Safety Evaluation Report

Related to the License

Renewal of Grand Gulf 

Nuclear Station, Unit 1

Docket Number 50-416

Entergy Operations, Inc.

Office of Nuclear Reactor Regulation

NUREG-2211

 

Safety Evaluation Report

Related to the License

Renewal of Grand Gulf 

Nuclear Station, Unit 1

Docket Number 50-416

Entergy Operations, Inc.

Manuscript Completed: October 2016

Date Published: November 2016

Office of Nuclear Reactor Regulation

NUREG-2211

 

iii

ABSTRACT

This safety evaluation report (SER) documents the technical review of the Grand Gulf Nuclear 

Station, Unit 1 (GGNS), license renewal application (LRA) by the United States (US) Nuclear 

Regulatory Commission (NRC) staff (the staff). By letter dated October 28, 2011, Entergy 

Operations, Inc. (Entergy or the applicant) submitted the LRA in accordance with Title 10, 

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

Code of Federal Regulations. Entergy requests renewal of the GGNS operating license 

(Operating License No. NPF-29) for a period of 20 years beyond the current expiration at 

midnight November 1, 2024.

GGNS is located approximately 20 miles southwest of Vicksburg, MS. The NRC issued the 

GGNS construction permit on September 4, 1974, and operating license on November 1, 1984. 

GGNS is of a boiling water reactor design. General Electric supplied the nuclear steam supply 

system and Allis-Chalmers Power Systems furnished the turbine generator set. The 

containment is a steel-lined reinforced concrete structure designed by Bechtel Power 

Corporation. The GGNS licensed power output is 4,408 megawatt thermal.

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

submitted through October 3, 2016, the cutoff date for consideration in the SER. The four open 

items previously identified in the SER with Open Items, issued January 31, 2013, have been 

closed (see Section 1.5); therefore, no open items remain to be resolved before the final 

determination is reached by the staff on the LRA.

v

TABLE OF CONTENTS

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

TABLE OF CONTENTS ............................................................................................................ v

ABBREVIATIONS ................................................................................................................... xv

SECTION 1 INTRODUCTION AND GENERAL DISCUSSION............................................ 1-1

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

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

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

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

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

1.4 Interim Staff Guidance................................................................................................. 1-6

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

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

1.7 Summary of Proposed License Conditions ................................................................ 1-10

SECTION 2 STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW................................................................................ 2-1

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

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

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

2.1.3 Scoping and Screening Program Review......................................................... 2-1

2.1.3.1 Implementation Procedures and Documentation Sources for 

Scoping and Screening .................................................................... 2-2

2.1.3.2 Quality Controls Applied to LRA Development ................................. 2-4

2.1.3.3 Training............................................................................................ 2-5

2.1.3.4 Conclusion of Scoping and Screening Program Review................... 2-5

2.1.4 Plant Systems, Structures, and Components Scoping Methodology ................ 2-6

2.1.4.1 Application of the Scoping Criteria in 10 CFR 54.4(a)(1).................. 2-6

2.1.4.2 Application of the Scoping Criteria in 10 CFR 54.4(a)(2).................. 2-9

2.1.4.3 Application of the Scoping Criteria in 10 CFR 54.4(a)(3)................ 2-13

2.1.4.4 Plant-Level Scoping of Systems and Structures............................. 2-15

2.1.4.5 Mechanical Component Scoping.................................................... 2-16

2.1.4.6 Structural Component Scoping ...................................................... 2-17

2.1.4.7 Electrical Component Scoping ....................................................... 2-20

2.1.4.8 Conclusion for Scoping Methodology ............................................. 2-21

2.1.5 Screening Methodology ................................................................................. 2-21

2.1.5.1 General Screening Methodology.................................................... 2-21

2.1.5.2 Mechanical Component Screening................................................. 2-22

2.1.5.3 Structural Component Screening ................................................... 2-23

2.1.5.4 Electrical Component Screening .................................................... 2-24
vi

2.1.5.5 Conclusion for Screening Methodology.......................................... 2-25

2.1.6 Summary of Evaluation Findings.................................................................... 2-25

2.2 Plant-Level Scoping Results...................................................................................... 2-25

2.2.1 Introduction.................................................................................................... 2-25

2.2.2 Summary of Technical Information in the Application..................................... 2-26

2.2.3 Staff Evaluation.............................................................................................. 2-26

2.2.4 Conclusion..................................................................................................... 2-27

2.3 Scoping and Screening Results: Mechanical Systems .............................................. 2-27

2.3.1 Reactor Coolant System ................................................................................ 2-28

2.3.1.1 Reactor System ............................................................................. 2-28

2.3.1.2 Reactor Coolant Pressure Boundary.............................................. 2-30

2.3.1.3 Nuclear Boiler System.................................................................... 2-31

2.3.1.4 Reactor Recirculation System........................................................ 2-32

2.3.1.5 Neutron Monitoring ........................................................................ 2-33

2.3.1.6 Fuel................................................................................................ 2-34

2.3.1.7 Miscellaneous RCS Systems in Scope for 10 CFR 54.4(a)(2)........ 2-34

2.3.2 Engineered Safety Features .......................................................................... 2-35

2.3.2.1 Residual Heat Removal ................................................................. 2-35

2.3.2.2 Low-Pressure Core Spray.............................................................. 2-36

2.3.2.3 High-Pressure Core Spray ............................................................. 2-37

2.3.2.4 Reactor Core Isolation Cooling ...................................................... 2-38

2.3.2.5 Pressure Relief .............................................................................. 2-39

2.3.2.6 Standby Gas Treatment ................................................................. 2-40

2.3.2.7 Containment Penetrations.............................................................. 2-41

2.3.2.8 Miscellaneous Engineering Safety Feature Systems in Scope 

for 10 CFR 54.4(a)(2)..................................................................... 2-42

2.3.3 Auxiliary Systems........................................................................................... 2-42

2.3.3.1 Control Rod Drive .......................................................................... 2-44

2.3.3.2 Standby Liquid Control................................................................... 2-45

2.3.3.3 Suppression Pool Makeup ............................................................. 2-46

2.3.3.4 Leakage Detection and Control...................................................... 2-47

2.3.3.5 Combustible Gas Control ............................................................... 2-48

2.3.3.6 Fuel Pool Cooling and Cleanup...................................................... 2-49

2.3.3.7 Standby Service Water .................................................................. 2-50

2.3.3.8 Component Cooling Water............................................................. 2-51

2.3.3.9 Plant Service Water ....................................................................... 2-51

2.3.3.10 Floor and Equipment Drainage ...................................................... 2-53

2.3.3.11 Compressed Air ............................................................................. 2-54

2.3.3.12 Fire Protection – Water .................................................................. 2-55

2.3.3.13 Fire Protection – Halon and CO2 .................................................... 2-60

2.3.3.14 Plant Chilled Water ........................................................................ 2-62
vii

2.3.3.15 Standby Diesel Generator.............................................................. 2-62

2.3.3.16 HPCS Diesel Generator................................................................. 2-63

2.3.3.17 Control Room Heating, Ventilation and Air Conditioning ................ 2-65

2.3.3.18 Heating, Ventilation and Air Conditioning ....................................... 2-66

2.3.3.19 Miscellaneous Auxiliary Systems in Scope for 

10 CFR 54.4(a)(2).......................................................................... 2-67

2.3.4 Steam and Power Conversion Systems ......................................................... 2-72

2.3.4.1 Condensate and Refueling Water Storage and Transfer................ 2-73

2.3.4.2 Miscellaneous Steam and Power Conversion Systems in 

Scope for 10 CFR 54.4(a)(2).......................................................... 2-74

2.4 Scoping and Screening Results: Structures............................................................... 2-80

2.4.1 Containment Building..................................................................................... 2-80

2.4.1.1 Summary of Technical Information in the Application..................... 2-80

2.4.1.2 Staff Evaluation.............................................................................. 2-83

2.4.1.3 Conclusion ..................................................................................... 2-83

2.4.2 Water Control Structures................................................................................ 2-83

2.4.2.1 Summary of Technical Information in the Application..................... 2-83

2.4.2.2 Staff Evaluation.............................................................................. 2-85

2.4.2.3 Conclusion ..................................................................................... 2-85

2.4.3 Turbine Building, Process Facilities and Yard Structures ............................... 2-85

2.4.3.1 Summary of Technical Information in the Application..................... 2-85

2.4.3.2 Staff Evaluation.............................................................................. 2-90

2.4.3.3 Conclusion ..................................................................................... 2-91

2.4.4 Bulk Commodities.......................................................................................... 2-91

2.4.4.1 Summary of Technical Information in the Application..................... 2-91

2.4.4.2 Staff Evaluation.............................................................................. 2-92

2.4.4.3 Conclusion ..................................................................................... 2-92

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems .................................................................................................................... 2-92

2.5.1 Electrical and Instrumentation and Control Systems ...................................... 2-93

2.5.1.1 Summary of Technical Information in the Application..................... 2-93

2.5.1.2 Staff Evaluation.............................................................................. 2-94

2.5.1.3 Conclusion ..................................................................................... 2-95

2.6 Conclusion for Scoping and Screening...................................................................... 2-95

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

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

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

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

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

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

3.0.2.1 Review of AMPs............................................................................... 3-4
viii

3.0.2.2 Review of AMR Results ................................................................... 3-5

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......................................... 3-10

3.0.3.2 AMPs Not Consistent with or Not Addressed in the GALL 

Report.......................................................................................... 3-213

3.0.3.3 Aging Management Related to Loss of Coating Integrity for 

Internal Coatings on In-Scope Mechanical SSCs ......................... 3-227

3.0.4 QA Program Attributes Integral to Aging Management Programs ................ 3-233

3.0.4.1 Summary of Technical Information in the Application................... 3-234

3.0.4.2 Staff Evaluation............................................................................ 3-235

3.0.4.3 Conclusion ................................................................................... 3-235

3.0.5 Operating Experience for Aging Management Programs ............................. 3-235

3.0.5.1 Summary of Technical Information in Application......................... 3-235

3.0.5.2 Staff Evaluation............................................................................ 3-236

3.0.5.3 UFSAR Supplement..................................................................... 3-247

3.0.5.4 Conclusion ................................................................................... 3-248

3.1 Aging Management of Reactor Vessel, Internals, and Reactor Coolant System...... 3-248

3.1.1 Summary of Technical Information in the Application................................... 3-248

3.1.2 Staff Evaluation............................................................................................ 3-248

3.1.2.1 AMR Results Consistent with the GALL Report............................ 3-270

3.1.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-279

3.1.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-287

3.1.3 Conclusion................................................................................................... 3-291

3.2 Aging Management of Engineered Safety Features Systems.................................. 3-291

3.2.1 Summary of Technical Information in the Application................................... 3-291

3.2.2 Staff Evaluation............................................................................................ 3-291

3.2.2.1 AMR Results Consistent with the GALL Report............................ 3-302

3.2.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-310

3.2.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-313

3.2.3 Conclusion................................................................................................... 3-317

3.3 Aging Management of Auxiliary Systems................................................................. 3-317

3.3.1 Summary of Technical Information in the Application................................... 3-318

3.3.2 Staff Evaluation............................................................................................ 3-318

3.3.2.1 AMR Results Consistent with the GALL Report............................ 3-338

3.3.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-358
ix

3.3.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-363

3.3.3 Conclusion................................................................................................... 3-390

3.4 Aging Management of Steam and Power Conversion Systems ............................... 3-390

3.4.1 Summary of Technical Information in the Application................................... 3-390

3.4.2 Staff Evaluation............................................................................................ 3-390

3.4.2.1 AMR Results Consistent with the GALL Report............................ 3-400

3.4.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-405

3.4.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-408

3.4.3 Conclusion................................................................................................... 3-413

3.5 Aging Management of Structures and Component Supports ................................... 3-413

3.5.1 Summary of Technical Information in the Application................................... 3-414

3.5.2 Staff Evaluation............................................................................................ 3-414

3.5.2.1 AMR Results Consistent with the GALL Report............................ 3-431

3.5.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-455

3.5.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-476

3.5.3 Conclusion................................................................................................... 3-490

3.6 Aging Management of Electrical and Instrumentation and Controls System ............ 3-491

3.6.1 Summary of Technical Information in the Application................................... 3-491

3.6.2 Staff Evaluation............................................................................................ 3-491

3.6.2.1 AMR Results Consistent with the GALL Report............................ 3-498

3.6.2.2 AMR Results Consistent with the GALL Report for Which 

Further Evaluation is Recommended ........................................... 3-500

3.6.2.3 AMR Results Not Consistent with or Not Addressed in the 

GALL Report................................................................................ 3-506

3.6.3 Conclusion................................................................................................... 3-507

3.7 Conclusion for Aging Management Review Results................................................. 3-507

SECTION 4 TIME-LIMITED AGING ANALYSES................................................................ 4-1

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

4.1.1 Summary of Technical Information in the Application....................................... 4-2

4.1.1.1 Identification of TLAAs ..................................................................... 4-2

4.1.1.2 Identification of Regulatory Exemptions ........................................... 4-3

4.1.2 Staff Evaluation................................................................................................ 4-3

4.1.2.1 Identification of TLAAs ..................................................................... 4-3

4.1.2.2 Identification of Exemptions in the LRA.......................................... 4-23

4.1.3 Conclusion..................................................................................................... 4-25

4.2 Reactor Vessel Neutron Embrittlement...................................................................... 4-25

4.2.1 Reactor Vessel Fluence................................................................................. 4-25
x

4.2.1.1 Summary of Technical Information in the Application..................... 4-25

4.2.1.2 Staff Evaluation.............................................................................. 4-25

4.2.1.3 UFSAR Supplement....................................................................... 4-37

4.2.1.4 Conclusion ..................................................................................... 4-38

4.2.2 Pressure-Temperature Limits......................................................................... 4-38

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

4.2.2.2 Staff Evaluation.............................................................................. 4-38

4.2.2.3 UFSAR Supplement....................................................................... 4-39

4.2.2.4 Conclusion ..................................................................................... 4-40

4.2.3 Upper-Shelf Energy ....................................................................................... 4-40

4.2.3.1 Summary of Technical Information in the Application..................... 4-40

4.2.3.2 Staff Evaluation.............................................................................. 4-41

4.2.3.3 UFSAR Supplement....................................................................... 4-45

4.2.3.4 Conclusion ..................................................................................... 4-45

4.2.4 Reactor Vessel Circumferential Weld Inspection Relief.................................. 4-45

4.2.4.1 Summary of Technical Information in the Application..................... 4-45

4.2.4.2 Staff Evaluation.............................................................................. 4-46

4.2.4.3 UFSAR Supplement....................................................................... 4-48

4.2.4.4 Conclusion ..................................................................................... 4-48

4.2.5 Reactor Vessel Axial Weld Failure Probability................................................ 4-48

4.2.5.1 Summary of Technical Information in the Application..................... 4-48

4.2.5.2 Staff Evaluation.............................................................................. 4-49

4.2.5.3 UFSAR Supplement....................................................................... 4-50

4.2.5.4 Conclusion ..................................................................................... 4-50

4.2.6 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis................... 4-50

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

4.2.6.2 Staff Evaluation.............................................................................. 4-51

4.2.6.3 UFSAR Supplement....................................................................... 4-53

4.2.6.4 Conclusion ..................................................................................... 4-53

4.3 Metal Fatigue............................................................................................................. 4-53

4.3.1 Class 1 Fatigue.............................................................................................. 4-53

4.3.1.1 Reactor Vessel............................................................................... 4-58

4.3.1.2 Reactor Vessel Feedwater Nozzle ................................................. 4-60

4.3.1.3 Reactor Pressure Vessel Internals................................................. 4-62

4.3.1.4 Reactor Recirculation Pumps......................................................... 4-64

4.3.1.5 Control Rod Drives......................................................................... 4-66

4.3.1.6 Class 1 Piping................................................................................ 4-67

4.3.2 Non-Class 1 Fatigue ...................................................................................... 4-70

4.3.2.1 Non-Class 1 Fatigue – Piping and In-Line Components ................. 4-70

4.3.2.2 Non-Class 1 Fatigue - Non-Piping Components............................. 4-72

4.3.3 Effects of Reactor Water Environment on Fatigue Life................................... 4-76
xi

4.3.3.1 Summary of Technical Information in the Application..................... 4-76

4.3.3.2 Staff Evaluation.............................................................................. 4-76

4.3.3.3 UFSAR Supplement....................................................................... 4-80

4.3.3.4 Conclusion ..................................................................................... 4-80

4.4 Environmental Qualification of Electric Equipment..................................................... 4-80

4.4.1 Summary of Technical Information in the Application..................................... 4-81

4.4.2 Staff Evaluation.............................................................................................. 4-81

4.4.3 UFSAR Supplement....................................................................................... 4-82

4.4.4 Conclusion..................................................................................................... 4-82

4.5 Concrete Containment Tendon Prestress Analyses................................................... 4-82

4.5.1 Summary of Technical Information in the Application..................................... 4-82

4.5.2 Staff Evaluation.............................................................................................. 4-82

4.5.3 UFSAR Supplement....................................................................................... 4-83

4.5.4 Conclusion..................................................................................................... 4-83

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses.................................................................................................................... 4-83

4.6.1 Containment Liner Plate, Metal Containments ............................................... 4-83

4.6.1.1 Summary of Technical Information in the Application..................... 4-83

4.6.1.2 Staff Evaluation.............................................................................. 4-83

4.6.1.3 UFSAR Supplement....................................................................... 4-85

4.6.1.4 Conclusion ..................................................................................... 4-85

4.6.2 Containment Penetrations.............................................................................. 4-85

4.6.2.1 Summary of Technical Information in the Application..................... 4-85

4.6.2.2 Staff Evaluation.............................................................................. 4-86

4.6.2.3 UFSAR Supplement....................................................................... 4-87

4.6.2.4 Conclusion ..................................................................................... 4-87

4.7 Other Plant-Specific TLAAs ....................................................................................... 4-87

4.7.1 Erosion of the MSL Flow Restrictors .............................................................. 4-87

4.7.1.1 Summary of Technical Information in the Application..................... 4-87

4.7.1.2 Staff Evaluation.............................................................................. 4-88

4.7.1.3 UFSAR Supplement....................................................................... 4-89

4.7.1.4 Conclusion ..................................................................................... 4-89

4.7.2 Determination of Intermediate High-Energy Line Break Locations ................. 4-90

4.7.2.1 Summary of Technical Information in the Application..................... 4-90

4.7.2.2 Staff Evaluation.............................................................................. 4-90

4.7.2.3 UFSAR Supplement....................................................................... 4-92

4.7.2.4 Conclusion ..................................................................................... 4-93

4.7.3 Fluence Effects for the Reactor Vessel Internals............................................ 4-93

4.7.3.1 Summary of Technical Information in the Application..................... 4-93

4.7.3.2 Staff Evaluation.............................................................................. 4-93

4.7.3.3 UFSAR Supplement....................................................................... 4-96
xii

4.7.3.4 Conclusion ..................................................................................... 4-97

4.7.4 Fatigue Analysis of Cranes ............................................................................ 4-97

4.7.4.1 Summary of Technical Information in the Application..................... 4-97

4.7.4.2 Staff Evaluation.............................................................................. 4-97

4.7.4.3 UFSAR Supplement....................................................................... 4-98

4.7.4.4 Conclusion ..................................................................................... 4-99

4.8 Conclusion for TLAAs................................................................................................ 4-99

SECTION 5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS................................................................................................ 5-1

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

APPENDICES

APPENDIX A GRAND GULF NUCLEAR STATION, UNIT 1, LICENSE RENEWAL 

COMMITMENTS..............................................................................................A-1

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

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

APPENDIX D REFERENCES ................................................................................................D-1
xiii

LIST OF TABLES

Table 1.4-1 Current Interim Staff Guidance........................................................................... 1-6

Table 3.0-1 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 ............................ 3-249

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

the GALL Report ............................................................................................ 3-292

Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report.......... 3-319

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

in the GALL Report ........................................................................................ 3-391

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

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

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

GALL Report .................................................................................................. 3-492

xv

ABBREVIATIONS

AC alternating current

AAI applicant action item

ACI American Concrete Institute

ACRS Advisory Committee on Reactor Safeguards

ADAMS Agency wide Document Access and Management System

AERM aging effect requiring management

AFW auxiliary feedwater

AISC American Institute of Steel Construction

AMP aging management program

AMR aging management review

ANSI American National Standards Institute

APEC area potential earth current

APRM average power range monitor subsystem

ART adjusted reference temperature

ASME American Society of Mechanical Engineers

ASTM American Society for Testing and Materials

ATWS anticipated transient without scram

B&W Babcock and Wilcox

BTP Branch Technical Position

BWR boiling water reactor

BWRVIP Boiling Water Reactor Vessel and Internals Project

CAP corrective action program

CASS cast austenitic stainless steel

CB&I Chicago Bridge & Iron

CFR Code of Federal Regulations

CLB current licensing basis

CMAA Crane Manufacturers Association of America

CMTR certified material test report

CPF conditional probability of failure

CRD control rod drive

CS core spray

CST condensate storage tank

CUF cumulative usage factor

CUFen fatigue cumulative usage factor

CRW clean radwaste

CUI corrosion under insulation

CW circulating water

DBA design basis accident

DBE design basis event

DM dissimilar metal

EAF environmentally assisted fatigue

ECCS emergency core cooling system

ECP electrochemical corrosion potential

EDG emergency diesel generator

EFPY effective full-power year
xvi

EIC electrical and instrumentation and control

EPRI Electric Power Research Institute

EPU extended power uprate

EQ environmental qualification

ER Environmental report (Applicant’s Environmental Report Operating License 

Renewal Stage)

ESF engineered safety features

Fen environmental fatigue life correction factor

FERC Federal Energy Regulatory Commission

FR Federal Register

FSAR final safety analysis report

FW feedwater

GALL Generic Aging Lessons Learned Report

GDC general design criteria or general design criterion

GE General Electric

GEH General Electric-Hitachi

GEIS generic environmental impact statement

GGNS Grand Gulf Nuclear Station, Unit 1

GL generic letter

GSI generic safety issue

HELB high-energy line break

HPCS high-pressure core spray

HVAC heating, ventilation, and air conditioning

HWC hydrogen water chemistry

I&C instrumentation and controls

I&FE inspection and flaw evaluation

IASCC irradiation assisted stress-corrosion cracking

ICMH in-core monitoring housing

ID inside diameter

IGA intergranular attack

IGSCC intergranular stress-corrosion cracking

IHSI induction heating stress improvement

IN information notice

INPO Institute of Nuclear Power Operations

ILRT integrated leakage rate test

IPA integrated plant assessment

IRM intermediate range monitor subsystem

ISG interim staff guidance

ISI inservice inspection

ISP Integrated Surveillance Program

kV kilo-volt

LAR license amendment request

LBB leak-before-break

LER licensee event report

LLRT local leakage rate test
xvii

LOCA loss-of-coolant accident

LPCI low-pressure coolant injection

LPCS low-pressure core spray

LPRM local power range monitor

LRA license renewal application

LRT leakage rate test

LTOP low-temperature overpressure protection

MC metal containment

MCM thousand circular mils

MEA material, environment, aging effect

MeV megaelectron volt

MoS2 molybdenum sulfide

MSIV main steam isolation valve

MSL main steam line

mV millivolt

MWt megawatts-thermal

NDE nondestructive examination

NEI Nuclear Energy Institute

NESC National Electrical Safety Code

NFPA National Fire Protection Association

NMCA noble metal chemical application

NPS nominal pipe size

NRC US Nuclear Regulatory Commission

NWC normal water chemistry

OEP Operating Experience Program

P&ID plant piping and instrumentation drawing

PH precipitation-hardened

ppm parts per million

P-T pressure-temperature

PTLR Pressure-Temperature Limits Report

PTS pressurized thermal shock

PWR pressurized water reactor

PWSCC primary water stress-corrosion cracking

QA quality assurance

RAI request for additional information

RAMA Radiation Analysis Modeling Application

RCIC reactor core isolation cooling

RCP reactor coolant pump

RCPB reactor coolant pressure boundary

RCS reactor coolant system

RCSC Research Council for Structural Connections

RFPT recirculation feed pump turbine

RG regulatory guide

RHR residual heat removal

RI-ISI risk-informed inservice inspection
xviii

RPV reactor pressure vessel

RV reactor vessel

RVI reactor vessel internal(s)

RWCU reactor water cleanup

RWST refueling water storage tank

SBO station blackout

SC structure and component

SCC stress-corrosion cracking

SCRAM emergency reactor shutdown

SE safety evaluation

SER safety evaluation report

SGTS standby gas treatment system

SLC standby liquid control

SRM source range monitor

SRP Standard Review Plan

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

Nuclear Power Plants

SS stainless steel

SRV safety relief valve

SSC system, structure, and component

SSES Susquehanna Steam Electric Station

SSW standby service water

TIP traversing in-core probe

TLAA time-limited aging analysis

TS technical specification(s)

UFSAR updated final safety analysis report

US United States

USE upper-shelf energy

UT ultrasonic examination

UV ultraviolet

VFLD vessel flange leak detection

yr year

Zn zinc
1-1

SECTION 1

INTRODUCTION AND GENERAL DISCUSSION

1.1 Introduction

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

Grand Gulf Nuclear Station, Unit 1 (GGNS), as filed by Entergy Operations, Inc. (Entergy or the 

applicant). By letter dated October 28, 2011, Entergy submitted its application to the United 

States (US) Nuclear Regulatory Commission (NRC) for renewal of the GGNS’s operating 

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

the results of its safety review of the LRA for compliance with Title 10, Part 54, “Requirements 

for Renewal of Operating Licenses for Nuclear Power Plants,” of the Code of Federal 

Regulations (10 CFR Part 54). The NRC project manager for the license renewal review is 

Emmanuel Sayoc. Mr. Sayoc may be contacted by telephone at 301-415-4084 or by electronic 

mail at Emmanuel.Sayoc@nrc.gov. Alternatively, written correspondence may be sent to the 

following address:

U.S. Nuclear Regulatory Commission

Division of License Renewal

Attention: Emmanuel Sayoc

Mail Stop O11F1

Washington, DC 20555-0001

In its October 28, 2011, submission letter, the applicant requested renewal of the operating 

license[s] issued under Section 103 (Operating License No. NPF-29) of the Atomic Energy Act 

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

midnight November 1, 2024. GGNS is located approximately 20 miles southwest of 

Vicksburg, MS. The NRC issued the GGNS construction permit on September 4, 1974, and the 

operating license on November 1, 1984. GGNS is a boiling water reactor design. General 

Electric supplied the nuclear steam supply system and Allis-Chalmers Power Systems furnished 

the turbine generator set. The containment is a steel-lined reinforced concrete structure 

designed by Bechtel Power Corporation. The GGNS licensed power output is 4,408 megawatt 

thermal. The updated final safety analysis report (UFSAR) shows details of the plant and the 

site.

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

environmental issues. 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 

GGNS license renewal is based on the applicant’s LRA and responses to the staff’s requests for 

additional information (RAIs). The applicant supplemented the LRA and provided clarifications 

through its responses to the staff’s RAIs in audits, meetings, and docketed correspondence. 

Unless otherwise noted, the staff reviewed and considered information submitted through 

October 3, 2016. The public may view the LRA and all pertinent information and materials, 

including the UFSAR, 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 at the Harriette Person Memorial Library, 606 Main St., Port Gibson, MS 39150. In 

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

on the NRC website at http://www.nrc.gov.
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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 GGNS’s proposed operation for 

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

LRA in accordance with NRC regulations and the guidance in NUREG-1800, Revision 2, 

“Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants”

(SRP-LR), dated December 2010.

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

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

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

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

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

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

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

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

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

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

renewal for GGNS.

1.2 License Renewal Background

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

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

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

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

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

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

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

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

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

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

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

license renewal for nuclear power plants.

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

page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). 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. As a result of this finding, the staff amended 10 CFR Part 54 in 1995. As 

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

process that is simpler, more stable, and more predictable than the previous 10 CFR Part 54. In 

particular, as amended, 10 CFR Part 54 focuses on the management of adverse aging effects 
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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. In June 2013, the staff revised and updated the 

environmental protection regulations (10 CFR Part 51) and issued a revised GEIS (GEIS, 

Revision 1) to incorporate lessons learned and knowledge gained from previous plant-specific 

environmental reviews. The revisions identify 78 environmental impact issues for consideration

in license renewal environmental reviews, 59 of which have been determined to be generic to all 

plant sites.

1.2.1 Safety Review

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

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

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

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

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

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

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

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

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

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

regulations for fire protection, environmental qualification, pressurized thermal shock, 

anticipated transient without scram, and station blackout.

