number of 

design transient full temperature cycles. 

The applicant states that the thermally induced stresses arising from temperature gradients are 

limited to a safe and low order of magnitude in assigning a maximum permissible time rate of 

temperature change on plant heatup, cooldown, and incremental loadings in the plant operating 

procedures. The applicant further states that the numbers of full temperature thermal cycles 

experienced by RCS piping is subject to the transient cycle limits identified in Table 4.3-1, and 

will not exceed 7000 cycles in 60 years of operation. Therefore, the applicant concluded that the 

Class 1 piping B31.1.0 stress calculations are valid for the period of extended operation and the 

TLAA remains valid for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). However, the applicant states that the cumulative numbers of design 

transients experienced by the main coolant large bore piping will continue to be managed by the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program in accordance with 

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

The staff notes that the discussion shown above applies to all parts of the Class 1 piping except 

the surge line, which is described below.

Pressurizer Surge Line Piping

The applicant states that PINGP participated in a program to assess the impact of thermal 

stratification on the surge line (including hot leg nozzle and pressurizer surge nozzle) and the 

PINGP operating procedures were modified to mitigate the severity of transients resulting from 

pressurizer surges during heatup and cooldown. The applicant notes that PINGP responses to 

NRC Bulletin 88-11 were provided in Reference 15 and Reference 16 of the LRA, and the NRC 

approved its analysis results for Units 1 and 2 in References 14 and 13 of the LRA, respectively. 

. The applicant states that it has responded to NRC Bulletin 88-

11, to re-evaluate (in accordance with ASME B&PV Code Section III, Subsection NB 1986 

Edition) the pressurizer surge line, including hot leg nozzle and pressurizer surge nozzle, to 

incorporate the effects of thermal stratification. The applicant notes that the original design of 

the plant did not consider thermal stratification of the surge line in its analyses. The applicant 

also notes that NRC Bulletin 88-11 mandates utilities to establish and implement a program to 

confirm pressurizer surge line integrity in view of the occurrence of thermal stratification as a 

result of the plant heatup/cooldown cycles. 
4-40

In the section, the applicant presents the maximum CUF values. For Unit 1, the maximum CUF 

for surge line is 0.90 (at the reducer under the pressurizer) and the CUF at the hot leg surge 

nozzle is 0.70. For Unit 2, the maximum CUF for the surge line is 0.85 (at the hot leg nozzle). 

The applicant states that the site-specific evaluations of the pressurizer surge line are 

considered TLAAs since the evaluations use time-limited assumptions. The applicant indicates 

that the dominant cycles in the surge line analysis are the 200 design heatup and cooldown 

transients shown in Table 4.3-1 with various system differential temperatures that include the 

stratification and striping associated with those transients. 

The applicant claims that, based on the 60-year projected cycles shown in LRA Table 4.3-1, 

since the number of analyzed heatups and cooldowns, as well as the other design transients 

presented in Table 4.3-1 will not be exceeded in 60 years of operation, this TLAA will remain 

valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i). At the same 

time, the applicant states that the cumulative numbers of design transients experienced by the 

pressurizer surge line will continue to be managed by the PINGP Metal Fatigue of Reactor 

Coolant Pressure Boundary Program in accordance with 10 CFR 54.21(c)(1)(iii).

4.3.1.7.2 Staff Evaluation

The staff reviewed LRA Section 4.3.1.6, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses remain valid for the period of the extended operation.

The staff found the applicant’s claim that the Class 1 piping TLAA remains valid for the period 

of extended operation in accordance with 10 CFR 54.21(c)(1)(i) acceptable based on the 

reasons described below:

For the piping components other than the surge line: The PINGP primary Class 1 piping is 

designed in accordance with USAS B31.1.0 or ASME Code Section III Subsection NC and no 

explicit fatigue analysis is required. The fatigue requirements under these Codes are 

incorporated in the allowable stress range requirements along with appropriate stress range 

reduction factors. If the number of full temperature thermal cycles experienced by the piping is 

less than 7000, no reduction will be imposed upon the allowable stress range. If the 7,000-cycle 

criterion is exceeded, appropriate reduction factors will be applied depending on the number of 

cycles the piping actually experienced. Since the total numbers of full temperature thermal 

cycles that the PINGP RCS piping will experience would not exceed 7,000 cycles in 60 years of 

operation, the TLAA for this group of piping remains valid for the period of extended operation. 

For the surge line piping: Since the projection shows that the number of heatup and cooldown 

cycles used for the analyses, as well as the other design transients presented in Table 4.3-1 will 

not be exceeded in 60 years of operation, the TLAA for this group of piping remains valid for the 

period of extended operation.

4.3.1.7.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names/types, design 

cycles and 60-year projections, and concluded that the CUF for the Class 1 piping based on 

those transients will remain valid for the period of the extended operation.
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On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for Class 1 piping is adequate.

4.3.1.7.4 Conclusion

Based on the review of the LRA, the staff found that the applicant has demonstrated 

conformance to 10 CFR 54.21(c)(1)(i) for PINGP Class 1 Piping TLAA. The staff also concludes 

that the UFSAR supplement contains an appropriate summary description of the activities for 

managing the effects of aging and the Metal Fatigue of Reactor Coolant Pressure Boundary 

Program and TLAA evaluation, as required by 10 CFR 54.21(d).

4.3.2 Non-Class 1 Fatigue

4.3.2.1 Summary of Technical Information in the Application

In LRA Section 4.3.2, the applicant discusses the fatigue evaluation for non-Class 1 

components and indicates that PINGP adopts the fatigue screening criteria provided in industry 

guidance to identify locations potentially susceptible to fatigue cracking for non-Class 1 

components. The applicant indicates that, per the guidance, those components which are 

operating below the temperature thresholds, 220 o

F for carbon steels and 270 oF for stainless 

steels, may be exempted from fatigue consideration.

LRA Section 2.0 identifies the non-Class 1 mechanical components within the scope of License 

Renewal that are subject to aging management review. The applicant fits them in two major 

categories: (1) piping and in-line components (tubing, piping, traps, thermowells, valve bodies, 

etc.); and (2) non-piping components (tanks, vessels, heat exchangers, pump casings, turbine 

casings, etc.). 

The applicant indicates that all mechanical systems within the scope of License Renewal were 

reviewed to identify components within the systems that meet the temperature screening criteria 

shown above and the PINGP Piping Attributes, Piping Specifications and P&IDs were used to 

determine system design and operating temperatures for each system. The applicant also 

indicates that Non-Class 1 components that exceeded the temperature screening criteria were 

reviewed to determine whether the number of full temperature design cycles for piping and inline components would be exceeded at 60 years, and whether the design basis of the affected 

vessel, heat exchanger, storage tank, or pump contain any specific fatigue design requirements. 

The applicant's finding is summarized below.

For Piping and In-Line Components. The applicant states that the impact of thermal cycles on 

non-Class 1 piping and in-line components is reflected in the calculation of the allowable stress 

range. The applicant notes that ASME Code Section III, Class 2 and 3, and B31.1.0 design 

codes all incorporate a stress range reduction factor for determination of the acceptability of 

piping design with respect to thermal stresses. The applicant indicates that in general, a stress 

range reduction factor of 1.0 in the stress analyses applies for up to 7,000 thermal cycles. The 

allowable stress range is reduced by the stress range reduction factor if the number of thermal 

cycles exceeds 7,000. The applicant indicates that for PINGP, the projected thermal cycles for 
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60-years of plant operation is less than 7,000 cycles. Therefore, the pipe stress calculations 

remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

For Pressure Vessel, Heat Exchangers, Storage Tanks and Pumps.

The applicant states that the tube and shell sides of the regenerative heat exchangers, residual 

heat exchangers, letdown and excess letdown heat exchangers, and sample heat exchangers 

were designed in accordance with ASME Code Section III Class C, or ASME Section VIII, 

Division 1. The applicant also indicates that the equipment specification requires that the 

supplier verify that all conditions of ASME Code Section III, Paragraph N-415.1 (i.e., exemption 

from fatigue evaluation for Class 1 components), are satisfied for the transient conditions 

specified in the equipment specification. The applicant further indicates that the design 

transients identified in the equipment specifications were reviewed and confirmed consistence 

with the design transients defined in Table 4.1-8 of the UFSAR (also shown in Table 4.3-1 of

LRA). The applicant indicates that since the design transient cycles bound the projected 60-year 

cycles, the exemption from fatigue evaluation considered in the original design of all these 

exchangers will remain valid during the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). At the same time, the applicant indicates that the cumulative numbers of 

design transients experienced by all these heat exchangers will continue to be managed by the 

Metal Fatigue of Reactor Coolant Pressure Boundary Program in accordance with 

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

The applicant indicates that 

PINGP non-Class 1 vessels, storage tanks and pumps within the scope of License Renewal 

were designed in accordance with ASME Code Section III Class C (or 3) and/or ASME Code 

Section VIII or equivalent. The applicant also indicates that there are no specific fatigue design 

requirements for PINGP non-Class 1 vessels, heat exchangers and pumps.

4.3.2.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses remain valid for the period of the extended operation.

The staff notes that no explicit fatigue evaluation is required for Class 2 and 3 components 

designed according to ASME Code III or USAS B31.1.0 design Codes. Furthermore, for Class 2 

and 3 components, the fatigue requirement is reflected in the allowable stress range such that 

the fatigue requirement is met if the total number of cycles of all full-thermal range transients 

experienced by the component is kept within 7,000 cycles. For this class of components, it is 

required that the maximum allowable stress range be reduced if the total number of full thermal 

transient cycles do exceed 7,000. 

The staff noted that Class 2 and 3 components are associated mostly with heatup or cooldown 

transients, which are limited to 200 cycles for PINGP. The staff noted that even by adding all 

cycles applicable to Class 1 components in LRA Table 4.3-1, the projected 60-year cycles are 

well below the 7,000-cycle criterion. This cycle count excludes the steady state fluctuations, 

which would have no effect on fatigue and excludes the load/unload cycles, which would not be 

applicable to Class 2 and 3 piping. By rule, the staff found that the applicant’s claim that the 

PINGP non-Class 1 (Class 2 and 3) piping will continue to meet the fatigue requirements during 

the period of extended operation acceptable because it satisfies the 7,000-cycle criterion and 

thus this TLAA can be disposed in accordance with 10 CFR 54.21(c)(1)(i). 
4-43

The staff notes that no explicit fatigue evaluation is required for Class 2 and 3 vessels, heat 

exchangers and pumps designed according to ASME Code Section III Class C (or 3), or ASME 

Code Section VIII, Division 1. The staff notes that if a component is qualified for exemption from 

fatigue evaluation for the current licensing basis (CLB), the exemption for the same component 

will remain valid during the period of extended operation if the projected 60-year cycles are 

bounded by the design transient cycles. PINGP does satisfy this transient cycle requirement. 

Based on this consideration, the staff found that the applicant’s claim that the current exemption 

from fatigue evaluation for the regenerative heat exchangers, residual heat exchangers, letdown 

and excess letdown heat exchangers, and sample heat exchangers will remain valid during the 

period of extended operation acceptable in accordance with 10 CFR 54.21(c)(1)(i). This is 

because the PINGP projected 60-year cycles are bounded by the design transient cycles. 

4.3.2.3 UFSAR Supplement

LRA Section A4.2 summarizes the transient data, including transient names and types, design 

cycles, and 60-year projections, and concluded that the CUF for the Non-Class 1 components 

based on those transients will remain valid for the period of the extended operation.

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for Non-Class 1 components is 

adequate.

4.3.2.4 Conclusion

On the basis of the review of the LRA, the staff concludes that the applicant has demonstrated 

conformance to 10 CFR 54.21(c)(1)(i) that the CLB analyses have been projected to the end of 

the period of extend operation for the non-Class 1 piping, and all non-Class 1 exchangers. The 

applicant indicates, that the transients experienced by the applicable heat exchangers will 

continue to be managed by the Metal Fatigue of Reactor Coolant Pressure Boundary Program 

in accordance with 10 CFR 54.21(c)(1)(iii). This is acceptable since it provides added 

assurance.

The staff also concludes that the UFSAR supplement contains an appropriate summary 

description of the activities for managing the effects of aging and the TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.3.3 Environmentally-Assisted Fatigue (GSI-190)

4.3.3.1 Summary of Technical Information in the Application

The staff notes that LRA Section 4.3.3 was revised after the applicant completed license 

renewal Commitment No. 36. By letter dated April 28, 2009, NSPM provided the staff updated 

fatigue analysis, upon completion of license renewal Commitment No. 36. Enclosure 1 of this 

letter transmits the LRA amendment with the updated analysis results. The completion of this 

commitment caused LRA Section 4.3.3 to be amended in its entirety. 
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In LRA Section 4.3.3, the applicant states that it has responded to NRC SECY-95-245 by 

evaluating environmentally-assisted fatigue (EAF) for some selected component locations to 

support its application for license renewal. The applicant also states that NUREG/CR-6260 

identified locations of interest for consideration of environmental effects. The staff notes that 

NUREG/CR-6260 (entitled: “Application of NUREG/CR-5999 Interim Fatigue Curves to Selected 

Nuclear Power Plant Components”) contains a list of sample locations which have been 

evaluated for the effects of LWR environments on fatigue. The list includes older and newer 

vintages of both BWR and PWR nuclear power plants of B&W, CE, GE, and Westinghouse 

designs. The applicant indicates that Section 5.5 of NUREG/CR-6260 is intended for older 

vintage Westinghouse plants, which is applicable to PINGP, and the corresponding PINGP 

locations are as follows:

 • Reactor vessel shell and lower head

 • Reactor vessel inlet and outlet nozzles

 • Pressurizer surge line (hot leg nozzle safe end)

 • RCS piping charging system nozzle

 • RCS piping safety injection accumulator nozzle

 • RHR Class 1 piping tee

The applicant indicates that it performed EAF evaluations for all six NUREG/CR-6260 locations 

listed above in accordance with the guidelines provided in NUREG/CR-5704 for austenitic 

stainless steels and NUREG/CR-6583 for carbon steels and low-alloy steels. 

The applicant indicates that of the six NUREG/CR-6260 locations, the design basis cumulative 

usage factors for the reactor vessel shell and lower head, and the reactor vessel inlet and outlet 

nozzles are reported in LRA Section 4.3.1.1. The CUF calculated in response to NRC 

Bulletin 88-11 are reported in LRA Section 4.3.1.6 for the pressurizer surge line piping (including 

the hot leg surge nozzles). The applicant indicated that per NUREG/CR-6260 the limiting 

pressurizer surge line location is at the safe end connected to the hot leg nozzle. 

The applicant indicates that since the PINGP primary Class 1 piping NUREG/CR-6260 locations 

are designed in accordance with B31.1.0, explicit fatigue analyses were not required. To 

support the LRA, the applicant performed fatigue analyses for the charging system nozzle, 

safety injection accumulator nozzle, the RHR Class 1 piping tee, and the pressurizer surge line 

hot leg nozzle. 

The applicant indicates that it performed fatigue usage evaluations for the safety injection 

accumulator nozzle and the RHR Class 1 piping tee in accordance with ASME Code Section III, 

1989 Edition guidelines, with 1989 Addenda, and the results are shown in the amended LRA 

Table 4.3-8. The applicant indicates that the transients applicable to these locations include 

inadvertent RCS depressurization, inadvertent accumulator blowdown, RHR operation during 

plant cooldown, RCS refueling, high head safety injection, and Operational Basis Earthquake

(OBE). 

The applicant indicates that fatigue evaluations for the charging system nozzle and surge line 

hot leg nozzle were calculated using ASME Code Section III, 2001 Edition with 2003 Addenda 

based on NSSS design transients shown in LRA Table 4.3-1. The applicant states that in 

addition to the bounding NSSS design transients, other types of transients that are applicable to 
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these components were also included in the fatigue evaluations. Namely, for the charging 

nozzle, these include inadvertent RCS depressurization, inadvertent auxiliary spray actuation, 

excessive feedwater flow, RCS refueling, and OBE. For the surge line hot leg nozzle, these 

include inadvertent RCS depressurization, inadvertent auxiliary spray actuation, control rod 

drop, excessive feedwater flow, RCS refueling, and OBE. The applicant further indicates that 

for the charging nozzle, additional transients including charging/letdown system flow shutoff and 

flow change transients were used. The applicant indicates that these two transients were 

derived based on a standard set of Westinghouse design transients for auxiliary systems, 

modified for the expected number of occurrences at 60 years. The applicant indicates that the 

cycles of all the transients used for the fatigue evaluations for these components were the 

expected number of cycles at 60 years. 

Based on the results shown in the amended LRA Table 4.3-8, the applicant concluded that the 

EAFs for all amended LRA Table 4.3-8 locations have been projected to the end of the period of 

extended operation, pursuant to 10 CFR 54.21(c)(1)(ii). Bound by License Renewal 

Commitment No. 33, the applicant stated that EAF at all NUREG/CR-6260 locations will be 

managed using cycle counting or cycle-based fatigue monitoring under the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program in accordance with 10 CFR 54.21(c)(1)(iii). All 

transients and revised cycle limits used for the fatigue evaluations will be included in the Metal 

Fatigue of Reactor Coolant Pressure Boundary Program. 

4.3.3.2 Staff Evaluation

The staff reviewed LRA Section 4.3.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that the 

analyses have been projected to the period of extended operation.

In its review, the staff noticed a footnote for LRA Table 4.3-8 states that the results for the 

pressurizer surge line hot leg nozzle safe end and for the charging system nozzle were from 

stress-based fatigue usage calculation. During the audit, the staff confirmed that “stress-based 

fatigue usage calculation” meant fatigue usage evaluations were performed by EPRI owned 

software named FatiguePro. The staff notes that FatiguePro takes a simplified approach in the 

fatigue usage calculation, and does not take all six stress components into consideration. The 

staff notes that FatiguePro is not endorsed by the NRC staff as it does not produce the six 

individual stress components needed to support the ASME Code Section III fatigue analysis 

method. Therefore, the staff issued RAI 4.3.1.1-1 in a letter dated December 10, 2008. In this 

RAI, the staff asked the applicant why a simplified transient fatigue evaluation is still being used. 

In a letter dated January 9, 2009, the applicant provided its response to this RAI as well as a 

commitment (Commitment No. 36) to perform Code compliant fatigue calculations stated in the 

response. In this response, the applicant stated that ASME Code (Subsection NB) compliant 

fatigue calculations are in process for these two locations and the revised CUFs results 

(unadjusted and adjusted for environmental effects) will be reported as an amendment to the 

PINGP LRA. The commitment was completed and provided to the staff by letter dated 

April 28, 2009.
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In SER Section 4.3.1.1.2, the staff provided the complete detail on RAI 4.3.1.1-1 applicant 

response to this RAI, and the staff evaluation of the response. On April 28, 2009, the applicant 

provided the result of the revised fatigue analysis in a letter titled “Supplemental Information 

Closing License Renewal Commitment No. 36 Regarding Application for Renewed Operating 

Licenses.” 

In reviewing the April 28, 2009 letter, the staff determined several areas that need clarification.

In a teleconference on May 4, 2009, the applicant agreed to supplement the LRA to provide 

additional details to support staff review of the revised fatigue analysis as described below:

(A) On Page 2 of April 28, 2009 letter, several paragraphs under the subsection titled 

“Determination of Fatigue Usage Unadjusted for Environmental Effects,” under Section 

4.3.3, describes the transients used for the Safety injection accumulator nozzle, charging 

nozzle, and PZR surge line hot leg nozzle. The staff noted that some of the transients 

used in fatigue evaluations for these components are not included in LRA Table 4.3-1 

(which shows only the bounding NSSS design transients). The non NSSS design 

transients are the following:

"inadvertent RCS depressurization, inadvertent auxiliary spray actuation, control rod drop, 

excessive feedwater flow, RCS refueling, OBE, inadvertent accumulator blowdown, RHR 

operation during plant cooldown, high head safety injection"

The staff requested the applicant to specify the number of design cycles for the non 

NSSS design transients listed above as well as the cycles most recently accrued and the 

cycles projected for 60 years. In addition, the staff also requested the applicant to 

confirm that all transients (including those listed above) used for the fatigue analysis 

have been tracked and monitored since the plant startup and tracking for all transients 

that may contribute fatigue usage will be continued during the period of extended 

operation.

In its letter dated May 8, 2009, the applicant supplemented the LRA with the information 

the staff requested. In the letter, the applicant stated that the transients asked by the 

staff were taken from the Westinghouse System Standard for applicable components. 

For each of these transients, the number of cycles used for fatigue analyses were based 

on the transient occurrences accrued through February 26, 2007, as projected through

60 years of licensed operations. Based on its review, the staff found the transmitted 

data reasonable and the concern was resolved. 

(B) On Page 3 of April 28, 2009 letter, the top paragraph states “... charging/letdown system 

flow shutoff and flow change transients were defined based on a standard set of 

Westinghouse design transients for auxiliary systems, as modified for the expected 

number of occurrences at 60 years...” 

The staff requested the applicant to provide basis for making the cycle modification on 

the flow shutoff and the flow change transients and specify the actual cycles used for the 

analysis.
4-47

In its letter dated May 8, 2009, the applicant supplemented the LRA with the information 

the staff requested. In the letter, the applicant listed the 60-year projected cycles. 

Based on its review, the staff found the transmitted data reasonable and the concern 

was resolved. 

Therefore, the staff found the revised analyses acceptable because they were performed in 

accordance with the ASME Section III NB-3200 guidelines, using all six stress components, and 

have accounted for the effects of insurge/outsurge and thermal stratification. Thus, the staff 

determined that the applicant successfully fulfilled Commitment No. 36. 

In its review, the staff noticed that in the calculation of Fen for the low alloy steels, the applicant 

assumes that the dissolved oxygen level for pressurized-water reactor plants is below 0.05 ppm 

at temperatures above 150 o

C. The staff notes that this assumption in effect takes away the 

dependency of Fen on strain rate and sulfur content, and weakens the dependency of Fen on 

temperature. Therefore, the staff issued RAI 4.3.3-2, in a letter dated December 10, 2008, 

requesting the applicant to justify this assumption.

In its response to RAI 4.3.3-2, dated January 9, 2009, the applicant states that at PINGP, RCS 

temperatures above 150 o

C (302 oF) correspond to operation in Mode 4 (Hot Shutdown, 350 oF 

> Tavg > 200 o

F), Mode 3 (Hot Standby, Tavg > 350 oF), Mode 2 (Startup), or Mode 1 (Power 

Operation). The applicant states that PINGP controls oxygen in the Reactor Coolant System 

(RCS) by maintaining a hydrogen overpressure in the Volume Control Tank. The applicant also 

states that minimum primary water hydrogen levels are maintained which are effective in 

mitigating oxidizing conditions due to radiolysis or oxygen ingress into the reactor coolant. 

The applicant states that the control parameters for RCS dissolved oxygen are in accordance 

with the PINGP Water Chemistry Program and the PINGP Technical Requirements Manual 

(TRM) which specify a dissolved oxygen action level limit of less than 100 ppb in Modes 1, 2, 3, 

and Mode 4 with RCS temperature > 250 o

F. The applicant states that per the TRM, if the limit 

is exceeded, the dissolved oxygen shall be restored to less than 100 ppb within a 24-hour 

period or the Unit shall be shutdown. The applicant states that at PINGP, dissolved oxygen in 

the RCS is typically less than 5 ppb prior to criticality (Modes 2, 3, and 4). The applicant further 

states that a review of PINGP RCS water chemistry data from 1999-2008 was performed and 

has confirmed that the dissolved oxygen content in the RCS never exceeded 40 ppb (0.04 ppm) 

when the RCS temperature was greater than 300 o

F. 

On the basis of its review, the staff found the applicant’s assumption that a dissolved oxygen 

level below 0.05 ppm is reasonable because it is supported by the past plant operating records. 

Based on the assumed dissolved oxygen level of 0.05 ppm, the applicant correctly obtained the 

value of the EAF correction factor, Fen = 2.455, for low alloy steel locations. Thus, the staff finds 

the applicant resolved the concern stated in RAI 4.3.3-2.

The LRA states that the bounding Fen value was used for all stainless steel locations. The staff 

determined that statement is misleading because according to NUREG/CR-5704, the bounding 

Fen value for the austenitic stainless steels is 15.35 but a Fen value of 2.55 was used in the LRA 

for the RHR Tee. In a teleconference held on February 10, 2009, the staff requested the 

applicant to clarify. In this teleconference, the applicant replied that the Fen for the RHR Tee was 

calculated based on the maximum temperature at the RHR heat exchanger, 350 o

F 
4-48

(the applicant indicated that this piece of information is documented in PINGP UFSAR Section 

10.2.4.2). The staff notes that for austenitic stainless steels, 200 o

C (392 oF) is a threshold level, 

below which the Fen is independent of the strain rate or the dissolved oxygen level. At a 

temperature of 350 o

F, which is below 392 oF, the Fen for the RHR Tee can be readily 

calculated as 2.55, the value listed in LRA Table 4.3-8. With such a clarification, the staff found 

that the applicant appropriately handled the Fen for the RHR Tee, so the staff’s concern was 

resolved. 

The staff notes that Fen values for all locations are listed in the revised LRA Table 4.3-8 

transmitted via NSPM letter dated April 28, 2009. The applicant states that for the charging and 

the surge line hot leg nozzles, the Fen was individually determined for each load set pair using 

Integrated Strain Rate approach shown in MRP-47 (EPRI report). The staff notes that MRP-47 

uses the same Fen equations as those shown in NUREG/CR-5704 for austenitic stainless steels 

and NUREG/CR-6583 for carbon steels and low-alloy steels. The Integrated Strain Rate 

approach shown in MRP-47 is similar to the approach used in NUREG/CR-6909, which adopts 

the research results of Nakamura, T., M. Higuchi, T. Kusunoki, and Y. Sugie, documented in 

“ASME Codes on Environmental Fatigue Evaluation,” Proc. of the 2006 ASME Pressure 

Vessels and Piping Conf., July 23–27, 2006, Vancouver, BC, Canada, paper # 

PVP2006-ICPVT11–93305. 

The applicant indicates that the Fen value shown in the revised LRA Table 4.3-8 is an "effective" 

overall Fen multiplier, which was back-calculated by dividing the total environmentally-adjusted 

CUF (sum of the adjusted usage factors from each load set pair) by the total unadjusted CUF 

(sum of the unadjusted usage factors from each load set pair).

On the basis of its review, the staff found the EAF analyses are acceptable because the 

applicant has followed the guidelines given in NUREG/CR-6583 and NUREG/CR-5704. 

Individually calculated contribution from each load set pair for the unadjusted CUF and the 

corresponding Fen remove the unnecessary conservatism while accumulating share of partial 

fatigue damage due to each load set pair under consideration. The staff found this approach 

acceptable because it does not lose counts of possible contribution from any load set pair. 

On the basis of its review of Section 4.3.3, the staff found the applicant’s claim that the 

environmentally-adjusted fatigue factor (CUFen) for all six NUREG/CR-6260 locations have 

been projected valid to the end of the period of extended operation, consistent with

10 CFR 54.21(c)(1)(ii). The projected (CUFen) are acceptable because the values are all within 

the limit of 1.0 for 60 years. In addition, the applicant stated that the EAF for the 

NUREG/CR-6260 locations will be managed during the period of extended operation using 

cycle counting or cycle-based fatigue monitoring in accordance with 10 CFR 54.21(c)(1)(iii). 

The staff found this provides additional assurance and is consistent with the GALL Report.

4.3.3.3 UFSAR Supplement

LRA Section A4.2 summarizes the transients data, including transient names, types, design 

cycles and 60-year projections, and concluded that the CUFen for the Class 1 components with 

environmental effects on fatigue based on those transients will remain valid for the period of the 

extended operation.
4-49

On the basis of the review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address fatigue analyses for Class 1 components 

involving environmental effects of fatigue is adequate.

4.3.3.4 Conclusion

Based on its review, as discussed above, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), the TLAA on the EAF for the 

NUREG/CR-6260 components have been projected valid to the end of the period of extended 

operation. The staff also concludes that license renewal Commitment No. 36 is fulfilled and can 

be closed.

In addition, the staff concludes that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.4 

The applicant's 10 CFR 50.49 Environmental Qualification (EQ) Program is a TLAA for 

purposes of license renewal. The TLAA of the EQ of electrical components includes all longlived, passive, and active electrical and instrumention and control (I&C) components that are 

important to safety and are located in a harsh environment. The harsh environments of the plant 

are those areas subject to environmental effects by loss-of-coolant accidents or high-energy line 

breaks. EQ equipment comprises safety-related and Q-list equipment, nonsafety-related 

equipment, whose failure could prevent satisfactory accomplishment of any safety-related 

function, and necessary post-accident monitoring equipment.

Environmental Qualification of Electrical Equipment 

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of TLAAs. The applicant 

shall demonstrate that: (i) the analyses remain valid for the period of extended operation, (ii) the 

analyses have been projected to the end of the period of extended operation, or (iii) the effects 

of aging on the intended function(s) will be adequately managed for the period of extended 

operation.

4.4.1 Summary of Technical Information in the Application 

LRA Section 4.4 summarizes the applicant’s evaluation of EQ of electrical equipment for the 

period of extended operation. The applicant evaluated EQ electrical components using

10 CFR 50.49(f) qualification methods. Aging evaluations for EQ components that specify a 

qualification of at least 40 years are considered TLAAs for license renewal. 

The applicant stated that when qualification time limits are approached, whether during the 

initial 40-year license term or the period of extended operation, the program requires 

replacement, refurbishment, or reanalysis to extend the qualification of the component under 

10 CFR 50.49(e)(5). The applicant also stated that reanalysis is an acceptable alternate for 

extending the qualified life of an EQ component. 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). 
4-50

4.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.4 to verify, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects 

of aging on the intended function(s) will be adequately managed for the period of extended 

operation.

The staff reviewed LRA Section 4.4 and plant basis documents to determine whether the 

applicant provided adequate information to meet the requirement of 10 CFR 54.21(c)(1). For the 

electrical equipment identified in the EQ master list, the applicant uses 10 CFR 54.21(c)(1)(iii) in 

its TLAA evaluation to demonstrate that the aging effects of EQ equipment will be adequately 

managed during the period of extended operation. The staff reviewed the EQ program to 

determine whether it will assure that the electrical and I&C components covered under this 

program will continue to perform their intended functions consistent with the CLB for the period 

of extended operation. The staff’s evaluation of the components qualification focused on how 

the EQ program manages the aging effects to meet the requirements delineated in 10 CFR 

50.49.

The staff conducted an audit of the information provided in Section B3.1 of the LRA and 

program basis documents. On the basis of its audit, the staff finds that the EQ program, which 

the applicant claimed to be consistent with the GALL program X.E1, “Environment Qualification 

of Electrical Components,” is consistent with EQ program in the GALL report. Therefore, the 

staff finds that the EQ program is capable of programmatically managing the qualified life of 

components within the scope of the program for license renewal. The continued implementation 

of the EQ program provides assurance that the aging effects will be managed and that 

components within the scope of the EQ program will continue to perform their intended 

functions for the period of extended operation.

4.4.3 UFSAR Supplement 

In LRA Sections A4.3 and A3.1, the applicant provided the UFSAR supplement containing a 

summary description of the Environmental Qualification of Electrical Components Program. This 

summary description is not consistent with that in Table 4.4.2 of SRP-LR as it does not contain 

reanalysis attributes. Reanalysis must address attributes of analytical methods, data collection 

and reduction methods, underlying assumptions, acceptance criteria, corrective actions if 

acceptance criteria are not met and the period of time prior to the end of qualified life when the 

reanalysis will be completed. In a letter dated November 5, 2008, the staff issued 

RAI AMP B.3.1-3, requesting the applicant to revise the UFSAR supplement description to 

include these reanalysis attributes. In response to the staff’s request. In a letter dated 

December 5, 2008, the applicant revised LRA Section A3.1, Environmental Qualification of 

Electrical Components Program, on Page A-17 the following paragraph was added to the end of 

the existing program description, to read as follows:

“Reanalysis is an acceptable alternative for extending the qualified life of an EQ component. 

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).”
4-51

The reanalysis is required when qualification time limits are approached, whether during the 

initial 40-year license term or the period of extended operation.

The staff finds the applicant’s response acceptable because the information in the UFSAR

supplement, as supplemented by the information in the applicant’s response to 

RAI AMP B3.1 3, is an adequate summary description of the program, as required by 

10 CFR 54.21(d), and this summary description is consistent with that in Table 4.4.2 of SRP-LR. 

4.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated that, for 

environmental qualification of electrical equipment, the effects of aging on the intended 

function(s) will be adequately managed for the period of extended operation, pursuant to 

10 CFR 54.21(c)(1)(iii). The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the TLAA evaluation, as required by 10 CFR 54.21(d).

4.5 

4.5.1 Summary of Technical Information in the Application 

Concrete Containment Tendon Prestress Analyses 

LRA Section 4.5 summarizes the evaluation of concrete containment tendon prestress for the 

period of extended operation. The LRA states that Units 1 and 2 containment have no 

prestressed tendons.

4.5.2 Staff Evaluation 

Units 1 and 2 containments have no prestressed tendons; therefore, the staff finds that this 

TLAA is not required.

4.5.3 UFSAR Supplement 

The staff concludes that no UFSAR supplement is required because Units 1 and 2 have no 

prestressed tendons in their containment buildings.

4.5.4 Conclusion 

On the basis of its review, as discussed above, the staff concludes this TLAA is not required.

4.6 

4.6.1 Reactor Containment Vessel Fatigue

Containment and Penetration Fatigue Analyses 

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 summarizes the evaluation of the primary containment for each unit, which 

consists of a cylindrical steel pressure vessel and is referred to as the Reactor Containment 

Vessel (RCV). The function of the RCV is to confine radioactive materials that could be released 

by accidental loss of integrity of the Reactor Coolant System pressure boundary. The LRA 
4-52

further states that the RCV is completely enclosed within the concrete Shield Building. A fivefoot annular space is provided between the RCV and the shield building. 

LRA Section 4.6.1 stated 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 

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 oF to 120 oF as 200 

cycles. LRA Table 4.3-1 indicates 126 heatup and 124 cooldown occurrences for a 60-year 

span; therefore, the applicant said 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 stated that RCV fatigue TLAA has been dispositioned 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 UFSAR

Table 4.1-8 and verified that the original plant design was for 200 heatup and cooldown cycles. 

The staff found that the projected thermal cycles of 126 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 UFSAR Supplement 

The applicant also provided an UFSAR supplement summary description of its TLAA evaluation 

of the RCV fatigue in LRA Section A4.4. On the basis of its review of the UFSAR 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.