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.
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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 fully utilized the process defined in NUREG-1801, Revision 2, “Generic 

Aging Lessons Learned (GALL) Report,” dated December 2010. 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. In December 1996, the 

staff revised the environmental protection regulations to facilitate the 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 plant-specific 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 January 31, 2012, at Port Gibson City Hall, to identify 

plant-specific environmental issues. The draft, plant-specific GEIS Supplement documented the 

results of the environmental review and made a preliminary recommendation as to the license 

renewal action. The staff held another public meeting to discuss the draft, plant-specific GEIS 

Supplement. The staff published the final, plant-specific GEIS Supplement separately from this 

report, after considering comments on the draft.
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1.3 Principal Review Matters

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

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

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

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

the staff’s safety review.

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

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

and finds that the applicant has submitted the required information.

Pursuant to 10 CFR 54.19(b), the NRC requires that the LRA include “conforming changes to 

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

term of the proposed renewed license.” On this issue, the applicant stated in the LRA:

10 CFR 54.19(b) requires that license renewal applications include “conforming 

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

account for the expiration term of the proposed renewal license.” The current 

indemnity agreement (No. B-72) for GGNS states in Article VII that the 

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

Item 3 of the Attachment to the agreement, which is the last to expire. Item 3 of 

the Attachment to the indemnity agreement, as revised by Amendment No. 4, 

lists GGNS operating license number NPF-29. The applicant requests that any 

necessary conforming changes be made to specify the extension of the 

agreement until the expiration of the renewed GGNS facility operating license 

sought in the application. In addition, should the license number change upon 

issuance of the renewed license, the applicant requests that conforming changes 

be made to Item 3 of the Attachment, and other sections of the indemnity 

agreement, as appropriate. 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 

during the staff’s review of the LRA, (c) an evaluation of TLAAs, and (d) a UFSAR supplement. 

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

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

10 CFR 54.21(d).

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

and at least 3 months before the scheduled completion of the staff’s review, the applicant 

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

the LRA, including the UFSAR supplement. By letters dated August 15, 2012, 

October 25, 2013, October 27, 2014, and December 10, 2015, the applicant submitted LRA 

updates which summarized the CLB changes that have occurred during the staff’s review of the 

LRA. These submissions satisfy 10 CFR 54.21(b) requirements.

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

requires that the LRA include changes or additions to the technical specifications (TS) that are 
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necessary to manage aging effects during the period of extended operation. In LRA 

Appendix D, the applicant stated that it had not identified any TS changes necessary for 

issuance of the renewed GGNS operating license. This statement adequately addresses the 

10 CFR 54.22 requirement.

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

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

the staff’s evaluation of the LRA technical information.

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

ACRS 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 Interim Staff Guidance

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

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

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

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

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

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

GALL Report.

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

addresses them.

Table 1.4-1 Current Interim Staff Guidance

ISG Issue

(Approved ISG Number) Purpose SER Section

“Aging Management of Stainless 

Steel Structures and Components in 

Treated Borated Water, Revision 1” 

(LR-ISG-2011-01)

This LR-ISG provides guidance as to 

an acceptable approach for 

managing the effects of aging during 

the period of extended operation for 

stainless steel structures and 

components exposed to treated 

borated water within the scope of 

10 CFR Part 54.

SER Section 3.5.2.1.10

“Aging Management Program for 

Steam Generators” 

(LR-ISG-2011-02)

This LR-ISG evaluates the suitability 

of using Revision 3 of NEI 97-06 for 

implementing the steam generator 

AMP.

N/A for the SER

“Generic Aging Lessons Learned 

(GALL) Report Revision 2 Aging 

Management Program XI.M41, 

‘Buried and Underground Piping and 

Tanks’” (LR-ISG-2011-03)

This LR-ISG provides an acceptable 

approach for managing the effects of 

aging of buried and underground 

piping and tanks within the scope of 

10 CFR Part 54.

SER Section 3.0.3.1.4

“Updated Aging Management Criteria 

for Reactor Vessel Internal 

Components of Pressurized Water 

Reactors” (LR-ISG-2011-04)

This LR-ISG revises the 

recommendations in the GALL 

Report and the staff’s acceptance 

criteria and review procedures in the 

SRP-LR to ensure consistency with 

Materials Reliability Program 

(MRP)-227-A. This LR-ISG also 

N/A for the SER
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ISG Issue

(Approved ISG Number) Purpose SER Section

provides a framework to ensure that 

PWR LRAs will adequately address 

age-related degradation and aging 

management of reactor vessel 

internal (RVI) components during the 

term of the renewed license.

“Ongoing Review of Operating 

Experience” (LR-ISG-2011-05)

This LR-ISG clarifies the staff’s 

existing position in the SRP-LR that 

acceptable license renewal AMPs 

should be informed and enhanced 

when necessary, based on the 

ongoing review of both plant-specific 

and industry operating experience.

SER Section 1.5, 3.0.5.2, 3.0.5.2.2 

and 3.0.5.3

“Wall Thinning Due to Erosion 

Mechanisms” (LR-ISG-2012-01)

This LR-ISG provides guidance on an 

acceptable approach to manage the 

effects of aging during the period of 

extended operation for wall thinning 

due to various erosion mechanisms 

for piping and components within the 

scope of 10 CFR Part 54. This 

LR-ISG also GALL Report AMP 

XI.M17, “Flow-Accelerated 

Corrosion.”

SER Section 3.0.3.1.21

“Aging Management of Internal 

Surfaces, Fire Water Systems, 

Atmospheric Storage Tanks, and 

Corrosion Under Insulation” 

(LR-ISG-2012-02)

This LR-ISG revises existing 

guidance in the GALL Report and 

SRP-LR related to aging 

management of internal surfaces of 

components and atmospheric 

storage tanks. Also, it provides 

recommendations for corrosion under 

insulation of component external 

surfaces.

SER Section 3.0.3.1.17, 3.0.3.2.2, 

3.2.2.2.8, 3.3.2.2.7, 3.3.2.3.7, 

3.4.2.2.5, and 3.4.2.3.2

“Aging Management of Loss of 

Coating or Lining Integrity for Internal 

Coatings/Linings on In-Scope Piping, 

Piping Components, Heat 

Exchangers, and Tanks” 

(LR-ISG-2013-01)

This LR-ISG provides an acceptable 

approach for managing these 

associated aging effects for 

components within the scope of 

license renewal.

SER Section 3.0.3.1.20, 3.0.3.3.1, 

3.0.3.3.2, and 3.0.3.3.3

LR-ISG-2015-01, “Changes to Buried and Underground Piping and Tank Recommendations,” 

was issued final on February 4, 2015, coincident with the final concurrence process of the 

SER. The staff concluded that the changes in the ISG do not affect the staff’s conclusions 

related to the applicant’s Buried Piping and Tanks Inspection Program documented in SER 

Section 3.0.3.1.4. The staff based its conclusion on a review of the changes in 

LR-ISG-2015-01. For example, the ISG: (a) reduced the number of recommended inspections 

of buried piping from that cited in the applicant’s program; (b) provided further options for 

cathodic protection acceptance criteria, but retained the former criteria; and (c) recommended 

that underground steel components be coated; however, as documented in SER 

Section 3.0.3.1.4, the applicant’s underground components are coated.

1.5 Summary – Closure of Open Items

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

October 3, 2016, the staff closed the following open items previously identified in the “Safety 
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Evaluation Report with Open Items Related to the License Renewal of Grand Gulf Nuclear 

Station, Unit 1,” dated January 31, 2013 (Agencywide Documents Access and Management 

System (ADAMS) Accession No. ML13032A194). No other open items remain to be addressed. 

An item is considered open if the staff has not made a finding under 10 CFR 54.29 (Standards 

for issuance of a renewed license) with respect to that particular item. A summary of the basis 

for each closed open item is presented here.

Open Item 3.0.3.1.33-1 One-Time Inspection – Small-Bore Piping

As described in SER Section 3.0.3.1.33, the GGNS operating experience review of the previous

10 years of condition reports does not fully demonstrate consistency with GALL Report 

AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” As described 

in SER Section 3.0.3.1.33, the staff determined that it needs the methodology and results of an 

applicant review of the period of plant operation leading up to the 10-year period covered in the 

previous review. This information is necessary to demonstrate that the one-time inspections 

recommended by GALL Report AMP XI.M35 will ensure that the effects of aging will be 

adequately managed for ASME Code Class 1 small-bore piping.

By letter dated April 15, 2013, the applicant stated that it completed an additional search of 

condition reports for the period beginning from the start of licensed operation of GGNS. Based 

on this additional search, the applicant stated that it identified no instances of age-related 

cracking of ASME Code Class 1 small-bore piping. The staff reviewed the applicant’s search 

methodology and results and determined that they are satisfactory. Because the applicant 

reviewed plant-specific operating experience covering the full operating history of the plant, and 

this review identified no instances of age-related cracking of ASME Code Class 1 small-bore 

piping, the staff determined that the applicant has demonstrated applicability of GALL Report 

AMP XI.M35 to GGNS. As such, the staff finds that the applicant’s One-Time Inspection –

Small-Bore Piping Program is consistent GALL Report AMP XI.M35 and will ensure that the 

effects of aging will be adequately managed for ASME Code Class 1 small-bore piping. Open 

Item 3.0.3.1.33-1 is closed.

Open Item 3.0.3.1.39-1 Service Water Integrity

As described in SER Section 3.0.3.1.39, recent GGNS plant‐specific operating experience 

condition reports discuss minor erosion to a valve flange connection in the standby service 

water (SSW) system. Proposals were made to include this valve in an “appropriate piping 

program” (GGNS MS‐46, “Project Plan for Monitoring Internal Erosion/Corrosion in Moderate 

Energy Piping Components”). Although the program plan identified the SSW system as a 

susceptible system in the moderate energy program, it was not clear to the staff whether 

components in the SSW system were being managed for loss of material due to erosion 

because it is not described in the LRA nor discussed in the onsite program evaluation 

documentation.

The applicant addressed the issues associated with Open Item 3.0.3.1.39-1 in its response to 

RAI B.1.41-3c, dated December 20, 2013. The applicant revised LRA Sections A.1.41 and 

B.1.41 to state that the Service Water Integrity Program also includes inspections for loss of 

material due to erosion and included a new enhancement to revise program documents to 

include inspections for this aging mechanism. In separate correspondence associated with a 

Predecisional Enforcement Conference, dated August 8, 2013, the applicant stated that its 

previous response had incorrectly stated that GGNS-MS-46 is not credited for managing loss of 

material due to erosion. As part of the current response, the applicant stated that it had 
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identified discrepancies in the GGNS-MS-46 database during the development of its RAI 

response and this condition had been entered into its corrective action program. On the basis 

of the staff’s evaluation of the applicant’s responses, Open Item 3.0.3.1.39-1 is closed. The 

staff’s resolution and closure of this issue is documented in SER Section 3.0.3.1.39.

Open Item 3.0.5-1 Operating Experience for Aging Management Programs

As described in SER Section 3.0.5, the staff determined that the applicant’s programmatic 

activities for the ongoing review of operating experience were consistent with the guidance in 

SRP-LR Section A.4.2, as established in LR-ISG-2011-05, with the exception of those activities 

associated with (1) identification of age-related operating experience, (2) evaluation of AMP 

implementation results, (3) content of personnel training, and (4) operating experience reporting. 

These four areas were the subject of Open Item 3.0.5-1.

Based on its review of additional information provided by the applicant in letters dated 

April 15, 2013, and October 11, 2013, the staff determined that the applicant’s activities for 

(1) identification of age-related operating experience, (2) evaluation of AMP implementation 

results, and (3) the content of its personnel training are consistent with the guidance in SRP-LR 

Section A.4.2. The staff ultimately determined that the applicant’s activities associated with 

operating experience reporting are not consistent with the guidance in SRP-LR Section A.4.2. 

However, the staff determined that this inconsistency is an acceptable departure from the 

guidance because these reporting activities would not directly facilitate the applicant’s ability to 

maintain the effectiveness of its own AMPs. Based on the completion of its review, the staff 

determined that the applicant’s programmatic activities for the ongoing review of operating 

experience are acceptable because they provide for: (a) the systematic review of plant-specific 

and industry operating experience to ensure that the license renewal AMPs are and will 

continue to be effective in managing the aging effects for which they are credited, and (b) the 

enhancement of AMPs or development of new AMPs when it is determined through the 

evaluation of operating experience that the effects of aging may not be adequately managed. 

Open Item 3.0.5-1 is closed.

Open Item 4.2.1-1 Reactor Vessel Fluence

The staff reviewed the applicant’s fluence analysis for the reactor vessel, consistent with the 

review procedures in SRP‐LR Section 4.2, which indicates that the applicant identifies (a) the 

neutron fluence for the reactor vessel at the expiration of the license renewal period; (b) the 

staff‐approved methodology used to determine the neutron fluence; and (c) whether the method 

follows the guidance in NRC RG 1.190. 

In its review, the staff determined that the applicant’s fluence method was inconsistent with NRC 

RG 1.190. RG 1.190 does not address the use of a method combining fluence results from two 

different methods. As a result, the staff requested a sufficient technical basis for combining the 

fluence results in order to ensure adequate analytic uncertainty analysis. Alternatively, the staff 

requested the applicant to provide results from a single method which is within the scope of RG 

1.190. 

The staff also noted that the method used to perform the MPM pre-EPU fluence calculations is 

not documented in an NRC-approved method. Therefore, the staff noted that a detailed 

description of the calculational method, and their qualification, as both pertain to GGNS, must 

be submitted for NRC staff review and approval for referencing in the LRA.
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As described in SER Section 4.2.1, the staff finds that the applicant’s response is acceptable 

because (1) the applicant provided the relevant reference to the staff-approved single fluence 

method (i.e., MPM method) that was approved in the staff’s August 18, 2015, safety evaluation

(SE), (2) the approved method, consistent with RG 1.190, was incorporated into the current 

licensing basis by License Amendment No. 204, and (3) the additional actions of the applicant, 

which are specified in the staff’s August 18, 2015, SE, will ensure adequate qualification of the 

fluence method for the locations outside the original beltline region (e.g., comparison of fluence 

calculations with dosimetry measurements at core shroud locations above the active core 

region).

Additionally, the staff finds that the applicant adequately evaluated the TLAA for the reactor 

vessel neutron fluence because (1) the applicant adequately identified neutron fluence 

calculations as a neutron embrittlement TLAA, (2) the applicant incorporated the staff-approved 

fluence method into the current licensing basis through the license amendment process, (3) the 

applicant performed 54-EFPY (effective full-power year) fluence calculations in accordance with 

the staff-approved method that is consistent with the guidance in RG 1.190, and (4) the 

applicant’s analysis provides neutron fluence projections to the end of the period of extended 

operation (54 EFPY). Open Item 4.2.1-1 is closed.

1.6 Summary of Confirmatory Items

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

October 3, 2016, the staff determines that no confirmatory items exist which would require a 

formal response from the applicant.

1.7 Summary of Proposed License Conditions

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

the applicant, the staff identified two proposed license conditions.

License Condition No. 1:

The information in the UFSAR supplement, submitted pursuant to 10 CFR 54.21(d), as revised 

during the LRA review process, and licensee commitments as listed in Appendix A of the 

“Safety Evaluation Report Related to the License Renewal of Grand Gulf Nuclear Station, Unit 

1,” are collectively the “License Renewal UFSAR Supplement.” This supplement is henceforth 

part of the UFSAR, which will be updated in accordance with 10 CFR 50.71(e). As such, the 

licensee may make changes to the programs, activities, and commitments described in this 

Supplement, provided the licensee evaluates such changes pursuant to the criteria set forth in 

10 CFR 50.59 and otherwise complies with the requirements in that section.

License Condition No. 2:

The “License Renewal UFSAR Supplement,” as updated by license condition [1] above, 

describes certain programs to be implemented and activities to be completed prior to the period 

of extended operation.

(a) The applicant shall implement those new programs and enhancements to existing 

programs no later than 6 months prior to the period of extended operation.
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(b) The applicant shall complete those activities by the 6-month date prior to the period of 

extended operation or the end of the last refueling outage prior to the period of extended 

operation, whichever occurs later.

(c) The applicant shall notify the NRC in writing within 30 days after having accomplished 

item (a) above and include the status of those activities that have been or remain to be 

completed in item (b) above.

The purpose of requiring the completion of implementation, inspection, and testing, either before 

the end of the last refueling outage or before the 6-month time frame, is to ensure that the 

implementation of programs and completion of specific activities can be confirmed by the staff’s 

oversight process before each plant enters its respective period of extended operation.

LRA Appendix A, Section A.5, “License Renewal Commitment List,” contains commitments for 

license renewal and an associated schedule for when the applicant plans to implement or 

complete the commitments. Through the commitments in LRA Appendix A, Section A.4, the 

applicant will implement new programs and enhancements to existing programs and will also 

complete inspection or testing activities. Because the applicant’s implementation schedule for 

some commitments, as provided originally in LRA Appendix A, Section A.5, could conflict with 

the implementation schedule intended by the generic second license condition described above, 

by letter dated November 21, 2013, the staff issued RAI A.1-1, which requested that the 

applicant provide the expected date for implementing all commitments prior to the period of 

extended operation and state whether the implementation would be documented as a license 

condition or as a supplement to the UFSAR. By letter dated December 20, 2013, the applicant 

responded to RAI A.1-1 and provided a revision to LRA Appendix A, in which it specified the 

time period when each commitment would be implemented and where it would be documented.

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SECTION 2

STRUCTURES AND COMPONENTS SUBJECT TO AGING 

MANAGEMENT REVIEW

2.1 Scoping and Screening Methodology

2.1.1 Introduction

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

Regulations (10 CFR 54.21) requires the applicant to identify the structures, systems and 

components (SSCs) within the scope of license renewal in accordance with 10 CFR 54.4(a). In 

addition, the license renewal application (LRA) must contain an integrated plant assessment 

(IPA) that identifies and lists those structures and components (SCs), contained in the SSCs 

identified to be within the scope of license renewal, that are subject to an aging management 

review (AMR).

2.1.2 Summary of Technical Information in the Application

LRA Section 2.0, “Scoping And Screening Methodology for Identifying Structures and 

Components Subject to Aging Management Review and Implementation Results,” provides the 

technical information required by 10 CFR 54.21(a).

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

Entergy Operations, Inc., System Energy Resources, Inc., and South Mississippi Electric Power 

Association (collectively, the applicant) used to identify the SSCs at the Grand Gulf Nuclear 

Station (GGNS) within the scope of license renewal (scoping) and the SCs subject to an AMR 

(screening).

LRA Section 2.1.1, “Scoping Methodology,” states, in part, that the applicant had considered the 

following in developing the scoping and screening methodology described in LRA Section 2.0:

• 10 CFR Part 54, “Requirements for Renewal of Operating Licenses for Nuclear Power 

Plants” (the Rule)

• 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 

(NEI 95-10)

2.1.3 Scoping and Screening Program Review

The United States (US) Nuclear Regulatory Commission (NRC) staff (the staff) evaluated the 

applicant’s scoping and screening methodology in accordance with the guidance contained in 

NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants,” (SRP-LR), Section 2.1, “Scoping and Screening Methodology.” The 

following regulations provide the basis for the acceptance criteria the staff used to assess the 

adequacy of the scoping and screening methodology that the applicant used to develop the 

LRA:
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• 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.

The staff reviewed the information in LRA Section 2.1 to ensure that the applicant described a 

process for identifying (1) SSCs that are within the scope of license renewal, in accordance with 

the requirements of 10 CFR 54.4(a), and (2) SCs that are subject to an AMR, in accordance 

with the requirements of 10 CFR 54.21(a).

In addition, the staff conducted a scoping and screening methodology audit at the GGNS facility 

located in Port Gibson, Mississippi, during the week of January 9–12, 2012. 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 methodology described in the LRA 

and the requirements of the Rule. The staff reviewed the project-level guidelines, topical 

reports, and implementing procedures that described the applicant’s scoping and screening 

methodology. The staff conducted detailed discussions with the applicant on the 

implementation and control of the license renewal, the quality practices the applicant used 

during the LRA development, and the training of its personnel that participated in the LRA 

development. On a sampling basis, the staff performed a review of scoping and screening 

results report and supporting current licensing basis (CLB) information for the standby service 

water (SSW) system and the turbine building. In addition, the staff performed walkdowns of 

selected portions of the SSW system and the turbine building, as a part of the sampling review 

of the implementation of the applicant’s 10 CFR 54.4(a)(2) scoping methodology.

2.1.3.1 Implementation Procedures and Documentation Sources for Scoping and 

Screening

2.1.3.1.1 Summary of Technical Information in the Application

The applicant had developed scoping and screening implementing procedures used to identify 

SSCs within the scope of license renewal and SCs subject to an AMR to implement the 

processes described in LRA Sections 2.1 and 2.2. Additionally, the applicant’s implementing 

procedures provided instruction on the review and consideration of CLB documentation 

sources, relative to the requirements of 10 CFR 54.4 and 10 CFR 54.21.

LRA Section 2.1 listed the following information sources used by the applicant during the license 

renewal scoping and screening process:

• updated final safety analysis report (UFSAR)

• GGNS equipment database

• design basis documents

• maintenance rule basis documents

• technical specifications (TS)

• fire hazards analysis

• engineering drawings
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2.1.3.1.2 Staff Evaluation

Scoping and Screening Implementation Procedures. The staff reviewed the applicant’s scoping 

and screening methodology implementing procedures, including license renewal guidelines, 

documents and reports, as documented in the staff’s “Scoping and Screening Methodology 

Audit Report Regarding the Grand Gulf Nuclear Station, Unit 1 License Renewal Application,” to 

ensure the guidance is consistent with the requirements of the Rule, the SRP-LR, and 

Regulatory Guide (RG) 1.188, which endorses the use of NEI 95-10. The staff determined that 

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

implementing procedures and AMRs was consistent with the Rule, the SRP-LR, and the 

endorsed industry guidance.

The applicant’s implementing procedures contained guidance for identifying plant SSCs within 

the scope of the Rule and SCs, contained in systems within the scope of license renewal, which 

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 contained in the LRA, 

including the implementation of staff positions documented in the SRP-LR, and the information 

in the applicant’s responses dated July 12, 2012, to the staff’s requests for additional 

information (RAIs) dated June 15, 2012.

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

and screening methodology implementing procedures are consistent with the methodology 

description provided in LRA Section 2.1, and the applicant’s methodology is sufficiently detailed 

in the implementing procedures to provide concise guidance on the scoping and screening 

process to be followed during the LRA activities.

Sources of Current Licensing Basis Information. 10 CFR 54.21(a)(3) requires, for each SC 

determined to be subject to an AMR, that the applicant demonstrate 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. Section 54.3(a) of 10 CFR Part 54 defines the CLB, 

in part, as 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, TS, 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 (GLs), and enforcement actions, and 

licensee commitments documented in NRC safety evaluations (SEs) or licensee event reports. 

The staff considered 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 

and as SCs requiring an AMR.

During the scoping and screening methodology audit, the staff determined that the applicant’s 

detailed license renewal program guidelines specified the use of the CLB source information in 

developing scoping evaluations. The staff reviewed pertinent information sources the applicant 

used, including the UFSAR, design basis documents, the equipment database, and plant piping 

and instrumentation drawings (P&IDs). In addition, the staff determined that the applicant had 

used additional sources of plant information pertinent to the scoping and screening process, 

including the maintenance rule basis documents, TS, and the fire hazards analysis.
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The equipment database, UFSAR, and plant drawings were the applicant’s primary repository 

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

staff discussed the applicant’s administrative controls for the equipment database and other 

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

implemented by plant procedures. Based on a review of the administrative controls, and a 

sample of the system classification information contained in the applicable documentation, the 

staff determined that the applicant has established adequate measures to control the integrity 

and reliability of system identification and safety classification data and, therefore, the 

information sources the applicant used during the scoping and screening process provided a 

controlled source of system and component data to support scoping and screening evaluations.

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

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

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

a listing of documents used to support scoping evaluations. The staff determined that the 

design documentation sources, required to be used by the applicant’s implementing procedures, 

provided sufficient information to ensure that the applicant identified SSCs to be included within 

the scope of license renewal consistent with the plant’s CLB.

2.1.3.1.3 Conclusion

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

procedures and the results from the scoping and screening methodology audit, the staff 

concludes that the applicant’s use of implementing procedures and consideration of document 

sources including CLB information is 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 controls the applicant used to ensure that the scoping and 

screening methodology employed to develop the LRA were adequate for the activity. The 

applicant used the following quality control processes during the LRA development:

• performed scoping and screening activities using approved documents and procedures

• employed databases to guide and support scoping and screening activities and generate 

license renewal documents. These databases included

− Equipment Database (EDB) – A database used as the central repository of 

equipment-specific information

− License Renewal Information System (LRIS) – A database used primarily for IPA

activities of scoping and developing AMR reports

During the scoping and screening methodology audit, the staff performed a sample review of 

implementing procedures and guides, examined the applicant’s documentation of activities 

contained in reports, reviewed the applicant’s activities performed to assess the quality of the 

LRA, and held discussions with the applicant’s license renewal management and license 

renewal project personnel. The staff determined that the applicant’s activities provide 

assurance that the LRA was developed consistent with the applicant’s license renewal program 

requirements.
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2.1.3.2.2 Conclusion

Based on its review of pertinent LRA development guidance, discussion with the applicant’s 

license renewal staff, and 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 training process the applicant used for license renewal project personnel. 

As outlined in the implementing procedures, the applicant had required training for personnel

participating in the development of the LRA and used trained and qualified personnel to prepare 

the scoping and screening implementing procedures.

The license renewal project personnel had been trained to the applicable project procedures 

and other relevant license renewal information using the applicant’s License Renewal Overview 

and Project Plan, as appropriate to their functions. Training topics had included 

10 CFR Part 54, relevant NRC and industry guidance documents, lessons learned from other 

nuclear power plant license renewals, and applicable implementing procedures. The training 

had been accomplished primarily by classroom instruction and reviewing documents and was 

documented on forms developed for that purpose.

The staff discussed training activities with the applicant’s management and license renewal 

project personnel and performed a sampling review of applicable documentation. The staff 

determined that the applicant had developed and implemented adequate controls for the 

training of personnel performing LRA activities.

2.1.3.3.2 Conclusion

Based on discussions with the applicant’s license renewal personnel responsible for the scoping 

and screening process and its review of selected documentation in support of the process, the 

staff concludes that the applicant developed and implemented adequate procedures to train 

personnel to implement the scoping and screening methodology described in the applicant’s 

implementing procedures and the LRA.

2.1.3.4 Conclusion of Scoping and Screening Program Review

Based on its review of LRA Section 2.1, review of the applicant’s scoping and screening 

implementing procedures, discussions with the applicant’s license renewal personnel, review of 

the quality controls applied to the LRA development, training of personnel participating in the 

LRA development, 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.
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2.1.4 Plant Systems, Structures, and Components Scoping Methodology

LRA Section 2.1.1, “Scoping Methodology,” described the applicant’s methodology used to 

scope SSCs in accordance with the requirements of the 10 CFR 54.4(a) criteria. The LRA 

states that the scoping process identified the 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-related function; or 

support a specific requirement for one of the five regulated events applicable to license renewal. 

LRA Section 2.1.1 also states that the scoping methodology GGNS used is consistent with 

10 CFR Part 54 and industry guidance contained in NEI 95-10.

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

2.1.4.1.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(1) in LRA Section 2.1.1.1, 

“Application of Safety-Related Scoping Criteria,” which states in part:

A system or structure is within the scope of license renewal if it performs a safety 

function during and following a design basis event as defined in 

10 CFR 50.54(a)(1).

[The applicant’s] procedure provides the criteria and methodology for determining 

and evaluating the safety and quality classification of systems, structures and 

components. The procedure defines design basis events consistent with 

10 CFR 50.49 (b)(1) and defines safety-related, or quality assurance Category 

SR, to include those structures, systems and components that are relied upon to 

remain functional during and following design basis events to assure the 

following:

• The integrity of the reactor coolant pressure boundary; or

• The capability to shut down the reactor and maintain it in a safe shutdown 

condition; or

• The capability to prevent or mitigate the consequences of accidents which 

could result in potential offsite exposures comparable to the applicable 

guideline exposures set forth in 10 CFR 50.34(a)(1), 10 CFR 50.67, or 

10 CFR 100.11, as applicable.

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 (RCPB), (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, as applicable.

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

states:
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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 systems, structures, 

and components that are relied upon to remain functional during and following 

design basis events (as defined in 10 CFR 50.49(b)(1)) to ensure the functions 

described in 10 CFR 54.4(a)(1).

During the scoping and screening methodology 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 GGNS. The 

staff reviewed the applicant’s basis documents that described design basis conditions in the 

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

and design basis documents discussed events such as internal and external flooding, tornados, 

and missiles. The staff determined that the applicant’s evaluation of DBEs was consistent with 

SRP-LR.