4.6.1.4 Conclusion 

On the basis of its review, as previously discussed, the staff concludes that the applicant has 

demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that for the RCV fatigue TLAA, the analyses of 

both Units’ RCVs remain valid through the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 
4-53

4.6.2 Containment Penetration Fatigue

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 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 B31.1.0-67 which begins to decrease code allowable 

stresses when thermal cycles become greater than 7,000. The penetrations designed as hot 

piping penetrations (> 250oF) are discussed in LRA Section 4.6.2. The LRA states the 

evaluation indicates that 7,000 thermal cycles will not be exceeded during the period of 

extended operation for any of the hot penetrations. Therefore, the applicant stated 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 4.6.2, 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 UFSAR 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 are 126 for heatup, 124 for cooldown, and 168 for reactor trips. These values 

bound the number of thermal cycles for the containment penetrations and will not 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 UFSAR Supplement 

The applicant provided an UFSAR supplement summary description of the TLAA evaluation of 

the containment penetration fatigue in LRA Section A4.4. On the basis of its review of the 

UFSAR 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 previously discussed, 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 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d). 

4.7 

LRA Section 4.7 summarizes the evaluation of the following plant-specific TLAAs:

Other Plant-Specific TLAA 
4-54

 • RCS piping leak-before-break analyses

 • reactor vessel underclad cracking

 • reactor coolant pump flywheel

 • fatigue analysis of cranes

 • probability of damage to safeguards equipment from turbine missiles

4.7.1 RCS Piping Leak-Before-Break Analyses 

4.7.1.1 Summary of Technical Information in the Application

The applicant evaluated postulated flaw growth as part of its original leak-before-break (LBB) 

analyses. These analyses consider the thermal aging of the cast austenitic stainless steel 

(CASS) piping and fatigue transients that cause the postulated flaw to grow during the operating 

life of the plant. These two analyses (thermal aging of the CASS and fatigue crack growth) could 

be influenced by time. Therefore, the applicant identified LBB analyses as potential TLAAs for 

PINGP, Units 1 and 2. 

In 1984, the applicant performed LBB analyses for the Unit 1 primary loop piping. In 1991, the 

applicant performed LBB analyses for the Unit 1 pressurizer surge line. The results of the LBB 

analyses are documented in reports, WCAP-10640-NP and WCAP-10639-P (-NP is the 

nonproprietary version and -P is the proprietary version) for the primary coolant piping and 

WCAP-12876-NP and WCAP-12877-P for the pressurizer surge line. WCAP-10640-NP 

established the methodology to evaluate thermal aging fracture toughness properties for LBB 

analyses of CASS in the primary loop fittings. The pipe straight sections are made from 

forgings. The NRC approved the application of the LBB methodology to PINGP Unit 1 primary 

loop piping in 1986. The NRC approved the Unit 1 surge line LBB analysis in September 1992. 

The applicant included the time-related assumptions in the thermal aging of CASS large bore 

main coolant piping and in the fatigue crack growth analyses of both large bore primary coolant 

piping and the surge line. 

In 1986, the applicant performed LBB analyses for the Unit 2 primary loop piping. The results of 

the analyses are documented in WCAP-10928-NP for the main coolant piping. 

WCAP-10928-NP established the methodology to evaluate thermal aging fracture toughness 

properties for LBB analyses of CASS in the primary loop pipe and fittings. The NRC approved 

the application of the LBB methodology to PINGP Unit 2 in 1986. The time-related assumptions 

include the following two analysis considerations: the thermal aging of CASS and the fatigue 

crack growth analysis. 

The first analysis consideration in WCAP-10640-NP and WCAP-10928-NP that could be 

influenced by plant operating time is the material properties of CASS used in the pipe fittings. 

Thermal aging causes an elevation in the yield strength of CASS and a decrease in fracture 

toughness, the decrease being proportional to the level of ferrite in the material. Thermal aging 

in CASS will continue until a saturation or fully aged point is reached. WCAP-10640-NP, 

WCAP-10928-NP, and WCAP-10930-NP address the fracture toughness properties of statically 

cast CF8M stainless steel. Specifically, fully aged fracture toughness values were used to 

conservatively calculate the JIC values for the cast pipe and fittings. The applicant stated that as 

the LBB evaluations for both units use fully aged fracture toughness properties, the thermal 
4-55

embrittlement analyses do not have a material property time-dependency and are not 

considered TLAAs. 

The second analysis consideration that could be influenced by time is the accumulation of 

actual fatigue transient cycles used in WCAP-10640-NP, WCAP-12876-NP, and 

WCAP-10928-NP. The applicant developed fatigue crack growth rate laws in a PWR 

environment based on available industry literature. The applicant evaluated the crack growth for 

all normal, upset, and test reactor vessel fatigue transients. The applicant noted that these 

design transients have not been changed or increased for license renewal as discussed in 

Section 4.3 of the LRA. 

4.7.1.2 Staff Evaluation

Pursuant to 10 CFR 54.21(c)(1)(i), the staff reviewed LRA Section 4.7.1 to verify that the LBB 

analyses for the main coolant loop 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 main coolant piping will be adequately managed for the period of extended 

operation. 

The TLAA concerns are thermal aging of the CASS material and fatigue crack growth analyses 

of the subject piping because these two issues are time-dependent. By letter dated 

November 20, 2008, the staff raised issues related to the applicant’s TLAA of the LBB analyses 

in LRA Section 4.7.1 and requested additional information. By letter dated December 11, 2008, 

the applicant provided its response to the staff’s RAI on Section 4.7.1. The technical issues 

related to the TLAA evaluation of the LBB analyses are as follows.

In response to RAI 4.7.1-1, the applicant provided the inspection history of the piping that has 

been approved for LBB at PINGP Units 1 and 2. The applicant stated that the primary loop 

piping in both units and the pressurizer surge line piping in Unit 1 and associated nozzle welds 

have been periodically examined in accordance with the requirements of ASME Code Section 

XI. The applicant used surface and volumetric inspection techniques since the beginning of the 

third inservice inspection interval, which began on December 17, 1993 for Unit 1 and on 

December 21, 1994 for Unit 2. The applicant reported that based on surface examination, some 

minor surface indications (e.g., small rounded and linear indications) were identified on the RCS 

piping. These indications were evaluated and dispositioned per the requirements of ASME Code 

Section XI. Some indications were removed (e.g., by light buffing), while others were found 

acceptable per the ASME Code, Section XI, and left in place. A review of the volumetric 

examination results found that some geometric indications were identified but no volumetric 

indications required corrective action or repair/replacement.

The RCS piping is currently subject to examination in accordance with ASME Code Section XI, 

1998 Edition, including the 1998, 1999, and 2000 Addenda, and the approved Risk Informed 

Inservice Inspection (RI-ISI) Program. These examinations will continue until the end of the 

current (fourth) inspection interval. Under the current inspection program, the associated piping 

and nozzle welds are volumetrically examined. Following completion of the current inspection 

interval, the PINGP aging management program (AMP), ASME Code Section XI Inservice 

Inspection, Subsections IWB, IWC, and IWD Program, will be updated as required by 

10 CFR 50.55a, and examinations will be conducted accordingly. The staff finds that the 
4-56

applicant has followed and will follow the requirements of ASME Code, Section XI and 

10 CFR 50.55a in performing examinations of LBB piping. Therefore, the staff finds the 

inspection program of the LBB piping at PINGP Units 1 and 2 is acceptable.

In response to RAI 4.7.1-2, the applicant clarified that the Unit 1 large bore primary coolant 

piping fittings (elbows) are fabricated from CASS (i.e., American Society for Testing and 

Materials (ASTM) A351). The Unit 1 large bore primary coolant piping straight sections are 

made from forgings (i.e., ASTM A376). All Unit 2 large bore primary coolant piping fittings and 

straight sections are fabricated from CASS (i.e., ASTM A351). The Units 1 and 2 pressurizer 

surge line piping fittings and straight sections are fabricated from forged product forms (i.e., 

ASTM A376, A403). Also, in response to RAI 4.7.1-3, the applicant clarified that LBB technology 

has not been implemented and LBB analyses have not been submitted to the NRC for the 

PINGP Unit 2 pressurizer surge line.

In RAI 4.7.1-4, the staff noted that Nickel-based Alloy 600/82/182 material in the PWR 

environment has been shown to be susceptible to primary water stress corrosion cracking 

(PWSCC). The staff asked the applicant to identify any Units 1 and 2 LBB piping which contain 

Alloy 82/182 weld metal and Alloy 600 components, to discuss any mitigation measures (such 

as weld overlays or mechanical stress improvement) that have been or will be implemented to 

reduce the effects of PWSCC on the LBB piping components, and to discuss the inspection 

history and future inspection frequency of the Alloy 81/182 dissimilar metal butt welds. 

In response to RAI 4.7.1-4, the applicant stated that PINGP has no LBB piping which contains 

Alloy 82/182 weld metal or Alloy 600 components. The applicant noted that the Unit 2 

pressurizer surge nozzle-to-safe end dissimilar metal weld is constructed of Alloy 82; however, 

this piping has not been approved for LBB.

To mitigate the effects of PWSCC on the Unit 2 pressurizer surge nozzle weld, a full structural 

weld overlay (FSWOL) on the pressurizer surge nozzle-to-safe end dissimilar metal and safe 

end-to-reducer stainless steel butt welds was recently installed during the PINGP Unit 2 

refueling outage (2R25). The NRC authorized the installation of the FSWOL in a letter dated 

June 15, 2008 [ADAMS Accession No. ML081360646].

The applicant ultrasonically examined the PlNGP Unit 2 pressurizer surge nozzle-to-safe end 

weld in November 2006 per ASME Code Section XI, Appendix VIII, Supplement 10. The 

examination met the ASME Code Section XI and EPRI MRP-139, "Primary System Piping Butt 

Weld Inspection and Evaluation Guidelines" requirements for examination coverage. No 

PWSCC indications were detected.

The applicant also ultrasonically examined the Unit 2 surge nozzle-to-safe end dissimilar metal 

weld in September 2008, prior to installation of the full structural weld overlay (FSWOL). The 

examinations were performed in accordance with the qualification requirements of ASME Code 

Section XI, Appendix VIII, Supplement 10. No recordable indications were identified.

In October 2008, following installation of the FSWOL, the applicant ultrasonically examined the 

new overlay weld and the nozzle-to-safe end dissimilar metal weld. One hundred percent of the 

Code required volume was inspected during the examinations. The ultrasonic test (UT) resulted 

in no recordable indications. 
4-57

Although the Unit 2 surge line has not been approved for LBB application and, therefore, is not 

part of the TLAA evaluation, the staff notes that the applicant has mitigated the potential for 

PWSCC of the nozzle-to-safe end dissimilar metal weld with a weld overlay. The applicant has 

inspected the subject weld in accordance with the NRC approved Alternative Request 2-RR-4-8. 

Therefore, the issue of PWSCC of the Alloy 82/182 dissimilar metal welds is closed. 

In RAI 4.7.1-5, the staff stated that the applicant discusses AMP B2.1.39, Thermal Aging 

Embrittlement of CASS Program, in Appendix B of the LRA. However, Section 4.7.1 of the LRA 

does not mention this AMP to manage the LBB piping that is made of CASS. The staff asked 

the applicant to discuss how CASS material of the LBB piping will be managed because AMP 

B2.1.39 does not seem to be used to monitor the CASS components in the LBB piping systems 

for thermal aging embrittlement. 

In response to RAI 4.7.1-5, the applicant stated that as specified in PINGP LRA Table 3.1.2-2, 

the Thermal Aging Embrittlement of CASS Program manages reduction of fracture toughness 

due to thermal aging embrittlement of CASS piping and fittings in the RCS piping. This is 

consistent with NUREG-1801, Line Item IV.C2-4. The Unit 1 and 2 RCS piping and fittings 

constructed of ASTM A351, CF8M material, are included in the scope of AMP B2.1.39.

The staff finds that the applicant does use AMP B2.1.39, Thermal Aging Embrittlement of CASS 

Program, which is consistent with the same program in NUREG-1801, to monitor the CASS 

components in the LBB piping system. Therefore, this issue is closed. The discussion below 

provides more details on the CASS component program.

In RAI 4.7.1-6, the staff noted that by letter dated May 19, 2000, the NRC forwarded to the 

Nuclear Energy Institute an evaluation of thermal aging embrittlement of CASS components 

[ADAMS Accession No. ML003717179]. In the NRC’s evaluation, the staff provided its positions 

on aging management of CASS components. The staff asked the applicant to address how the 

CASS components in the LBB piping at both units satisfy the staff positions in its evaluation 

dated May 19, 2000.

In response to RAI 4.7.1-6, the applicant stated that as described in its May 19, 2000 letter, the 

staff’s position on thermal aging embrittlement in primary system CASS components has been 

incorporated in NUREG-1801, Chapter XI, Program XI.M12, Thermal Aging Embrittlement of 

CASS. The program includes (a) determination of the susceptibility of CASS components to 

thermal aging embrittlement, and (b) for potentially susceptible components, aging management 

is accomplished through either enhanced volumetric examination or plant- or componentspecific flaw tolerance evaluation. 

As shown in LRA Table 3.1.2-2, PINGP relies on the Thermal Aging Embrittlement of CASS 

Program to manage the reduction of fracture toughness in CASS RCS piping and fittings. As 

described in LRA Section B2.1.39, the PINGP Thermal Aging Embrittlement of CASS Program 

is a new program that will be consistent with the recommendations of NUREG-1801, Chapter 

XI, Program XI.M12, Thermal Aging Embrittlement of CASS. 

The PINGP Thermal Aging Embrittlement of CASS Program scope includes the following CASS 

piping components which have been approved for LBB:
4-58

 • Unit 1 large bore primary coolant piping fittings (elbows), which are constructed of

statically cast ASTM A351, Type CF8M material

 • Unit 2 large bore primary coolant piping (straight sections), which is constructed of 

centrifugally cast ASTM A351, Type CF8M material

 • Unit 2 large bore primary coolant piping fittings (elbows), which are constructed of 

statically cast ASTM A351, Type CF8M material

The PINGP Thermal Aging Embrittlement of CASS Program includes a determination of the 

susceptibility of CASS components to thermal aging embrittlement based on casting method, 

molybdenum content, and percent ferrite. After applying the screening criteria specified in 

Section 3 of the May 19, 2000 letter and NUREG-1801, XI.M12, Element 1, the following CASS 

components, in the scope of the CASS aging management program, were determined to be 

potentially susceptible to thermal aging embrittlement:

A segment of straight RCS piping is potentially susceptible to thermal aging embrittlement due 

to its high molybdenum content and ferrite content which exceeds 20 percent by weight:

Unit 2 RCS 27.5-inch inside diameter cold leg piping in Loop A, Heat Number C-1737

The following RCS fittings are potentially susceptible to thermal aging embrittlement due to their 

high molybdenum content and ferrite content which exceeds 14 percent by weight:

 • Unit 1 RCS 27.5-inch inside diameter, 35 degree Elbow, Heat No. 33676

 • Unit 1 RCS 31.0-inch inside diameter, 90 degree Elbow w/Splitter, Heat No. 13704

 • Unit 1 RCS 31.0-inch inside diameter, 90 degree Elbow w/Splitter, Heat No. 19114

 • Unit 2 RCS 27.5-inch inside diameter, 35 degree Elbow, Heat No. 37758-2

 • Unit 2 RCS 31.0-inch inside diameter, 40 degree Elbow, Heat No. 38992-3

 • Unit 2 RCS 31.0-inch inside diameter, 90 degree Elbow, Heat No. 392312

For the CASS components determined to be potentially susceptible to thermal aging 

embrittlement, in accordance with criteria specified in Section 3.0 of the May 19, 2000 letter and 

in NUREG-1801, XI.M12, Elements 3 and 4, the PINGP CASS aging management program will 

provide enhanced volumetric examinations to detect and size cracks, or component-specific 

flaw tolerance evaluations will be performed. The PINGP CASS aging management program 

will provide enhanced volumetric examinations on the base metal determined to be limiting due 

to applied stress, operating time, and environmental considerations, using examination methods 

that meet the criteria of ASME Code Section XI, Appendix VIII. Alternatively, component-specific 

flaw tolerance evaluations will be performed using specific geometry and applied stress to 

demonstrate that the thermally-embrittled material has adequate toughness.

Per NUREG-1801, XI.M12, Element 5, the PINGP CASS Program will incorporate the 

inspection schedule of IWB-2400 or IWC-2400 for potentially susceptible CASS components 

using ASME examination methods for the detection of cracking. Alternatively, componentspecific flaw tolerance evaluations will be performed. Consistent with the criteria specified in 

Section 3.0 of the May 19, 2000 letter and in NUREG-1801, XI.M12, Element 6, flaws detected 

in CASS components will be evaluated in accordance with the applicable procedures of 

IWB-3500 or IWC-3500 in Section XI of the ASME Code. Alternatively, flaw tolerance evaluation 
4-59

for components with ferrite content up to 25 percent will be performed according to the 

principles associated with IWB-3640 procedures for submerged arc welds disregarding the 

ASME Code restriction of 20 percent ferrite in IWB-3641(b)(1). PINGP does not have RCS 

CASS piping with greater than 25 percent ferrite. Per NUREG-1801, XI.M12, Element 7, repair 

and replacement of CASS components will be performed in accordance with the requirements 

of ASME Code Section XI, Subsection IWA-4000.

The staff finds that the applicant’s Thermal Aging Embrittlement of CASS Program is consistent 

with the staff’s guidance in its May 19, 2000 letter and NUREG-1801. Therefore, the applicant’s 

management of the thermal aging of the CASS components is acceptable. 