The staff determined that the applicant performed scoping of SSCs for the 10 CFR 54.4(a)(1) 

criterion in accordance with license renewal implementing procedures that 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 report of the scoping results to confirm that the applicant applied the methodology in 

accordance with the implementing procedures. In addition, the staff discussed the methodology 

and results with the applicant’s personnel who were responsible for these evaluations.

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

10 CFR 54.4(a)(1) and determined that the CLB definition of safety-related met the definition of 

safety-related specified in the Rule. The staff reviewed a sample of the license renewal scoping 

results for the SSW system to provide additional assurance that the applicant adequately 

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

that the applicant developed the scoping results for the sampled system 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 determined 

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 additional information would be required to complete its review. RAI 2.1-1, 

dated June 15, 2012, states, in part:

During the on-site scoping and screening methodology audit, the staff reviewed 

the definitions of the term safety-related contained in fleet procedures, the 

UFSAR and the LRA, used to identify SSCs within the scope of license renewal. 

The staff determined that the applicability of 10 CFR 50.67 to GGNS was not 

specifically addressed in the definitions of the term safety related in the fleet 

procedures, the UFSAR or the LRA. The staff requested that the applicant 
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confirm the definition of the term safety-related used in the development of the 

LRA and address the applicability of 10 CFR 50.67 to GGNS, as it relates to 

identifying SSCs within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1)(iii). Perform a review of this issue and indicate if the review 

concludes that use of the scoping methodology precluded the identification of 

SSCs that should have included within the scope of license renewal in 

accordance with 10 CFR 54.4(a).

The applicant responded to RAI 2.1-1, by letter dated July 12, 2012, which states, in part

The guideline exposures of 10 CFR 50.67 apply to GGNS based on license 

amendment 145. Components are classified as safety-related if they are relied 

upon to remain functional during and following design basis events to assure the 

capability to prevent or mitigate the consequences of accidents which could 

result in potential offsite exposures comparable to the applicable guideline 

exposures set forth in 10 CFR 50.67. Consequently, these components are 

included in the scope of license renewal. Use of the scoping method did not 

preclude the identification of SSCs that should have been included within the 

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

The staff reviewed the response to RAI 2.1-1 and determined that the applicant had confirmed 

the definition of the term safety-related used in the development of the LRA and had addressed

the applicability of 10 CFR 50.67 to GGNS, as it relates to identifying SSCs within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1)(iii). The staff determined that 

10 CFR 50.67 was applicable to GGNS and that it had been appropriately considered during the 

identification of safety-related SSCs within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). RAI 2.1-1 is resolved.

The staff determined additional information would be required to complete its review. RAI 2.1-2, 

dated June 15, 2012, states, in part:

During the onsite scoping and screening methodology audit, the staff determined 

that certain SSCs identified as safety-related in the plant equipment database 

were not included within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). In addition, the staff requested the applicant to provide the 

bases for not including any SSCs, identified as safety-related in the plant 

equipment database, within the scope of license renewal in accordance with 

10 CFR 54.4(a)(1). Perform a review of this issue and indicate if the review 

concludes that use of the scoping methodology precluded the identification of 

SSCs that should have been included within the scope of license renewal in 

accordance with 10 CFR 54.4(a).

The applicant responded to RAI 2.1-2, by letter dated July 12, 2012, which states, in part:

Mechanical components classified as safety-related in the plant equipment 

database, but not subject to an aging management review, were reevaluated to 

assure they are either short-lived or are passive components or are 

conservatively classified as safety-related based on management decision even 

though they don’t perform a safety function. With the exception of two 

components, the review confirmed that mechanical components classified as 

safety-related in the equipment database that are not subject to aging 
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management review are either short-lived or active components, or are 

conservatively classified as safety-related based on management decision.

Two isokinetic probes in the standby gas treatment system discharge stack are 

classified as safety-related based on their support of the stack pressure

boundary. These probes have been determined to be subject to aging 

management review as part of the standby gas treatment system.

The staff reviewed the response to RAI 2.1-2 and determined that the applicant had confirmed, 

with the exception of two isokinetic probes, that all SSCs identified as safety-related in the plant 

equipment data base, and having a 10 CFR 54.4(a)(1) intended function, were included within 

the scope of license renewal in accordance with 10 CFR 54.4(a)(1). The staff further 

determined that, during review of the RAI, the applicant had identified two isokinetic probes that 

were within the scope of license renewal and required an AMR to be performed. RAI 2.1-2 is 

resolved.

2.1.4.1.3 Conclusion

Based on its review of the LRA and the applicant’s implementing procedures and scoping 

results report, review of a system on a sampling basis, discussions with the applicant, and the 

applicant’s responses to RAIs 2.1-1 and 2.1-2, the staff concludes that the applicant’s 

methodology for identifying safety-related SSCs, relied upon to remain functional during and 

following DBEs and including the SSCs within the scope of license renewal, is consistent with 

the SRP-LR and 10 CFR 54.4(a)(1), and, therefore, is acceptable.

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

2.1.4.2.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(2) in LRA Section 2.1.1.2, 

“Application of Criterion for Nonsafety-Related SSCs Whose Failure Could Prevent the 

Accomplishment of Safety Functions,” which states in part:

This review identified nonsafety-related systems and structures containing 

components whose failure could prevent satisfactory accomplishment of a safety 

function. The method used was consistent with the preventive option described 

in Appendix F of NEI 95-10. Consideration of hypothetical failures that could 

result from system interdependencies that are not part of the current licensing 

basis and that have not been previously experienced is not required.

LRA Section 2.1.1.2.1, “Functional Failures of Nonsafety-Related SSCs,” states, in part:

At GGNS, systems and structures required to perform a function to support a

safety function are generally classified as safety-related and have been included 

in the scope of license renewal per Section 2.1. For the exceptions where 

nonsafety-related equipment is required to remain functional to support a safety 

function (e.g., systems with components in closed systems supporting the 

secondary containment pressure boundary), the system containing the 

equipment has been included in scope, and the function is listed as an intended 

function for 10 CFR 54.4(a)(2) for the system.
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LRA Section 2.1.1.2.2, “Physical Failures of Nonsafety-Related SSCs,” which states, in part:

Some nonsafety-related components could affect safety-related components due 

to their physical proximity; that is, their physical location can result in interaction 

between the components should the nonsafety-related component fail. Based on 

the license renewal rule and the guidance in NEI 95-10, physical failures of 

nonsafety-related SSCs in scope based on 10 CFR 54.4(a)(2) fit into the 

following two categories.

(1) Nonsafety-Related SSCs Directly Connected to Safety-Related SSCs

For nonsafety-related SSCs directly connected to safety-related SSCs (typically 

piping systems), the connected piping and supports up to and including the first 

seismic or equivalent anchor beyond the safety-nonsafety interface are within the 

scope of license renewal.

(2) Nonsafety-Related SSCs with the Potential for Spatial Interaction with

Safety-Related SSCs

Spatial interactions can occur as (1) physical impact or flooding, (2) pipe whip, jet

impingement, or harsh environments (such as caused by a high-energy line 

break (HELB)), or (3) spray or leakage.

2.1.4.2.2 Staff Evaluation

Pursuant to 10 CFR 54.4(a)(2), the applicant must consider all nonsafety-related SSCs whose 

failure could prevent the satisfactory accomplishment of safety-related functions, for SSCs relied 

on to remain functional during and following a DBE to ensure (1) the integrity of the RCPB, 

(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.

RG 1.188, Revision 1, endorses the use of NEI 95-10, Revision 6. NEI 95-10 discusses the 

staff’s position on 10 CFR 54.4(a)(2) scoping criteria, including nonsafety-related SSCs typically 

identified in the CLB; consideration of missiles, cranes, flooding, and HELBs; nonsafety-related 

SSCs connected to safety-related SSCs; nonsafety-related SSCs in proximity to safety-related 

SSCs; and mitigative and preventive 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 2.1.1.2, and subsections, in which the applicant described the scoping methodology for 

nonsafety-related SSCs in accordance with the requirements of 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 in accordance with the 
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requirements of 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 2.1.1.2, and subsections, and the applicant’s 

10 CFR 54.4(a)(2) implementing procedure. The staff determined that the applicant had 

reviewed the UFSAR, plant drawings, plant equipment database, 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 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 2.1.1.2 and subsections, and the 

applicant’s 10 CFR 54.4(a)(2) implementing procedure. The applicant had reviewed the 

safety-related to nonsafety-related interfaces for each mechanical system in order to identify the 

nonsafety-related components located between the safety to nonsafety-related interface and 

license renewal structural boundary.

The staff determined that in order to identify the nonsafety-related SSCs connected to 

safety-related SSCs and required to be structurally sound to maintain the integrity of the 

safety-related SSCs, the applicant used a combination of the following to identify the portion of 

nonsafety-related piping systems to include within the scope of license renewal:

• seismic anchors

• equivalent anchors

• bounding conditions described in NEI 95-10, Revision 6, Appendix F (base-mounted 

component, flexible connection, inclusion to the free end of nonsafety-related piping, or 

inclusion of the entire piping run)

The staff determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs, directly connected to safety-related SSCs, within the scope of license 

renewal was in accordance with the guidance of the SRP-LR and the requirements of 

10 CFR 54.4(a)(2).

Nonsafety-Related SSCs with the Potential for Spatial Interaction with Safety-Related SSCs. 

The staff reviewed LRA Section 2.1.1.2, and subsections, and the applicant’s 10 CFR 54.4(a)(2) 

implementing procedure that described the method used to identify nonsafety-related SSCs with 

the potential for spatial interaction with safety-related SSCs within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(2). The staff determined that the applicant had 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 
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between nonsafety-related and safety-related SSCs that are located in the same space, which 

was described in the LRA as a structure containing active or passive safety-related SSCs.

The staff determined that the applicant had identified all nonsafety-related SSCs containing 

liquid or steam and located in spaces containing safety-related SSCs and included the 

nonsafety-related SSCs within the scope of license renewal, unless the applicant had evaluated 

it and determined that the failure of the nonsafety-related SC would not result in the loss of a 

10 CFR 54.4(a)(1) intended function. 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 determined that the applicant’s methodology for identifying and including 

nonsafety-related SSCs with the potential for spatial interaction with safety-related SSCs within 

the scope of license renewal was in accordance with the guidance of the SRP-LR and the 

requirements of 10 CFR 54.4(a)(2).

The staff determined additional information would be required to complete its review. RAI 2.1-3, 

dated June 15, 2012, states, in part:

During the on-site scoping and screening methodology audit the staff reviewed 

the license renewal application, the 10 CFR 54.4(a)(2) implementing documents 

and license renewal drawings, and also performed plant walkdowns. The staff 

determined through the audit activities and discussion with the applicant that 

equipment that was no longer required had been abandoned in place. They

requested that the applicant provide details on the activities performed to confirm 

that all abandoned equipment, that at any time contained fluids and is in the 

proximity of safety-related SSCs, has been verified to be drained or included 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). If 

abandoned equipment has not been verified to be drained and is not included 

within the scope of license renewal, provide a technical basis for not including the 

abandoned equipment within the scope of license renewal in accordance with 

10 CFR 54.4(a)(2). Perform a review of this issue and indicate if the review 

concludes that use of the scoping methodology precluded the identification of 

SSCs that should have been included within the scope of license renewal in 

accordance with 10 CFR 54.4(a).

The applicant responded to RAI 2.1-3, by letter dated July 12, 2012, which states, in part:

The only components for which credit for being abandoned was taken in the 

GGNS LRA were components in the auxiliary steam system. As stated in LRA 

Section 2.3.3.19, the auxiliary steam system contains components which have 

been abandoned, isolated, and drained. These details were determined through 

review of documents including piping and instrumentation diagrams, a design 

change package, a system operating instruction, and through discussions with 

site personnel.

Any abandoned equipment, located in a space with safety-related equipment, 

that was not verified to be drained was included within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). 
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A review of this issue indicated that use of this scoping method did not preclude 

the identification of systems and components within the scope of license renewal 

in accordance with 10 CFR 54.4(a). For instance, UFSAR Section 9.4.1.1.1 

states that humidifiers in the control room HVAC system were abandoned in 

place. However, these humidifiers were subject to AMR, as identified in LRA

Tables 2.3.3-17 and 3.3.2-17. Thus, no credit was taken in the GGNS LRA for 

these components being abandoned.

The staff reviewed the response to RAI 2.1-3 and determined that the applicant had performed 

a review and confirmed that all abandoned equipment had been isolated and confirmed drained 

or included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). 

RAI 2.1-3 is resolved.

2.1.4.2.3 Conclusion

Based on its review of the LRA and the applicant's implementing procedures and scoping 

results report, selected system reviews and walkdowns, discussions with the applicant, and the 

applicant’s response to RAI 2.1-3, the staff concludes that the applicant’s methodology for 

identifying and including nonsafety-related SSCs whose failure could prevent satisfactory 

accomplishment of the intended functions of safety-related SSCs within the scope of license 

renewal, is in accordance with the requirements 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

The applicant addressed the methods used to identify SSCs included within the scope of license 

renewal, in accordance with the requirements of 10 CFR 54.4(a)(3). LRA Section 2.1.1.3, 

“Application of Criterion for Regulated Events,” states in part:

The scope of license renewal includes those systems, structures, and 

components relied on in safety analyses or plant evaluations to perform a 

function that demonstrates compliance with the Commission’s regulations for fire 

protection (10 CFR 50.48), environmental qualification (10 CFR 50.49), 

pressurized thermal shock (10 CFR 50.61) [not applicable to GGNS, a BWR], 

anticipated transients without scram (10 CFR 50.62), and station blackout 

(10 CFR 50.63). Systems and structures in the scope of license renewal for fire 

protection include those required for compliance with 10 CFR 50.48. Equipment 

relied on for fire protection includes SSCs credited with fire prevention, detection, 

and mitigation in areas containing equipment important to safe operation of the 

plant as well as systems that contain plant components credited for safe

shutdown following a fire.

2.1.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.1.1.3, which described the methods used to identify, and 

include within the scope of license renewal, those SSCs relied on in safety analyses or plant 

evaluations to perform a function that demonstrates compliance with the NRC’s regulations for 

fire protection (10 CFR 50.48), environmental qualification (EQ) (10 CFR 50.49), anticipated 

transients without scram (ATWS) (10 CFR 50.62), and station blackout (SBO) (10 CFR 50.60). 
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As part of this review, during the scoping and screening methodology audit, the staff had 

discussions with the applicant, reviewed implementing procedures and the technical basis 

documents, license renewal drawings, and the scoping results report. The staff determined that 

the applicant had evaluated the CLB to identify SSCs that perform functions addressed in 

10 CFR 54.4(a)(3), “Regulated Events,” and included these SSCs within the scope of license 

renewal as documented in the scoping report. In addition, the staff determined that the scoping 

report referenced the information sources used for determining the SSCs credited for 

compliance with the events.

Fire Protection. The staff reviewed the applicant’s implementing procedure and technical basis 

documents that described the method used to identify SSCs within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(3) (Fire Protection—10 CFR 50.48). The implementing 

procedure described a process that considered CLB information, including the UFSAR and the 

applicable Fire Protection technical basis documents. The staff reviewed applicable portions of 

the LRA, CLB information, and license renewal drawings, to verify that the appropriate SSCs 

were included within the scope of license renewal. In addition, the staff reviewed a selected 

sample of scoping results for the systems and structures identified in the applicable Fire 

Protection technical basis documents.

Based on its review of the CLB documents and the sample review, the staff determined that the 

applicant’s methodology was adequate for identifying and including SSCs credited in performing 

fire protection functions within the scope of license renewal in accordance with the requirements 

of 10 CFR 54.4(a)(3).

Environmental Qualification. The staff reviewed the applicant’s implementing procedure that 

described the method used to identify SSCs within the scope of license renewal in accordance with 

10 CFR 54.4(a)(3) (Environmental Qualification—10 CFR 50.49). The implementing procedure 

described a process that considered CLB information and used a bounding approach that included 

all plant electric and instrumentation and control (I&C) SSCs within the scope of license renewal. 

The staff reviewed applicable portions of the LRA, CLB information, and license renewal drawings, 

to verify that the appropriate SSCs were included within the scope of license renewal. Based on its 

review of the CLB documents and a sample of scoping results documentation, the staff determined 

that the applicant’s methodology was adequate for identifying and including SSCs credited in 

performing EQ functions within the scope of license renewal in accordance with the requirements of 

10 CFR 54.4(a)(3).

Anticipated Transient Without Scram. The staff reviewed the applicant’s implementing 

procedure that described the method used to identify SSCs within the scope of license renewal 

in accordance with 10 CFR 54.4(a)(3) (Anticipated Transients Without Scram—10 CFR 50.62). 

The implementing procedure described a process that considered CLB information and used a 

bounding approach that included all plant electric and I&C SSCs within the scope of license 

renewal. The staff reviewed the applicable portions of the LRA, CLB information, and license 

renewal drawings, to verify that the appropriate SSCs were included within the scope of license 

renewal. Based on its review of the CLB documents and a sample of scoping results 

documentation, the staff determined that the applicant’s methodology was adequate for 

identifying and including SSCs credited in performing ATWS functions within the scope of 

license renewal in accordance with the requirements of 10 CFR 54.4(a)(3).

Station Blackout. The staff reviewed the applicant’s implementing procedure that described 

the method used to identify SSCs within the scope of license renewal in accordance with 10 

CFR 54.4(a)(3) (Station Blackout—10 CFR 50.63). The implementing procedure described a 

process that considered CLB information and used a bounding approach that included all 
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plant electrical and I&C SSCs within the scope of license renewal. The staff reviewed 

applicable portions of the LRA, CLB information, and license renewal drawings to verify that 

the appropriate SSCs were included within the scope of license renewal. Based on its review 

of the CLB documents and a sample of scoping results documentation, the staff determined 

that the applicant’s methodology was adequate for identifying and including SSCs credited in 

performing SBO functions within the scope of license renewal in accordance with the 

requirements of 10 CFR 54.4(a)(3).

2.1.4.3.3 Conclusion

Based on its review of the LRA and the applicant’s implementing procedures and scoping 

results report, reviews of systems on a sampling basis, and discussions with the applicant, the 

staff concludes that the applicant‘s methodology for identifying and including SSCs relied upon 

to remain functional during regulated events is consistent with the SRP-LR and 

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

LRA Section 2.1.1, “Scoping Methodology” states, in part:

For mechanical system scoping, a system is defined as the collection of 

components in the equipment database assigned to the system code. System 

functions are determined based on the functions performed by those 

components. Defining a system by the components in the database is consistent 

with the evaluations performed for maintenance rule scoping by the site.

Intended functions for structures and mechanical systems were identified based 

on reviews of applicable plant licensing and design documentation. Documents 

reviewed included the UFSAR, Technical Specifications, the Fire Hazards 

Analysis (Appendix 9A of the UFSAR), the Appendix R Safe Shutdown Analysis, 

Maintenance Rule basis documents, design basis documents, and various 

station drawings as necessary.

2.1.4.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology for identifying SSCs within the scope of license 

renewal to verify it met the requirements of 10 CFR 54.4. The applicant had developed 

implementing procedures that described the processes used to identify the systems and 

structures that are subject to 10 CFR 54.4 review and to determine if the system or structure 

performed intended functions consistent with the criteria of 10 CFR 54.4(a) and to document the 

activities in scoping results report. The process defined the plant in terms of systems and 

structures and was completed for all systems and structures on site to ensure that the entire 

plant was assessed.

The staff determined that the applicant had identified the SSCs within the scope of license 

renewal and documented the results of the scoping process in a report in accordance with the 

implementing procedures. The report included a description of the structure or system, a listing 

of functions performed by the system or structure, identification of intended functions, the 
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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 scoping and screen 

methodology audit, the staff reviewed a sampling of the implementing procedure and report and 

determined 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 and 

structure scoping results reviewed during the scoping and screening methodology audit, the 

staff concludes that the applicant’s methodology for identifying SSCs within the scope of license 

renewal, and their intended functions, is consistent with the requirements of 10 CFR 54.4 and, 

therefore, is acceptable.

2.1.4.5 Mechanical Component Scoping

2.1.4.5.1 Summary of Technical Information in the Application

LRA Section 2.1.1, “Scoping Methodology” states, in part:

For mechanical system scoping, a system is defined as the collection of 

components in the equipment database assigned to the system code. System 

functions are determined based on the functions performed by those 

components. Defining a system by the components in the database is consistent 

with the evaluations performed for maintenance rule scoping by the site.

Intended functions for structures and mechanical systems were identified based 

on reviews of applicable plant licensing and design documentation. Documents 

reviewed included the UFSAR, Technical Specifications, the Fire Hazards 

Analysis (Appendix 9A of the UFSAR), the Appendix R Safe Shutdown Analysis, 

Maintenance Rule basis documents, design basis documents, and various 

station drawings as necessary.

2.1.4.5.2 Staff Evaluation

The staff reviewed LRA Section 2.1.1, implementing procedures, scoping results report, and the 

CLB source information associated with mechanical scoping. The staff determined that the CLB 

source information and implementing procedures’ guidance the applicant used was adequate to 

identify mechanical SSCs 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 during the scoping and screening methodology audit. 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 2.1.1 and the guidance contained in the SRP-LR.

On a sampling basis, the staff reviewed the applicant’s scoping report for the SSW system and 

the process used to identify mechanical components that met the scoping criteria of 

10 CFR 54.4. The staff reviewed the implementing procedures, confirmed that the applicant 

had identified and used pertinent engineering and licensing information, and discussed the 

methodology and results with the applicant. As part of the review process, the staff reviewed 
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the system’s identified intended functions and the process used to identify system component 

types. The staff confirmed that the applicant had identified and highlighted license renewal 

drawings to identify components subject to aging management review in accordance with the 

implementing procedure guidance. Additionally, the staff determined that the applicant had 

independently confirmed the results in accordance with the implementing procedures. The staff 

determined that the applicant’s license renewal personnel verifying the results had performed 

independent reviews of the scoping report and the applicable license renewal drawings to 

ensure accurate identification of the system intended functions. The staff determined that the 

systems and components identified by the applicant were evaluated against the criteria of 

10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff confirmed that the applicant had used pertinent 

engineering and licensing information to determine that SCs were included within the scope of 

license renewal in accordance with 10 CFR 54.4(a).

2.1.4.5.3 Conclusion

Based on its review of the LRA, scoping implementation procedures, discussions with the 

applicant, and a sampling review of mechanical scoping results, the staff concludes that the 

applicant’s methodology for identification of the 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 Component Scoping

2.1.4.6.1 Summary of Technical Information in the Application

LRA Section 2.1.1, “Scoping Methodology” states, in part:

Structural components included in system codes with mechanical equipment, 

such as snubbers, and structural commodities associated with mechanical 

systems, such as pipe hangers and insulation, are evaluated as structural 

components and bulk commodities.

As the starting point for structural scoping, a list of plant structures was 

developed from a review of the UFSAR, plant layout drawings, Fire Hazards 

Analysis, design criteria documents, and maintenance rule basis documents. 

The list includes structures that potentially support plant operations or could 

adversely impact structures that support plant operations (i.e., seismic II/I). In 

addition to buildings and facilities, the list of structures includes other structures 

that support plant operation (e.g., electrical manholes and foundations for 

freestanding tanks).

2.1.4.6.2 Staff Evaluation

The staff reviewed LRA Section 2.1.1, implementing procedures, scoping results report, and the 

CLB source information associated with structural scoping. The staff determined that the CLB 

source information and implementing procedures’ guidance the applicant used was acceptable 

to identify structural SSCs 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 during the scoping and screening methodology audit. 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 
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description provided in the LRA Section 2.1.1 and the guidance contained in the SRP-LR, 

Section 2.1.

On a sampling basis, the staff reviewed the applicant’s scoping report for the turbine building 

and the process used to identify structural systems and components that met the scoping 

criteria of 10 CFR 54.4. The staff reviewed the implementing procedures, confirmed that the 

applicant had identified and used pertinent engineering and licensing information, and 

discussed the methodology and results with the applicant. As part of the review process, the 

staff reviewed the turbine building’s identified intended functions and the process used to 

identify structural component types. Additionally, the staff determined that the applicant had 

confirmed the results in accordance with the implementing procedures. The staff determined 

that the applicant’s license renewal personnel verifying the results had performed independent 

reviews of the scoping report and the applicable license renewal drawings to ensure accurate 

identification of the system intended functions. The staff determined that the SCs the applicant 

identified were evaluated against the criteria of 10 CFR 54.4(a)(1), (a)(2), and (a)(3). The staff 

confirmed that the applicant had used pertinent engineering and licensing information to 

determine that SCs were included within the scope of license renewal in accordance with 

10 CFR 54.4(a).

The staff determined additional information would be required to complete its review. RAI 2.1-4, 

dated June 15, 2012, states, in part:

During the on-site scoping and screening methodology audit the staff reviewed 

the license renewal application, license renewal implementing documents, 

current licensing basis documentation and performed walkdowns of the 

incomplete and abandoned Unit 2 turbine building and other adjacent structures.

The staff determined that the Unit 2 turbine building, which is adjacent to the 

GGNS turbine building and control building, both of which are within the scope of 

license renewal in accordance with 10 CFR 54.4(a)(1), is not included within the 

scope of license renewal in accordance with 10 CFR 54.4(a)(2). In addition, the 

staff noted that the radioactive waste building, which is also adjacent to the 

GGNS turbine building (but not the control building), is included within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(2) for an intended function 

that includes, “Maintain structural integrity of nonsafety-related components such 

that safety functions are not affected and no impact on in-scope structures.”

During the scoping and screen methodology audit the applicant indicated that the 

basis for not including the incomplete and abandoned Unit 2 turbine building 

within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) was an 

analysis that demonstrated that the Unit 2 turbine building would not move in a 

way that impacts adjacent buildings following flooding and earthquake events. 

However, the applicant did not provide information that demonstrated that the 

Unit 2 turbine building would not be subject to the effects of aging similar to other 

buildings of the same construction that the applicant had included within the 

scope of license renewal and made subject to an aging management program.

The staff requested that the applicant provide a technical basis for not including 

the incomplete and abandoned Unit 2 turbine building, located adjacent to the 

GGNS turbine building and the control building, within the scope of license 

renewal in accordance with 10 CFR 54.4(a)(2). If an analysis is cited as the 
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technical basis for not including the Unit 2 turbine building within the scope of 

license renewal, demonstrate how the analysis considers the effects of aging 

relative to other buildings of similar construction that are included within the 

scope of license renewal. Perform a review of this issue and indicate if the review 

concludes that use of the scoping methodology precluded the identification of 

SSCs that should have been included within the scope of license renewal in 

accordance with 10 CFR 54.4(a).

The applicant responded to RAI 2.1-4, by letter dated July 12, 2012, which states, in part:

The Grand Gulf Nuclear Station (GGNS) Unit 2 turbine building is a 

non-Category I structure located adjacent to the GGNS Unit 1 turbine building 

and the control building. The Unit 2 turbine building is constructed of reinforced 

concrete and structural steel with metal roof decking and metal siding. The 

interior walls are constructed of reinforced concrete or concrete masonry block. 

The structure consists of steel superstructure with an exterior metal siding above 

the operating floor at El. 166'-0" and reinforced concrete below El. 166'-0". The 

Unit 2 turbine building is designed to comply with seismic Category I 

requirements and tornado effects (except the siding and its supporting members) 

and thus will have no effect on the adjacent Category I structures. As indicated 

in the LRA Table 2.2-4, construction of the Unit 2 turbine building has been 

abandoned; however the partially completed building still remains. An analysis 

was performed of the partially completed Unit 2 turbine building configuration to 

evaluate any potential effect on surrounding structures. The analysis 

demonstrated that the Unit 2 turbine building will not move in a way that would 

impact adjacent buildings following flooding and earthquake events. The 

analysis was the technical basis for not including the abandoned and partially 

completed Unit 2 turbine building within the scope of license renewal. However, 

to ensure that the effects of aging do not affect its structural integrity as analyzed 

(i.e., it was analyzed to withstand design basis events to preclude adverse 

impact on adjacent category I structures), the Unit 2 turbine building is being 

included within the scope of license renewal for 10 CFR 54.4(a)(2) and subject to 

an AMR. Since the Unit 2 turbine building does not provide structural support or 

house any system, structure, or component (SSC) performing a license renewal 

intended function, only the Unit 2 turbine building steel superstructure framing 

and main concrete structural elements are subject to an AMR.

A review was performed of the GGNS scoping method as described in LRA 

Section 2.1.1. During the review, Entergy determined that the Unit 2 auxiliary 

building was in a condition similar to that of the Unit 2 turbine building. To ensure 

that the effects of aging do not affect its structural integrity, during the period of 

extended operation (PEO), the partially completed Unit 2 auxiliary building is also 

being included within the scope of license renewal for 10 CFR 54.4(a)(2) and 

subject to an AMR. The GGNS Structures Monitoring Program will be enhanced 

to include managing the effects of aging on the GGNS Unit 2 turbine building and 

the GGNS Unit 2 auxiliary building during the PEO.

The staff reviewed the response to RAI 2.1-4 and determined that the applicant had performed 

a review and made a determination to include the abandoned Unit 2 turbine building and Unit 2 

auxiliary building within the scope of license renewal in accordance with 10 CFR 54.4(a)(2) and 

that the buildings were subject to an AMR. RAI 2.1-4 is resolved.
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2.1.4.6.3 Conclusion

Based on its review of the LRA, scoping implementation procedures, and a sampling review of 

structural scoping results, and the applicant’s response to RAI 2.1-4, the staff concludes that the 

applicant’s methodology for identification of the structures and structural components within the 

scope of license renewal is in accordance with the requirements of 10 CFR 54.4 and, therefore, 

is acceptable.

2.1.4.7 Electrical Component Scoping

2.1.4.7.1 Summary of Technical Information in the Application

LRA Section 2.1.1, “Scoping Methodology” states, in part:

For the purposes of system level scoping, plant EIC systems are included in the 

scope of license renewal by default. EIC components in mechanical systems are 

included in the evaluation of EIC components, regardless of whether the 

mechanical system is included in scope. Intended functions for EIC systems are 

not identified since the bounding (i.e., included by default) scoping approach 

makes it unnecessary to determine if an EIC system has an intended function. 

Switchyard equipment, which is not part of the plant’s EIC systems, was 

reviewed for station blackout (SBO) intended functions based on NRC guidance 

in NUREG-1800, Section 2.5.2.1.1.

2.1.4.7.2 Staff Evaluation

The staff reviewed LRA Section 2.1 and the guidance contained in the implementing procedures 

and scoping results report to perform the review of the electrical scoping process. The staff 

reviewed the applicant’s approach to identifying electrical and instrumentation and control SSCs 

relied upon to perform the functions described in 10 CFR 54.4(a). The staff reviewed portions of 

the documentation the applicant used to perform the electrical scoping process, including 

license renewal procedures, basis documents, scoping and screening report, the UFSAR, CLB 

documentation, and NEI 95-10.

The staff noted that after the scoping of electrical and instrumentation and controls (I&C)

components was performed, the in-scope electrical components were categorized into electrical 

commodity groups. Commodity groups include electrical and I&C components with common 

characteristics. Component level intended functions of the component types were identified, 

such as cable, connections, fuse holders, terminal blocks, high-voltage transmission conductor, 

connections and insulators, switchyard bus and connections.

As part of this review, the staff discussed the methodology with the applicant, reviewed the 

implementing procedures developed to support the review, and reviewed the scoping results for 

a sample of SSCs that were identified within the scope of license renewal. The staff determined 

that the applicant scoping included appropriate electrical and I&C components as well as 

electrical and I&C components contained in mechanical or structural systems within the scope 

of license renewal on a commodity basis.
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2.1.4.7.3 Conclusion

Based on its review of the LRA, scoping implementing procedures, and a sampling review of 

electrical scoping results, the staff concludes that the applicant’s methodology for identifying 

electrical components 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 Conclusion for Scoping Methodology

Based on its review of the LRA, implementing procedures, and a sampling review of scoping 

results, the staff concludes that the applicant’s scoping methodology is consistent with the 

guidance contained in the SRP-LR and identified those SSCs (1) that are safety related, 

(2) whose failure could affect safety-related functions, and (3) that are necessary to 

demonstrate compliance with the NRC’s regulations for fire protection, EQ, ATWS, and SBO. 

The staff concludes that the applicant’s methodology is consistent with the requirements of 

10 CFR 54.4(a), and, therefore, is acceptable.

2.1.5 Screening Methodology

2.1.5.1 General Screening Methodology

After identifying systems and structures within the scope of license renewal, the applicant 

implemented a process for identifying SCs subject to an AMR, in accordance with 

10 CFR 54.21.

2.1.5.1.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify SCs included within the scope of license 

renewal that are subject to an AMR in accordance with the requirements of 10 CFR 54.21. LRA 

Section 2.1.2, “Screening Methodology” states, in part:

NEI 95-10 provides industry guidance for screening structures and components 

to identify the passive, long-lived structures and components that support an 

intended function. The screening process for GGNS followed the 

recommendations of NEI 95-10.

Within the group of systems and structures that are in scope, passive long-lived 

components or structural elements that perform intended functions require aging 

management review. Components or structural elements that support an 

intended function do not require aging management review if they are either 

active or subject to replacement based on a qualified life.

Although the requirements for the integrated plant assessment are the same for 

each system and structure, in practice the screening process differed for 

mechanical systems, electrical systems, and structures.

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 and 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 
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(passive), as well as components that are not subject to periodic replacement based on a 

qualified life or specified time period (long lived). In addition, the IPA must include a description 

and justification of the methodology used to identify 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 the applicant used to identify the mechanical, structural,

and electrical SSCs within the scope of license renewal that are 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). 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 on a sampling basis the screening results report for the 

SSW system and the turbine building. The applicant provided the staff with a detailed 

discussion of the processes used for each discipline and provided administrative documentation 

that described the screening methodology. Specific methodology for mechanical, structural,

and electrical SCs is discussed in SER Sections 2.1.5.2, 2.1.5.3, and 2.1.5.4.

2.1.5.1.3 Conclusion

Based on its 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 the SCs that are subject to an AMR is consistent with 

the requirements of 10 CFR 54.21 and, therefore, is acceptable

2.1.5.2 Mechanical Component Screening

2.1.5.2.1 Summary of Technical Information in the Application

The applicant addressed the methods used to identify mechanical SCs included within the 

scope of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21 discussed in LRA Sections 2.1.2.1, “Screening of Mechanical Systems,” and 

2.1.2.1.1, “Identifying Components Subject to Aging Management Review.”

LRA Section 2.1.2.1.1 “Identifying Components Subject to Aging Management Review,” states, 

in part:

Within the system, components are subject to aging management review if they 

perform an intended function without moving parts or a change in configuration or 

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

specified time period.

In making the determination that a component performs an intended function 

without moving parts or a change in configuration or properties, it is not 

necessary to consider the piece parts of the component. However, in the case of 

valves, pumps, and housings for fans and dampers, the valve bodies, pump 

casings, and housings may perform an intended function by maintaining the 

pressure boundary and may therefore be subject to aging management review.
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Replacement programs are based on vendor recommendations, plant 

experience, or any means that establishes a specific service life, qualified life, or 

replacement frequency under a controlled program. Components that are 

subject to replacement based on qualified life or specified time period are not 

subject to aging management review. Where flexible elastomer hoses/expansion 

joints or other components are periodically replaced, these components are not 

subject to aging management review.

2.1.5.2.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for mechanical component screening as 

described in LRA Sections 2.1.2.1 and 2.1.2.1.1, implementing procedures, basis documents, 

and the mechanical scoping and screening report. The staff determined 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 mechanical SCs subject to an AMR.

The staff determined that the applicant had identified SCs that were found to meet the passive 

criteria in accordance with the guidance contained in NEI 95-10. In addition, the staff 

determined that the applicant had evaluated the identified passive commodities to determine 

that they were not subject to replacement based on a qualified life or specified time period (long

lived) and that the remaining passive, long-lived components were subject to an AMR.

The staff performed a sample review to determine if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the SSW system screening report and 

discussed the report with the applicant and confirmed proper implementation of the screening 

process.

2.1.5.2.3 Conclusion

Based on its review of the LRA, implementing procedures, and the sampled mechanical 

screening results, the staff concludes that the applicant’s methodology for identification of 

mechanical SCs 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

The applicant addressed the methods used to identify structural SCs included within the scope 

of license renewal that are subject to an AMR in accordance with the requirements of 

10 CFR 54.21. LRA Section 2.1.2.2 “Screening of Structures,” states, in part:

For each structure within the scope of license renewal, the structural components 

and commodities were evaluated to determine those subject to aging 

management review. This evaluation (screening process) for structural 

components and commodities involved a review of design basis documents 

(UFSAR, design criteria documents, design specifications, site drawings, etc.) to 

identify specific structural components and commodities that make up the 

structure. Structural components and commodities subject to aging management 

review are those that (1) perform an intended function without moving parts or a 
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change in configuration or properties, and (2) are not subject to replacement 

based on qualified life or specified time period.

2.1.5.3.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for structural component screening as 

described in LRA Section 2.1.2.2, implementing procedures, basis documents, and the 

structural scoping and screening report. The staff determined 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 structural SCs subject to an AMR.

The staff determined that the applicant had identified structural SCs which were found to meet 

the passive criteria in accordance with NEI 95-10. In addition, the staff determined that the 

applicant evaluated the identified passive commodities to determine that they were not subject 

to replacement based on a qualified life or specified time period (long lived) and that the 

remaining passive, long-lived components were determined to be subject to an AMR.

The staff performed a sample review to determine if the screening methodology outlined in the 

LRA and implementing procedures was adequately implemented. During the scoping and 

screening methodology audit, the staff reviewed the turbine building screening report and 

discussed the report with the applicant and confirmed proper implementation of the screening 

process.

2.1.5.3.3 Conclusion

Based on its review of the LRA, implementing procedures, and the sampled structural 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 Section 2.1.2.3 “Electrical and Instrumentation and Control Systems,” states, in part:

The EIC aging management review evaluates commodity groups containing 

components with similar characteristics. Screening applied to commodity groups 

determines which EIC components are subject to aging management review. An 

aging management review is required for commodity groups that perform an 

intended function, as described in 10 CFR 54.4, without moving parts or without 

a change in configuration or properties (passive) and that are not subject to 

replacement based on a qualified life or specified time period (long-lived).

2.1.5.4.2 Staff Evaluation

The staff reviewed the applicant’s methodology used for electrical component screening in LRA 

Section 2.1.2.3 and the applicant’s implementing procedures, basis documents, and the 

electrical scoping and screening report. The staff determined that the applicant used the 

screening process described in these documents, along with the information contained in 
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NEI 95-10 Appendix B and the SRP-LR, to identify the electrical and instrumentation and 

control (EIC) components subject to an AMR.

The staff determined that the applicant had identified commodity groups that were found to meet 

the passive criteria in accordance with NEI 95-10. In addition, the staff determined that the 

applicant evaluated the identified passive commodities to identify whether they were subject to 

replacement based on a qualified life or specified time period (short lived), or not subject to 

replacement based on a qualified life or specified time period (long lived) and that the remaining 

passive, long-lived components were determined to be subject to an AMR.

2.1.5.4.3 Conclusion

Based on its review of the LRA, the screening implementation procedure, drawings, discussion 

with the applicant, and a sample of the results of the screening methodology, the staff 

concludes that the applicant’s methodology for identification of electrical components within the 

scope of license renewal and subject to an AMR is in accordance with the requirements of 

10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.5.5 Conclusion for Screening Methodology

Based on its review of the LRA and the screening implementing procedures, discussions with 

the applicant, and a sample review of screening results, the staff determines that the applicant’s 

screening methodology is consistent with the guidance contained in the SRP-LR and identified 

those passive, long-lived components within the scope of license renewal and subject to an 

AMR. The staff concludes that the applicant’s methodology is consistent with the requirements 

of 10 CFR 54.21(a)(1) and, therefore, is acceptable.

2.1.6 Summary of Evaluation Findings

Based on its review of the information presented in LRA Section 2.1, the supporting information 

in the scoping and screening implementing procedures and scoping results report, the 

information presented during the scoping and screening methodology audit, discussions with 

the applicant sample system reviews, and the applicant’s responses dated July 12, 2012, to the 

staff’s RAIs, the staff confirms that the applicant’s scoping and screening methodology is 

consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1). The staff also 

concludes that the applicant’s description and justification of its scoping and screening 

methodology are adequate to meet the requirements of 10 CFR 54.21(a)(1). From this review, 

the staff concludes that the applicant’s methodology for identifying systems and structures 

within the scope of license renewal and SCs requiring an AMR is acceptable.

2.2 Plant-Level Scoping Results

2.2.1 Introduction

In LRA Section 2.1, the applicant described the methodology for identifying SSCs within the 

scope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to 

determine which SSCs must be included within the scope of license renewal. The staff 

reviewed the plant-level scoping results to determine whether the applicant has properly 

identified all systems and structures relied upon to mitigate DBEs, as required by 

10 CFR 54.4(a)(1), systems and structures the failure of which could prevent satisfactory 

accomplishment of any safety-related functions, as required by 10 CFR 54.4(a)(2), and systems 
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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

In LRA Tables 2.2-1 and 2.2-3, the applicant listed plant mechanical systems, structures, and 

electrical and I&C systems that are within the scope of license renewal. Based on the DBEs 

considered in the plant’s 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 safety evaluation report 

(SER) Section 2.1. To verify the applicant properly implemented its methodology, the staff’s 

review focused on the implementation results shown in LRA Table 2.2-1-A, “Mechanical 

Systems within the Scope of License Renewal”; Table 2.2-1-B, “Plant EIC Systems within the 

Scope of License Renewal”; Table 2.2-2, “Mechanical Systems Not within the Scope of License 

Renewal”; Table 2.2-3, “Structures within the Scope of License Renewal”; and Table 2.2-4, 

“Structures Not within the Scope of License Renewal,” to confirm that there were no omissions 

of plant-level systems and structures within the scope of license renewal.

The staff determined whether the applicant properly identified the systems and structures within 

the scope of license renewal in accordance with 10 CFR 54.4. The staff reviewed selected 

systems and structures that the applicant did not identify as within the scope of license renewal 

to verify whether the systems and structures have any intended functions requiring their 

inclusion within the scope of license renewal. The staff’s review of the applicant’s 

implementation was conducted in accordance with the guidance in SRP-LR Section 2.2, 

“Plant-Level Scoping Results.”

In RAI 2.2-1, dated May 9, 2012, the staff noted LRA Section 2.2, Tables 2.2-1-A, 2.2-1-B, 

2.2-2, 2.2-3, and 2.2-4 provide the results of applying the license renewal scoping criteria to the 

systems, structures, and components.

The license renewal scoping criteria is described in Section 2.1. The following UFSAR systems 

did not appear in LRA Tables 2.2-1-A, 2.2-1-B, 2.2-2, 2.2-3 or 2.2-4.

UFSAR Section System

7.5.1.2.18. Post-Accident Sampling Post-accident sampling system

18.1.7. Plant Safety Parameter Display

18.2.2 Safety Parameter Display System

Safety-related display instrumentation system

11.3 Gaseous Radwaste System Gaseous waste management systems

7.6.2.11 Auxiliary Building Isolation System Auxiliary Building Isolation System

The applicant was requested to justify its exclusion of the above systems from Tables 2.2-1-A, 

2.2-1-B, 2.2-2, 2.2-3, or 2.2-4.
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In its response, by letter dated June 5, 2012, the applicant stated the UFSAR identifies these 

systems using system names that explain their function within the plant. The post-accident 

sampling system is a subsystem of the process sampling system and is described in LRA 

Section 2.3.3.19. The safety parameter display system uses components of the emergency 

response facilities and is identified in LRA Table 2.2-1-B. Gaseous radwaste management is 

accomplished with various plant systems. These include vent systems of normally and 

potentially radioactive components, building ventilation systems, the offgas system, and the 

mechanical vacuum pump system. Building ventilation systems are described in LRA 

Section 2.3.3.18. The primary gaseous radwaste management system is the main condenser 

steam jet air ejector low-temperature system, or offgas system. The low-temperature offgas 

system is described in LRA Section 2.3.4.2. The auxiliary building isolation system is a 

subsystem of the containment and drywell I&C system. The containment and drywell I&C

system is described in LRA Section 2.3.2.7.

Based on its review, the staff finds the applicant’s response to RAI 2.2-1 acceptable because 

the applicant explained that these systems are subsystems, which are within systems that are 

included in Tables 2.2-1-A, 2.2-1-B, 2.2-2, 2.2-3, or 2.2-4. Therefore, the staff’s concern 

described in RAI 2.2-1 is resolved.

2.2.4 Conclusion

The staff reviewed LRA Section 2.2, the RAI response, and UFSAR supporting information to 

determine whether the applicant failed to identify any systems and structures within the scope of 

license renewal. The staff finds no such omissions. Based on its review, the staff concludes 

that the applicant has adequately identified in accordance with 10 CFR 54.4 the systems and 

structures within the scope of license renewal.

2.3 Scoping and Screening Results: Mechanical Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

mechanical systems. Specifically, this section discusses:

• reactor coolant system (RCS)

• engineered safety features (ESF)

• auxiliary systems

• steam and power conversion systems

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

mechanical system components that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all mechanical systems. 

The objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, components and supporting structures for mechanical systems that appear to 

meet the license renewal scoping criteria. Similarly, the staff evaluated the applicant’s 

screening results to verify that all passive, long-lived components were subject to an AMR in 

accordance with 10 CFR 54.21(a)(1).
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In its scoping evaluation, the staff reviewed the applicable LRA sections and drawings, focusing 

on components that have not been identified as within the scope of license renewal. The staff 

reviewed relevant licensing basis documents, including the UFSAR, for each mechanical 

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.

2.3.1 Reactor Coolant System

LRA Section 2.3.1 identifies the reactor vessel (RV), reactor vessel internals (RVI), and RCS

SCs subject to an AMR for license renewal. The applicant described the supporting SCs of the 

RV, RVI, and RCS in the following LRA sections:

• 2.3.1.1, “Reactor System”

• 2.3.1.2, “Reactor Coolant Pressure Boundary”

• 2.3.1.3, “Nuclear Boiler System”

• 2.3.1.4, “Reactor Recirculation System”

• 2.3.1.5, “Neutron Monitoring”

• 2.3.1.6, “Fuel”

• 2.3.1.7, “Miscellaneous RCS Systems in Scope for 10 CFR 54.4(a)(2)”

The staff’s findings on review of LRA Sections 2.3.1.1–2.3.1.7 are provided in SER 

Sections 2.3.1.1–2.3.1.7, respectively.

2.3.1.1 Reactor System

2.3.1.1.1 Summary of Technical Information in the Application

The reactor system consists of the RV and its attachments and RVI. The reactor pressure 

vessel (RPV) is a vertical, cylindrical pressure vessel of welded construction designed by GE. 

The RPV has a cylindrical shell, bottom head, and upper head. Both the upper head and upper 

shell have a forged flange welded to them for vessel closure. The upper head is secured to the 

RPV by studs, nuts, and washers. The RPV flanges are sealed by two concentric rings 

designed to prevent leakage through the inner or outer seal at any operating condition.

The RVI components include the core (including fuel assemblies, control rod assemblies, 

control rod guide thermal sleeves, guide rods, in-core dry tubes, and in-core guide tubes), core 

support structure (control rod guide tubes, core plate and holddown bolts, fuel supports, shroud, 

shroud support, and top guide), core spray (CS) lines and spargers, differential pressure line, 

feedwater (FW) spargers, jet pump assemblies and instrumentation, low-pressure coolant 
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injection couplings, steam dryer, shroud head and steam separator assembly, and surveillance 

sample holders.

The intended functions of the reactor system within the scope of license renewal include the 

following:

• maintain the RCPB

• provide a barrier to radiation release

• contain and support the reactor core, internals, and coolant moderator

• provide a floodable volume in which the core can be adequately cooled in the event of a 

breach in the RCPB

• maintain core geometry to ensure control rods and emergency core cooling systems 

(ECCSs) can perform their safety functions

• provide active nuclear fuel and cladding

• provide emergency reactor shutdown capability

The RPV evaluation boundary consists of the vessel shell, heads, closure flanges, vessel 

closure bolting, nozzles, safe ends, safe end extensions, nozzle caps, nozzle flanges (including 

blank flanges), thermal sleeves, in-core penetrations (housings), internal attachments (including 

shroud support, jet pump riser support pads, CS brackets, steam dryer holddown brackets, 

guide rod brackets, surveillance specimen brackets, steam dryer support brackets, and FW

sparger brackets), stabilizer brackets, support skirt and bearing plate, the control rod drive 

(CRD) stub tubes and housings, and associated pressure boundary bolting.

The RVI evaluation boundary includes the core support subcomponents and other RVI

components. There are no boundary drawings for the RV or the RVI. Additional details for 

components subject to an AMR can be found in UFSAR Sections 3.9.5, 4.1, 4.1.2, 4.1.3, 4.6, 

5.3.1, and 5.3.3. LRA Table 2.3.1-1 lists the RV components that require AMR and their 

intended functions. LRA Table 2.3.1-2 lists the RVI components that require AMR and their 

intended functions.

2.3.1.1.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the reactor system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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 Pressure Boundary

2.3.1.2.1 Summary of Technical Information in the Application

The RCPB consists of those systems and components that contain or transport fluids coming 

from, or going to, the reactor core. The reactor recirculation system (Section 2.3.1.4) and the 

nuclear boiler system (Section 2.3.1.3) comprise a majority of the RCPB. A list of systems that 

contain RCPB components can be found in LRA Table 2.3.1.2-A.

The intended functions of the RCPB within the scope of license renewal include the following:

• maintain integrity of the RCPB

• provide isolation and integrity of primary containment

• provide capability to trip recirculation pumps

Additional details for RCPB components subject to an AMR can be found in UFSAR 

Section 5.1. UFSAR references for individual systems that make up the RCPB can be found in 

their respective sections.

The following highlighted license renewal drawings provide the details of SSCs for the scope of 

license renewal and subject to an AMR:

LRA-M-1081B LRA-M-1077A LRA-M-1077B LRA-M-1077D

LRA-M-1077E LRA-M-1078A LRA-M-1078B LRA-M-1078E

LRA-M-1082 LRA-M-1085A LRA-M-1085B LRA-M-1085C

LRA-M-1087 LRA-M-1086 LRA-M-1090A LRA-M-1097

LRA-M-1112 LRA-M-1083B LRA-M-1079

LRA Table 2.3.1-3 identifies the RCPB component types that are within the scope of license 

renewal and subject to an AMR.

2.3.1.2.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RCPB components within the scope of license renewal, as required 

by 10 CFR 54.4(a). The staff also finds 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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2.3.1.3 Nuclear Boiler System

2.3.1.3.1 Summary of Technical Information in the Application

The nuclear boiler system is comprised of the main steam and FW lines and the nuclear 

pressure relief system and automatic depressurization system components. The nuclear boiler 

system transports steam from the RPV to the turbine. Each of the four main steam lines 

contains two air operated main steam isolation valves (MSIVs) to protect against the 

post-accident release of radiation. Between the RPV and the MSIVs are safety/relief valves that 

protect the RCS from overpressure. Additionally, each main steam line contains a flow restrictor 

assembly to limit the blowdown rate. The automatic depressurization system allows the low 

pressure ECCS to inject water to the RPV in the event of a small break loss-of-coolant accident 

(LOCA) by rapidly decreasing the pressure in the RPV.

Additional details for components subject to an AMR can be found in UFSAR Sections 5.2.2.4.1, 

5.4.4, 5.4.5, 5.4.9, 6.3.1.2.4, 6.3.2.2.2, and 7.3.1.1.2.4.1.12.

The intended functions of the nuclear boiler system within the scope of license renewal include 

the following:

• maintain RCPB integrity

• provide primary containment isolation and integrity

• reduce RPV pressure to allow low pressure ECCS to inject when needed

• limit the blowdown rate

• provide steam to the reactor core isolation cooling (RCIC) turbine

The following highlighted license renewal drawings provide the details of SSCs for the scope of 

license renewal and subject to an AMR:

LRA-M-1077A LRA-M-1077B LRA-M-1077D LRA-M-1077E

LRA-M-1124A LRA-M-1067A LRA-M-1068A LRA-M-1124B

LRA-M-1067D LRA-M-1068C LRA-M-1077C LRA-M-1124C

LRA-M-1067E LRA-M-1101 LRA-M-1067M

LRA Tables 2.3.1-3 and 2.3.1-4-1list the component types that require AMR and their intended 

functions.

2.3.1.3.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.3.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the nuclear boiler system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 
2-32

identified 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 Recirculation System

2.3.1.4.1 Summary of Technical Information in the Application

The reactor recirculation system provides coolant flow through the core. The reactor 

recirculation system consists of the two recirculation pump loops external to the RV. Each 

external loop contains one motor-driven recirculation pump, a hydraulically-actuated flow control 

valve, two motor-operated gate valves, a flow measuring system, and provides the piping path 

to the RV jet pumps.

Additional details for components subject to an AMR can be found in UFSAR Section 5.1, 

Section 5.4.1, and Table 9.5-12.

The intended functions of reactor recirculation system component types within the scope of 

license renewal includes:

• serves as a pressure boundary and limits the release of fission products

• provides a containment isolation function

The following highlighted license renewal drawings provide the details of SSCs for the scope of 

license renewal and subject to an AMR.

LRA-M-1078A LRA-M-1078B LRA-M-1078C LRA-M-1078D

LRA-M-1078E LRA-M-0033B LRA-M-1079 LRA-M-1089

LRA-M-0034B LRA-M-1080B LRA-M-1099 LRA-M-1069D

LRA-M-1083B LRA-M-1110A LRA-M-1072B LRA-M-1085A

LRA-M-1111A LRA-M-1088C LRA-M-1088E

LRA Tables 2.3.1-3 and 2.3.1-4-2 list the component types that require AMR and their intended 

functions.

2.3.1.4.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.4.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the reactor recirculation system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds 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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2.3.1.5 Neutron Monitoring

2.3.1.5.1 Summary of Technical Information in the Application

The purpose of the neutron monitoring system is to provide indication of neutron flux that can be 

correlated to thermal power level. The system includes in-core neutron detectors and 

out-of-core electronic monitoring equipment. The five major subsystems are: source range 

monitor (SRM) subsystem, intermediate range monitor (IRM) subsystem, local power range 

monitor (LPRM) subsystem, traversing incore probe (TIP) subsystem, and average power range 

monitor (APRM) subsystem. The SRM and IRM detectors and cable are located inside the RV

in a dry tube sealed against RV pressure. The LPRM assembly consists of four neutron 

detectors contained in a multiple dry tube assembly. Each LPRM assembly also contains a 

calibration tube for a TIP. The TIP subsystem provides a way to calibrate the individual LPRM 

sensors by correlating TIP signals to LPRM signals as the TIP is positioned in various radial and 

axial locations in the core through a drive mechanism. A TIP drive mechanism uses a fission 

chamber attached to a flexible drive cable. The cable is driven from outside the drywell by a 

gearbox assembly. The APRM channel uses electronic equipment that averages the output 

signals from a selected set of LPRMs.

Additional details for components subject to an AMR can be found in UFSAR Sections 7.1.2.1.4, 

7.6.1.5, and 7.7.1.6.

The intended functions of the neutron monitoring system component types within the scope of 

license renewal include:

• maintain RCPB integrity

There are no license renewal drawings specific to the neutron monitoring system. LRA

Tables 2.3.1-2 and 2.3.2-7 list the component types that require AMR and their intended 

functions.

2.3.1.5.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.5.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the neutron monitoring system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds 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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2.3.1.6 Fuel

2.3.1.6.1 Summary of Technical Information in the Application

Fuel assembly subcomponents comprise the fuel system. Fuel assemblies provide active 

nuclear fuel, the ability to maintain the fuel in a controllable and coolable configuration, and 

fission product retention. Fuel assemblies are replaced regularly and are therefore in scope for 

license renewal, but not subject to an AMR.

Additional details for components of the fuel review can be found in UFSAR Section 4.2.

The intended functions of the fuel system component types within the scope of license renewal 

include:

• provide a barrier to radiation release

• provide structural integrity

There are no license renewal drawings for the fuel system.

2.3.1.6.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.1.6.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the fuel system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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).

2.3.1.7 Miscellaneous RCS Systems in Scope for 10 CFR 54.4(a)(2)

2.3.1.7.1 Summary of Technical Information in the Application

LRA Section 2.3.1.7 describes the purpose for including nonsafety-related SSCs within the 

scope of license renewal for both the nuclear boiler system (LRA Section 2.3.1.3) and the 

reactor recirculation system (LRA Section 2.3.1.4) based on the criterion in 10 CFR 54.4(a)(2)

for physical interactions. References to the tables listing the component types that require AMR 

(Tables 2.3.1-4-1 and 2.3.1-4-2) and references to the license renewal drawings for both of 

these systems were included in this section.

2.3.1.7.2 Staff Evaluation

SER Sections 2.3.1.3 and 2.3.1.4 provide the staff evaluation for the individual systems.
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2.3.1.7.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2) 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

finds 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 feature SCs subject to an AMR for license 

renewal. The applicant described the supporting SCs of the ESF in the following LRA sections:

• 2.3.2.1, “Residual Heat Removal”

• 2.3.2.2, “Low Pressure Core Spray”

• 2.3.2.3, “High Pressure Core Spray”

• 2.3.2.4, “Reactor Core Isolation Cooling”

• 2.3.2.5, “Pressure Relief”

• 2.3.2.6, “Standby Gas Treatment”

• 2.3.2.7, “Containment Penetrations”

• 2.3.2.8, “Miscellaneous ESF Systems in Scope for 10 CFR 54.4(a)(2)”

The staff’s findings on review of LRA Sections 2.3.2.1–2.3.2.8 are in SER Sections 2.3.2.1–

2.3.2.8, respectively.