In RAI 4.7.1-7, the staff asked the applicant whether the current fatigue crack growth analyses 

are performed for 60 years. In response to RAI 4.7.1-7, the applicant clarified that as reported in 

Section 6.0 of WCAP-10640-NP and WCAP-10639-P (for Unit 1) and WCAP-10928-NP and 

WCAP-10929-P (for Unit 2), the purpose of the fatigue crack growth analyses for the primary 

coolant loop piping was to determine the sensitivity of the piping to the presence of small 

cracks. For the Unit 1 and Unit 2 large primary loop piping, a finite element stress analysis was 

completed for one of the highest-stressed cross sections of a plant typical in geometry and 

operational characteristics to any Westinghouse PWR system, such as PINGP Units 1 and 2. 

Crack growths calculated in the selected region are representative of the entire primary loop. All 

normal, upset, and test conditions were considered, and circumferentially oriented surface flaws 

were postulated in the region, assuming the flaw was located in three different locations of the 

pipe. Fatigue crack growth rate laws were used. The results of fatigue crack growth at 40 years 

for semi-elliptical surface flaws of circumferential orientation and various depths show that crack 

growth is very small at all three locations.

The TLAAs associated with the fatigue crack growth analyses are the normal, upset, and test 

conditions (i.e., NSSS design transients) that were used to calculate fatigue crack growth at 40 

years. These design transients have not been changed or increased for license renewal as 

discussed in Section 4.3 of the PINGP LRA. The existing numbers of thermal and loading cycles 

for each transient remain valid for 60 years of plant operation. Therefore, the fatigue crack 

growth calculations reported in WCAP-10640-NP and WCAP-10639-P (Unit 1) and 

WCAP-10928-NP and WCAP-10929-P (Unit 2) remain valid for the period of extended operation 

in accordance with 10 CFR 54.21(c)(1)(i). 

As reported in Section 6.0 of WCAP-12876-NP and WCAP-12877-P, the purpose of the fatigue 

crack growth analyses for the PINGP Unit 1 pressurizer surge line was to determine the 

sensitivity of the pressurizer surge line to the presence of small cracks when subjected to the 

transients discussed in WCAP-12839, “Structural Evaluation of Prairie Island Unit 1 Pressurizer 

Surge Line, Considering the Effects of Thermal Stratification.”

For the Unit 1 pressurizer surge line, fatigue crack growth analyses were performed at two 

locations where detailed fracture mechanics evaluations were completed: (1) surge line piping 

near the reactor coolant hot leg nozzle, and (2) surge line piping near the pressurizer surge 

nozzle. Various initial semi-elliptical surface flaws with a six-to-one aspect ratio were assumed 

to exist. The largest initial flaw assumed was one with a depth equal to 10 percent of the 

nominal wall thickness. A fatigue crack growth law for austenitic stainless steel in a PWR 

environment was developed and used in the crack growth analyses. The results of fatigue crack 
4-60

growth at 40 years for an initial flaw of 10 percent nominal wall thickness show that crack growth 

is very small at both locations. 

The TLAAs associated with the fatigue crack growth analyses are the normal, upset, and test 

conditions (i.e., NSSS design transients) and pressurizer surge line transient subevents (to 

reflect stratification effects) presented in WCAP-12839 that were used to calculate fatigue crack 

growth at 40 years. The NSSS design transients and pressurizer surge line subevents have not 

been changed or increased for license renewal as discussed in Section 4.3 of the PINGP LRA. 

The existing numbers of thermal and loading cycles for each transient remain valid for 60 years 

of plant operation. Therefore, the fatigue crack growth calculations reported in WCAP-12876-NP 

and WCAP-12877-P remain valid for the period of extended operation in accordance with 

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

The staff finds that although the fatigue crack growth for primary loop piping and surge line 

piping was calculated based on 40 years of transients, the transient cycles used in the analysis 

bound 60 years of operation. Therefore, the applicant’s fatigue crack growth calculations are 

acceptable for the extended period of operation.

As part of fatigue crack growth calculations, the staff asked the applicant, in RAI 4.7.1-8, 

whether the Unit 1 pressurizer surge line has experienced temperature transients in which 

temperature differences exceeded the design transients used in the LBB analyses. In response 

to RAI 4.7.1-8, the applicant stated that in accordance with Section 1.1 of WCAP-12876-NP and 

WCAP-12877-P, the results of the pressurizer surge line thermal stratification evaluation 

described in WCAP-12839 were used in the LBB analyses of the Unit 1 pressurizer surge line. 

PINGP monitors thermal stratification in the pressurizer surge line by tracking the maximum 

temperature differential between the pressurizer water and the RCS (Loop B) hot leg during 

heatups and cooldowns to ensure compliance with the thermal stratification transients defined in 

WCAP-12839. There have been no instances in which temperature differences between the 

pressurizer and RCS have exceeded the design transients defined in WCAP-12839. In addition, 

the numbers of heatup and cooldown cycles experienced by the surge line are within the cycle 

limits specified in the analysis. Therefore, there have been no instances where the Unit 1 

pressurizer surge line has experienced temperature transients that have exceeded the design 

transients used in the LBB analyses. 

The staff finds that Unit 1 pressurizer surge line has not experienced out-of-limit temperature 

transients. Therefore, the fatigue crack growth calculation for Unit 1 surge line has not been 

affected. 

4.7.1.3 UFSAR Supplement 

In LRA Section A4.5, the applicant summarized its RCS LBB analyses as discussed in UFSAR

Sections 4.6.2.3 and 4.6.2.4. The applicant also summarized its TLAA evaluation of the LBB 

analyses for the Units 1 and 2 primary coolant system piping and Unit 1 pressurizer surge line. 

On the basis of its review of the UFSAR supplement, the staff concludes that the summary 

description of the applicant’s actions to address the TLAA evaluation of the subject piping is 

adequate.
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4.7.1.4 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 Units 1 and 2 primary coolant system 

piping and Unit 1 pressurizer surge line remains valid for the period of extended operation. 

Pursuant to 10 CFR 54.21(c)(1)(iii), the staff concludes that the applicant has demonstrated that 

the effects of aging on the intended functions of the Units 1 and 2 primary coolant system piping 

and Unit 1 pressurizer surge line will be adequately managed for the period of extended 

operation. 

The staff concludes further that the UFSAR supplement contains an appropriate summary 

description of the TLAA evaluation of the LBB analyses for primary coolant system piping at 

Units 1 and 2 and for the Unit 1 pressurizer surge line, as required by 10 CFR 54.21(d).

4.7.2 Reactor Pressure Vessel Underclad Cracking 

4.7.2.1 Summary of Technical Information in Application

Section 4.7.2 of the LRA addresses the TLAA of RPV underclad cracking for the extended 

period of operation. The applicant references Topical Report WCAP-15338, “A Review of 

Cracking with Weld Deposited Cladding in Operating PWR Plants,” (Reference 96) which was 

prepared by the Westinghouse Owners Group (WOG), as the primary analysis for the TLAA of 

RPV underclad cracking. The applicant further references the SER issued by the staff in 

September 2002 (Reference 66), which concludes that the analysis presented in WCAP-15338 

applies to all Westinghouse plants. The applicant states that the analyses contained in 

WCAP-15338 can be used to demonstrate that fatigue growth of the subject flaws is 

insignificant over 60 years of operation and the presence of underclad cracks are of no concern 

relative to the structural integrity of the RPV. In addition, the applicant states that the action 

items specified in the NRC issued SER approving WCAP-15338, are satisfied for PINGP Units 1 

and 2. 

4.7.2.2 Staff Evaluation

The staff reviewed LRA Section 4.7.2 to verify, pursuant to 10 CFR 54.21(c)(1)(i), that the 

analysis has been projected to the end of the period of extended operation. Intergranular 

separations (underclad cracking) in low alloy steel heat-affected zones (HAZ) under austenitic 

stainless steel weld claddings were first identified in 1970 and were reported to occur in only 

SA-508 Class 2 RPV forgings manufactured to a coarse grain practice and clad by high-heatinput submerged arc processes. This type of underclad cracking is known as reheat cracking 

due to the cracking resulting from post-weld heat treatment of single-layer austenitic stainless 

steel cladding that was deposited using high-heat input welding processes. Another type of 

underclad cracking is identified as cold cracking and has occurred in SA-508 Class 3 forgings 

after deposition of the second and third layers of austenitic stainless steel cladding, where 

neither pre-heating nor post-heating was applied during the cladding procedure. The cold 

cracking was determined to be attributable to residual stresses near the yield strength in the 

weld metal or base metal interface after cladding deposition, combined with a crack-sensitive 

microstructure in the HAZ and high levels of diffusible hydrogen in the austenitic stainless steel 
4-62

or Inconel weld metals. Both these types of cracking underneath the RPV cladding are relevant 

to PINGP, Units 1 and 2. Hence, LRA Section 4.7.2 of the PINGP LRA addresses the TLAA of 

the RPV underclad cracking for the extended period of operation. 

WCAP-15338 contains an analysis of underclad cracking and the subsequent growth of these 

cracks with time in the RPV steel. The WOG concluded that the evaluation contained in this 

report may be used to demonstrate that fatigue growth of the subject flaws is insignificant over 

60 years and the presence of the underclad cracks are of no concern relative to the structural 

integrity of the RPV. The staff issued a SER dated September 25, 2002 for WCAP-15338 and 

concluded that Westinghouse’s methodology in performing the flaw evaluation is consistent with 

well-established flaw evaluation procedures and criteria in the ASME Code and, therefore, is 

adequate. In addition, the staff concluded that any WOG plant may reference WCAP-15338 in a 

LRA to satisfy the requirements of 10 CFR 54.21(c)(1) for demonstrating the appropriate 

findings regarding evaluation of TLAA for the RPV components for the period of extended 

operation. 

However, in order for a license renewal applicant to reference the WCAP-15338 report when 

considering the TLAA of RPV underclad cracking, the applicant must complete the following 

action items: 

The license renewal applicant is to verify that its plant is bounded by the WCAP-15338 report. 

Specifically, the renewal applicant is to indicate whether or not the number of design cycles and 

transients assumed in the WCAP-15338 analysis bounds the number of cycles for 60 years of 

operation of its RPV. 

Section 54.21(d) of 10 CFR requires that an UFSAR supplement for the facility contains a 

summary description of the programs and activities for managing the effects of aging and the 

evaluation of TLAA for the period of extended operation. Those applicants for license renewal 

referencing the WCAP-15338 report for the RPV components shall ensure that the evaluation of 

the TLAA is summarily described in the UFSAR supplement.

The applicant has referenced WCAP-15338 in LRA Section 4.7.2 and states that both the above 

action items pertaining to license renewal TLAA of RPV underclad cracking are satisfied. PINGP 

is a 2-loop plant, thus for action item 1, the applicant provided the design cycles and transients 

for PINGP, Units 1 and 2 in Table 4.1-8 of the PINGP UFSAR and LRA Table 4.3-1 and 

concluded that the number of these design cycles and transients is less than the number of

design cycles and transients used in the WCAP-15338 report analysis. However, WCAP-15338 

does not explicitly state the number of design cycles and transients used in the analysis. 

Therefore, the staff issued RAI 4.7.2 in a letter dated November 4, 2008, requesting the 

applicant to provide the bounding number of design cycles and transients that were used in the 

WCAP-15338 report analysis. The applicant submitted a response to RAI 4.7.2 in a letter dated 

November 12, 2008 to the NRC, wherein the applicant provided the number of design cycles 

and transients that were used in the WCAP-15338 report analysis. Specifically, the applicant 

stated that the number of design cycles used in the fatigue crack growth evaluation is reported 

in a table on page 9-10 of WCAP-15338-A, where WCAP-15338-A is the accepted version of 

the WCAP-15338 report. Based on 60 years of plant operation, the projected number of design 

cycles and transients expected to be experienced by PINGP, Units 1 and 2 as shown in Table 

4.3-1 of the LRA are bounded by the number of design cycles and transients assumed in the 
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WCAP-15388-A analysis as given in the table on page 9-10 of the WCAP-15388-A report. 

Therefore, the staff confirms that the requirements of action item 1 are satisfied. 

For action item 2, PINGP provided a summary description of the RPV underclad cracking TLAA 

evaluation in its UFSAR supplement, which is contained in Appendix A4.6 of the LRA. Therefore 

action item 2 above is also satisfied. 

4.7.2.3 UFSAR Supplement

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the RPV underclad cracking in LRA Appendix A4.6. On the basis of its review of the UFSAR

supplement, the staff concludes that the summary description of the applicant’s actions to 

address the RPV underclad cracking TLAA is adequate.

4.7.2.4 Conclusion

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the RPV underclad cracking 

TLAA has been projected to the end of the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.3 Reactor Coolant Pump Flywheel

4.7.3.1 Summary of Technical Information in Application

Section 4.7.3 of LRA addresses the TLAA of the reactor coolant pump flywheel. Specifically, the 

applicant has addressed the effect of fatigue crack initiation and growth in the flywheel bore 

keyway from stresses due to starting the motor. The applicant has referenced the analysis 

contained in Topical Report WCAP-15666, “Extension of Reactor Coolant Pump Motor Flywheel 

Examination,” which evaluates the fatigue crack initiation and growth in the reactor coolant 

pump flywheel for 60 years. The applicant stated that the analysis presented in WCAP-15666 

adequately addresses the stress and fracture evaluation pertaining to fatigue crack initiation and 

growth through the extended period of operation, thus satisfying the reactor coolant pump 

flywheel TLAA requirements in accordance with 10 CFR 54.21(c)(1)(i). 

4.7.3.2 Staff Evaluation

The staff reviewed LRA Section 4.7.3 to verify, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

reactor coolant pump flywheel TLAA has been projected to the end of the period of extended 

operation.

The reactor coolant pump motors are large, vertical, squirrel cage, induction motors. The motors 

have flywheels to increase rotational-inertia, thus prolonging pump coastdown and assuring a 

more gradual loss of main coolant flow to the core in the event that the pump power is lost. The 

flywheel is mounted on the upper end of the rotor, above the upper radial bearing and inside the 

motor frame. The aging effect of concern is fatigue crack initiation and growth in the flywheel 

bore keyway from stresses due to starting the motor. 
4-64

Topical Report WCAP-15666 provides analyses of the fatigue crack initiation and growth in the 

flywheel bore keyway from stresses due to starting the motor. Based on the results of the 

WCAP-15666 analyses, the fatigue crack growth in the flywheel after 6,000 cycles of the reactor 

coolant pump (60-year plant life) determined using the approved methodology of ASME Code, 

Section XI, is negligible (0.08 in) even when assuming a conservative initial crack length of 

10 % through the flywheel. In addition, according to the SER (January 2003) for WCAP-15666, 

the staff found the pump flywheel conditional failure probability analysis in the report to be fairly 

conservative in its assumptions of input parameters (pump motor revolutions per minute, 

number of cycles per year, initial crack length) required to predict critical crack sizes through the 

extended period of operation and that this probabilistic approach supported the negligible 

fatigue crack growth analysis previously mentioned. Therefore, the staff finds the fatigue crack 

growth TLAA for PINGP Units 1 and 2 reactor coolant pump flywheels for the extended period of 

operation to be acceptable on the basis of the staff’s acceptability of the WCAP-15666 

analyses. 

4.7.3.3 UFSAR Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the reactor coolant pump flywheels in LRA Appendix A4.7. On the basis of its review of the 

UFSAR supplement, the staff concludes that the summary description of the applicant’s actions 

to address the reactor coolant pump flywheel TLAA is adequate.

4.7.3.4 Conclusion

Based on the staff’s review as discussed in the above evaluation, the staff concludes that the 

applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the reactor coolant pump 

flywheel TLAA has been projected to the end of the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an appropriate summary description of the 

TLAA evaluation, as required by 10 CFR 54.21(d).

4.7.4 Fatigue Analysis of Cranes 

4.7.4.1 Summary of Technical Information in the Application 

In LRA Section 4.7.4, the applicant states that the polar cranes, auxiliary building crane, turbine 

building cranes, and spent fuel crane were qualified to Electric Overhead Crane Institute (EOCI) 

Specification # 61 but are in compliance with the design standards of CMAA-70, with limited 

exceptions. The applicant also states that among the criteria of CMAA-70 is a design load cycle 

limit of 20,000 cycles and NMC has reviewed these cranes and determined that even very 

conservative estimates of the number of cycles to be achieved in 60 years of operation do not 

exceed the 20,000 cycle limit in CMAA-70. 

Therefore, the applicant concludes that the crane designs will remain valid for the period of 

extended operation in accordance with the requirements of 10 CFR 54.21(c)(1)(i).
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4.7.4.2 Staff Evaluation 

The staff reviewed LRA Section 4.7.4, pursuant to 10 CFR 54.21(c)(1)(i), to verify that the 

analyses remain valid for the period of the extended operation.

The staff noted that the fatigue usage of cranes is directly proportional to the number of times 

the cranes perform load lifting duties. Since the information contained in LRA Section 4.7.4 is 

insufficient for making a fatigue evaluation, the staff issued RAI 4.7.4-1, in a letter dated 

December 10, 2008, requesting the applicant to provide an estimate for the number of lifting 

cycles that have occurred in the polar cranes, auxiliary building crane, the turbine building 

cranes, and spent fuel crane and the 60-year lifting cycle projections for these cranes.