2.3.2.1 Residual Heat Removal

2.3.2.1.1 Summary of Technical Information in the Application

LRA Section 2.3.2.1 describes the residual heat removal (RHR) system and the drywell, 

suppression pool, and upper containment pool system. The LRA states that the purpose of the 

RHR system is to remove decay and sensible heat from the RV and the containment under 

normal operation, shutdown, refueling, and accident conditions. The RHR system removes 

decay and sensible heat during and after plant shutdown, injects water into the RV following a 

LOCA, and removes heat from the containment following a LOCA. The LRA states that the 

drywell, suppression pool, and upper containment pool includes the suppression pool 

ECCS/RCIC suction strainer, suction piping and expansion joints, and the air regulator valves 

for the gate seals in the upper containment pool. The suppression pool strainer and suction 

piping provide the safety-grade source of water to the ECCS and RCIC pumps.

The LRA states that the RHR system has the intended functions to restore and maintain water 

level in the RV for cooling after a LOCA, to provide an alternate shutdown cooling function to 

remove decay and sensible heat from the reactor core in the event the shutdown suction line 

from the reactor recirculation system is unavailable, to remove heat from the suppression pool 

following a DBA, to remove decay and sensible heat from the reactor core to cooldown and 

maintain the reactor in a cold shutdown condition, to assist the fuel pool cooling and cleanup

system in removing decay heat from fuel assemblies stored in the fuel pools, to remove heat 

and condense steam from the drywell to prevent over-pressurization of the containment 

following a LOCA, to remove fission products dispersed in the containment atmosphere 

following a LOCA, to maintain integrity of the RCPB, and to support containment pressure 

boundary. The RHR system also has the intended functions to maintain integrity of 
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nonsafety-related components such that no physical interaction with safety-related components 

could prevent satisfactory accomplishment of a safety function and to provide emergency 

makeup to the spent fuel pool. Additionally, the RHR system has an intended function to 

demonstrate compliance with the NRC’s regulations for fire protection (10 CFR 50.48).

The LRA states that the drywell, suppression pool, and upper containment pool system has an

intended function to provide the safety-grade source of water to the ECCS and RCIC pumps. 

The system also has an intended function to demonstrate compliance with the NRC’s 

regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.2-1 identifies the RHR system component types that 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 and UFSAR Sections 1.2.2.3.4, 5.4.7, 6.3.1.2.3, 6.3.2.2, 

6.3.2.2.4, and 6.5.2, and LRA Tables 2.3.2-1 and 3.2.2-1, using the evaluation methodology 

described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RHR system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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).

2.3.2.2 Low-Pressure Core Spray

2.3.2.2.1 Summary of Technical Information in the Application

LRA Section 2.3.2.2 describes the purpose of the LPCS. As part of the ECCS, it limits the 

release of radioactive materials to the environs following a LOCA. The system pumps water 

through a peripheral ring spray sparger mounted above the reactor core. The system also

provides inventory makeup and spray cooling during large breaks when reactor pressures are 

relatively low. Additionally, the low-pressure core spray (LPCS) system provides inventory

makeup for small breaks after the automatic depressurization system reduces the RV pressure.

The LRA states that the LPCS system’s intended functions are to supply water spray to fuel 

bundles in the reactor core to prevent excessive fuel cladding temperatures in the event of a 

LOCA, to maintain integrity of the RCPB, and to support the containment pressure boundary. 

The system also has an intended function to maintain integrity of nonsafety-related components 

such that no physical interaction with safety-related components could prevent satisfactory 

accomplishment of a safety function.
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LRA Table 2.3.2-2 identifies the LPCS system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.2.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.2 and UFSAR Sections 6.3.1.2 and 6.3.2.2, and LRA 

Tables 2.3.2-2 and 3.2.2-2, using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the LPCS system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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).

2.3.2.3 High-Pressure Core Spray

2.3.2.3.1 Summary of Technical Information in the Application

LRA Section 2.3.2.3 describes the purpose of the high-pressure core spray (HPCS) system,

which is part of the ECCS. The system limits the release of radioactive materials to the 

environs following a LOCA. The HPCS system pumps water through a peripheral ring spray 

sparger mounted above the reactor core. For small breaks that do not result in rapid reactor

depressurization, the system maintains reactor water level and depressurizes the vessel. For

large breaks, the HPCS system cools the core by a spray.

The LRA states that the HPCS system has the intended functions to supply water spray to fuel 

bundles in the reactor core to prevent excessive fuel cladding temperatures in the event of a 

LOCA, to maintain integrity of the RCPB, and to support the containment pressure boundary. 

The system also has an intended function to maintain the integrity of nonsafety-related 

components such that no physical interaction with safety-related components could prevent 

satisfactory accomplishment of a safety function.

LRA Table 2.3.2-3 identifies the HPCS system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.2.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.3, UFSAR Sections 6.3.1.2 and 6.3.2.2, and LRA 

Tables 2.3.2-3 and 3.2.2-3, using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3.
2-38

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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.3.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the HPCS system components within the scope of license renewal, as 

required by 54.4(a). The staff also finds 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).

2.3.2.4 Reactor Core Isolation Cooling

2.3.2.4.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the purpose of the RCIC system, which is to provide makeup 

water to the RV following a RV isolation accompanied by a loss of coolant flow from the FW

system to provide adequate core cooling and control of the RV water level.

The LRA states that the RCIC system has the intended functions to provide makeup water to 

the RV following a RV isolation accompanied by a loss of coolant flow from the FW system to 

provide adequate core cooling and control of the RV water level, to maintain integrity of the 

RCPB, and to support the containment pressure boundary. The system also has an intended 

function to maintain integrity of nonsafety-related components such that no physical interaction 

with safety-related components could prevent satisfactory accomplishment of a safety function. 

Additionally, the reactor core isolation system has intended functions to demonstrate 

compliance with the NRC’s regulations for fire protection (10 CFR 50.48) and SBO

(10 CFR 50.63).

LRA Table 2.3.2-4 identifies the RCIC system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.2.4.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.4, UFSAR Section 5.4.6.2.1 and Appendix 8A, and LRA 

Tables 2.3.2-4 and 3.2.2-4, using the evaluation methodology described in SER Section 2.3 and 

the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).
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2.3.2.4.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the RCIC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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).

2.3.2.5 Pressure Relief

2.3.2.5.1 Summary of Technical Information in the Application

LRA Section 2.3.2.5 describes the nuclear pressure relief, the automatic depressurization

components, and the quencher confirmatory test program systems. The purpose of the 

automatic depressurization system is to rapidly reduce RV pressure in a small break LOCA

situation in which the HPCS system fails to maintain the RV water level. The automatic 

depressurization system uses some of the relief valves that are part of the nuclear pressure 

relief system. The nuclear pressure relief system consists of safety/relief valves located on the 

main steam lines between the RV and the first isolation valve within the drywell. These valves 

protect against overpressure of the nuclear system. The quencher confirmatory test program 

system includes piping, valves, and instruments used in the one-time quencher confirmatory 

test. The objectives of the test were to confirm the validity of the methods used to predict the 

pressure fields within the containment suppression pool caused by safety/relief valve air 

clearing loads.

The LRA states that the pressure relief systems have the intended functions to prevent 

over-pressurization of the RCPB by use of a pressure relief system and to reduce RV pressure 

in a LOCA situation in which the HPCS system fails to maintain the RV water level. The 

pressure relief systems also have an intended function to demonstrate compliance with the 

NRC‘s regulations for fire protection (10 CFR 50.48). The quencher confirmatory test program 

system has the intended function to support the automatic depressurization system pressure 

boundary.

LRA Table 2.3.2-5 identifies the pressure relief system component types that are within the 

scope of license renewal and subject to an AMR.

2.3.2.5.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.5, and UFSAR Sections 1.2.2.4.8, 5.2.2, 5.2.2.4, 

6.2.1.1.3.3.1.1, 6.3.1.2.4, 6.3.2.2.2, 7.3.1.1.1.4, and Appendix 6A: Section 3BA.7.2.2.3 and 

Appendix 6B (QCTP system code) and LRA Tables 2.3.2-5 and 3.2.2-5 using the evaluation 

methodology described in SER Section 2.3 and the guidance in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).
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2.3.2.5.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the pressure relief system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds 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).

2.3.2.6 Standby Gas Treatment

2.3.2.6.1 Summary of Technical Information in the Application

LRA Section 2.3.2.6 describes the purpose of the standby gas treatment system (SGTS), which 

is to minimize exfiltration of contaminated air from the enclosure building, the auxiliary building, 

and the containment following an accident or abnormal condition that could result in abnormally 

high airborne radioactivity in these areas.

The LRA states that the SGTS has the intended functions to provide recirculation, filtration, and 

exhaust of the secondary containment air to maintain a negative pressure in the secondary 

containment volume and limit release of radioisotopes to the environment under accident 

conditions and to support the containment pressure boundary.

LRA Table 2.3.2-6 identifies the SGTS component types that are within the scope of license 

renewal and subject to an AMR.

2.3.2.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.2.6 and UFSAR Sections 6.5.1.1 and 6.5.3.2, and LRA 

Table 2.3.2-6 using the evaluation methodology described in SER Section 2.3 and the guidance 

in SRP-LR Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.6.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the SGTS components within the scope of license renewal, as required 

by 10 CFR 54.4(a). The staff also finds 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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2.3.2.7 Containment Penetrations

2.3.2.7.1 Summary of Technical Information in the Application

LRA Section 2.3.2.7 describes primary and secondary containment penetrations in systems that 

are not included in another AMR. This section provides a grouping of containment isolation 

valves from the primary and secondary containment, drywell monitoring, and containment and 

drywell I&C systems into a consolidated review.

The LRA states that the containment penetrations have an intended function to support 

containment integrity. The containment penetrations also have an intended function to maintain

integrity of nonsafety-related components such that no physical interaction with safety-related 

components could prevent satisfactory accomplishment of a safety function. Additionally, the 

containment penetrations have an intended function that demonstrates compliance with the 

NRC’s regulations for fire protection (10 CFR 50.48). The drywell monitoring system has an 

intended function to support the containment pressure boundary. The containment and drywell

I&C system has the intended functions to support safety-related pressure instrumentation in the 

drywell and containment and to support the containment pressure boundary.

LRA Table 2.3.2-7 identifies the containment penetrations component types that are within the 

scope of license renewal and subject to an AMR.

2.3.2.7.2 Staff Evaluation

The staff reviewed LRA Sections 2.3.2.7, and UFSAR Sections 1.2.2.4.9.1, 5.4.1, 

6.2.1.1.3.3.1.1, 6.5.3.1, 7.1.2.1.4.5, 7.7.1.6, 9.2.3, 9.2.4, 9.5.9, 9.2.11, 9.3.6, 9.4.6, 9.4.7, 9.4.8, 

11.2, Figures 7.7-10, 7.6.1.4.3.9, 12.3.4.2, and 7.5.1, and LRA Tables 2.3.2-7 and 3.2.2-7, using 

the evaluation methodology described in SER Section 2.3 and the guidance in SRP-LR 

Section 2.3.

During its review, the staff evaluated the system functions described in the LRA and 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.7.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the containment penetrations within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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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2.3.2.8 Miscellaneous Engineering Safety Feature Systems in Scope for 

10 CFR 54.4(a)(2)

2.3.2.8.1 Summary of Technical Information in the Application

LRA Section 2.3.2.8 describes the following ESF systems, described in the referenced sections, 

which are within the scope of license renewal based on the criterion of 10 CFR 54.4(a)(2) for 

physical interactions.

• RHR (LRA Section 2.3.2.1)

• LPCS (LRA Section 2.3.2.2)

• HPCS (LRA Section 2.3.2.3)

• RCIC (LRA Section 2.3.2.4)

2.3.2.8.2 Staff Evaluation

SER Sections 2.3.2.1 through 2.3.2.4 document the staff evaluation for the individual 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 has identified as within the scope of license renewal to verify that 

the applicant has not omitted any passive and long-lived components subject to an AMR in 

accordance with the requirements of 10 CFR 54.21(a)(1).

2.3.2.8.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) 

components within the scope of license renewal, as required by 10 CFR 54.4(a). The staff also 

finds 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, “Control Rod Drive”

• 2.3.3.2, “Standby Liquid Control”

• 2.3.3.3, “Suppression Pool Makeup”

• 2.3.3.4, “Leakage Detection and Control”

• 2.3.3.5, “Combustible Gas Control”

• 2.3.3.6, “Fuel Pool Cooling and Cleanup”

• 2.3.3.7, “Standby Service Water”

• 2.3.3.8, “Component Cooling Water”

• 2.3.3.9, “Plant Service Water”

• 2.3.3.10, “Floor and Equipment Drainage”

• 2.3.3.11, “Compressed Air”

• 2.3.3.12, “Fire Protection – Water”
2-43

• 2.3.3.13, “Fire Protection – Halon and CO2”

• 2.3.3.14, “Plant Chilled Water”

• 2.3.3.15, “Standby Diesel Generator”

• 2.3.3.16, “HPCS Diesel Generator”

• 2.3.3.17, “Control Room Heating, Ventilation and Air Conditioning”

• 2.3.3.18, “Heating, Ventilation and Air Conditioning”

• 2.3.3.19, “Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2)”

The staff’s findings on review of LRA Sections 2.3.3.1 – 2.3.3.19 are in SER 

Sections 2.3.3.1-2.3.3.19, respectively.

Auxiliary Systems Generic Requests for Additional Information

In RAI 2.3.3-1, dated May 9, 2012, the staff noted LRA Section 2.1 describes the applicant’s 

scoping methodology, which specifies how systems or components were determined to be 

included in the scope of license renewal. The staff confirms the inclusion of all components 

subject to an AMR by reviewing the results of the screening of components within the license 

renewal boundary. For eight drawing locations, the continuation of piping in scope for license 

renewal could not be located. The applicant was requested to provide sufficient information to 

locate the license renewal boundary.

If the continuation cannot be shown on license renewal boundary drawings, then the applicant 

was requested to provide additional information describing the extent of the scoping boundary 

and to verify whether or not there are additional AMR component types between the 

continuation and termination of the scoping boundary. If the scoping classification of a section 

of the piping changes over the continuation, the applicant was requested to provide additional 

information to clarify the change in scoping classification.

In its response dated June 5, 2012, the applicant provided information to clarify the extent of the 

license renewal boundary for each of the eight continuations. In each case, the applicant

detailed the routing and location of the piping in question and stated that all relevant component 

types have been identified in the LRA.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3-1 acceptable because 

the applicant provided additional information to locate the license renewal boundaries. No new 

systems or components were added to the scope of license renewal as a result of the response 

to RAI 2.3.3-1 and no component types were identified that had not been previously evaluated. 

Therefore, the staff’s concern described in RAI 2.3.3-1 is resolved.

In RAI 2.3.3-2, dated May 9, 2012, the staff noted LRA Section 2.1.2.1.3, “Mechanical System 

Drawings,” describes the applicant’s development of license renewal drawings. This LRA

section does not describe the use of a solid red line in several license renewal drawings to 

denote the end of the license renewal scoping boundary. Examples of this notation can be 

found on boundary drawings LRA-M-1061A, LRA-M-1094C, and LRA-M-1109F but is not 

necessarily limited to these drawings only. The applicant was requested to provide additional 

information to describe the use of the solid red line on license renewal drawings. For all cases 

where the red line is used, the applicant was asked to clarify if the piping in question leaves a 

space that contains components within the scope of license renewal for 10 CFR 54.4(a)(1), at 

the point of the red line. Additionally, for all cases where the red line is used, the applicant was 

asked to clarify if the license renewal boundary includes a seismic anchor or equivalent support 
2-44

between the safety-related and nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary.

In its response dated June 5, 2012, the applicant stated solid red lines signify (1) a transition 

from a drawing that is maintained to a drawing that is not maintained and as such is not 

provided as an LRA drawing, or (2) a transition through a wall that separates a plant space 

containing components within the scope of license renewal for 10 CFR 54.4(a)(1) from another 

space, thus depicting the limit of the potential spatial interaction in this area. In both cases, all 

nonsafety-related fluid-filled components whose failure could affect safety-related components 

because of their physical proximity are in scope for 10 CFR 54.4(a)(2) and subject to an AMR. 

In addition for both cases, seismic anchors or equivalent supports are included as necessary 

between the safety-related and nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3-2 acceptable because 

the applicant generically explained the use of the solid red line on boundary drawings and 

specifically explained for the examples provided in the RAI. Therefore, the staff’s concern 

described in RAI 2.3.3-2 is resolved.

2.3.3.1 Control Rod Drive

2.3.3.1.1 Summary of Technical Information in the Application

The CRD system consists of locking piston CRD mechanisms and the hydraulic system. The 

CRD hydraulic system consists of hydraulic control units, a hydraulic power supply (pumps), 

interconnecting piping, and instrumentation. The CRD hydraulic system delivers clean, 

demineralized water for driving, rapid insertion, and cooling functions related to the operation of 

the CRDs. The hydraulic control units manage water flow to and from the control rod. One 

supply pump pressurizes the system with water from a condensate supply header, which takes 

suction from the condensate treatment system or condensate storage tanks (CSTs).

The scram accumulators store sufficient energy to fully insert a control rod at any vessel 

pressure. The accumulator is a hydraulic cylinder with a free-floating piston. The piston 

separates the water on top from the nitrogen below. During a scram, the scram inlet (and 

outlet) valves open and permit the stored energy in the accumulators to discharge into the 

drives.

The scram discharge volume header is designed to receive and contain all the water discharged 

by each of the hydraulic control units during a scram. The scram discharge volume header 

drains to an instrument volume.

The alternate rod insertion system consists of three parallel vent paths from the scram pilot air 

header. The alternate rod insertion system is designed to initiate a scram independent of the 

reactor protection system. This is accomplished by the opening of two solenoid valves, in 

series, to depressurize the scram pilot header that actuates the CRD scram valves.

Additional details for components subject to an AMR can be found in UFSAR Section 4.6.1.1.

The intended functions of the CRD system within the scope of license renewal include the 

following:
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• provide emergency reactor shutdown (SCRAM); manual and automatic

• provide primary containment isolation and integrity

• maintain RCPB integrity

The following highlighted license renewal drawings provide the details of SSCs for the scope of 

license renewal and subject to an AMR:

LRA-M-1081A LRA-M-1081B LRA-M-1051A

LRA Tables 2.3.3-1 and 2.3.1-3 list the component types that require AMR and their intended 

functions.

2.3.3.1.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.3.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the CRD system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately identified the 

system components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.2 Standby Liquid Control

2.3.3.2.1 Summary of Technical Information in the Application

The standby liquid control (SLC) system consists of a boron solution tank, two 

positive-displacement pumps, two explosive valves, and associated piping and valves to 

transfer the borated water from the storage tank to the RPV. The SLC system is manually 

initiated from the main control room to pump a boron neutron absorber solution into the reactor 

if the operator determines that the reactor cannot be shut down with the control rods or if 

suppression pool pH control is required to mitigate the dose consequences of a LOCA. The 

liquid is piped into the RV and discharged into the core through the HPCS header so that it 

mixes with the cooling water rising through the core.

The intended functions of the SLC system within the scope of license renewal include the 

following:

• provide borated water to the RCS to bring the reactor to a shutdown condition at any 

time in the reactor core life
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• provide primary containment isolation and integrity

• maintain RCPB integrity

Additional details for components subject to an AMR can be found in UFSAR 

Sections 6.2.4.3.1.1.6 and 9.3.5.2.

The following highlighted license renewal drawings provide the details of SSCs for the scope of 

license renewal and subject to an AMR:

LRA-M-1082

LRA Tables 2.3.3-2 and 2.3.1-2 list the component types that require AMR and their intended 

functions.

2.3.3.2.2 Staff Evaluation

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.3.3.2.3 Conclusion

On the basis of its LRA and UFSAR review, the staff concludes that the applicant has 

appropriately identified the SLC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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).

2.3.3.3 Suppression Pool Makeup

2.3.3.3.1 Summary of Technical Information in the Application

LRA Section 2.3.3.3 states that the purpose of the suppression pool makeup system is to 

transfer water from the upper containment pool to the suppression pool following a LOCA. The 

water transfer from the suppression pool makeup system ensures the suppression pool top row 

vents are adequately covered to maintain post-LOCA-long-term steam condensation.

The LRA states that the suppression pool makeup system’s intended functions are to transfer 

water from the upper containment pool to the suppression pool by gravity flow following a 

LOCA, to support safety-related suppression pool level instrumentation, and to support the 

containment pressure boundary.

LRA Table 2.3.3-3 identifies the suppression pool makeup system component types that are 

within the scope of license renewal and subject to an AMR.
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2.3.3.3.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.3, UFSAR Section 6.2.7, and the license renewal 

boundary drawings using the evaluation methodology discussed 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 request for additional information as discussed 

below.

In RAI 2.3.3.3-1, dated May 9, 2012, the staff noted LRA Table 2.3.3-3 appears to be incorrectly 

labeled “Suppression Pool Cleanup System Components Subject to Aging Management 

Review” when it is associated with LRA Section 2.3.3.3, Suppression Pool Makeup. The 

applicant was requested to clarify the title of LRA Table 2.3.3-3 and verify that all components 

associated with the suppression pool makeup system subject to an AMR have been identified.

In its response dated June 5, 2012, the applicant stated the title of LRA Table 2.3.3-3 has been 

revised to “Suppression Pool Makeup System.” Table 2.3.3-3 component types include all 

components associated with the suppression pool makeup system that are subject to an AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.3-1 acceptable 

because the applicant revised the LRA table title and stated all components associated with the 

system are included within the component types of Table 2.3.3-3. Therefore, the staff’s concern 

described in RAI 2.3.3.3-1 is resolved.

2.3.3.3.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the suppression pool makeup system components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.4 Leakage Detection and Control

2.3.3.4.1 Summary of Technical Information in the Application

LRA Section 2.3.3.4 states that the purpose of the leak detection system is to detect, 

annunciate, and isolate leakages in systems that are part of or connected to the RCPB or the 

fuel pool cooling system. The leak detection system consists of temperature, pressure, 

radiation, flow, and level sensors with associated instrumentation and alarms.

The LRA states that the leakage detection and control system’s intended functions are to 

monitor leakage from the fuel pool, to maintain integrity of the RCPB, and to support the 

containment pressure boundary. The leakage detection and control system also has an 

intended function to maintain integrity of nonsafety-related components such that no physical 

interaction with safety-related components could prevent satisfactory accomplishment of a 

safety function.

LRA Table 2.3.3-4 identifies the leakage detection and control system component types that 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 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.4.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the leakage detection and control system components within the scope 

of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.5 Combustible Gas Control

2.3.3.5.1 Summary of Technical Information in the Application

LRA Section 2.3.3.5 states that the purpose of the combustible gas control system is to control 

the concentration of hydrogen, which may be released in the drywell and containment following 

a LOCA. Three subsystems provide hydrogen gas control: the drywell purge system, the 

hydrogen control system, and the backup containment purge system. The hydrogen ignition 

system is used to control the excessive quantity of hydrogen generated during the occurrence of 

a degraded core accident. The drywell purge compressors dilute post-LOCA drywell 

radionuclide concentrations.

The LRA states that the combustible gas control system’s intended functions are to control the 

concentration of hydrogen released in the drywell and containment following a LOCA, to dilute 

the drywell atmosphere with containment air and purge the drywell atmosphere into the 

containment, to induce the controlled combustion of hydrogen in containment, to provide drywell 

vacuum relief protection relative to the containment, and to support the containment pressure 

boundary. The combustible gas control system also has an intended function to maintain 

integrity of nonsafety-related components such that no physical interaction with safety-related 

components could prevent satisfactory accomplishment of a safety function.

LRA Table 2.3.3-5 identifies the combustible gas control system component types that 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 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

components subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1).
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2.3.3.5.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the combustible gas control system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has 

adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.6 Fuel Pool Cooling and Cleanup

2.3.3.6.1 Summary of Technical Information in the Application

LRA Section 2.3.3.6 describes the fuel pool cooling and cleanup and the servicing equipment 

systems. The purpose of the fuel pool cooling and cleanup system is to maintain acceptable 

temperature, clarity, and radioactivity levels of the water in the upper containment, fuel storage, 

and cask pools. The servicing equipment systems include tools and equipment used primarily 

during refueling outages.

The LRA states that the fuel pool cooling and cleanup system’s intended functions are to 

remove the decay heat from spent fuel assemblies, to monitor fuel pool water level and maintain 

a water level above the fuel sufficient to provide radiation shielding, and to support the 

containment pressure boundary. The fuel pool cooling and cleanup system also has an 

intended function to maintain integrity of nonsafety-related components such that no physical 

interaction with safety-related components could prevent satisfactory accomplishment of a 

safety function. The servicing equipment systems have an intended function to provide 

criticality protection that is performed by Boraflex plates in the pool racks.

LRA Table 2.3.3-6 identifies the fuel pool cooling and cleanup system component types that are 

within the scope of license renewal and subject to an AMR.

2.3.3.6.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.6 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.6.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the spent fuel pool cooling and cleanup system components within the 

scope of license renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant 

has adequately identified the system components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.3.7 Standby Service Water

2.3.3.7.1 Summary of Technical Information in the Application

LRA Section 2.3.3.7 states that the purpose of the SSW system is to remove heat from 

equipment required for a safe reactor shutdown by dissipating that heat to the environment 

through the ultimate heat sink. The SSW system also provides cooling to unit components, as 

required, during normal shutdown and reactor isolation modes.

The LRA states that the SSW system’s intended functions are to supply cooling water to 

safety-related systems and components during plant shutdown, reactor isolation, refueling and 

post-accident conditions; to transfer heat from safety-related loads to the environment; and to 

support the containment pressure boundary. The SSW system also has an intended function to 

maintain integrity of nonsafety-related components such that no physical interaction with 

safety-related components could prevent satisfactory accomplishment of a safety function. 

Additionally, the SSW system has an intended function to demonstrate compliance with the 

NRC‘s regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.3-7 identifies the SSW system component types that are within the scope of 

license renewal and subject to an AMR.

2.3.3.7.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.7, UFSAR Section 9.2.1 and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 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 has identified as within the scope of license 

renewal to verify that the applicant has not omitted any passive and long-lived components 

subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). The staff’s 

review 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 request 

for additional information as discussed below.

In RAI 2.3.3.7-1, dated May 9, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are in scope of license renewal for 

10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/nonsafety-related 

interface. In three instances the staff could not locate seismic anchors on the 

10 CFR 54.4(a)(2) nonsafety-related lines connected to the safety-related lines. The applicant 

was requested to provide additional information to locate the seismic anchors between the 

safety-related and nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary.

In its response dated June 5, 2012, the applicant described the specific location of the seismic 

anchors or identified equivalent anchors for the three anchors in question.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.7-1 acceptable 

because the applicant provided a description of the location of the anchors, which were at 

appropriate locations on the nonsafety-related lines. Therefore, the staff’s concern described in

RAI 2.3.3.7-1 is resolved.
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2.3.3.7.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes that 

the applicant appropriately identified the control enclosure ventilation system components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.8 Component Cooling Water

2.3.3.8.1 Summary of Technical Information in the Application

LRA Section 2.3.3.8 states that the purpose of the component cooling water system is to cool 

auxiliary plant equipment during normal operating and normal shutdown conditions. The system

also provides cooling water for some components during a loss of offsite power.

The LRA states that the component cooling water’s intended functions are to maintain integrity 

of the SSW system pressure boundary, and to support the containment pressure boundary. 

The component cooling water also has an intended function to maintain the integrity of 

nonsafety-related components such that no physical interaction with safety-related components 

could prevent satisfactory accomplishment of a safety function.

LRA Table 2.3.3-8 identifies the component cooling water system component types that 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 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.8.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the component cooling water system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds 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).

2.3.3.9 Plant Service Water

2.3.3.9.1 Summary of Technical Information in the Application

LRA Section 2.3.3.9 states that the purpose of the plant service water system is to cool plant 

auxiliary equipment during normal operating and normal shutdown conditions. The system is 

designed to cool plant auxiliaries that are not required for safe reactor shutdown and are not 

potential sources of radioactive contamination during normal operation. The plant service water 
2-52

system distributes water from the radial well system through the various heat exchangers, 

chillers and coolers, and discharges to the circulating water (CW) system.

The LRA states that the plant service water system’s intended functions are to maintain integrity 

of the SSW system pressure boundary and to support the containment pressure boundary. The 

plant service water system also has the intended functions to support the containment pressure 

boundary and to maintain integrity of nonsafety-related components such that no physical 

interaction with safety-related components could prevent satisfactory accomplishment of a 

safety function.

LRA Table 2.3.3-9 identifies the plant service water system component types that 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 9.2.8, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 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 has identified as within the scope of license 

renewal to verify that the applicant has not omitted any passive and long-lived components 

subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). The staff’s 

review 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 request 

for additional information as discussed below.

In RAI 2.3.3.9-1, dated May 9, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are in scope of license renewal for 

10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/nonsafety-related 

interface. On license renewal boundary drawing LRA-M-1072A, location B-5, the staff could not 

locate a seismic anchor at safety-related valve Q1P44F116 (anchor could not be located on 

(a)(2) branch line 24"-JBD-77 continuing to line 30"-JBD-77 continuing to drawing 

LRA-M-1059A, A-8). The applicant was requested to provide additional information to locate 

the seismic anchors between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary.

In its response dated June 5, 2012, the applicant described the location of the anchor on the 

nonsafety-related piping 24"-JBD-77 attached to the safety-related piping at valve Q1P44F116.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.9-1 acceptable 

because the applicant the appropriate location of the anchor in question, which is at an 

acceptable location between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.9-1 

is resolved.

2.3.3.9.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes the 

applicant appropriately identified the plant service water system 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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all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.10 Floor and Equipment Drainage

2.3.3.10.1 Summary of Technical Information in the Application

LRA Section 2.2.2.10 states that the purpose of the floor and equipment drainage system is to 

collect liquid waste throughout the plant and discharge the radioactive and potentially 

radioactive waste to the radwaste system for processing. The system is also used to detect 

abnormal leakage in the emergency safety features rooms, the drywell, and containment.

The LRA states that the floor and equipment drainage system’s intended function is to support 

the containment pressure boundary. The floor and equipment drainage system also has the 

intended functions to maintain integrity of nonsafety-related components such that no physical 

interaction with safety-related components could prevent satisfactory accomplishment of a 

safety function and to provide flood protection for safety-related components.

LRA Table 2.3.3-10 identifies the floor and equipment drainage system component types that 

are within the scope of license renewal and subject to an AMR.

2.3.3.10.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.10, UFSAR Section 9.3.3, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 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 has identified as within the scope of license 

renewal to verify that the applicant has not omitted any passive and long-lived components 

subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). The staff’s 

review 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 request 

for additional information as discussed below.

In RAI 2.3.3.10-1, dated May 9, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/

nonsafety-related interface. At 10 locations, the staff could not locate a seismic anchor on the 

10 CFR 54.4(a)(2) nonsafety-related lines connected to the safety-related line. The applicant 

was requested to provide additional information to locate the seismic anchors between the 

safety-related/nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary.

In its response dated June 5, 2012, the applicant described the location of the 10 seismic and/or 

equivalent anchors.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.10-1 acceptable 

because the applicant provided the location of these 10 seismic and/or equivalent anchors, 

which were at acceptable locations. Therefore, the staff’s concern described in RAI 2.3.3.10-1 

is resolved.
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2.3.3.10.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes that 

the applicant appropriately identified the floor and equipment drainage system components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.3.3.11 Compressed Air

2.3.3.11.1 Summary of Technical Information in the Application

LRA Section 2.3.3.11 describes the compressed air and hatches and locks systems. The 

purpose of the compressed air systems is to provide a continuous supply of compressed air of 

suitable quality and pressure to air operated components throughout the plant and for general 

plant use. The compressed air systems include the plant compressed air, service air, and 

instrument air systems. The hatches and locks system includes the containment and drywell 

equipment hatches, the containment personnel airlocks, and the drywell airlock. The purpose of 

the equipment hatches is to provide equipment access to the containment and drywell during 

outages. The purpose of the airlocks is to provide personnel access to the containment and 

drywell while also providing a continuous seal between the inside and outside of the 

containment or drywell.

The LRA states that the compressed air system’s intended function is to support the 

containment pressure boundary. The compressed air system also has the intended functions to 

maintain integrity of nonsafety-related components such that no physical interaction with 

safety-related components could prevent satisfactory accomplishment of a safety function and 

to support the containment pressure boundary. The hatches and locks system has the intended 

functions to provide a reserve capacity of compressed air for those components requiring a 

supply of compressed air to provide ESF and containment pressure boundary and to support 

the containment pressure boundary.

LRA Table 2.3.3-11 identifies the compressed air system component types that are within the 

scope of license renewal and subject to an AMR.

2.3.3.11.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.11, UFSAR Section 9.3.1, and the license renewal 

boundary drawings using the evaluation methodology discussed in SER Section 2.3 and the 

guidance in SRP-LR Section 2.3. 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 has identified as within the scope of license 

renewal to verify that the applicant has not omitted any passive and long-lived components 

subject to an AMR in accordance with the requirements of 10 CFR 54.21(a)(1). The staff’s 

review 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 requests 

for additional information as discussed below.

In RAI 2.3.3.11-1, dated May 9, 2012, the staff noted that license renewal boundary drawing 

LRA-M-1077A, locations C-6 and H-6, and LRA-M-1077D, locations D-6 and G-6, show 
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1"-JDD-19 lines to be in scope for 10 CFR 54.4(a)(1) with continuations from drawing 

LRA-M-1067A. However, the continuations of these lines on license renewal boundary drawing 

LRA-M-1067A are shown as not in scope. The applicant was requested to provide additional 

information to clarify the scoping classification of these pipe sections.

In its response dated June 5, 2012, the applicant stated that the 1"-JDD-19 lines were 

inadvertently highlighted to the check valves and that they are not subject to an AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.11-1 and correction to 

remove the 1"-JDD-19 lines from the scope of license renewal acceptable because upstream of 

check valves F024A, B, C, and D, the 1"-JDD-19 lines are nonsafety-related and not fluid filled. 

Therefore, the staff’s concern described in RAI 2.3.3.11-1 is resolved.

In RAI 2.3.3.11-2, dated May 9, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are in scope of license renewal for 

10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/nonsafety-related 

interface. In four locations, the staff could not locate seismic anchors on the 10 CFR 54.4(a)(2) 

nonsafety-related lines connected to safety-related lines: The applicant was requested to 

provide additional information to locate the seismic anchors between the safety-related/

nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) scoping boundary.

In its response dated June 5, 2012, the applicant described the location of the four seismic 

and/or equivalent anchors.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.11-2 acceptable 

because the applicant described the location of the seismic and/or equivalent anchors, which 

were appropriately located at the end of the 10 CFR 54.4(a)(2) scoping boundary. Therefore, 

the staff’s concern described in RAI 2.3.3.11-2 is resolved.

2.3.3.11.3 Conclusion

On the basis of its review of the LRA, UFSAR, and RAI responses, the staff concludes that the 

applicant appropriately identified the compressed air system components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately identified 

all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.12 Fire Protection – Water

2.3.3.12.1 Summary of Technical Information in the Application

LRA Section 2.3.3.12 describes the purpose of the fire protection system, which is to provide an 

adequate supply of water or chemicals to points throughout the plant area where fire protection 

may be required. The fire protection system consists of fire water suppression subsystems, 

chemical firefighting equipment, portable fire extinguishers, portable breathing apparatus, and 

the I&C for fire detection, alarm, and operation of the fire-fighting systems. The halon and CO2

systems are described in LRA Section 2.3.3.13.

The LRA states that the fire protection – water system has an intended function to support the 

containment pressure boundary. The system also has the intended function to support the 

containment pressure boundary and to maintain integrity of nonsafety-related components such 
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that no physical interaction with safety-related components could prevent satisfactory 

accomplishment of a safety function. Additionally, the fire protection – water system has an 

intended function that demonstrates compliance with the NRC‘s regulations for fire protection 

(10 CFR 50.48).

LRA Table 2.3.3-12 identifies the fire protection – water system component types that are within 

the scope of license renewal and subject to an AMR.

2.3.3.12.2 Staff Evaluation

The staff reviewed the LRA Section 2.3.3.12; the UFSAR, Revision 5; and LRA drawings using 

the evaluation methodology described in the SER Section 2.3 and 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 in accordance with the requirements of 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 following fire protection documents cited in the CLB listed in the 

GGNS Operating License Condition 41:

• NRC SERs dated August 23, 1991, and September 29, 2006

Based on the documents above, the staff reviewed the GGNS commitment to 10 CFR 50.48, 

“Fire Protection” (i.e., approved Fire Protection Program). The review consisted of a 

point-by-point comparison with Appendix A to Branch Technical Position (BTP) Auxiliary 

Systems Branch 9.5-1, documented in the UFSAR Table 9.5-11.

During its review of LRA Section 2.3.3.12, the staff identified areas in which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results.

In its letter dated May 29, 2012, the staff issued RAI 2.3.3.12-1 and stated that Section 9.5.1.1, 

“Water Supply System,” of the SER dated September 1981, discussed the radwaste building 

water supply system. The staff notes that LRA boundary drawing LRA-M-0035G shows the 

radwaste building fire water system as out of scope (i.e., not colored in purple). The staff 

requested that the applicant verify whether the radwaste building fire water system is 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 the system is 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 a letter dated June 22, 2012, the applicant responded to RAI 2.3.3.12-1 and stated that the 

portions of the fire protection system in the radwaste building include no equipment credited 

with fire prevention, detection, or mitigation in areas containing equipment important to safe 

operation of the plant or systems that contain plant components credited for safe shutdown 

following a fire per 10 CFR 50.48. Therefore, the portions of the fire protection system in the 

radwaste building perform no intended function for license renewal and are not in the scope and 

not subject to an AMR.
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The staff found that the applicant’s analysis of fire protection regulations does not completely 

capture the fire protection SSCs required for compliance with 10 CFR 50.48. The applicant 

indicated that the fire suppression systems in question perform no intended function in support 

of the plant license renewal and, therefore, are excluded from the scope of license renewal and 

not subject to an AMR. The staff finds this contrary to the commitments the applicant made to 

satisfy BTP APCSB 9.5-1, Appendix A, Position F.14, “Radwaste Building” (i.e., that the 

automatic sprinklers are provided for the oil separator in the radwaste building to meet the 

guidance of Appendix A to BTP APCSB 9.5-1). Therefore, the fire suppression systems and 

components in question should be operable to meet 10 CFR 50.48 (in accordance with the 

CLB) as stated in 10 CFR 54.4(a)(3). In addition, fire suppression systems and components 

should not be excluded on the basis that they are not required to function to suppress a fire or to 

comply with 10 CFR 50.48, without factoring in the CLB.

By letter dated July 27, 2012, the staff issued follow-up RAI 2.3.3.12-1a, requesting the 

applicant clarify why the radwaste building oil separator automatic sprinklers are not required for 

compliance with 10 CFR 50.48 and within the scope of license renewal. The staff requested the 

applicant to justify excluding these components from the scope of license renewal and an AMR.

In its response dated August 21, 2012, the applicant stated that the fire suppression system 

components associated with the radwaste building oil separator automatic sprinklers (oil waste 

room) will be included in the scope of license renewal and subject to an AMR. The Fire Water 

System Program will manage the effects of aging for those components. The 

component/material/environment combinations associated with these components are already 

included in LRA Table 3.3.2-12 for carbon steel piping, gray cast iron valve bodies with internal 

raw water and indoor air external environments and copper alloy greater than 15 percent zinc or 

greater than 8 percent aluminum nozzles and valve bodies with raw water environment internal 

and indoor air external.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.12-1a acceptable 

because it clarifies that the radwaste building oil separator automatic sprinklers in question are 

in the scope of license renewal and subject to an AMR. The staff’s concern described in 

RAI 2.3.3.12-1 is resolved.

In its letter dated May 29, 2012, the staff issued RAI 2.3.3.12-2 and stated that the LRA 

boundary drawing listed below shows the following fire protection systems or components as 

out of scope (i.e., not colored in yellow):

LRA Drawing Systems/Components Location

LRA-M-0035L Fire water suppression systems associated with 

Emergency Safety Features Transformers, ESF11 

and ESF21

H3 

The staff requested that the applicant verify whether the fire protection systems or components 

listed above are in the scope of license renewal in accordance with 10 CFR 54.4(a) and whether 

they 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 are not subject to an AMR, the staff requested that the 

applicant provide justification for the exclusion.

In a letter dated June 22, 2012, the applicant responded to RAI 2.3.3.12-2 and stated that the

Transformers ESF11 and ESF21 are the nonsafety-related source of power to engineered

safeguards busses at GGNS during normal operation. The portions of the fire protection system
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associated with transformers ESF11 and ESF21 include no equipment credited with fire

prevention, detection, or mitigation in areas containing equipment important to safe operation of

the plant or systems that contain plant components credited for safe shutdown following a fire

per 10 CFR 50.48. The fire protection system components associated with emergency safety

features transformers ESF11 and ESF21 perform no license renewal intended function and,

therefore, are not in the scope of license renewal and subject to an AMR.

The staff finds that the applicant‘s analysis of fire protection regulations does not completely 

capture the fire protection SSCs required for compliance with 10 CFR 50.48. The applicant 

indicated that the fire suppression systems in question perform no intended function in support 

of the plant license renewal and, therefore, are excluded from the scope of license renewal and 

not subject to an AMR. The staff finds this contrary to the commitments the applicant made to 

satisfy BTP APCSB 9.5-1, Appendix A, Position D.1(h) and Grand Gulf Fire Hazard Analysis 

Report, Appendix 9A, Section 9A.5.59.2, “Safe Shutdown Equipment.” The applicant’s CLB

demonstrates that the ESF11 and ESF21 transformer fire suppression systems were credited to 

meet the guidance of Appendix A to BTP APCSB 9.5-1. Therefore, the fire suppression 

systems and components in question should be operable to meet 10 CFR 50.48 (in accordance 

with the CLB) as stated in 10 CFR 54.4(a)(3). In addition, fire suppression systems and 

components should not be excluded on the basis that they are not required to function to 

suppress a fire or to comply with 10 CFR 50.48, without factoring in the CLB.

By letter dated July 27, 2012, the staff issued follow-up RAI 2.3.3.12-2a, requesting that the 

applicant clarify why the Transformer ESF11 and ESF21 fire suppression systems are not 

required for compliance with 10 CFR 50.48 and within the scope of license renewal. The staff 

requested the applicant to justify excluding Transformer ESF11 and ESF21 fire suppression 

systems from the scope of license renewal and an AMR.

In a letter dated August 21, 2012, the applicant responded to RAI 2.3.3.12-2a and stated that 

the fire suppression system components associated with the ESF11 and ESF21 transformers 

will be included in the scope of license renewal and subject to an AMR. The Fire Water System 

Program will manage the effects of aging for those components. The 

component/material/environment combinations associated with these components are already 

included in LRA Table 3.3.2-12 for carbon steel piping, strainer housings, valve bodies with 

internal raw water and indoor air external environments and copper alloy greater than 

15 percent zinc or greater than 8 percent aluminum strainers with raw water environment 

internal and external, as well as carbon steel piping with outdoor-air internal and external and 

also with soil external. Further the applicant stated the items are added to Table 3.3.2-12 for 

nozzles in the outdoor air environment as shown below. Changes are shown with additions 

underlined.

Based on its review, the staff finds the applicant’s response acceptable because it clarifies that 

the fire suppression systems associated with the ESF11 and ESF21 transformers are in the 

scope of license renewal and subject to an AMR. Further, the applicant has updated LRA 

Table 3.3.2-12 and to include the nozzle component type. The staff’s concern described in 

RAI 2.3.3.12-1 is resolved.

In its letter dated May 29, 2012, the staff issued RAI 2.3.3.12-3 and asked the applicant to 

determine if LRA Tables 2.3.3-12 and 3.3.2-12 should include the following fire protection 

components:
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• fire hose connections and hose racks

• pipe supports, hangers, and couplings

• yard fire hydrants

• water sprinklers and hose standpipes

• floor drains for fire water

• fire water systems associated with SGTS charcoal filters and containment exhaust 

system charcoal filters

• fire water supply filter housings

• dikes and curbs for oil spill confinement

If the applicant determined that LRA Tables 2.3.3-12 and 3.3.2-12 should not include these 

components, the staff asked that the applicant justify the exclusion of these components from 

the scope of license renewal.

In its response, dated June 22, 2012, the applicant provided the results of the scoping and 

screening for the listed fire protection component types addressed in RAI 2.3.3.12-3. Although 

the description of the “piping” item provided in LRA Table 2.3.3-12 does not list these 

components specifically, the applicant stated that it considers this item to include the fire hose 

connection, couplings, and hose standpipes. LRA Table 3.3.2-12 provides the AMR results of 

these components. The applicant indicated that the hose racks and pipe support and hangers 

are included in the structural AMR under component types “fire hose reels” and “component and 

piping support,” respectively, in LRA Table 3.5.2-4. The applicant also confirmed that yard fire 

hydrants are in the scope of license renewal and subject to an AMR. Yard fire hydrants are 

included in LRA AMR Table 3.3.2-12 as the “valve body” component types. In its response, the 

applicant also confirmed that “sprinklers” are included in component type “nozzle” in LRA

Table 2.3.3-12, with AMR results provided in LRA Table 3.3.2-12. The floor drains are included 

in LRA Tables 2.3.3-10 and 2.3.3.19-20 under component type “piping” with the AMR results 

provided in LRA Tables 3.3.2-10 and 3.3.2-19-20. The applicant indicated that the fire water 

systems associated with SGTS charcoal filters and containment exhaust system charcoal filters 

are in the scope of license renewal and subject to an AMR and highlighted on LRA drawing 

LRA-M-0035B-0 at locations B7 and D6. Fire water supply filter housings are included in 

component types “strainer housing” in LRA Table 2.2.3-12 with the AMR results provided in LRA

Table 3.3.2-12. In addition, the applicant indicated that the dikes and curbs for oil spill 

confinement are included in the structural AMR under component type “floor slabs” and “interior 

wall” (for concrete) in LRA Table 2.4-2, with the AMR results provided in LRA Table 3.5.2-2.

Based on its review, the staff found that the applicant had addressed and resolved each item in

response to the RAI as discussed above. Therefore, the staff found the response to

RAI 2.3.3.12-3 acceptable for the purpose of determining whether the applicant has adequately 

identified the fire protection system components within the scope of license renewal.

2.3.3.12.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the fire protection – water system components within the scope 

of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).
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2.3.3.13 Fire Protection – Halon and CO2

2.3.3.13.1 Summary of Technical Information in the Application

LRA Section 2.3.3.13 describes the purpose of the fire protection system, which is to provide an 

adequate supply of water or chemicals to points throughout the plant area where fire protection 

may be required. The fire protection system consists of fire water suppression subsystems, 

chemical firefighting equipment, portable fire extinguishers, portable breathing apparatus, and 

the I&C for fire detection, alarm, and operation of the fire-fighting systems. The fire protection –

water system is described in LRA Section 2.3.3.12.

The LRA states that the fire protection – halon and CO2 system has an intended function to 

support the containment pressure boundary. The system also has an intended function to 

demonstrate compliance with the NRC‘s regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.3-13 identifies the fire protection – halon and CO2 system component types that 

are within the scope of license renewal and subject to an AMR.

2.3.3.13.2 Staff Evaluation

The staff reviewed the LRA Section 2.3.3.13; the UFSAR, Revision 5; and LRA drawings using 

the evaluation methodology described in the SER Section 2.3 and 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 in accordance with the requirements of 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 following fire protection documents cited in the CLB listed in the 

GGNS Operating License Condition 41:

• NRC SERs dated August 23, 1991 and September 29, 2006

Based on the documents above, the staff reviewed the GGNS commitment to 10 CFR 50.48

(i.e., approved Fire Protection Program). The review consisted of a point-by-point comparison 

with Appendix A to (BTP) Auxiliary Systems Branch 9.5-1, documented in the UFSAR

Table 9.5-11.

During its review of LRA Section 2.3.3.13, the staff identified areas in which additional 

information was necessary to complete its review of the applicant’s scoping and screening 

results.

In its letter dated June 22, 2012, the staff issued RAI 2.3.3.13-1 and stated that the LRA 

boundary drawings listed below show the following fire protection systems or components as 

out of scope (i.e., not colored in blue):

LRA Drawing Systems/Components Location

LRA-M-0035E Pressure relief valves, piping, and components 

associated with carbon dioxide (CO2) fire 

suppression system 

G3
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LRA Drawing Systems/Components Location

LRA-M-0035F Halon 1301 fire suppression system in:

Division III Switchgear Room C4

Emergency Remote Shutdown Panel E4

Room OC 405 G4

Division I Switchgear Room A6

Control Cabinet Room F6

Room OC 406 B8

Room OC 705 F8

The staff requested that the applicant verify whether the fire protection systems or components 

listed above are in the scope of license renewal in accordance with 10 CFR 54.4(a) and whether 

they 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 are not subject to an AMR, the staff requested that the 

applicant provide justification for the exclusion.

In a letter dated June 22, 2012, the applicant responded to RAI 2.3.3.13-1 and stated that the 

pressure relief valves, piping, and components on LRA-M-0035E location G3 that are not 

highlighted are used to provide CO2 to purge the main generator of hydrogen or air. This 

portion of the carbon dioxide system performs no license renewal intended function since it 

includes no equipment credited with fire prevention, detection, or mitigation in areas containing 

equipment important to safe operation of the plant or systems that contain plant components 

credited for safe shutdown following a fire per 10 CFR 50.48.

The portions of the Halon 1301 fire suppression system shown on LRA-M-0035F in the 

locations listed above are not in scope for license renewal since they include no equipment 

credited with fire prevention, detection, or mitigation in areas containing equipment important to 

safe operation of the plant or systems that contain plant components credited for safe shutdown 

following a fire per 10 CFR 50.48. As indicated in Note 3 of the drawing, the components were 

intended to serve Unit 2 and are not functional. This note is provided on the drawing for each 

line listed above.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.13-1 acceptable 

because the applicant explained that the portion of the CO2 system in question is used for main 

generator purge, not for plant fire protection, and does not have a license renewal intended 

function, and is, therefore excluded from the scope of license renewal and is not subject to an 

AMR. For the portion of the Halon 1301 fire suppression system in question, the applicant 

clarifies that this portion is associated with GGNS Unit 2, which is not functional.

2.3.3.13.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI responses, the staff concludes the 

applicant appropriately identified the fire protection – halon and CO2 system components within 

the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).
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2.3.3.14 Plant Chilled Water

2.3.3.14.1 Summary of Technical Information in the Application

LRA Section 2.3.3.14 states that the purpose of the plant chilled water system is to provide 

chilled water to the nonsafety-related turbine building, control building, radwaste building, 

auxiliary building, diesel generator building, and containment fan-coil units for space cooling and 

dehumidification. The system also supplies cooling water for the sample coolers located 

throughout the plant. A chemical addition tank is available to chemically treat the system to 

prevent corrosion and an expansion tank is provided to pressurize the system.

The LRA states that the plant chilled water system’s intended function is to support the 

containment pressure boundary. The plant chilled water system also has the intended functions 

to support the containment pressure boundary and to maintain integrity of nonsafety-related 

components such that no physical interaction with safety-related components could prevent 

satisfactory accomplishment of a safety function.

LRA Table 2.3.3-14 identifies the plant chilled water system component types that 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 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.14.3 Conclusion

On the basis of the staff review of the LRA and UFSAR, the staff concludes that the applicant 

has appropriately identified the plant chilled water system components within the scope of 

license renewal, as required by 10 CFR 54.4(a). The staff also finds 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).

2.3.3.15 Standby Diesel Generator

2.3.3.15.1 Summary of Technical Information in the Application

LRA Section 2.3.3.15 states that the purpose of the standby diesel generator system is to 

provide power in the event of a loss of offsite power to the ESF electrical loads for safe reactor 

shutdown and to mitigate the consequences of a DBA such as a LOCA. Standby alternating 

current (AC) power is supplied by three diesel generators. Each ESF division is supplied by a 

separate diesel generator. The standby diesel generator auxiliary subsystems include the fuel 

oil, cooling water, starting air, lubricating oil, and combustion air intake and exhaust systems.

The LRA states that the standby diesel generator system’s intended function is to supply 

standby power to the Division 1 and 2 safety-related equipment required to shut down the 
2-63

reactor, maintain the reactor in a safe shutdown condition, and mitigate the consequences of an 

accident, in the event of a loss of preferred power. The standby diesel generator also has an 

intended function to maintain integrity of nonsafety-related components such that no physical 

interaction with safety-related components could prevent satisfactory accomplishment of a 

safety function. Additionally, the standby diesel generator has an intended function to 

demonstrate compliance with the NRC‘s regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.3-15 identifies the standby diesel generator system component types that are 

within the scope of license renewal and subject to an AMR.

2.3.3.15.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.15 using the evaluation methodology described in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.15.3 Conclusion

On the basis of the staff review of the LRA and UFSAR, the staff concludes that the applicant 

has appropriately identified the standby diesel generator system components within the scope 

of license renewal, as required by 10 CFR 54.4(a). The staff also finds 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 HPCS Diesel Generator

2.3.3.16.1 Summary of Technical Information in the Application

LRA Section 2.3.3.16 describes the purpose of the HPCS diesel generator system, which is to 

provide power, in the event of a loss of offsite power, to the HPCS pump motor and supporting 

system components. In conjunction with the standby diesel generator system, the HPCS diesel 

generator system provides power for safe reactor shutdown and to mitigate the consequences 

of a DBA such as a LOCA. The HPCS diesel generator auxiliary subsystems include fuel oil, 

cooling water, starting air, lubricating oil, and combustion air intake and exhaust.

The LRA states the HPCS diesel generator system’s intended function is to supply standby 

power to the Division 3 safety-related equipment of the HPCS and supporting systems required 

for the operation of the HPCS system in the event of a loss of preferred power. The HPCS 

diesel generator system also has an intended function to maintain integrity of nonsafety-related 

components such that no physical interaction with safety-related components could prevent 

satisfactory accomplishment of a safety function.

LRA Table 2.3.3-16 identifies the HPCS diesel generator system component types that are 

within the scope of license renewal and subject to an AMR.
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2.3.3.16.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.16, UFSAR Sections 8.3.1.1, 9.5.4, 9.5.5, 9.5.6, 9.5.7, 

and 9.5.8, and the license renewal boundary drawings, using the evaluation methodology 

discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as 

within the scope of license renewal to verify that the applicant has not omitted any passive and 

long-lived components subject to an AMR in accordance with the requirements of 

10 CFR 54.21(a)(1). The staff’s review 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 requests for additional information as discussed below.

In RAI 2.3.3.16-1, dated May 9, 2012, the staff noted license renewal boundary drawings 

LRA-M-1093B and LRA-M-1093C, location E-3 and E-7, respectively, show fuel injector casings 

as not within scope for 10 CFR 54.4(a)(1) and not listed in Table 2.3.3-16 as a component type 

subject to an AMR. However, the piping attached to the fuel injector casings is within the scope 

of license renewal for 10 CFR 54.4(a)(1). The applicant was requested to justify not including 

the fuel injector casings within the scope of license renewal for 10 CFR 54.4(a)(1) and to justify 

why the injector casing component type was excluded from LRA Table 2.3.3-16.

In its response dated June 5, 2012, the applicant stated the fuel injector casings are 

subcomponents and integral parts of a complex assembly (HPCS diesel generators) and per the 

guidance in NEI 95-10, Revision 6, Appendix B, the injectors are not subject to an AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-1 acceptable 

because the injectors are integral components of the diesel generator, which is not subject to 

AMR. Therefore, the staff’s concern described in RAI 2.3.3.16-1 is resolved.

In RAI 2.3.3.16-2, dated May 9, 2012, the staff noted license renewal boundary drawing 

LRA-M-1093A shows fuel pipeline continuations between the diesel generator fuel oil day tank 

and both Engine A on drawing LRA-M-1093B and Engine B on drawing LRA-M-1093C. The 

drawings show there is only a single diesel generator fuel oil day tank and single diesel 

generator fuel oil storage tank for the HPCS diesel generator.

The LRA Section 2.3.3.16 description of the HPCS diesel generator, Fuel Oil section, states, 

“[t]he HPCS diesel generator fuel oil system consists of storage tanks, transfer pumps, fuel oil 

day tanks...” This implies there are multiple storage tanks and day tanks in the system. The

applicant was requested to provide additional information to clarify whether there is one or 

multiple diesel generator fuel oil day tank(s) and diesel generator fuel oil storage tank(s) for the 

HPCS diesel generator.