In a letter dated January 09, 2009, NSPM responded to RAI 4.7.4-1 stating that the NUREG0612 cranes with fatigue TLAAs include the polar cranes, auxiliary building crane, the turbine 

building cranes, and spent fuel crane, and the cranes are described in Section 12.2.12 of the 

PINGP UFSAR. The applicant states in its response to RAI 4.7.4-1 that Northern States Power 

Company (NSP) has previously issued a letter to the NRC, dated November 8, 1982, titled 

“Control of Heavy Loads (Response to Staff Concerns on the Six Month Submittal),” in which it 

stated that the evaluation of fatigue for the polar cranes, auxiliary building cranes, and turbine 

building cranes assumed 800 design loading cycles for the heaviest load over 40 years. The 

applicant stated that the largest actual load and weight (3,700 pounds) for the spent fuel crane 

is substantially less than the rated crane capacity of 6,000 pounds. The applicant further stated

that this assumed loading cycle allows for two outages per year and ten lifts of the heaviest load 

per outage over 40 years. Multiplying this assumed 800 load cycle by 1.5 to accommodate 60 

years of operation yields a projection of 1,200 heavy load cycles throughout the period of 

extended operation, providing significant margin to the design load cycle limit of 20,000 cycles. 

The applicant states that as of January 2009, both PINGP Unit 1 and 2 have completed 25 

refueling outages. Multiplying 10 lifts of the heaviest load per outage by 25 refueling outages 

yields an estimate of 250 heavy load cycles to date for the polar cranes and turbine building 

cranes, and an estimate of 500 heavy load cycles to date for the auxiliary building crane and the 

spent fuel crane since they service both units. Based upon the estimated number of heavy lifting 

cycles accrued to date, it is not expected that these cranes will attain the projected number of 

lifts (i.e., 1,200) after 60 years of operation.

On the basis of its review, the staff found the applicant has provided the information requested 

and the staff’s concern resolved because the applicant’s estimates, 1,200 cycles for any crane 

over 60 years, are reasonable, with ample margins (greater than 90 percent), to reach the 

design cycle limit (20,000 cycles). Therefore, the structural integrity of the cranes will be 

maintained for safe use during the renewed license term.

4.7.4.3 UFSAR Supplement 

The applicant provided an UFSAR supplement summary description of its TLAA evaluation of 

the cranes in LRA Section A4.8. On the basis of its review of the UFSAR supplement, the staff 

concluded that the summary description of the applicant’s actions to address the crane lifting 

cycle limit issue is adequate.
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4.7.4.4 Conclusion 

On the basis of its review, the staff concludes that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(i), that, for the crane lifting cycle limit TLAA, the crane design analyses will 

remain valid for the period of extended operation. The staff also concludes that the UFSAR

supplement contains an appropriate summary description of the TLAA evaluation, as required 

by 10 CFR 54.21(d).

4.7.5 Probability of Damage to Safeguards Equipment from Turbine Missiles 

The applicant’s basis for deleting LRA Section 4.7.5, Probability of Damage to Safeguards 

Equipment from Turbine Missiles, is discussed in SER Section 4.1.1.1. The staff’s basis for 

concluding that the Turbine Missile Analysis associated with LRA Section 4.7.5, Probability of 

Damage to Safeguards Equipment from Turbine Missiles, is not a TLAA for the LRA is 

discussed in SER Section 4.1.2.1.

4.8 

The staff reviewed the information in LRA Section 4.0, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes, that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3 and that the applicant has demonstrated that: (1) the TLAAs will 

remain valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i); (2) the 

TLAAs have been projected to the end of the period of extended operation, as required by 

10 CFR 54.21(c)(1)(ii); or (3) that the effects of aging on intended function(s) will be adequately 

managed for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staff 

also reviewed the UFSAR supplement for the TLAAs and finds that the supplement contains 

descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, 

the staff concludes, as required by 10 CFR 54.21(c)(2) that no plant-specific, TLAA-based 

exemptions are in effect.

Conclusion for TLAAs 

With regard to these matters, the staff concludes that there is reasonable assurance that the 

activities authorized by the renewed licenses will continue to be conducted in accordance with 

the CLB, and that any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are 

in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulation.
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SECTION 5 

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

The NRC staff issued its safety evaluation report (SER) with open items related to the renewal 

of operating license for the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2 on 

June 4, 2009. On July 7, 2009, the applicant presented its license renewal application, 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 license renewal application. The staff’s evaluation is 

documented in an SER that was issued by letter dated October 16, 2009.

During the 568th meeting of the ACRS held on December 3-5, 2009, the ACRS completed its 

review of the PINGP license renewal application and the NRC staff’s SER. The ACRS 

documented its findings in a letter to the Commission dated December 10, 2009. 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

.

December 10, 2009

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 PRAIRIE ISLAND NUCLEAR GENERATING PLANT, 

UNITS 1 AND 2

Dear Chairman Jaczko:

During the 568th meeting of the Advisory Committee on Reactor Safeguards, December 3-5, 

2009, we completed our review of the license renewal application for the Prairie Island Nuclear 

Generating Plant (PINGP), Units 1 and 2, and the final Safety Evaluation Report (SER) 

prepared by the NRC staff. Our Plant License Renewal Subcommittee also reviewed this 

matter during its meeting on July 7, 2009. During these reviews, we had the benefit of 

discussions with representatives of the NRC staff and the applicant, Northern States Power 

Company, a Minnesota Corporation, (NSPM). We also had the benefit of the documents 

referenced. This report fulfills the requirement of 10 CFR 54.25 that the ACRS review and 

report on all license renewal applications.

CONCLUSION AND RECOMMENDATION

1. The programs established and committed to by the applicant to manage age-related 

degradation provide reasonable assurance that PINGP, Units 1 and 2 can be operated in 

accordance with their current licensing bases for the period of extended operation without 

undue risk to the health and safety of the public.

2. The NSPM application for renewal of the operating licenses of PINGP, Units 1 and 2 should 

be approved.

BACKGROUND AND DISCUSSION 

PINGP consists of two two-loop pressurized water reactors with dry ambient pressure 

containments and is located approximately 39 miles southeast of Minneapolis, MN. The 

licensed power output of each unit is 1650 megawatts thermal with a gross electrical output of 

approximately 575 megawatts-electric. NSPM requested renewal of the PINGP, Units 1 and 2 

operating licenses for 20 years beyond the current license terms, which expire on August 9, 

2013, for Unit 1, and on October 29, 2014, for Unit 2.
5-3

In the final SER, the staff documented its review of the license renewal application and other 

information submitted by the applicant or obtained from the staff audits and inspections at the 

plant site. The staff reviewed the completeness of the applicant’s identification of the structures,

systems, and components (SSCs) that are within the scope of license renewal; the integrated 

plant assessment process; the applicant’s identification of the plausible aging mechanisms 

associated with passive, long-lived components; the adequacy of the applicants Aging 

Management Programs (AMPs); and the identification and assessment of time-limited aging 

analyses (TLAAs) requiring review.

In the license renewal application, NSPM identified the SSCs that fall within the scope of license 

renewal. For these SSCs, the applicant performed a comprehensive aging management 

review. Based on this review, the applicant will implement 43 AMPs for license renewal, which 

include existing, new, and enhanced programs. Ten programs have exceptions to the 

corresponding programs described in the Generic Aging Lessons Learned (GALL) Report. Two 

of the programs are plant-specific programs that do not have counterparts in the GALL Report. 

The NSPM application either demonstrates consistency with the GALL Report or documents 

deviations to the approaches specified in that Report. As noted above, 10 of the AMPs include 

exceptions to the corresponding programs in the GALL Report. We reviewed these exceptions 

and agree with the staff that they are acceptable. The staff conducted two license renewal 

audits and one inspection at the PINGP site. The audits and in-office reviews verified the 

appropriateness of the scoping and screening methodology, AMPs, aging management review, 

and TLAAs. The inspections verified that the license renewal requirements are appropriately 

implemented. Based on the audits, in-office reviews, and inspections, the staff concluded in the 

final SER that the proposed activities will adequately manage the effects of aging of SSCs 

identified in the application and that the intended functions of these SSCs will be maintained 

during the period of extended operation. We agree with this conclusion.

For 20 years, both PINGP units have experienced intermittent leakage of borated water from 

their refueling cavities, when flooded for refueling, into and through the reinforced concrete 

structures within containments. The leak rate has been 1 to 2 gallons per hour, as measured by 

accumulation in lower levels of the containments. Earlier efforts to locate and seal the sources 

of this leakage were not effective, and additional measures have recently been taken to prevent 

further leakage.

The staff established an Open Item to address three issues related to the prior, and any future, 

refueling cavity leakage: (1) the leaking borated water may contact the containment vessel, 

remain in contact with the vessel between outages, and cause degradation; (2) the leaking 

borated water may contact the concrete reinforcement and cause degradation; and (3) the 

leaking borated water may react with the concrete and cause degradation.

As described in the final SER, the applicant has performed a number of inspections and 

evaluations to verify that no unacceptable degradation has occurred. Also, the applicant has 

committed to perform additional inspections and evaluations, prior to entering the period of 

extended operation, to ensure that no unacceptable degradation of the containment vessel, the 
5-4

concrete reinforcement, or the concrete has occurred as a result of the intermittent leakage from 

the refueling cavities. The commitments include the removal of concrete from a low point in the 

containment and inspection of the exposed containment vessel bottom head and reinforcing 

steel. Also, the applicant will remove concrete samples known to have been exposed to 

borated water leakage, test them for compressive strength, and perform a petrographic 

examination to evaluate for degradation. 

Repairs performed during the fall 2009 Unit 1 refueling outage appear to have reduced the leak 

rate substantially. Similar repairs are planned for Unit 2 during the 2010 spring refueling outage. 

During the two consecutive refueling outages following cavity leak repairs in each unit, the 

applicant will perform visual inspections of the areas where reactor cavity leakage had been 

observed previously to confirm that the leakage issue has been resolved.

The staff concludes that these inspections, evaluations, and commitments are adequate to 

address the refueling cavity leakage issue. We agree with this conclusion.

The staff identified water in manholes as a generic, current operating plant issue in Information 

Notice 2002-12, “Submerged Safety-Related Electrical Cables,” and Generic Letter 2007-01, 

“Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients.” There is one manhole at PINGP that contains medium voltage cables 

in scope of license renewal and is subject to periodic inspection for the accumulation of water. 

NSPM has committed to implement a Non-EQ Inaccessible Medium-Voltage Cables Program 

involving two parts: first, inspection (and draining, if necessary) of the applicable manholes on a 

periodic basis; and second, the conduct of periodic testing to confirm that the condition of the 

conductor insulation on the applicable cables is not degrading. This new AMP will be 

implemented prior to entering the period of extended operation. 

The staff has determined that implementation of the Non-EQ Inaccessible Medium-Voltage 

Cables Program will ensure that the aging effects on inaccessible medium-voltage cables will be 

adequately managed during the period of extended operation. We agree with this conclusion.

The applicant identified the systems and components requiring TLAAs and reevaluated them for 

the period of extended operation. The staff concluded that the applicant has provided an 

adequate list of TLAAs. Further, the staff concluded that 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. 
5-5

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 licenses for PINGP, Units 1 and 2. 

The programs established and committed to by NSPM provide reasonable assurance that the 

PINGP Units 1 and 2 can be operated in accordance with their current licensing bases for the 

period of extended operation without undue risk to the health and safety of the public. The 

NSPM application for renewal of the operating licenses for PINGP, Units 1 and 2 should be 

approved.

Sincerely,

/RA/

Mario V. Bonaca 

Chairman
5-6

REFERENCES

1. Memorandum to E. M. Hackett, Executive Director, Advisory Committee on Reactor 

Safeguards, transmitting Advisory Committee on Reactor Safeguards Review of the 

Prairie Island Nuclear Generating Plant, Units 1 and 2 License Renewal Application -

Safety Evaluation Report, 10/16/2009 (ML092730160 and ML092890209)

2. Letter to U.S. Nuclear Regulatory Commission, transmitting Prairie Island, Units 1 and 2 

Application for Renewed Operating Licenses, 04/11/2009 (ML081130666)

3. Letter to M. D. Wadley, Site Vice President, Prairie Island Nuclear Generating Plant, 

transmitting Prairie Island Nuclear Generating Plant, Units 1 and 2 NRC License 

Renewal Scoping, Screening, and Aging Management Inspection Report 

05000282/2009006; 05000306/2009006, 03/27/2009 (ML090860804)

4. Letter to M. D. Wadley, Site Vice President, Prairie Island Nuclear Generating Plant, 

transmitting Prairie Island Nuclear Generating Plant, Units 1 and 2, License Renewal 

Safety Audit Report, 04/21/2009 (ML090850009)

5. U.S. Nuclear Regulatory Commission, NUREG-1801, Volumes 1 & 2, Revision 1, 

“Generic Aging Lessons Learned Report,” 09/2005 (ML052700171)

6. U. S. Nuclear Regulatory Commission, Information Notice 2002-12: Submerged SafetyRelated Electrical Cables, 03/21/2002 (ML020790238)

7. U. S. Nuclear Regulatory Commission, Generic Letter 2007-01: Inaccessible or 

Underground Power Cable Failures that Disable Accident Mitigation Systems or Cause 

Plant Transients, 02/07/2007 (ML070360665)
6-1

SECTION 6 

CONCLUSION

The staff of the U.S. Nuclear Regulatory Commission (the staff) reviewed the license renewal 

application (LRA) for the Prairie Island Nuclear Generating Plant (PINGP), Units 1 and 2, in 

accordance with the NRC regulations and NUREG-1800, “Standard Review Plan for Review of 

License Renewal Applications for Nuclear Power Plants,” dated September 2005. 

Title 10, Section 54.29, of the Code of Federal Regulations (10 CFR 54.29) provides the 

standards for issuance of a renewed license. Pursuant to 10 CFR 54.29(a), the Commission 

may issue a renewed license if it finds that actions have been identified and have been or will be 

taken, such that there is reasonable assurance that the activities authorized by the renewed 

license will continue to be conducted in accordance with the current licensing basis (CLB).

On the basis of its review of the LRA, the staff determines that the requirements of 10 CFR 

54.29(a) have been met.

The staff notes that the requirements of 10 CFR Part 51, Subpart A, will be documented in a 

plant specific supplement to NUREG-1437, “Generic Environmental Impact Statement for 

License Renewal of Nuclear Plants (GEIS).”

APPENDIX A

A-1

APPENDIX A

PINGP UNIT 1 AND UNIT 2 LICENSE RENEWAL COMMITMENTS

During the review of the Prairie Island Nuclear Generating Plant (PINGP) Unit 1 and Unit 2, 

license renewal application (LRA) by the staff of the United States (US) Nuclear Regulatory 

Commission (NRC) (the staff), the applicant made commitments related to aging management 

programs (AMPs) to manage aging effects for structures and components.

The following table lists these commitments along with the implementation schedules and 

sources for each commitment. 

Table 1.1 PINGP License Renewal Commitments

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

Commitment 

Number Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement 

or

Implementation 

Schedule

1 Each year, following the submittal of the PINGP License 

Renewal Application and at least three months before 

the scheduled completion of the NRC review, NMC will 

submit amendments to the PINGP application pursuant 

to 10 CFR 54.21(b). These revisions will identify any 

changes to the Current Licensing Basis that materially 

affect the contents of the License Renewal Application, 

including the UFSAR supplements.

1.4 12 months after LRA 

submittal date and at 

least 3 months before 

completion of NRC 

review

Annual Update 

submitted by letter 

dated 4/13/09

2 Following the issuance of the renewed operating 

license, the summary descriptions of aging 

management programs and TLAAs provided in 

Appendix A, and the final list of License Renewal 

commitments, will be incorporated into the PINGP 

UFSAR as part of a periodic UFSAR update in 

accordance with 10 CFR 50.71(e). Other changes to 

specific sections of the PINGP UFSAR necessary to 

reflect a renewed operating license will also be 

addressed at that time.

A1.0 First UFSAR update in 

accordance with 

10 CFR 50.71(e) 

following issuance of 

renewed operating 

licenses

3 An Aboveground Steel Tanks Program will be 

implemented. Program features will be as described in 

LRA Section B2.1.2.

B2.1.2 U1 - 8/9/2013

U2 - 10/29/2014

4 Procedures for the conduct of inspections in the 

External Surfaces Monitoring Program, Structures 

Monitoring Program, Buried Piping and Tanks 

Inspection Program, and the RG 1.127 Inspection of 

Water-Control Structures Associated with Nuclear 

Power Plants Program will be enhanced to include 

guidance for visual inspections of installed bolting.

B2.1.6 U1 - 8/9/2013

U2 - 10/29/2014

5 A Buried Piping and Tanks Inspection Program will be 

implemented. Program features will be as described in 

LRA Section B2.1.8.

B2.1.8 U1 - 8/9/2013

U2 - 10/29/2014
A-2

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

6 The Closed-Cycle Cooling Water System Program will 

be enhanced to include periodic inspection of 

accessible surfaces of components serviced by closedcycle cooling water when the systems or components 

are opened during scheduled maintenance or 

surveillance activities. Inspections are performed to 

identify the presence of aging effects and to confirm the 

effectiveness of the chemistry controls. Visual 

inspection of component internals will be used to detect 

loss of material and heat transfer degradation. 

Enhanced visual or volumetric examination techniques 

will be used to detect cracking.

[Revised in letter dated 1/20/2009 in response to RAI 

3.3.2-13-01]

B2.1.9 U1 - 8/9/2013

U2 - 10/29/2014

7 The Compressed Air Monitoring Program will be 

enhanced as follows:

· Station and Instrument Air System air quality will be 

monitored and maintained in accordance with the 

instrument air quality guidance provided in ISA S7.0.01-

1996. Particulate testing will be revised to use a 

particle size methodology as specified in ISA S7.0.01.

· The program will incorporate on-line dew point 

monitoring.

[Revised in letter dated 2/6/2009 in response to Region 

III License Renewal Inspection]

B2.1.10 U1 - 8/9/2013

U2 - 10/29/2014

8 An Electrical Cable Connections Not Subject to 10 CFR 

50.49 Environmental Qualification Requirements 

Program will be completed. Program features will be as 

described in LRA Section B2.1.11.

B2.1.11 U1 - 8/9/2013

U2 - 10/29/2014

9 An Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements 

Program will be implemented. Program features will be 

as described in LRA Section B2.1.12.

B2.1.12 U1 - 8/9/2013

U2 - 10/29/2014

10 An Electrical Cables and Connections Not Subject to 10 

CFR 50.49 Environmental Qualification Requirements 

Used in Instrumentation Circuits Program will be 

implemented. Program features will be as described in 

LRA Section B2.1.13.

B2.1.13 U1 - 8/9/2013

U2 - 10/29/2014
A-3

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

11 The External Surfaces Monitoring Program will be 

enhanced as follows:

· The scope of the program will be expanded as 

necessary to include all metallic and non-metallic 

components within the scope of License Renewal that 

require aging management in accordance with this 

program.

· The program will ensure that surfaces that are 

inaccessible or not readily visible during plant 

operations will be inspected during refueling outages.

· The program will ensure that surfaces that are 

inaccessible or not readily visible during both plant 

operations and refueling outages will be inspected at 

intervals that provide reasonable assurance that aging 

effects are managed such that the applicable 

components will perform their intended function during 

the period of extended operation.

· The program will apply physical manipulation 

techniques, in addition to visual inspection, to detect 

aging effects in elastomers and plastics.

· The program will include acceptance criteria (e.g., 

threshold values for identified aging effects) to ensure 

that the need for corrective actions will be identified 

before a loss of intended functions.

· The program will ensure that program documentation 

such as walkdown records, inspection results, 

and other records of monitoring and trending activities 

are auditable and retrievable. 

[Revised in letter dated 2/6/2009 in response to RAI 

B2.1.14-1 Follow up question]

B2.1.14 U1 - 8/9/2013

U2 - 10/29/2014

12 The Fire Protection Program will be enhanced to 

require periodic visual inspection of the fire barrier 

walls, ceilings, and floors to be performed during 

walkdowns at least once every refueling cycle. 

[Revised in letter dated 12/5/2008 in response to RAI 

B2.1.15-3]

B2.1.15 U1 - 8/9/2013

U2 - 10/29/2014

13 The Fire Water System Program will be enhanced as 

follows:

· The program will be expanded to include eight 

additional yard fire hydrants in the scope of the annual 

visual inspection and flushing activities.

· The program will require that sprinkler heads that have 

been in place for 50 years will be replaced or a 

representative sample of sprinkler heads will be tested 

using the guidance of NFPA 25, "Inspection, Testing 

and Maintenance of Water-Based Fire Protection 

Systems" (2002 Edition, Section 5.3.1.1.1). Sample 

testing, if performed, will continue at a 10-year interval 

following the initial testing.

B2.1.16 U1 - 8/9/2013

U2 - 10/29/2014
A-4

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

14 The Flux Thimble Tube Inspection Program will be 

enhanced as follows:

- The program will require that the interval between 

inspections be established such that no flux thimble 

tube is predicted to incur wear that exceeds the 

established acceptance criteria before the next 

inspection.

- The program will require that re-baselining of the 

examination frequency be justified using plant-specific 

wear rate data unless prior plant-specific NRC 

acceptance for the re-baselining was received. If design 

changes are made to use more wear-resistant thimble 

tube materials, sufficient inspections will be conducted 

at an adequate inspection frequency for the new 

materials.

- The program will require that flux thimble tubes that 

cannot be inspected must be removed from service.

B2.1.18 U1 - 8/9/2013

U2 - 10/29/2014

15 The Fuel Oil Chemistry Program will be enhanced as 

follows:

· Particulate contamination testing of fuel oil in the 

eleven fuel oil storage tanks in-scope of License 

Renewal will be performed, in accordance with ASTM D 

6217, on an annual basis.

· One-time ultrasonic thickness measurements will be 

performed at selected tank bottom and piping locations 

prior to the period of extended operation.

B2.1.19 U1 - 8/9/2013

U2 - 10/29/2014

16 A Fuse Holders Program will be implemented. Program 

features will be as described in LRA Section B2.1.20.

B2.1.20 U1 - 8/9/2013

U2 - 10/29/2014

17 An Inaccessible Medium Voltage Cables Not Subject to 

10 CFR 50.49 Environmental Qualification 

Requirements Program will be implemented. Program 

features will be as described in LRA Section B2.1.21

B2.1.21 U1 - 8/9/2013

U2 - 10/29/2014

18 An Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program will be 

implemented. Program features will be as described in 

LRA section B2.1.22. Inspections for stress corrosion 

cracking will be performed by visual examination with a 

magnified resolution as described in 10 CFR 

50.55a(b)(2)(xxi)(A) or with ultrasonic methods.

[Revised in letter dated 2/6/2009 in response to RAI 

B2.1.22-1 Follow Up question]

B2.1.22 U1 - 8/9/2013

U2 - 10/29/2014

19 The Inspection of Overhead Heavy Load and Light

Load (Related to Refueling) Handling Systems Program 

will be enhanced as follows:

· Program implementing procedures will be revised to 

ensure the components and structures subject to 

inspection are clearly identified.

· Program inspection procedures will be enhanced to 

include the parameters corrosion and wear where 

omitted.

B2.1.23 U1 - 8/9/2013

U2 - 10/29/2014

20 A Metal-Enclosed Bus Program will be implemented. 

Program features will be as described in LRA Section 

B2.1.26.

B2.1.26 U1 - 8/9/2013

U2 - 10/29/2014
A-5

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

21 Number Not Used

[Deleted by Applicant in a letter Dated 3/27/2009]

22 Number Not Used

[Deleted by Applicant in a letter Dated 4/13/2009]

23 A One-Time Inspection Program will be completed. 

Program features will be as described in LRA Section 

B2.1.29.

B2.1.29 U1 - 8/9/2013

U2 - 10/29/2014

24 A One-Time Inspection of ASME Code Class 1 SmallBore Piping Program will be completed. Program 

features will be as described in LRA Section B2.1.30.

B2.1.30 U1 - 8/9/2013

U2 - 10/29/2014

25 A. A PWR Vessel Internals Program will be 

implemented. Program features will be as described in 

LRA Section B2.1.32.

B. An inspection plan for reactor internals will be 

submitted for NRC review and approval at least twentyfour months prior to the period of extended operation. 

In addition, the submittal will include any necessary 

revisions to the PINGP PWR Vessel Internals Program, 

as well as any related changes to the PINGP scoping, 

screening and aging management review results for 

reactor internals, to conform to the NRC-approved 

Inspection and Evaluation Guidelines.

[Revised in letter dated 5/12/2009]

[Revised in letter dated 6/24/09 in response to 

Follow-up RAI B2.1.38]

B2.1.32 A. U1 – 8/9/2013

 U2 – 10/29/2014

B. U1 – 8/9/2011

 U2 – 10/29/2012

26 The Reactor Head Closure Studs Program will be 

enhanced to incorporate controls that ensure that any 

future procurement of reactor head closure studs will be 

in accordance with the material and inspection 

guidance provided in NRC Regulatory Guide 1.65.

B2.1.33 U1 - 8/9/2013

U2 - 10/29/2014

27 The Reactor Vessel Surveillance Program will be 

enhanced as follows:

· A requirement will be added to ensure that all 

withdrawn and tested surveillance capsules, not 

discarded as of August 31, 2000, are placed in storage 

for possible future reconstitution and use.

· A requirement will be added to ensure that in the event 

spare capsules are withdrawn, the untested capsules 

are placed in storage and maintained for future 

insertion.

B2.1.34 U1 - 8/9/2013

U2 - 10/29/2014
A-6

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

28 The RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program will be 

enhanced as follows:

· The program will include inspections of concrete and 

steel components that are below the water line at the 

Screenhouse and Intake Canal. The scope will also 

require inspections of the Approach Canal, Intake 

Canal, Emergency Cooling Water Intake, and 

Screenhouse immediately following extreme 

environmental conditions or natural phenomena 

including an earthquake, flood, tornado, severe 

thunderstorm, or high winds.

· The program parameters to be inspected will include 

an inspection of water-control concrete components 

that are below the water line for cavitation and erosion 

degradation. 

· The program will visually inspect for damage such as 

cracking, settlement, movement, broken bolted and 

welded connections, buckling, and other degraded 

conditions following extreme environmental conditions 

or natural phenomena. 

B2.1.35 U1 - 8/9/2013

U2 - 10/29/2014

29 A Selective Leaching of Materials Program will be 

completed. Program features will be as described in 

LRA B2.1.36.

B2.1.36 U1 - 8/9/2013

U2 - 10/29/2014
A-7

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

30 The Structures Monitoring Program will be enhanced as 

follows:

· The following structures, components, and component 

supports will be added to the scope of the inspections:

- Approach Canal

- Fuel Oil Transfer House 

- Old Administration Building and Administration 

Building Addition

- Component supports for cable tray, conduit, cable, 

tubing tray, tubing, non-ASME vessels, exchangers, 

pumps, valves, piping, mirror insulation, 

non-ASME valves, cabinets, panels, racks, equipment 

enclosures, junction boxes, bus ducts, breakers, 

transformers, instruments, diesel equipment, housings 

for HVAC fans, louvers, and dampers, 

HVAC ducts, vibration isolation elements for diesel 

equipment, and miscellaneous electrical and 

mechanical equipment items

- Miscellaneous electrical equipment and 

instrumentation enclosures including cable tray, 

conduit, wireway, tube tray, cabinets, panels, racks, 

equipment enclosures, junction boxes, breaker 

housings, transformer housings, lighting fixtures, and 

metal bus enclosure assemblies 

- Miscellaneous mechanical equipment enclosures 

including housings for HVAC fans, louvers, and 

dampers 

- SBO Yard Structures and components including SBO 

cable vault and bus duct enclosures. 

- Fire Protection System hydrant houses

- Caulking, sealant and elastomer materials

- Nonsafety-related masonry walls that support 

equipment relied upon to perform a function that 

demonstrates compliance with a regulated event(s).

· The program will be enhanced to include additional 

inspection parameters. 

· The program will require an inspection frequency of 

once every five (5) years for structures and 

structural components within the scope of the program.

The frequency of inspections can be adjusted, if 

necessary, to allow for early detection and timely 

correction of negative trends.

· The program will require periodic sampling of 

groundwater and river water chemistries to ensure they 

remain non-aggressive.

B2.1.38 U1 - 8/9/2013

U2 - 10/29/2014

31 A Thermal Aging Embrittlement of Cast Austenitic 

Stainless Steel (CASS) Program will be implemented. 

Program features will be as described in LRA Section 

B2.1.39.

B2.1.39 U1 - 8/9/2013

U2 - 10/29/2014
A-8

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

32 The Water Chemistry Program will be enhanced as 

follows:

· The program will require increased sampling to be 

performed as needed to confirm the effectiveness of 

corrective actions taken to address an abnormal 

chemistry condition.

· The program will require Reactor Coolant System 

dissolved oxygen Action Level limits to be consistent 

with the limits established in the EPRI PWR Primary 

Water Chemistry Guidelines. 

[Revised in letter dated 12/5/2008 in response to RAI 

B2.1.40-3]

B2.1.40 U1 - 8/9/2013

U2 - 10/29/2014

33 The Metal Fatigue of Reactor Coolant Pressure 

Boundary Program will be enhanced as follows:

· The program will monitor the six component locations 

identified in NUREG/CR-6260 for older vintage 

Westinghouse plants, either by tracking the cumulative 

number of imposed stress cycles using cycle counting, 

or by tracking the cumulative fatigue usage, including 

the effects of coolant environment. The following 

locations will be monitored:

- Reactor Vessel Inlet and Outlet Nozzles

- Reactor Pressure Vessel Shell to Lower Head

- RCS Hot Leg Surge Line Nozzle

- RCS Cold Leg Charging Nozzle

- RCS Cold Leg Charging Nozzle

- RCS Cold Leg Safety Injection Accumulator Nozzle

- RHR-to-Accumulator Piping Tee

· Program acceptance criteria will be clarified to require 

corrective action to be taken before a cumulative fatigue 

usage factor exceeds 1.0 or a design basis transient 

cycle limit is exceeded.

[Revised in letter dated 1/9/2009 in response to RAI 

4.3.1.1-1]

B3.2 U1 - 8/9/2013

U2 - 10/29/2014

34 Reactor internals baffle bolt fatigue transient limits of 

1835 cycles of plant loading at 5% per minute and 1835 

cycles of plant unloading at 5% per minute will be 

incorporated into the Metal Fatigue of Reactor Coolant 

Pressure Boundary Program and UFSAR Table 4.1-8. 

B3.2 U1 - 8/9/2013

U2 - 10/29/2014

35 NSPM will perform an ASME Section III fatigue 

evaluation of the lower head of the pressurizer to 

account for effects of insurge/outsurge transients. The 

evaluation will determine the cumulative fatigue usage 

of limiting pressurizer component(s) through the period 

of extended operation. The analyses will account for 

periods of both “Water Solid” and “Standard Steam 

Bubble” operating strategies. Analysis results will be 

incorporated, as applicable, into the Metal Fatigue of 

Reactor Coolant Pressure Boundary Program. 

[Revised in letter dated 1/9/2009 in response to RAI 

4.3.1.1-1]

4.3.1.3 U1 - 8/9/2013

U2 - 10/29/2014
A-9

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

36 NSPM will complete fatigue calculations for the 

pressurizer surge line hot leg nozzle and the charging 

nozzle using the methodology of the ASME Code 

(Subsection NB) and will report the revised CUFs and 

CUFs adjusted for environmental effects at these 

locations as an amendment to the PINGP LRA. 

Conforming changes to LRA Section 4.3.3, “PINGP 

EAF Results,” will also be included in that amendment 

to reflect analysis results and remove references to 

stress-based fatigue monitoring. 

[Added in letter dated 1/9/2009 in response to RAI 

4.3.1.1-1]

4.3.3 4/30/2009

Letter dated 4/28/2009 

from the applicant to 

NRC completes this 

commitment, see 

ML091190418

37 NSPM will revise procedures for excavation and 

trenching controls and archaeological, cultural and 

historic resource protection to identify sensitive areas 

and provide guidance for ground-disturbing activities. 

The procedures will be revised to include drawings and 

illustrations to assist users in identifying culturally 

sensitive areas, and pictures of artifacts that are 

prevalent in the area of the Plant site. The revised 

procedures will also require training of the Site 

Environmental Coordinator and other personnel 

responsible for proper execution of excavation or other 

ground-disturbing activities.

[Added in ER revision submitted in letter dated 

3/4/2009]

ER 4.16.1 8/9/2013

38 NSPM will conduct a Phase I Reconnaissance Field 

Survey of the disturbed areas within the Plant’s 

boundaries. In addition, NSPM will conduct Phase I 

field surveys of areas of known archaeological sites to 

precisely determine their boundaries. NSPM will use 

the results of these surveys to designate areas for 

archaeological protection.

[Added in ER revision submitted in letter dated 

3/4/2009]

ER 4.16.2 8/9/2013

39 NSPM will prepare, maintain and implement a Cultural 

Resources Management Plan (CRMP) to protect 

significant historical, archaeological, and cultural 

resources that may currently exist on the Plant site. In 

connection with the preparation of the CRMP, NSPM 

will conduct botanical surveys to identify culturally and 

medicinally important species on the Plant site, and 

incorporate provisions to protect such plants into the 

CRMP.

[Added in ER revision submitted in letter dated 

3/4/2009]

ER 4.16.2 8/9/2013

40 NSPM will consult with a qualified archaeologist prior to 

conducting any ground-disturbing activity in any area 

designated as undisturbed and in any disturbed area 

that is described as potentially containing 

archaeological resources (as determined by the Phase I 

Reconnaissance Field Survey discussed in 

Commitment Number 38).

[Added in ER revision submitted in letter dated 

3/4/2009]

ER 4.16.2 8/9/2013
A-10

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

41 During the first refueling outage following 

refueling cavity leak repairs in each Unit 

(scheduled for refueling outages 1R26 and 

2R26), concrete will be removed from the Sump 

C pit to expose an area of the containment vessel 

bottom head. Visual examination and ultrasonic 

thickness measurement will be performed on the 

portions of the containment vessels exposed by 

the excavations. An assessment of the condition 

of exposed concrete and rebar will also be 

performed. Petrographic examination will be 

performed on sample pieces of the removed 

concrete if the removal method provides pieces 

suitable for examination. Degradation observed 

in the exposed containment vessel, concrete or 

rebar, or as a result of petrographic examination 

of concrete samples, will be entered into the 

Corrective Action Program, and evaluated for 

impact on structural integrity and identification of 

additional actions that may be warranted.

[Added in letter dated 4/6/09 in response to Follow Up 

RAI B2.1.38] [Revised in letter dated 8/7/09 in 

response to a follow-up question from a conference call 

on 7/22/09]

B2.1.38 U1 - 8/9/2013

U2 - 10/29/2014

42 During the two consecutive refueling outages following 

refueling cavity leak repairs in each Unit (scheduled for 

refueling outages 1R26 and 2R26), visual inspections 

will be performed of the areas where reactor cavity 

leakage had been observed previously to confirm that 

leakage has been resolved. The inspection results will 

be documented. If refueling cavity leakage is again 

identified, the issue will be entered into the Corrective 

Action Program and evaluated for identification of 

additional actions to mitigate leakage and monitor the 

condition of the containment vessel and internal 

structures. 