In its response dated June 5, 2012, the applicant stated LRA Section 2.3.3.16 was revised to 

clarify that there is only one fuel oil storage tank and one fuel oil day tank for the HPCS diesel 

generator.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.16-2 acceptable 

because the applicant has revised Section 2.3.3.16 to reflect that there is only one fuel oil 

storage tank and one fuel oil day tank for the HPCS diesel generator. Therefore, the staff’s 

concern described in RAI 2.3.3.16-2 is resolved.
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2.3.3.16.3 Conclusion

On the basis of its review of the LRA, UFSAR, and RAI responses, the staff concludes the 

applicant appropriately identified the HPCS diesel generator system components within the 

scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has adequately 

identified all the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.3.17 Control Room Heating, Ventilation and Air Conditioning

2.3.3.17.1 Summary of Technical Information in the Application

LRA Section 2.3.3.17 states that the purpose of the control room heating, ventilation, and air 

conditioning (HVAC) system is to provide an environment in the control room suitable for the 

operation of safety-related equipment under accident conditions and for the comfort and safety 

of the operators. The system includes the control room air conditioning and standby fresh air 

subsystems.

The LRA states that the control room HVAC system’s intended functions are to provide a 

suitable environment during normal and accident conditions for the operation of safety-related 

equipment in the control room envelope and to limit operator exposure to hazardous chemical 

and radioactive releases. The control room HVAC system also has an intended function to 

maintain integrity of nonsafety-related components such that no physical interaction with 

safety-related components could prevent satisfactory accomplishment of a safety function.

LRA Table 2.3.3-17 identifies the control room HVAC system component types that 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 and UFSAR Sections 6.4 and 9.4.1, and LRA 

Table 2.3.3-17, 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 has not omitted from the scope of 

license renewal any components with intended functions delineated under 10 CFR 54.4(a). The 

staff then reviewed those components that the applicant has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

2.3.3.17.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the control room HVAC system components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds that the applicant has adequately 

identified the system components subject to an AMR in accordance with the requirements 

stated in 10 CFR 54.21(a)(1).
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2.3.3.18 Heating, Ventilation and Air Conditioning

2.3.3.18.1 Summary of Technical Information in the Application

LRA Section 2.3.3.18 describes the HVAC system, which is divided into the following HVAC 

subsystems:

• Containment Cooling

• Drywell Cooling

• Auxiliary Building Ventilation

• Fuel Handling Area Ventilation

• ESF Electrical Switchgear Rooms Cooling

• Emergency Pump Room Ventilation

• Turbine Building Ventilation

• Diesel Generator Building Ventilation

• Standby Service Water Pumphouse Ventilation

• Fire Water Pumphouse Ventilation

• Control Building HVAC

• Emergency Switchgear and Battery Rooms Ventilation

The SGTS and control room HVAC system are described in LRA Sections 2.3.2.6 and 2.3.3.17, 

respectively. Building louvers mounted in the external walls and fire dampers are included in 

LRA Section 2.4.

The LRA states that the HVAC system has the intended functions to support the containment 

pressure boundary; to maintain a suitable room temperature to support operation of the ESF 

electrical switchgear, equipment in the ECCS pump rooms and associated piping penetration 

rooms, equipment in the RCIC pump room, equipment in the fuel pool cooling and cleanup 

pump room during loss of normal ventilation, equipment in the diesel generator rooms when the 

diesels are operating, equipment in SSW pumphouse A and B when the SSW and HPCS 

service water pumps are operating, batteries and switchgear, safety-related equipment in the 

control building HVAC equipment room under accident and post-accident conditions; and to 

provide combustion air to the diesel generators, to maintain a slight negative pressure in the 

battery rooms to prevent ex-filtration of hydrogen and maintain battery room hydrogen 

concentrations within acceptable levels with dilution air and exhaust flow. The HVAC system 

also has the intended function to maintain integrity of nonsafety-related components such that 

no physical interaction with safety-related components could prevent satisfactory 

accomplishment of a safety function. Additionally, the HVAC system has an intended function 

that demonstrates compliance with the NRC’s regulations for fire protection (10 CFR 50.48).

LRA Table 2.3.3-18 identifies the HVAC component types that are within the scope of license 

renewal and subject to an AMR.

2.3.3.18.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.18 and UFSAR Sections 6.2.1.1.2.6, 9.4.2, and 

9.4.4-9.4.10, and LRA Table 2.3.3-18, 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 has not omitted 

from the scope of license renewal any components with intended functions delineated under 

10 CFR 54.4(a). The staff then reviewed those components that the applicant has identified as 
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within the scope of license renewal to verify that the applicant has not omitted any passive and 

long-lived components subject to an AMR in accordance with the requirements of 

10 CFR 54.21(a)(1).

2.3.3.18.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the HVAC system components within the scope of license renewal, as 

required by 10 CFR 54.4(a). The staff also finds 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 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2)

2.3.3.19.1 Summary of Technical Information in the Application

LRA Section 2.3.3.19 describes auxiliary systems that are within the scope of license renewal 

based on the criterion of 10 CFR 54.4(a)(2) for physical interactions. The following auxiliary 

systems are described in individual system sections, as noted:

• CRD (LRA Section 2.3.3.1)

• SLC (LRA Section 2.3.3.2)

• leakage detection and control (LRA Section 2.3.3.4)

• combustible gas control (LRA Section 2.3.3.5)

• SSW (LRA Section 2.3.3.7)

• component cooling water (LRA Section 2.3.3.8)

• plant service water (LRA Section 2.3.3.9)

• floor and equipment drainage (LRA Section 2.3.3.10)

• compressed air (LRA Section 2.3.3.11)

• fire protection – water (LRA Section 2.3.3.12)

• plant chilled water (LRA Section 2.3.3.14)

• standby diesel generator (LRA Section 2.3.3.15)

• HPCS diesel generator (LRA Section 2.3.3.16)

• Control Room HVAC (LRA Section 2.3.3.17)

• HVAC (LRA Section 2.3.3.18)

• miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) (LRA Section 2.3.3.19)

The LRA describes the following additional systems that are within the scope of license renewal 

based on the criterion of 10 CFR 54.4(a)(2) for physical interactions:

• process radiation monitoring

• reactor water cleanup

• CRD maintenance facility, flush tank filter, and leak test

• containment leak rate test

• auxiliary steam

• makeup water treatment

• process sampling

• turbine building cooling water

• suppression pool cleanup

• domestic water

• drywell chilled water
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• NobleChemTM injection and monitoring

• sanitary waste

The LRA states that these systems have an intended function to maintain integrity of 

nonsafety-related components such that no physical interaction with safety-related components 

could prevent satisfactory accomplishment of a safety function.

2.3.3.19.2 Staff Evaluation

The staff reviewed LRA Section 2.3.3.19, UFSAR Sections 5.4.8, 6.2.6, 7.6, 9.2.3, 9.2.4, 9.2.9, 

9.2.11, 9.3.2, 9.3.6, 9.5.9, and 11.5, and the license renewal boundary drawings, using the 

evaluation methodology discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 

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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1). The staff’s review 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 requests for additional information as discussed 

below.

In RAI 2.3.3.19-1, dated May 14, 2012, the staff noted LRA Section 2.1.1.2.2(1) indicates that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/

nonsafety-related interface. In three locations, the staff could not locate in the makeup water 

treatment system seismic anchors on the 10 CFR 54.4(a)(2) nonsafety-related lines connected 

to safety-related lines. The applicant was requested to provide additional information to locate 

the seismic anchors between the safety-related and nonsafety-related interface and the end of 

the 10 CFR 54.4(a)(2) scoping boundary.

In its response dated June 11, 2012, the applicant provided information to locate the three 

seismic anchors or equivalent anchors between the safety-related/nonsafety-related interfaces.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-1 acceptable 

because the applicant described the location of the seismic or equivalent anchors, which were 

at appropriate locations between the safety-related/nonsafety-related interface and the end of 

the 10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in

RAI 2.3.3.19-1 is resolved.

In RAI 2.3.3.19-2, dated May 14, 2012, the staff noted auxiliary steam system license renewal 

boundary drawing LRA-M-0036C, location D-6, shows line 1"-HBD-1108 I-“E” as within the 

scope of license renewal for 10 CFR 54.4(a)(2). The drawing also shows a portion of the 

connecting clean radwaste (CRW) drain line (1-1/2"-HBD-1108 1-“E” line) as within the scope of 

license renewal for 10 CFR 54.4(a)(2). However, there is no separation (i.e., valve) between 

the in-scope portion of this CRW drain line and the out-of-scope portion of the auxiliary steam 

system. The applicant was requested to provide additional information to clarify the scoping 

classification of this pipe section.
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In its response dated June 11, 2012, the applicant stated that the scoping should have extended 

to the closed isolation valve, F098. The applicant also confirmed the addition of “piping” and 

“valve body” to LRA Table 3.3.2-19-2.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-2 acceptable 

because the applicant included, within the scope of license renewal, the closed isolation valve 

(F098) that separates the in-scope portion of this CRW drain line and the out-of-scope portion of 

the auxiliary steam system. Therefore, the staff’s concern described in RAI 2.3.3.19-2 is 

resolved.

In RAI 2.3.3.19-3, dated May 14, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/

nonsafety-related interface. On reactor water cleanup system license renewal boundary 

drawing LRA-M-1080B, location G-4, the staff could not locate a seismic anchor on the 

nonsafety-related piping downstream of safety-related line 4"-HBC-355, where the pipe leaves 

the auxiliary building. The applicant was requested to provide additional information to locate 

the seismic anchor between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary.

In its response dated June 11, 2012, the applicant described the location the seismic anchor on 

nonsafety-related piping 4"-HBD-759 connected to safety-related piping 4"-HBC-355.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-3 acceptable 

because the applicant described the location of the seismic anchor, which is located 

appropriately between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.19-3 

is resolved.

In RAI 2.3.3.19-4, dated May 14, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/

nonsafety-related interface. On domestic water system license renewal boundary drawing 

LRA-M-0034B, location F-3, the staff could not locate the seismic anchor on the 

nonsafety-related 3"-HCD-439 line connected to safety-related line 3"-HCC-65. The applicant 

was requested to provide additional information to locate the seismic anchor between the 

safety-related/nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary.

In its response dated June 11, 2012, the applicant described the location of the anchor on 

nonsafety-related piping 3"-HCD-439 attached to safety-related piping 3"-HCC-65.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-4 acceptable 

because the applicant described the location of the seismic anchor, which was at an appropriate 

location between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.19-4 

is resolved.

In RAI 2.3.3.19-5, dated May 14, 2012, the staff noted containment leak rate test system license 

renewal boundary drawing LRA-M-1072F, location B-3 and B-4, shows the after cooler and 

refrigerated air dryer as not within the scope of license renewal. However, the lines connecting 
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to these two components are shown as in scope for 10 CFR 54.4(a)(2). The applicant was 

requested to provide additional information to clarify the scoping classification of the after cooler 

and refrigerated air dryer.

In its response dated June 11, 2012, the applicant stated the shell side of the aftercooler and 

refrigerated air dryer contains compressed air; the tube sides are liquid filled. Any leakage or 

spray from the tubes within the aftercooler and air dryer is contained in the housing and will not 

affect safety-related components; consequently, the tubes are not in the scope of license 

renewal. The housing is included in scope as “piping” in LRA Table 2.3.3-19-12 and included in 

the aging management evaluation in LRA Table 3.3.2-19-12.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-5 acceptable 

because the aftercooler and refrigerated air dryer housings are in scope for license renewal and 

are included in Table 3.3.2-19-12 as component types subject to an AMR. Therefore, the staff’s 

concern described in RAI 2.3.3.19-5 is resolved.

In RAI 2.3.3.19-6, dated May 14, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/nonsafety-related 

interface. On containment leak rate test system license renewal boundary drawing 

LRA-M-1111A, locations E-7, D-7, and C-7, the staff could not locate the seismic anchors on the 

nonsafety-related lines connected to safety-related lines 1"-HCB-36,1"-HCB-37, and 1"-HCB-38. 

The applicant was requested to provide additional information to locate the seismic anchors 

between the safety-related/nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) 

scoping boundary.

In its response dated June 11, 2012, the applicant stated the containment leak rate system is 

disconnected after testing where the highlighting ends on the drawing and is not part of the 

containment pressure boundary and is not in scope.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-6 acceptable 

because the equipment beyond the drawing highlighting is temporary and therefore not subject 

to AMR. Therefore, the staff’s concern described in RAI 2.3.3.19-6 is resolved.

In RAI 2.3.3.19-7, dated May 14, 2012, the staff noted LRA Section 2.1.1.2.2(1) states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/

nonsafety-related interface. On process sampling system license renewal boundary drawing 

LRA-M-1069D, the staff could not locate seismic anchors on the 10 CFR 54.4(a)(2) 

nonsafety-related line between the safety-related/nonsafety-related interface at location H-8 and 

the end of the 10 CFR 54.4(a)(2) scoping boundary at valve SV-F572, location H-3. The 

applicant was requested to provide additional information to locate the seismic anchor between 

the safety-related/nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) scoping 

boundary.

In its response dated June 11, 2012, the applicant described the location of the equivalent 

anchor between the safety-related/nonsafety-related interfaces.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-7 acceptable 

because the applicant described the location of the seismic anchor, which was at an appropriate 

location between the safety-related/nonsafety-related interface and the end of the 
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10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in RAI 2.3.3.19-7 

is resolved.

In RAI 2.3.3.19-8, dated May 14, 2012, the staff noted process sampling system license renewal 

boundary drawing LRA-M-1069D shows various sampling lines within the scope of license 

renewal for 10 CFR 54.4(a)(2). However, the license renewal boundary of these lines, at 

locations B/C-2 and H-3, is shown to end at valves F026 and F031. It is not clear that the piping 

no longer has the potential to impact safety-related components beyond valves F026 and F031. 

The applicant was requested to provide additional information to clarify the extent of the license 

renewal boundary.

In its response dated June 11, 2012, the applicant stated that the piping and piping components 

beyond the valves contain air and do not have any potential to affect safety-related components.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-8 acceptable 

because the lines beyond valves F026 and F031 do not need to be within the scope of license 

renewal since they contain air and do not have the potential to affect safety-related components. 

Therefore, the staff’s concern described in RAI 2.3.3.19-8 is resolved.

In RAI 2.3.3.19-9, dated May 14, 2012, the staff noted process sampling system license renewal 

boundary drawing LRA-M-1069B shows 10 sampling lines that are within the scope of license 

renewal for 10 CFR 54.4(a)(2). However, connected to these 10 piping sections are drip lines 

that are not shown as within the scope of license renewal. The applicant was requested to 

provide additional information to clarify the license renewal boundary.

In its response dated June 11, 2012, the applicant stated that the 10 drip lines are within the 

scope of license renewal for 10 CFR 54.4(a)(2) and are subject to an AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-9 acceptable 

because the applicant stated that the 10 drip lines in question are appropriately included within 

the components subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.19-9 

is resolved.

In RAI 2.3.3.19-10, dated May 14, 2012, the staff noted turbine building cooling water system 

license renewal boundary drawing LRA-M-1044A, location F-6, shows line 1"-JBD-1342 to be 

within the scope of license renewal for 10 CFR 54.4(a)(2) with a continuation to drawing 

LRA-M-1062C (location D-1). However, the continuation of this line on drawing LRA-M-1062C 

is shown as not within the scope of license renewal. The applicant was requested to provide 

additional information to clarify the scoping classification of this pipe section.

In its response dated June 11, 2012, the applicant stated that the continuation on drawing 

LRA-M-1062C should have been highlighted as within the scope of license renewal. The 

affected components subject to an AMR are already captured in the component type “piping” in 

LRA Table 2.3.3-19-18.

Based on its review, the staff finds the applicant’s response to RAI 2.3.3.19-10 acceptable 

because the applicant described the correct scoping classification for the piping on drawing 

LRA-M-1062C and appropriately included the piping within the scope of license renewal, which 

establishes an acceptable license renewal scoping boundary. Therefore, the staff’s concern 

described in RAI 2.3.3.19-10 is resolved.
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2.3.3.19.3 Conclusion

On the basis of its review of the LRA, UFSAR, and RAI responses, the staff concludes the 

applicant appropriately identified the miscellaneous auxiliary systems in scope for 

10 CFR 54.4(a)(2) components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified all the components subject to 

an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).

2.3.4 Steam and Power Conversion Systems

LRA Section 2.3.4 identifies the steam and power conversion systems SCs subject to an AMR 

for license renewal. The applicant described the supporting SCs of the steam and power 

conversion systems in the following LRA sections:

• 2.3.4.1, “Condensate and Refueling Water Storage and Transfer”

• 2.3.4.2, “Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2)”

The staff’s findings on the review of LRA Sections 2.3.4.1 – 2.3.4.2 are in SER 

Sections 2.3.4.1 – 2.3.4.2, respectively.

Steam and Power Conversion Request for Additional Information

In RAI 2.3.4-1, dated May 15, 2012, the staff noted LRA Section 2.1 describes the applicant’s 

scoping methodology, which specifies how systems or components were determined to be 

included in the scope of license renewal. The staff confirms the inclusion of all components 

subject to aging management by reviewing the results of the screening of components within 

the license renewal boundary. For seven license renewal boundary drawing locations, the 

continuation of piping in scope for license renewal could not be located. The applicant was 

requested to provide sufficient information to locate these seven license renewal boundaries. If 

the continuation cannot be shown on license renewal boundary drawings, then the applicant 

was requested to provide additional information describing the extent of the scoping boundary 

and if there are additional AMR component types between the continuation and the termination 

of the scoping boundary. If the scoping classification of a section of the piping changes over the 

continuation, the applicant was requested to provide additional information to clarify the change 

in scoping classification.

In its response dated June 11, 2012, the applicant provided information to clarify the extent of 

the license renewal boundary for each of the seven continuations. In each case, the applicant

detailed the routing and location of the piping in question and stated there were no additional 

component types subject to an AMR or scoping classification changes.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4-1 acceptable because 

the applicant provided sufficient information to clarify the extent of the license renewal boundary 

for each of the seven continuations and stated there were no additional component types 

subject to an AMR. Therefore, the staff’s concern described in RAI 2.3.3.19-10 is resolved.
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2.3.4.1 Condensate and Refueling Water Storage and Transfer

2.3.4.1.1 Summary of Technical Information in the Application

LRA Section 2.3.4.1 describes the condensate refueling water storage and transfer, and the 

remote shutdown systems. The LRA states that the purpose of the condensate and refueling 

water storage and transfer system is to pump and store condensate for the RCIC and HPCS 

systems; maintain the level of condensate in the condenser hotwell; provide condensate to 

other plant systems, where required; and handle water during refueling and fuel shipping cask 

loading operations. The system includes the condensate storage and transfer subsystem and 

the refueling water storage and transfer subsystem. The purpose of the remote shutdown 

system is to provide the necessary controls and instrumentation for reactor systems and 

secondary support systems to shut down the reactor from outside the main control room.

The LRA states that the condensate refueling water storage and transfer system has the 

intended functions to support automatic transfer of HPCS and RCIC pump suction to the 

suppression pool on low CST level and to support the containment pressure boundary. The 

condensate refueling water storage and transfer system also has an intended function to 

maintain integrity of nonsafety-related components such that no physical interaction with 

safety-related components could prevent satisfactory accomplishment of a safety function. 

Additionally, the condensate refueling water storage and transfer system has intended functions 

that demonstrate compliance with the NRC’s regulations for fire protection (10 CFR 50.48) and 

SBO (10 CFR 50.63).

LRA Table 2.3.4-1 identifies the condensate and refueling water storage and transfer system 

component types that are within the scope of license renewal and subject to an AMR.

2.3.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.1, UFSAR Sections 7.4.1.4, 7.4.1.5, 9.2.6, 9.5.1, and 

Appendix 8A, and the license renewal boundary drawings, using the evaluation methodology 

discussed in SER Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as 

within the scope of license renewal to verify that the applicant has not omitted any passive and 

long-lived components subject to an AMR in accordance with the requirements of 

10 CFR 54.21(a)(1). The staff’s review 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 requests for additional information as discussed below.

In RAI 2.3.4.1-1, dated May 15, 2012, the staff noted LRA Section 2.1.2.1 states that 

nonsafety-related SSCs attached to safety-related SSCs are within the scope of license renewal 

for 10 CFR 54.4(a)(2) up to the first seismic anchor past the safety-related/nonsafety interface. 

In two instances, the staff could not locate seismic anchors on the nonsafety-related lines. The 

applicant was requested to provide additional information to locate these two seismic anchors 

between the safety-related/nonsafety-related interface and the end of the 10 CFR 54.4(a)(2) 

scoping boundary.

In its response dated June 11, 2012, the applicant described the location of the two seismic 

anchors.
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Based on its review, the staff finds the applicant’s response to RAI 2.3.4.1-1 acceptable 

because the applicant described the location of the two seismic anchors, which are at 

acceptable locations between the safety-related/nonsafety-related interface and the end of the 

10 CFR 54.4(a)(2) scoping boundary. Therefore, the staff’s concern described in RAI 2.3.4.1-1 

is resolved.

In RAI 2.3.4.1-2, dated May 15, 2012, the staff noted license renewal boundary drawing 

LRA-M-1065, locations B-6 and C-6, shows expansion joint XJ-G521 to be within the scope of 

license renewal. However, similar expansion joints (XJ-G522) at location E-5 are shown as not 

within the scope of license renewal, and noted as “not long-lived.” The applicant was requested 

to provide additional information to clarify the difference in scoping classification.

In its response dated June 11, 2012, the applicant stated that all the expansion joints (XJ-521 

and XJ-522) are not subject to an AMR as they are “not long-lived” and are periodically replaced 

and XJ-G521 should not have been highlighted. The applicant updated LRA Table 3.4.2-2-19 to 

exclude the component type “Expansion Joint” with material “Elastomer.”

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.1-2 acceptable 

because the applicant explained the difference in the scoping classification of the expansion 

joints. The expansion joints in question are periodically replaced and therefore not a long-lived

component subject to AMRs. The applicant has updated LRA Table 3.4.2-2-19 to exclude the 

expansion joints from AMR. Therefore, the staff’s concern described in RAI 2.3.4.1-2 is 

resolved.

2.3.4.1.3 Conclusion

On the basis of its review of the LRA, UFSAR, and RAI responses, the staff concludes that the 

applicant appropriately identified the plant service water system components within the scope of 

license renewal, as required by 10 CFR 54.4(a), and the applicant has adequately identified all 

the components subject to an AMR in accordance with the requirements stated in 

10 CFR 54.21(a)(1).

2.3.4.2 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2)

2.3.4.2.1 Summary of Technical Information in the Application

LRA Section 2.3.4.2 describes steam and power conversion systems that are within the scope 

of license renewal based on the criterion of 10 CFR 54.4(a)(2) for physical interactions. The 

condensate and refueling water storage and transfer system is described in LRA 

Section 2.3.4.1.

The LRA describes the following additional systems that are within the scope of license renewal 

based on the criterion of 10 CFR 54.4(a)(2) for physical interactions:

• FW control

• main and reheat stem

• condensate and FW

• condensate cleanup

• heater vents and drains

• main turbine and auxiliaries
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• main and reactor feed pump turbine seal steam and drain

• lube oil

• moisture separator-reheater vents and drains

• extraction steam

• turbine bypass

• generator

• seal oil

• generator primary water

• excitation

• condenser air removal

• low temperature offgas

• CW

The LRA states that these systems have an intended function to maintain integrity of 

nonsafety-related components such that no physical interaction with safety-related components 

could prevent satisfactory accomplishment of a safety function.

2.3.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.3.4.2, UFSAR Sections 1.2.2.5.9, 7.2.1.1, 7.3.1.1, 7.7.2.4, 

10.2, 10.2.2.2, 10.3, 10.4, 10.4.2, 10.4.3, 10.4.4, 10.4.5, 10.4.6, 10.4.7, 10.4.7.2, and 11.3, and 

the license renewal boundary drawings, using the evaluation methodology discussed in SER 

Section 2.3 and the guidance in SRP-LR Section 2.3. 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 has identified as within the scope of 

license renewal to verify that the applicant has not omitted any passive and long-lived 

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

The staff’s review 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 

requests for additional information as discussed below.

In RAI 2.3.4.2-1, dated May 15, 2012, the staff noted 16 instances on license renewal boundary 

drawings showing piping “to & from turbine bldg. cooling water system” and vent piping as not 

within scope of license renewal. However, these piping sections are shown on license renewal 

boundary drawing LRA-M-1062B as within the scope of license renewal for 10 CFR 54.4(a)(2). 

The applicant was requested to provide additional information to clarify the scoping 

classification of these pipe sections.

In its response dated June 11, 2012, the applicant stated for these 16 instances the piping and 

components in question are highlighted on the primary system drawings and are in scope for 

license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-1 acceptable 

because the components in question are highlighted as in scope on other primary drawings. 

Therefore, the staff’s concern described in RAI 2.3.4.2-1 is resolved.

In RAI 2.3.4.2-2, dated May 15, 2012, the staff noted condensate and FW system license 

renewal boundary drawing LRA-M-1053E, locations F-4, F-6, and F-8, shows 1/2"-GBD-188, 

1/2"-GBD-187, and 1/2"-GBD-186, “oxygen flow control rack,” piping to the condensate system 

as not within the scope of license renewal. However, the piping is connected to in-scope piping 
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without a separation (i.e., valve). The applicant was requested to provide additional information 

to justify the scoping classification of these pipe sections.

In its response dated June 11, 2012, the applicant stated these lines are in scope up to the first 

isolation valve and should have been highlighted on the drawing. Piping upstream of the 

isolation valve is not fluid filled and therefore not in scope for 10 CFR 54.4(a)(2). Affected 

components subject to AMR are captured under the component types “piping” and “valve body”

in LRA Table 2.3.4-2-3.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-2 acceptable 

because the applicant clarified the extent of the license renewal boundary and included the 

additional piping in the scope of license renewal. Therefore, the staff’s concern described in

RAI 2.3.4.2-2 is resolved.

In RAI 2.3.4.2-3, dated May 15, 2012, the staff noted CW system license renewal boundary 

drawing LRA-M-1059B, locations B-3 and B-4, shows injection nozzles of the condenser tube 

cleaning system “A” and “B” as within the scope of license renewal. LRA Table 2.3.4-2-18 does 

not list these injection nozzles. The applicant was requested to provide additional information to 

justify the exclusion of an injection nozzle component type from LRA Table 2.3.4-2-18.

In its response dated June 11, 2012, the applicant stated the injection nozzles are inside the 

10 CFR 54.4(a)(2) piping and their failure would not cause spray or leakage onto safety-related

equipment. Therefore, the nozzles are not subject to an AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-3 acceptable 

because the nozzles are inside nonsafety-related piping, cannot impact safety-related

equipment, and are therefore not subject to an AMR. Therefore, the staff’s concern described in

RAI 2.3.4.2-3 is resolved.

In RAI 2.3.4.2-4, dated May 15, 2012, the staff noted main and reheat steam system license 

renewal boundary drawing LRA-M-1051A, locations C-3 and C-4, shows two 48-inch lines to the 

low pressure turbines A and C from the moisture separator reheaters as not within the scope of 

license renewal. However, the 48-inch line to the low pressure turbine B from the moisture 

separator reheater is shown as within the scope of license renewal for 10 CFR 54.4(a)(2).

Additionally, moisture separator reheater vents and drains system license renewal boundary 

drawings LRA-M-1056A & B, locations G-4 & G-5, show 1-inch vent piping to the moisture 

separator reheater hot reheat line as not within scope of license renewal. However, these lines 

are connected to the moisture separator reheaters, which are in scope for 10 CFR 54.4(a)(2). 

The applicant was requested to provide additional information to justify the scoping classification 

of these pipe sections.

In its response dated June 11, 2012, the applicant stated these piping and piping components 

are part of the moisture separator reheater and low pressure turbines pressure boundary and 

are in scope for 10 CFR 54.4(a)(2), are subject to an AMR, and should have been highlighted 

from the low pressure turbines to the moisture separator reheaters.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-4 acceptable 

because the applicant clarified that these piping and piping components are in scope for 

10 CFR 54.4(a)(2), are subject to an AMR, and should have been highlighted on the LRA 

drawings. Therefore, the staff’s concern described in RAI 2.3.4.2-4 is resolved.
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In RAI 2.3.4.2-5, dated May 15, 2012, the staff noted main and reheat steam system license 

renewal boundary drawing LRA-M-1051D, location F-7, shows 6"-HBD-1145 piping from the 

2nd stage reheater “B” excess steam bypass to the moisture separator/reheater as not within 

the scope of license renewal. However, on license renewal boundary drawing LRA-M-1056B, 

location G-8, this pipe is shown as within the scope of license renewal for 10 CFR 54.4(a)(2). 

The applicant was requested to provide additional information to clarify the scoping 

classification of this pipe section.

In its response dated June 11, 2012, the applicant stated this piping, as part of the main and 

reheat steam system excess steam bypass, is in scope for 10 CFR 54.4(a)(2) and is subject to 

AMR.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-5 acceptable 

because the applicant clarified that the piping is within the scope of license renewal in 

accordance with 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.4.2-5 is 

resolved.