[Added in letter dated 4/6/09 in response to Follow Up 

RAI B2.1.38]

B2.1.38 U1 - 8/9/2013

U2 - 10/29/2014

43 Preventive maintenance requirements will be 

implemented to require periodic replacement of rubber 

flexible hoses in the Diesel Generators and Support 

System and in the 122 Diesel Driven Fire Pump that are 

exposed to fuel oil or lubricating oil internal 

environments.

[Added in letter dated 4/6/09 in response to RAI 3.3.2-8-

1]

[Revised in letter dated 6/5/09]

Table 3.3.2-8 U1 - 8/9/2013

U2 - 10/29/2014
A-11

APPENDIX A: PINGP LICENSE RENEWAL COMMITMENTS

44 During the first refueling outage following refueling 

cavity leak repairs in each Unit (scheduled for refueling 

outages 1R26 and 2R26), a concrete sample will be 

obtained from a location known to have been wetted by 

borated water leakage from the refueling cavity. These 

concrete samples (one per Unit) will be tested for 

compression strength and will be subjected to 

petrographic examination to assess the degradation, if 

any, resulting from borated water exposure. 

Degradation identified as a result of the testing and 

examination of the concrete samples will be entered 

into the Corrective Action Program, and evaluated for 

impact on structural integrity and identification of 

additional actions that may be warranted.

[Added in letter dated 8/7/09 in response to a follow-up 

question from a conference call on 7/22/09.]

U1 - 8/9/2013

U2 -

10/29/2014

B2.1.38

APPENDIX B

B-1

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the licensing correspondence between the staff of the U.S. 

Nuclear Regulatory Commission (NRC) (the staff) and Northern States Power Company, a 

Minnesota Corporation, (NSPM or the applicant). This appendix also lists other correspondence 

concerning the staff’s review of the Prairie Island Nuclear Generating Plant, Units 1 and 2, 

license renewal application (LRA) (Docket Nos. 50-282 and 50-306).

APPENDIX B: CHRONOLOGY

Date Subject

4/11/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2 - Application for Renewed 

Operating Licenses to be Extended 20 Years Beyond Current Expiration Dates (ADAMS Accession No. 

ML081130666)

4/11/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island Nuclear Generating Plant, Units 1 and 2 -

Supporting Information for NRC Review of Application for Renewed Operating Licenses (ADAMS 

Accession No. ML081140720)

4/16/2008 Letter from Northern States Power Co Nuclear Management Co LLC to NRC, Prairie Island, Units 1 & 2, 

and Monticello, Application for Order and Conforming License Amendments to Transfer Operating 

Authority Under Facility Operating Licenses (ADAMS Accession No. ML081090353)

4/28/2008 Letter from NRC to Nuclear Management Co LLC, Receipt and Availability of the LRA for the Prairie Island 

Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession No. ML081050091)

4/28/2008 Federal Register Notice, Receipt and Availability of the LRA for the Prairie Island Nuclear Generating Plant, 

Units 1 and 2 (ADAMS Accession No. ML081050100)

4/30/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2 - Applicant's Environmental 

Report - Operating License Renewal Stage, Appendix E, Table of Contents through Section 2.0, "Site and 

Environmental Interfaces" (ADAMS Accession No. ML081130677)

4/30/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2 - Applicant's Environmental 

Report - Operating License Renewal Stage, Appendix E, Section 3.0, "Proposed Action," through Section 

9.0, "Status of Compliance" (ADAMS Accession No. ML081130681)
B-2

APPENDIX B: CHRONOLOGY

4/30/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2 - Applicant's Environmental 

Report - Operating License Renewal Stage, Appendix E, Attachment A, "NRC NEPA Issues for License 

Renewal of Nuclear Power Plants," through Attachment F, "Severe Accident Mitigation Alternatives" 

(ADAMS Accession No. ML081130684)

5/6/2008 Federal Register Notice, Prairie Island, FRN - Notice of Receipt and Availability of Application for Renewal 

of Prairie Island Nuclear Generating Plant - 73 FR 25034 (ADAMS Accession No. ML083500086)

5/13/2008 Press Release-08-093: License Renewal Application for Prairie Island Nuclear Plant Available for Public 

Inspection (ADAMS Accession No. ML081340103)

5/16/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2, Supplemental Information 

Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML081400797)

5/19/2008 Letter from NRC to Nuclear Management Co LLC, Receipt and Availability of the License Renewal 

Application for the Prairie Island Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession No. 

ML081330711)

5/19/2008 Federal Register Notice, Correction to Notice of Receipt and Availability of Application for Renewal of 

Prairie Island Nuclear Generating Plant, Units 1 and 2.Notice of Receipt and Availability of Application for 

Renewal of Prairie Island Nuclear Generating Plant, Units 1 and 2 (ADAMS Accession No. ML081330712)

5/27/2009 Federal Register Notice, Notice of Receipt and Availability of Application for Renewal of Prairie Island 

Nuclear Generating Plant, Units 1 and 2. Notice of Receipt and Availability of Application for Renewal of 

Prairie Island Nuclear Generating Plant, Units 1 and 2 (http://edocket.access.gpo.gov/2008/pdf/E8-

16729.pdf)

5/30/2008 Letter from Nuclear Management Co LLC to NRC, Prairie Island, Units 1 and 2 - Revised Boundary 

Drawings to Support NRC Review of Application for Renewed Operating Licenses (ADAMS Accession No. 

ML081560697)

6/10/2008 Federal Register Notice, Notice of Acceptance for Docketing of the Application and Notice of Opportunity 

for Hearing Regarding Renewal of Facility Operating License Nos. DPR-42 and DPR-60 for an Additional 

20-year Period (ADAMS Accession No. ML081370294)

6/17/2008 Federal Register Notice, Prairie Island, FRN - Notice of Acceptance for Docketing of Application and Notice 

of Opportunity for Hearing Re Renewal of License - 73 FR 34335 (ADAMS Accession No. ML083500089)
B-3

APPENDIX B: CHRONOLOGY

6/26/2008 Federal Register, Notice of Intent To Prepare an Environmental Impact Statement and Conduct Scoping 

Process For License Renewal For The Prairie Island Nuclear Generating Plant Units 1 & 2 (TAC Nos. 

MD8528, MD8529) (ADAMS Accession No. ML081620382)

7/15/2008 Prairie Island Nuclear Generating Plant, Units 1 and 2-Notice of Intent to Prepare an Environmental Impact 

Statement and Conduct Scoping Process for License Renewal for the Prairie Island Nuclear Generating 

Plant, Unit 1 & 2 (TAC Nos. MD8528 and MD8529) (ML081970679)

7/22/2008 Federal Register Notice, Prairie Island, FRN - Notice of Intent to Prepare and EIS and Conduct Scoping -

73 FR 42628 (ADAMS Accession No. ML083500090)

7/30/2008 Transcript of Prairie Island License Renewal Public Scoping Meeting on 07/30/2008 - Afternoon Session, 

Pp. 1-44 (ADAMS Accession No. ML082470336)

7/30/2008 Prairie Island License Renewal Public Scoping Meeting Transcript: Evening Session, July 30, 2008, Pages 

1-79 (ADAMS Accession No. ML082490514)

9/8/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Surface Water, Binder 2 of 3 (ADAMS Accession No. ML083120222)

9/8/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Surface Water, Binder 1 of 3 (ADAMS Accession No. ML083120223)

9/8/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Socioeconomics, Binder 1 of 1 (ADAMS Accession No. 

ML083120226)

9/8/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Groundwater Resources, Binder 1 of 1 (ADAMS Accession No. 

ML083120227)

9/8/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Terrestrial Ecology, Binder 1 of 1 (ADAMS Accession No. 

ML083120228)

9/18/2008 Prairie Island, License Renewal Environmental Report Additional Information, Documents Requested 

During NRC Environmental Review, Environmental Health & Waste Issues, Binder 1 of 1 (ADAMS 

Accession No. ML083120229)

9/26/2008 Letter from Northern States Power Co to NRC, Prairie Island Nuclear Generating Plant Units 1 and 2, 

Submittal of Documents for Public Disclosure as Requested During NRC License Renewal Environmental 

Audit (ADAMS Accession No. ML083120218)

10/23/2008 Letter from NRC to Nuclear Management Co LLC, Review of the Prairie Island Nuclear Generating Plant 

Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and MD8514) (ADAMS Accession No. 

ML082950551)
B-4

APPENDIX B: CHRONOLOGY

11/4/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant Units 1 & 2, License Renewal Application (ADAMS Accession No. 

ML082970818)

11/5/2008 Letter from NRC to Northern States Power Co Nuclear Management Co, LLC, Request for Additional 

Information for the Review of the Prairie Island Nuclear Generating Plant Units 1 & 2, License Renewal 

Application (TAC Nos. MD8513 and MD8514) (ADAMS Accession No. ML082830947)

11/6/2008 Letter from NRC to Nuclear Management Co LLC, Prairie Island, Units 1 & 2, Information Request For 

NRC License Renewal Inspection (ADAMS Accession No. ML083110863)

11/12/2008 Letter Northern States Power Co to NRC, Prairie Island Nuclear Generating Units 1 and 2, Responses to 

NRC Requests for Additional Information Dated November 4, 2008 Regarding Application for Renewed 

Operating Licenses (ADAMS Accession No. ML083370202)

11/19/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083010585)

11/19/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083180394)

11/19/2008 Letter from NRC to Northern States Power Co, Request for Additional Information License Renewal 

Application, Prairie Island Nuclear Generating Plant, Units 1 & 2 (ADAMS Accession No. ML083240032)

11/20/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083180962)

11/20/2008 Letter from NRC to Northern States Power Co, Request for Additional Information, Prairie Island Units 1 & 

2 License Renewal Application, Sections 4.7.1 and 2.5 (ADAMS Accession No. ML083181015)

11/21/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information Dated October 23, 2008, Regarding Application for Renewed Operating Licenses 

(ADAMS Accession No. ML083370505)
B-5

APPENDIX B: CHRONOLOGY

11/25/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083180558)

12/1/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) RAI 2.4.1-1, 2.4.3-1, 2.4.7-1, 2.4.7-2, 2.4.8-1, 2.4.11-1 (ADAMS Accession No. ML083250716)

12/2/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083310078)

12/5/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC MD8513 and 

MD8514). RAIB2.1.3-1; B2.1.27-1; B2.1.8-1; B2.1.8-2; B2.1.8-3; B2.1.8-4; B2.1.19-1; B2.1.19-2; B2.1.19-3 

(ADAMS Accession No. ML083250720)

12/5/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated November 5, 2008, Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML083650197)

12/10/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083010561)

12/11/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated November 19, 2008, Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML083650032)

12/11/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information Dated November 20, 2008, Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML083650035)

12/11/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information Dated November 25, 2008, Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML083650036)

12/11/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information Dated December 1, 2008, Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML083650037)
B-6

APPENDIX B: CHRONOLOGY

12/16/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC MD8513 and 

MD8514) (ADAMS Accession No. ML083250329)

12/18/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for The Review of The 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) (ADAMS Accession No. ML083170561)

12/18/2008 Letter from NRC to Northern States Power Co, Request for Additional Information for The Review of The 

Prairie Island Nuclear Generating Plant, Units 1 & 2, License Renewal Application (TAC Nos. MD8513 and 

MD8514) Cover Letter (ADAMS Accession No. ML083170566)

12/18/2008 Letter from Northern States Power Co to NRC Prairie Island, Units 1 and 2, Responses to Requests for 

Additional Information Regarding Application for Renewed Operating Licenses (ADAMS Accession No. 

ML083590337)

12/18/2008 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to Requests for 

Additional Information Regarding Application for Renewed Operating Licenses (ADAMS Accession No. 

ML083590341)

12/24/2008 Letter from NRC to Northern States Power Co, Request for Additional Information Regarding the Review of 

the License Renewal Application for Prairie Island Nuclear Generating Plant, Units 1 and 2 (TAC MD8528 

and MD8529) (ADAMS Accession No. ML083520121)

1/9/2009 Letter from Northern States Power Co to NRC Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated December 10, 2008 Regarding Application for Renewed Operating 

License (ADAMS Accession No. ML090120541)

1/15/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated December 16, 2008 Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML090210645)

1/16/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information Dated December 2, 2008 Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML090360518)

1/20/2009 Letter from Wadley M D, Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to 

NRC Requests for Additional Information Dated December 18, 2008 Regarding Application for Renewed 

Operating Licenses (ADAMS Accession No. ML090270448)
B-7

APPENDIX B: CHRONOLOGY

1/23/2009 Summary of Telephone Conference Call Held On December 9, 2008, Between The U. S. Nuclear 

Regulatory Commission and Northern States Power Co, Concerning Follow Up Questions Pertaining to 

The SAMA RAI for PINGS, Units 1 and 2, (TAC MD8528 & MD8529) (ADAMS Accession No. 

ML083660069)

1/23/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated December 24, 2008 Regarding Application for Renewed Operating 

Licenses (ADAMS Accession No. ML090260290)

1/27/2009 Letter from NRC to Northern States Power Co, 08/18/08 - 08/22/08 Summary of Site Audit Related to the 

Review of the License Renewal Application for Prairie Island Nuclear Generating Plant, Units 1 and 2 

(ADAMS Accession No. ML083440479)

2/3/2009 Letter from NRC to Northern States Power Co, Public Exit Meeting for an NRC License Renewal Inspection 

(ML090350405)

2/3/2009 02/03/2009-Summary of Telephone Conference Between NRC and Prairie Island Nuclear Generating 

Plant, Concerning Requests for Additional Information Pertaining to License Renewal Application (ADAMS 

Accession No. ML090860064)

2/4/2009 12/03/08 Summary of Telephone Conference Call Held Between NRC & Northern States Power Co, 

Concerning Follow-Up Question Pertaining to the PINGS, Units 1& 2, License Renewal Environmental 

Review and Site Audit (ADAMS Accession No. ML090060852)

2/6/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Submittal of Supplemental 

Information Regarding Application for Renewed Operating Licenses (ADAMS Accession No. 

ML090510148)

2/10/2009 02/10/2009 Meeting Summary, Telephone Conference Call Between the NRC and Prairie Island, 

Concerning Requests for Additional Information Pertaining to the Prairie Island Units 1 and 2, License 

Renewal Application (ADAMS Accession No. ML090860063)

2/11/2009 Press Release-III-09-003: NRC to Discuss Results of License Renewal Inspection for Prairie Island Nuclear 

Power Plant (ADAMS Accession No. ML090420533)

2/11/2009 02/11/09 Summary of Telephone Conference Call Between NRC and Prairie Island Nuclear Generating 

Plant, Concerning Requests for Additional Information Pertaining to License Renewal Application (ADAMS 

Accession No. ML090860062)

2/20/2009 Letter from NRC, to Northern States Power Co, Request for Additional Information For Prairie Island 

Nuclear Generating Units 1 and 2, License Renewal Application (TAC Nos. MD8513 and MD8514) 

(ADAMS Accession No. ML090340684)
B-8

APPENDIX B: CHRONOLOGY

2/23/2009 02/23/09 Summary of Telephone Conference Call Held Between NRC and Prairie Island, Concerning 

Request for Additional Information Pertaining to the Prairie Island Units 1 and 2 (ADAMS Accession No. 

ML090860061)

2/24/2009 Safety Evaluation Report Input for License Renewal Application for Prairie Island Units 1 & 2 (ADAMS 

Accession No. ML090540530)

2/26/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Responses to NRC Requests 

for Additional Information Dated February 20, 2009 and Follow Up Questions Regarding Application for 

Renewed Operating Licenses (ADAMS Accession No. ML090680041)

3/4/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2 - Revisions to Environmental 

Report Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML090690683)

3/4/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Supplemental Information 

Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML090690684)

3/12/2009 Letter from NRC to Northern States Power Co, Ltr. 03122009 Prairie Island Exit Meeting Summary 

(ML090720898)

3/12/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Supplemental Information 

Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML090790208)

3/27/2009 Letter from NRC to Northern States Power Co, IR 05000282-09-006, 05000306-09-006 on 01/06/2009 -

02/18/2009 for Prairie Island, Units 1 and 2, License Renewal Scoping, Screening and Aging Management 

(ADAMS Accession No. ML090860804)

3/27/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 & 2, Supplemental Information 

Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML090970736)

3/31/2009 Letter from NRC to Northern States Power Co, Request for Additional Information for the Review of the 

Prairie Island Nuclear Generating Plant, Units 1 and 2, License Renewal Application (TAC Nos. MD8513 

and MD8514) (ADAMS Accession No. ML090840421)

4/6/2009 03/02/2009 Meeting Summary, Meeting Between NRC Staff and Northern States Power Company, 

Minnesota (NSPM) (ADAMS Accession No. ML090930026)

4/6/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 & 2, Responses to NRC Requests for 

Additional Information Dated March 31, 2009 and Follow Up Questions Regarding Application for Renewed 

Operating Licenses (ADAMS Accession No. ML091120351)
B-9

APPENDIX B: CHRONOLOGY

4/13/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Supplemental Information 

Regarding Application for Renewed Operating Licenses (ADAMS Accession No. ML091110323)

4/13/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Annual Update (Revision) of 

Application for Renewed Operating Licenses (ADAMS Accession No. ML091110324)

4/21/2009 Letter from NRC to Northern States Power Co, Scoping and Screening Audit Summary Regarding the 

Prairie Island Nuclear Generating Plant, Units 1 and 2, License Renewal Application (ADAMS Accession 

No. ML083300107)

4/21/2009 Letter from NRC to Northern States Power Co, Prairie Island Nuclear Generating Plant, Units 1 and 2, 

License Renewal Application, Safety Audit Report (TAC MD8513 and MD8514) (ADAMS Accession No. 

ML090850009)

4/28/2009 Letter from Northern States Power Co to NRC, Supplemental Information Closing License Renewal 

Commitment Number 36 Regarding Application for Renewed Operating License (ADAMS Accession No. 

ML091190418)

5/8/2009 Letter from Northern States Power Co to NRC, Supplemental Information Regarding Application for 

Renewed Operating License (ADAMS Accession No. ML091390294)

5/12/2009 Letter from Northern States Power Co to NRC, Supplemental Information Regarding Application for 

Renewed Operating License (ADAMS Accession No. ML091470263)

5/29/2009 03/30/09 Summary of Telephone Conference Call Held Between NRC and Prairie Island, Concerning 

Request for Additional Information Pertaining to the Prairie Island Units 1 and 2 (ADAMS Accession No. 

ML091180290) 

5/29/2009 04/15/09 Summary of Telephone Conference Call Held Between NRC and Prairie Island, Concerning 

Request for Additional Information Pertaining to the Prairie Island Units 1 and 2 (ADAMS Accession No. 

ML091170124)

6/5/2009 Letter from Northern States Power Co to NRC, Supplemental Information Regarding Application for 

Renewed Operating License (ADAMS Accession No. ML091670101)

6/10/2009 Letter from NRC to Northern States Power Co, Request for Additional Information Regarding the Review of 

the License Renewal Application for Prairie Island Nuclear Generating Plant, Units 1 and 2 (TAC MD8513

and MD8514) (ADAMS Accession No. ML091540412)

6/24/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information for Renewed Operating Licenses (ADAMS Accession No. ML091800018)

7/30/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, NSPM Comments on NRC 

Safety Evaluation Report with Open Items Related to Renewal of Operating Licenses (ADAMS Accession 

No. ML092230126)
B-10

APPENDIX B: CHRONOLOGY

8/7/2009 Letter from Northern States Power Co to NRC, Prairie Island, Units 1 and 2, Responses to NRC Requests 

for Additional Information for Renewed Operating Licenses (ADAMS Accession No. ML092360408)

8/7/2009 Letter from Northern States Power Co to NRC, Supplemental Information Regarding Application for 

Renewed Operating License (ADAMS Accession No. ML092360409)

8/21/2009 Letter from Northern States Power Co to NRC, Supplemental Information Regarding Application for 

Renewed Operating License (ADAMS Accession No. ML092440763)

12/10/2009 Letter from Mario V. Bonaca, ACRS to Gregory B. Jaczko, Chairman NRC, “Report on the Safety Aspets of 

the License Renewal Application for the Prairie Island Nuclear Generating Plant, Units 1 and 2”, (Accession 

No. ML093420316)

04/15/2011 NRC Letter Transmitting the Supplement Safety Evaluation report Related to the License Renewal of 

PINGP Units 1 and 2 (ADAMS Accession No. ML110800492)
APPENDIX C

C-1

APPENDIX C

PRINCIPAL CONTRIBUTORS

This appendix lists the principal contributors for the development of this safety evaluation report 

(SER) and their areas of responsibility.

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

H. Ashar Structural Engineering

D. Ashley SER Support

R. Auluck Management Oversight

B. Berson SER Support

T. Chan Management Oversight

G. Cheruvenki Vessel and Internals Integrity

G. Cranston Management Oversight

M. Cunningham Management Oversight

E. Davidson Scoping & Screening

Dr. J. Davis SER Support

R. Dennig Management Oversight

K. Desai Reactor Systems Engineer

J. Dozier Management Oversight

M. Evans Management Oversight

Q. Gan Mechanical Engineering

N. Goodman Project Manager

M. Heath SER Support

B. Heida Containment and Ventilation

P. Hiland Management Oversight

A. Hiser Management Oversight

Dr. D. Hoang Civil & Structural Engineering

B. Holian Management Oversight

N. Iqbal Fire Protection

A. Klein Management Oversight

S. Lee Management Oversight

B. Lehman Civil & Structural Engineering

R. Li Structural Engineering
C-2

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

L. Lois Reactor Systems Engineer

K. Manoly Management Oversight

R. Matthew Management Oversight

M McConnell Electrical Engineering

J. Medoff Audit Team Member

D. Mills SER Support

M. Mitchell Management Oversight

D. Nguyen Electrical Engineering

B. Parks Reactor Systems Engineer

E. Patel Consultant

R. Plasse Project Manager

B. Rogers Scoping & Screening

W. Ruland Management Oversight

P. Sahay Electrical Engineering

S. Sakai Scoping & Screening

A. Sallman Scoping & Screening

A. Shaikh Vessel and Internals Integrity

S. Sheldon Region III Inspection

E. Smith Scoping & Screening

R. Sun Audit Team Member

G. Thomas Civil & Structural Engineering

J. Tsao Flaw Evaluations & Welding

G. Wilson Management Oversight

E. Wong Chemical Engineering

D. Wrona Management Oversight

Z. Xi Civil & Structural Engineering

C. Yang Mechanical Engineering

O. Yee Mechanical Engineering

M. Yoder Chemical Engineering
APPENDIX D

D-1

APPENDIX D

REFERENCES

This appendix lists the references used throughout this SER for review of the LRA for Prairie 

Island Nuclear Generating Plant, Units 1 and 2.

APPENDIX D: PINGP References

1 10 CFR Part 50, “Domestic Licensing of Production and Utilization Facilities”

2 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power 

Plants"

3 10 CFR 50.55a, “Codes and Standards”

4 10 CFR 50.63, "Loss of All Alternating Power" 

5 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants”

6 10 CFR 54.21, “Contents of application-general information”

7 10 CFR 54.4 (a)(3) "Scope"

8 10 CFR Part 50 Appendix A Criterion 17, "Electric Power"

9 4th Interval Inservice Inspection Plan–Units 1 and 2, December 21, 2004 Through December 20, 2014, H10.5

10 American Concrete Institute, ACI 201.2R-77 "Guide to Durable Concrete" 

11 American Concrete Institute, ACI 318

12 American Society of Mechanical Engineers (ASME) Code, Section XI, Non-mandatory Appendix G,”Fracture 

Toughness Criteria for Protection Against Failure,” 2007 Edition

13 American Society of Mechanical Engineers ASME Boiler and Pressure Vessel Code.

14 ASME Code Class 1, 2 and 3

15 ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD

16 ANSI N45.2.6

17 Appendix A to the Branch Technical Position (BTP), Auxiliary and Power Conversion Systems Branch 

(APCSB), 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants," May 1, 1976.

18 Applicant’s response to NRC Generic Letter 9706, “Degradation of Steam Generator Internals,” dated March 

30, 1998.
D-2

APPENDIX D: PINGP References

19 American Society of Testing Materials (ASTM) E 185, 1982 Edition, “Conducting Surveillance Tests for LightWater Cooled Nuclear Power Reactor Vessels”

20 ASTM D4541, "Test Method for Pull-Off Strength of Coatings Using Portable Adhesion Testers" 

21 ASTM D5163, "Standard Guide for Establishing Procedures to Monitor the Performance of Coating Service 

Level 1 Coating Systems in an Operating Nuclear Power Plant"

22 ASTM D714-04, "Standard Method for Evaluating Degree of Blistering of Paints" ASTM D61 0-01, "Standard 

Method for Evaluating Degree of Rusting of Painted Steel Surfaces"

23

Berkow, Herbert, U.S. NRC, Letter to Gordon Bischoff, Westinghouse Owners Group, “Final Safety Evaluation 

for Topical Report WCAP-14040, Revision 3, ‘Methodology Used to Develop Cold Overpressure Mitigating 

System Setpoints and RCS Heatup and Cooldown Limit Curves,’” February 27, 2004. ADAMS Accession 

Number ML040620297.

24 Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor Coolant System” (as supplemented)

25 D6677, "Standard Test Method for Evaluation by Knife"

26 EPRI 1010639, “Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools” Revision 4, 

January 2006

27 EPRI MRP-139, "Primary System Piping Butt Weld Inspection and Evaluation Guidelines"

28 EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, April 1988

29 EPRI TR 1002884, “Pressurized Water Reactor (PWR) Primary Water Chemistry Guidelines,” Revision 5

30 EPRI TR-1008224, “PWR Secondary Water Chemistry Guidelines,” Revision 6, December 2004

31 EPRI TR-102134, “PWR Secondary Water Chemistry Guidelines”

32 EPRI TR-104213, “Bolted Joint Maintenance & Applications Guide,” December 1, 1995

33 EPRI TR-105714, “PWR Primary Water Chemistry Guidelines”

34 EPRI TR-107396, “Closed Cooling Water Chemistry Guidelines”, October 1997

35 EPRI TR-107396, Revision 1 (1007820), “Closed Cooling Water Chemistry Guideline”, April 2004

36 EPRI TR-107514, “Age-Related Degradation Inspection Method and Demonstration: In Behalf of Calvert Cliffs 

Nuclear Power Plant License Renewal Application”, April 1998

37 EPRI TR-107569-V1R5, “PWR Steam Generator Examinations and Guidelines.”

38 Final statement of consideration (SOC) on the updates of 10 CFR 50.55a, “codes and standards” (refer to 

Federal Register [FR] Volume 73, No. 176, pages 52730 – 52750)

39 GALL AMP XI.M31, “RV Surveillance”

40 GALL Report and Section A.1.2.3.10 of the “Standard Review Plan for Review of License Renewal 

Applications for Nuclear Power Plants”
D-3

APPENDIX D: PINGP References

41 Generic Letter (GL) 80-113, “Control of Heavy Loads,” December 22, 1980

42 Generic Letter (GL) 92-01, “Reactor Vessel Structural Integrity,” November 10, 1999 (ADAMS Accession No. 

ML993330371)

43 Generic Letter 96-04, Boraflex Degradation in Spent Fuel Pool Storage Racks

44 Generic Letter 9706, “Degradation of Steam Generator Internals”

45 Generic Safety Issue (GSI)-78, “Monitoring of Fatigue Transient Limits for Reactor Coolant System”

46 GL 2004-02, “Potential Impact of Debris Blockage on Emergency Recirculation During Design Basis 

Accidents at Pressurized Water Reactors” 

47 GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment" July 18, 1989

48 GL 89-13, Supplement 1, “Service Water System Problems Affecting Safety-Related Components,” April 4, 

1990

49 GSI-166, "Adequacy of Fatigue Life of Metal Components”

50 GSI-190, “Fatigue Evaluation of Metal Components for 60-Year Plant Life”

51 GSI-191, “Assessment of Debris Accumulation on PWR Sump Performance”

52

Letter from Christopher I. Grimes, U.S. Nuclear Regulatory Commission, License Renewal and 

Standardization Branch, to Douglas J. Walters, Nuclear Energy Institute, License Renewal Issue No. 98-0030, 

Thermal Aging Embrittlement of Cast Stainless Steel Components, May 19, 2000 (ADAMS Accession No. 

ML003717179)

53 Letter from William H. Bateman, NRC to Alex Marion, Nuclear Energy Institute, Subject: “NEI 97-06, Steam 

Generator Program Guidelines, Revision 2,” dated October 3, 2005

54 Lois, Lambros, US Nuclear Regulatory Commission, Memorandum to Wetzel, Beth A., “Prairie Island Units 1 

and 2: Fluence Evaluation for Pressure-Temperature Limits,” Dockets 50-282 and 50-306, March 23, 1998

55 McLane, V., et al., “ENDF/B-VI: Evaluated Nuclear Data Library for Nuclear Science and Technology,” 

December 1996

56 NEI 9706, “Steam Generator Program Guidance,” Rev. 2

57 Northern States Power, “Prairie Island Nuclear Generating Plant Application for Renewed Operating License,” 

Dockets 50-282 and 50-306, April 1, 2008

58 NRC Bulletin 2003-02, “Leakage from Reactor Pressure Vessel Lower Head Penetrations and Reactor 

Coolant Pressure Boundary Integrity,” August 21, 2003

59 NRC Bulletin 2004-01, “Inspection of Alloy 82/182/600 Materials used in the Fabrication of Pressurizer 

Penetrations and Steam Piping Connections at Pressurized-Water Reactors,” May 28, 2004

60 NRC Bulletin 88-08, “Thermal Stresses in Piping Connected to Reactor Coolant Systems,” June 22, 1988

61 NRC Bulletin 88-09, “Thimble Tube Thinning in Westinghouse Reactors,” July 26, 1988

62 NRC Bulletin No. 88-11, "Pressurizer Surge Line Thermal Stratification," December 20, 1988
D-4

APPENDIX D: PINGP References

63 NRC Information Notice No. 87-44, "Thimble Tube Thinning in Westinghouse Reactors," September 16, 1987

64 NRC Information Notice No. 87-44, Supplement 1, "Thimble Tube Thinning in Westinghouse Reactors," March 

28, 1988

65 NRC Order EA-03-009, “Issuance of First Revised Order (EA-03-009) Establishing Interim Inspection 

Requirements for Reactor Pressure Vessel Heads at PWRs,” April 4, 2004

66 NRC Safety Evaluation Report dated October 15, 2001 of WCAP-15338, “A Review of Cracking Associated 

with Weld Deposited Cladding in Operating PWR Plants,” (ADAMS Accession No. ML012890230)

67 NUREG/CR-4513, Rev. 1, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in 

LWR Systems, U.S. Nuclear Regulatory Commission, August 1994

68 NUREG/CR-4513, Rev. 1, Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in 

LWR Systems, U.S. Nuclear Regulatory Commission, August 1994

69 NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless 

Steels,” April 1999

70 NUREG/CR-5999 Interim Fatigue Curves for Selected Nuclear Power Plant Components”

71 NUREG/CR-6177, “Assessment of Thermal Embrittlement of Cast Stainless Steels,” May 1994

72 NUREG/CR-6260, “Application of NUREG/CR-5999 Interim Fatigue Curves for Selected Nuclear Power Plant 

Components”

73 NUREG/CR-6583, “Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy 

Steels,” February 1998

74 NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980.

75 NUREG-0800, Revision 1, “Standard Review Plan for the Review of Safety Analysis Report of Nuclear Power 

Plants” 

76 NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants”

77 NUREG-1785, “Safety Evaluation Report Related to the License Renewal of H.B. Robinson Steam Electric 

Plant, Unit 2,” March 2004

78 NUREG-1800, Revision 1, “Standard Review Plan for Review of License Renewal Applications for Nuclear 

Power Plants,” September 2005

79 NUREG-1801, Revision 1, “Generic Aging Lessons Learned (GALL) Report,” September 2005

80 NUREG-1833, “Technical Bases for Revision to the License Renewal Guidance Documents,” October 2005

81 Prairie Island Nuclear Generating Plant LR-AMP-403

82 Prairie Island Nuclear Generating Plant, Units 1 and 2, "Fire Protection Safety Evaluation Report, " September 

6, 1979.

83 Prairie Island, Updated Safety Analysis Report (UFSAR)

84

Radiation Safety Information Computational Center, “Coupled 47 Neutron, 20 Gamma-Ray Group Cross 

Section Library Derived from ENDF/B-VI for LWR Shielding and Pressure Vessel Dosimetry Applications, 

(BUGLE-96)” March 1996
D-5

APPENDIX D: PINGP References

85 Radiation Safety Information Computational Center, “Two-Dimensional Discrete Ordinates Transport Code 

System (DORT),” August, 1993

86

Responses to NRC Request for Additional Information Dated November 4, 2008 (ADAMS Accession No. 

ML0833702020). Regarding Application for Renewed Operating Licenses for Prairie Island Nuclear 

Generating Plant Units, 1 and 2

87 U.S Nuclear Regulatory Commission Regulatory Guide (RG) 1.99, “Radiation Embrittlement of Reactor 

Vessel Materials,” Revision 2, May 1988

88 RG 1.54 Rev 1 "Service level I, II, and III Protective Coatings Applied to Nuclear Power Plants"

89 RG 1.65 "Materials and Inspections for Reactor Vessel Closure Studs," October 1973

90 Section 6.0 of AMP XI.M31 in NUREG-1801, “Generic Aging Lessons Learned Report,” Volume 2, Revision 1

91 Supplemental response to GL 2004-02, "Potential Impact of Debris Blockage on Emergency Recirculation 

during DBA at Pressurized-Water Reactors," (dated 2-28-08)

92 Technical Specification Task Force Traveler (TSTF) 449, “Steam Generator Tube Integrity,” Revision 4.

93 U.S. Nuclear Regulatory Commission, “Calculational and Dosimetry Methods for Determining Pressure Vessel 

Neutron Fluence,” Regulatory Guide 1.190, March, 2001. ADAMS Accession Number ML010890301

94 WCAP-14637, "Prairie Island Unit 2 Heatup and Cooldown Limit Curves for Normal Operation,” Revision 3, 

December 1999 (ADAMS Accession Nos. ML023230354 and ML003703560, respectively). 

95

Westinghouse Electric Company, “Methodology Used to Develop Cold Overpressure Mitigating System 

Setpoints and RCS Heatup and Cooldown Limit Curves,” WCAP14040-A, May, 2004. ADAMS Accession 

Number ML050120209

96

Westinghouse Electric Corporation, WCAP-15338-A, “A Review of Cracking Associated with Weld Deposited 

Cladding in Operating PWR Plants,” Pittsburgh, Pennsylvania, March 2001 (ADAMS Accession No. 

ML083530289)

97 "Supplemental Response to Generic Letter 96-04, Boraflex Degradation in Spent Fuel Pool Storage Racks,”

March 27, 1997




UNITED STATES 

NUCLEAR REGULATORY COMMISSION

WASHINGTON, DC 20555-0001

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OFFICIAL BUSINESS
 

NUREG-1960 Safety Evaluation Report Related to the License Renewal of 

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