In RAI 2.3.4.2-6, dated May 15, 2012, the staff noted lube oil system license renewal boundary 

drawing LRA-M-1066D was included in the drawing package but is not included in the table of 

license renewal boundary drawings in LRA Section 2.3.4.2. The applicant was requested to 

clarify why license renewal boundary drawing LRA-M-1066D is not included in the list of 

drawings associated with the lube oil system.

In its response dated June 11, 2012, the applicant corrected LRA Section 2.3.4.2 to include 

LRA-M-1066D in the listing of license renewal drawings.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-6 acceptable 

because the applicant corrected the discrepancy in the scoping boundary and included the 

missing drawing in the revised listing of license renewal drawings associated with the lube oil 

system. Therefore, the staff’s concern described in RAI 2.3.4.2-6 is resolved.

In RAI 2.3.4.2-7, dated May 15, 2012, the staff noted seal oil system license renewal boundary 

drawings LRA-M-1116A and B show details for miscellaneous vents and drains for turbine 

generator equipment. However, there are inconsistencies between the information presented in 

drawing LRA-M-1116A, Table 1, and the highlighted detail drawings for valves and piping in 

scope for 10 CFR 54.4(a)(2). For example, valve NIN44F119 is highlighted in scope on 

LRA-M-1116A, Table 1, but it is not highlighted in the connection M52 drawing or the associated 

detail drawing. Another example is the 3/4"-HC0-410 that is shown as within the scope of 

license renewal in the connection M38 drawing and drawing LRA-M-1116A, detail 5, but it is 

shown as not within the scope of license renewal in LRA-M-1116A, Table 1. The applicant was 

requested to provide additional information to clarify the discrepancies between the scoping 

boundaries shown in LRA-M-1116A, Table 1, and the connection and detail drawings.

In its response dated June 11, 2012, the applicant stated valve NIN44F119 is in scope for 

10 CFR 54.4(a)(2) and should have been highlighted on the “connection M52” detail. Line 

3/4"-HCD-410 is also within scope for 10 CFR 54.4(a)(2). Tables on LRA drawings are used to 

show valves that are subject to an AMR, but not piping lines. The applicant also stated that the 

review associated with this RAI response confirmed that no additional component types were 

subject to an AMR.
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Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-7 acceptable 

because the applicant stated that valve NIN44F119 and line 3/4"-HCD-410 are within the scope 

of license renewal in accordance with 10 CFR 54.4(a)(2). The applicant also explained that

Table 1 is used to show valves that are subject to an AMR but not piping lines. The applicant 

also confirmed there were no additional component types subject to an AMR. Therefore, the 

staff’s concern described in RAI 2.3.4.2-7 is resolved.

In RAI 2.3.4.2-8, dated May 15, 2012, the staff noted seal oil system license renewal boundary 

drawing LRA-M-1116B, location G-8, shows the detail for connection M51 as within the scope of 

license renewal for 10 CFR 54.4(a)(2). However, drawing LRA-M-1116A, Table 1, does not 

have any information on connection M51. The applicant was requested to provide additional 

information to clarify the scoping classification for connection M51.

In its response dated June 11, 2012, the applicant stated that connection M51 is within the 

scope of license renewal for 10 CFR 54.4(a)(2) and subject to an AMR and that LRA-M1116B,

location G-B, shows the detail for connection M51 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 2.3.4.2-8 acceptable 

because the applicant confirmed that connection M51 is within the scope of license renewal for 

10 CFR 54.4(a)(2) and adequately explained the apparent discrepancy. Therefore, the staff’s 

concern described in RAI 2.3.4.2-8 is resolved.

In RAI 2.3.4.2-9, dated May 15, 2012, the staff noted generator primary water system license 

renewal boundary drawing LRA-M-1044A, location G-6, shows “Cooler B003” as not within the 

scope of license renewal. However lines 1"-JBD-1341 and 1"-JBD-1342 run through the cooler 

and are within the scope of license renewal for 10 CFR 54.4(a)(2). The applicant was 

requested to provide additional information to clarify why cooler B003 is not shown as within the 

scope of license renewal.

In its response dated June 11, 2012, the applicant stated that the tube side of cooler B003 is 

liquid filled and the shell side is gas filled. Leakage or spray from the tubes within the cooler 

boundary will not affect any safety-related components; therefore, the tubes within the cooler 

are not in the scope of license renewal.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-9 acceptable 

because the applicant clarified the scoping boundary and the shell side of cooler B003 does not 

need to be within the scope of license renewal since it is gas filled and leakage or spray from 

the liquid filled tubes within the cooler will not affect any safety-related components and. 

Therefore, the staff’s concern described in RAI 2.3.4.2-9 is resolved.

In RAI 2.3.4.2-10, dated May 15, 2012, the staff noted generator primary water system license 

renewal boundary drawing LRA-M-1044A, locations F-1 and E-6, show traps D035 and D037 as 

within the scope of license renewal. LRA Table 2.3.4-2-14 does not list traps as a component 

type subject to an AMR. The applicant was requested to provide additional information to justify 

the exclusion of a trap component type from Table 2.3.4-2-14.

In its response dated June 11, 2012, the applicant stated that the components were 

inadvertently omitted from the LRA and revised LRA Tables 2.3.4-2-14 and 3.4.2-2-14 to include 

the component type “Trap.”
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Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-10 acceptable 

because the applicant corrected the discrepancy in the scoping boundary and added the 

component type “Trap” to LRA Tables 2.3.4-2--14 and 3.4.2-2-14. Therefore, the staff’s concern 

described in RAI 2.3.4.2-10 is resolved.

In RAI 2.3.4.2-11, dated May 15, 2012, the staff noted main turbine and auxiliaries system 

license renewal boundary drawing LRA-M-1117A, locations D-3 and D-4, show valves 

PV F505A and PV 505B with associated piping as not within the scope of license renewal.

However, these valves are shown on drawing LRA-M-1057A, location H-4, as within the scope 

of license renewal for 10 CFR 54.4(a)(2). The applicant was requested to provide additional 

information to clarify the scoping classification of these pipe sections.

In its response dated June 11, 2012, the applicant stated the “dashed” lines used on 

LRA-M-1117A indicate these components are shown on another drawing, in this case 

LRA-M-1057A. LRA-M-1057A shows these components are in the scope of license renewal for 

10 CFR 54.4(a)(2).

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-11 acceptable 

because applicant explained the apparent discrepancy and the dashed lines indicate these 

components are shown on another drawing and the piping in question is in the scope of license 

renewal for 10 CFR 54.4(a)(2). Therefore, the staff’s concern described in RAI 2.3.4.2-11 is 

resolved.

In RAI 2.3.4.2-12, dated May 15, 2012, the staff noted main turbine and auxiliaries’ system 

license renewal boundary drawing LRA-M-1117A, location A-2, shows the “control fluid purifier 

skid” as not within the scope of license renewal. However, the lines connecting to this skid are 

within the scope of license renewal for 10 CFR 54.4(a)(2). The applicant was requested to 

provide additional information to justify the exclusion of the “control fluid purifier skid” from the 

scope of license renewal.

In its response dated June 11, 2012, the applicant stated that the skid was inadvertently not 

highlighted on LRA-M-1117A. The component types for this system are included in LRA

Table 2.3.4-2-6, Main Turbine and Auxiliaries, and are included in the aging management 

evaluation in LRA Table 3.4.2-2-6.

Based on its review, the staff finds the applicant’s response to RAI 2.3.4.2-12 acceptable 

because the applicant clarified the discrepancy in the scoping boundary and the skid has been 

included in the scope of license renewal and the component types for this system are included 

in LRA Table 2.3.4-2-6. Therefore, the staff’s concern described in RAI 2.3.4.2-12 is resolved.

2.3.4.2.3 Conclusion

On the basis of its review of the LRA, UFSAR, and RAI responses, the staff concludes the 

applicant appropriately identified the miscellaneous steam and power conversion systems in 

scope for 10 CFR 54.4(a)(2) components within the scope of license renewal, as required by 

10 CFR 54.4(a), and that the applicant has adequately identified all the components subject to 

an AMR in accordance with the requirements stated in 10 CFR 54.21(a)(1).
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2.4 Scoping and Screening Results: Structures

This section documents the staff’s review of the applicant’s scoping and screening results for 

structures. Specifically, this section discusses:

• containment building

• water control structures

• turbine building, process facilities, and yard structures

• bulk commodities

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

SCs that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all structures. The 

objective was to determine whether the applicant has identified, in accordance with 

10 CFR 54.4, components and supporting structures for structures that appear to meet the 

license renewal scoping criteria. Similarly, the staff evaluated the applicant’s screening results 

to verify that all passive, long-lived SCs were subject to an AMR in accordance with 

10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections, 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 structure 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.

2.4.1 Containment Building

2.4.1.1 Summary of Technical Information in the Application

In LRA Section 2.4.1, the applicant described the Mark III containment structure as both a 

biological shield and a pressure container during a loss-of-coolant accident or steam line break 

accident. The containment structure, as well as all penetrations and the interior structures, are 

seismic Category I structures.
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2.4.1.1.1 Containment

The containment building consists of a foundation mat, right circular cylinder, and a 

hemispherical dome. The cylindrical wall, dome, and foundation mat are constructed of 

reinforced concrete. The wall, dome, and associated internal structures are founded on the mat 

foundation. The applicant stated that the containment also provides support for the RPV

support pedestal. The pedestal is rigidly connected to the reinforced concrete base mat. The 

outside face of the mat is covered with a stainless steel clad, carbon steel liner plate, which also 

serves as the lower extension of the weir wall, forming the interior boundary of the suppression 

pool directly opposite the suppression pool vents.

2.4.1.1.2 Enclosure Building

The enclosure building completely encloses the portions of the containment above the auxiliary 

building roof levels. A flexible seal around the periphery of the enclosure and auxiliary building 

interface maintains leakage limits. The applicant also stated that the enclosure building is a 

steel framed, seismic Category I structure with uninsulated metal siding and an insulated roof 

deck. The building is designed so that most of the siding can become detached during high 

tornado winds, which completely vents the building; however, the main structural framing is 

designed to remain in place. The building is founded on the dome and wall of the containment 

and is anchored to steel-embedded plates and concrete piers. Struts founded on the 

containment shell support the structural steel frame and an internal inspection platform allows 

access around the periphery of the building.

2.4.1.1.3 Drywell

The drywell is a reinforced concrete structure with a concrete foundation common to the 

containment foundation. Its cylindrical walls are subdivided into two structural components, a 

lower wall and an upper wall. The lower wall has two stiffened steel surface plates penetrated 

by steel vents. The annulus between the surface plates is concrete; the lower portion is 

supported by and anchored to the containment base slab. The applicant stated that the lower 

steel portion also is integrally connected with the upper wall. The upper wall is a reinforced 

concrete cylinder supported by the steel of the lower wall section and its internal concrete. A 

reinforced concrete roof contains a circular opening for the drywell head. The head, which is 

part of the drywell pressure retention boundary, is equipped with a pair of horizontal mating 

flanges. The lower flange is equipped with two compression seals. The drywell head, 

constructed of stainless steel, is located directly over the RPV. The drywell liner plate, which 

forms the suppression pool walls, is a stainless-steel-clad carbon steel plate.

2.4.1.1.4 Suppression Pool and Weir Wall

The suppression pool serves as a heat sink during normal operational transients and accident 

conditions. The suppression pool area of the containment liner is stainless steel and serves as 

the fission product barrier. A reinforced concrete slab cantilevered over the suppression pool 

provides support for the traversing in-core probe station. This reinforced concrete slab has a 

steel box structure that projects beneath the slab into the suppression pool. The applicant also 

stated that the weir wall is a vertical, reinforced concrete, right circular cylinder fixed at the 

bottom and free at the top. The outside face of the wall is covered with a stainless-steel-clad 

carbon steel liner plate, which forms the inner boundary of the suppression pool. The weir wall 

supports the steel floor framing at El 114 feet, 6 inches, pipe supports and pipe restraints, and 

provides missile protection during a DBE.
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2.4.1.1.5 Refueling and Reactor Servicing Areas

The refueling pool, located on and integrally attached to the drywell roof, consists of reinforced 

concrete walls and floors. The outer walls of the drywell form the boundary of the refueling pool. 

Three interior cross walls form four smaller compartments that subdivide this large pool. The 

interior face of the pool is lined with a stainless steel liner plate. A horizontal transfer tube 

penetration at one end of the pool allows transfer for fuel elements between the containment 

and the auxiliary building.

The applicant stated that the containment building is supplied with a refueling platform for fuel 

movement and servicing, an auxiliary platform for servicing operations from the refueling floor 

level, and a vessel platform for reactor servicing from the vessel flange level. These 

components perform the following functions:

• The refueling platform is a gantry crane used to transport fuel and reactor components to 

and from pool storage and the RV. The platform spans the fuel storage and vessel 

pools on bedded tracks in the refueling floor. A telescoping mast and grapple, 

suspended from a trolley system, lifts and orients fuel bundles for core, storage rack, 

and upender placement.

• The auxiliary platform operates over the upper containment pools and provides an 

additional work area for reactor servicing. A hoist is provided for reactor servicing tasks. 

Part of the auxiliary platform is used as the vessel flange level service platform.

• The reactor level servicing platform provides a reactor flange level working surface for 

in-vessel inspection and reactor internals servicing and permits servicing access for the 

full vessel diameter.

The applicant further stated that the containment building serves the following intended 

functions under 10 CFR 54.4(a)(1), (a)(2), and (a)(3):

• provide shelter, support, and protection for safety-related equipment and 

nonsafety-related equipment within the scope of license renewal. The containment 

building houses equipment credited in Appendix R, safe shutdown analysis and for fire 

protection (10 CFR 50.48) for SBO (10 CFR 50.63) and for anticipated transients without 

scram (10 CFR 50.62)

• provide radiation-shielding barriers to offsite radiation exposure

• provide structural support to limit the release of radioactive materials so that offsite 

doses from a postulated DBA are below the guideline values of 10 CFR Part 100, 

“Reactor Site Criteria”

• provide structural support to limit the release of radioactive materials so that offsite 

doses from a postulated refueling accident fall below the guideline values of 

10 CFR 50.67, “Accident Source Term”

• provide a heat sink during normal operational transients and accident conditions 

(suppression pool)

• maintain the integrity of nonsafety-related structural components so they do not affect 

safety functions

The applicant also stated that the structural commodities support or protect plant equipment, 

including system components, piping, and electrical conductors. Structural commodities unique 
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to the containment building are included in this review. Those that are common to inscope 

systems and structures (e.g., anchors, embedments, pipe and equipment supports, instrument 

panels and racks, cable trays, and conduits) are reviewed in Section 2.4.4, “Bulk Commodities.”

LRA Table 2.4-1 identifies the components subject to an AMR for the containment building by 

component type and intended function.

2.4.1.2 Staff Evaluation

The staff reviewed LRA Section 2.4.1 and the UFSAR 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 delineated under 10 CFR 54.4(a). The staff then reviewed those 

SCs the applicant included as within the scope of license renewal to verify that the applicant has 

not omitted any passive and long-lived SCs subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.1.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the containment building components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds 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).

2.4.2 Water Control Structures

2.4.2.1 Summary of Technical Information in the Application

In LRA Section 2.4.2, the applicant stated that the water control structures reviewed in this 

section are the SSW cooling towers and Culvert No. 1 and its drainage channel.

2.4.2.1.1 Standby Service Water Cooling Towers

The applicant stated that the ultimate heat sink is comprised of two separate seismic Category I 

mechanical draft cooling tower, pump house, and basin structures. Each tower consists of four 

cells, and each cell has a separate stack. Only four cells are required to support operation.

The applicant also stated that the cooling tower basins are the supply source to the SSW 

system and do not perform any other function. The two SSW cooling towers, pump house, and 

basin structures are located northwest of the containment building. The structure-supporting 

components and general construction are described below:

• A makeup water storage basin consists of a reinforced concrete base slab, exterior 

walls, interior walls and columns to support the cooling tower, a reinforced concrete 

cover slab, a pump house, and a valve room. The SSW cooling tower basins, which 

support the cooling towers, are supported on reinforced concrete base mats and 

founded on the Catahoula Formation
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• A pump house supported on the basin roof slab houses the SSW and HPCS pumps 

(Pump House A) or one SSW pump (Pump House B) and related equipment and piping. 

The pump house consists of a concrete operating floor slab and exterior walls and roof 

to protect the seismic Category I equipment from tornado winds and missiles. To 

prevent debris from entering the piping system, a platform with a perforated plate covers 

the sump area from which the SSW and HPCS service water pumps take suction

• A pipe and valve room consists of a reinforced concrete enclosure structure above the 

basin cover slab to protect the seismic Category I piping and valves from tornado winds 

and missiles

• The mechanical draft SSW cooling towers supported by the basin columns and interior 

walls consist of concrete exterior walls, interior walls, columns and beams, a roof slab, 

and four concrete fan stacks with steel grating over each fan stack top to protect the fans 

from tornado-entrained debris. The stacks are designed to provide full horizontal missile 

protection for the fans. The towers are provided with air intake louvers in the side wall 

and contain fill within the frame structure

The applicant further stated that the two structures have the following intended functions 

covered under 10 CFR 54.4(a)(1), (a)(2), or (a)(3):

• provide a flow path for cooling water from safety-related and nonsafety-related cooling 

water systems

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• maintain ultimate heat sink

• provide support, shelter, and protection for equipment covered under Appendix R safe 

shutdown capability analysis and provisions for fire protection (10 CFR 50.48)

2.4.2.1.2 Culvert No. 1 and Drainage Channel

The applicant stated that Culvert No. 1 is located at the downstream end of the channel draining 

area designated as Basin B. The applicant also stated that Culvert No. 1 is a corrugated metal 

pipe culvert with a reinforced concrete headwall at the point of entry. The drainage channel 

consists of a reinforced concrete slab with soil and riprap slopes. The applicant stated that 

Culvert No. 1 and the drainage channel have the following intended function for 

10 CFR 54.4(a)(2): maintain integrity of nonsafety-related structural components so they do not 

affect safety functions.

The applicant further stated that structural commodities support or protect plant equipment, 

including system components, piping, and electrical conductors. Structural commodities that 

are unique to the water control structures are included in this review. Those that are common to 

inscope systems and structures (e.g., anchors, embedments, equipment supports, instrument 

panels, racks, cable trays, and conduits) are reviewed in Section 2.4.4.

LRA Table 2.4-2 identifies the components subject to an AMR for the water control structures by 

component type and intended function.
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2.4.2.2 Staff Evaluation

The staff reviewed LRA Section 2.4.2 and the UFSAR 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 delineated under 10 CFR 54.4(a). The staff then reviewed those 

SCs the applicant included as within the scope of license renewal to verify that the applicant has 

not omitted any passive and long-lived SCs subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.2.3 Conclusion

On the basis of its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the water control structures components within the scope of license 

renewal, as required by 10 CFR 54.4(a). The staff also finds 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).

2.4.3 Turbine Building, Process Facilities and Yard Structures

2.4.3.1 Summary of Technical Information in the Application

In LRA Section 2.4.3, the applicant stated that the turbine building, process facilities, and yard 

structures consisted of the following:

• turbine building

• process facilities

− auxiliary building

− control building

− diesel generator building

− radioactive waste building

• yard structures

− CST foundation

− condensate storage and refueling water storage tank (RWST) retaining basin

− containment building (GGN2)

− control house—switchyard

− diesel generator fuel oil storage tanks access tunnel

− fire water pump house and storage tanks foundation

− manholes and duct banks

− radioactive waste building pipe tunnels

− RWST foundation

− transformer and switchyard support structures and foundations

2.4.3.1.1 Turbine Building

The applicant stated that the turbine building is a non-Category I structure located adjacent to 

seismic Category I structures. The building is constructed of reinforced concrete and structural 

steel with metal roof decking. The interior walls are concrete and concrete block construction. 
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The turbine building houses safety-related instruments, but the building, including the 

foundation, is designed to seismic Category I requirements able to withstand tornado-force 

winds (except the siding and its supporting members) and will have no adverse effects on the 

adjacent Category I structures.

The turbine building has the following intended functions under 10 CFR 54.4(a)(1), 

(a)(2), and (a)(3):

• provide structural support to safety-related equipment

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• provide support and protection for safety-related equipment and nonsafety-related 

equipment within the scope of license renewal

2.4.3.1.2 Process Facilities

Auxiliary Building. The applicant stated that the auxiliary building is a seismic Category I 

structure that completely encircles the containment from base mat to mid-height. The applicant 

also stated that the auxiliary building is constructed of reinforced concrete, structural steel, and 

supported on a reinforced concrete base mat on structural fill. The building is a multilevel 

structure with floor slabs, reinforced concrete walls, structural steel columns, and composite 

columns supported by the concrete foundation. Reinforced concrete block walls make up 

portions of the internal structure. The applicant further stated that the floor and roof systems are 

of composite construction, using structural steel framework and reinforced concrete slabs. A 

horizontal waterstop is provided between the control, turbine, and containment foundations and 

the auxiliary building foundation. Vertical waterstops are placed in the walls at various locations 

to provide watertightness.

This structure has the following intended functions under 10 CFR 54.4(a)(1), (a)(2), or (a)(3):

• provide shelter, support, and protection for safety-related equipment and 

nonsafety-related equipment within the scope of license renewal. The auxiliary building 

houses equipment covered in the Appendix R safe shutdown analysis, provisions for fire 

protection covered in 10 CFR 50.48, and provisions for SBO, as specified in 

10 CFR 50.63.

• provide radiation-shielding barriers to offsite radiation exposure

• provide missile protection for the portion of the RCPB, located in the auxiliary building 

steam tunnel

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

Control Building. The applicant stated that the control building is located adjacent to the turbine 

and auxiliary buildings and houses the main control room, upper cable spreading room, 

safeguard switchgear, and battery rooms. The applicant also stated that the building is a 

multilevel reinforced concrete and steel structure. The structure is composed of composite 

sections of concrete slabs resting on steel beams. The control building’s foundation is a 

reinforced concrete base mat founded on the Catahoula Formation. The mat is physically 

separated from adjoining buildings by compressible material to prevent seismic interaction.
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The applicant further stated that the structure has the following intended functions as covered 

under 10 CFR 54.4(a)(1), (a)(2), and (a)(3):

• provide functional support as a habitable environment for the operators in the control

room post-accident

• provide radiation and missile shielding protection

• provide support, shelter, and protection for control room building components under the 

Appendix R safe shutdown capability analysis (10 CFR 50.48) and for SBO 

(10 CFR 50.63)

• maintain integrity of nonsafety-related components so they do not affect safety functions

Diesel Generator Building. The applicant stated that the diesel generator building is a seismic 

Category I structure that provides shelter and protection to the emergency diesel generators. 

The applicant also stated that the building is a three-celled (one for each generator), one-story 

concrete structure supported by a reinforced concrete base slab founded on structural backfill. 

The base mat is separated from the auxiliary building by compressible material to prevent 

seismic interaction. The diesel generators rest upon individual concrete foundations, separated 

from the building foundation.

The applicant further stated that the diesel generator building has the following intended 

functions under 10 CFR 54.4(a)(1), (a)(2), and (a)(3):

• provide support and protection for safety-related equipment and nonsafety-related

equipment within the scope of license renewal. The diesel generator building houses

equipment (emergency diesel generators) covered under the Appendix R safe shutdown

analysis and provisions for fire protection (10 CFR 50.48)

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

Radioactive Waste Building. The applicant stated that the radioactive waste building is a 

non-Category I structure designed to comply with Category I requirements to prevent 

uncontrolled release of radioactivity from waste material to the environment. The applicant also 

stated that the radwaste building is partially embedded in soil. The building is a multilevel 

structure with floor slabs, reinforced concrete walls, concrete block walls, and structural steel. 

The reinforced concrete walls and structural steel columns support the superstructure. The floor 

and roof systems are of composite construction, using structural steel framework and reinforced 

concrete slabs. The foundation is a reinforced concrete mat supported on structural fill. 

Waterstops are provided between the turbine and radwaste building foundation and are placed 

between the walls of the two buildings to provide watertightness.

The applicant further stated that the radioactive waste building has the following intended 

function under 10 CFR 54.4 (a)(2): maintain structural integrity if nonsafety-related components 

such that safety functions are not affected and no impact on in-scope structures.

2.4.3.1.3 Yard Structures

Condensate Storage Tank Foundation. The applicant stated that the CST foundation supports 

the CST, which provides the required condensate capacity and flow of condensate for the RCIC

and HPCS systems and maintains the required level in the condenser hotwell. The applicant 
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also stated that the CST is located adjacent to the RWST and shares a common concrete 

retaining basin with the RWST. The CST foundation consists of reinforced concrete founded on 

structural fill.

The applicant further stated that the CST foundation has the following intended functions under 

10 CFR 54.4(a)(1), (a)(2), and (a)(3):

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• provide support and protection for safety-related equipment and nonsafety-related

equipment within the scope of license renewal. The CST foundation supports CSTs as 

covered in the Appendix R safe shutdown analysis and provisions for fire protection 

(10 CFR 50.48) and for SBO (10 CFR 50.63)

Condensate Storage and Refueling Water Storage Tank Retaining Basin. The applicant stated 

that the CST and RWST retaining basin is integral to the foundation of the CST and RWST. 

The retaining basin is sized to retain the full capacity of the CST and the RWST to prevent an 

uncontrolled release of contents. The applicant also stated that the retaining basin is a 

reinforced concrete structure supported on compacted structural fill.

The applicant further stated that the CST and RWST retaining basin has the following intended 

function for 10 CFR 54.4(a)(2): Provide support and protection of the CST and RWST.

Containment Building. The applicant stated that the containment building (GGN2), located 

adjacent to the control building, is partially complete and abandoned in place. It contains no 

system or components required for plant operations. Even though Unit 2 construction has been 

abandoned, the partially completed building still remains. The applicant also stated that the 

partially completed external concrete walls provide missile protection for louvers and other 

vulnerable openings of the control building against tornado-generated missiles. The structure 

has no safety function. Its failure will not compromise any safety-related system or component 

and will not prevent safe reactor shutdown.

The applicant further stated that GGN2 is made of reinforced concrete and is open to the 

atmosphere above El 243 feet, 6 inches.

The applicant also stated that GGN2 has the following intended functions under 

10 CFR 54.4(a)(2):

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• provide missile protection for portions of the control building’s external openings

Control House—Switchyard. The applicant stated that the switchyard control house is a 

single-story structure in the main switchyard that houses relays associated with the offsite 

500 kilovolts (kV) and 115 kV lines. This prefabricated metal building is supported on a 

reinforced concrete slab foundation. The building is nonseismic and provides protection for 

equipment required for SBO recovery.

The applicant also stated that the switchyard control house has the following intended function 

under 10 CFR 54.4 (a)(3): Provide support and shelter for electrical equipment required for 

SBO recovery.
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Diesel Generator Fuel Oil Storage Tanks Access Tunnel. The applicant stated that the diesel 

generator fuel oil storage tank access tunnel provides access to fuel oil pumps associated with 

the tanks. Each tank is buried in structural backfill, and a separate shaft constructed from a 

6-foot diameter corrugated metal pipe provides access to each pump. A reinforced concrete 

slab outfitted with a manhole cover protects the access shaft against missiles.

The applicant also stated that the diesel fuel oil storage tanks access tunnel has the following 

intended functions under 10 CFR 54.4(a)(2) and (a)(3):

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• provide structural and functional support for safety-related equipment and 

nonsafety-related equipment within the scope of license renewal. The tunnel provides 

access to fuel oil tanks, which support equipment (emergency diesel generators) as 

covered under the Appendix R safe shutdown analysis for fire protection (10 CFR 50.48)

Fire Water Pumphouse and Storage Tanks Foundation. The applicant stated that the fire water 

pumphouse and storage tanks foundation provide support for the site’s fire protection water 

supply system. The applicant also stated that the fire water pumphouse consists of structural 

steel with a metal siding exterior and internal walls of concrete block. The pumphouse is 

supported on a reinforced concrete foundation on compacted granular structural fill. A circular 

reinforced concrete foundation and compacted granular fill support the tanks.

The applicant also stated that the fire water pumphouse and storage tanks foundation has the 

following intended function under 10 CFR 54.4(a)(3): Provide support, shelter, and protection 

for components credited for fire protection (10 CFR 50.48).

Manholes and Duct Banks. The applicant stated that manholes and duct banks exist in the 

GGNS yard for underground routing of cables and piping. The seismic Category I electrical 

manholes are located in the yard between the SSW cooling tower and the control building. The 

applicant also stated that the manholes are reinforced concrete structures buried in structural 

backfill and fitted with a ductile cast iron manhole cover for access. Duct banks are located 

below grade in structural backfill and consist of reinforced concrete, which encloses the 

electrical conduits and provides missile protection.

The applicant further stated that the manholes and duct banks have the following intended 

functions under 10 CFR 54.4(a)(1), (a)(2), and (a)(3):

• provide support and protection for safety-related equipment and nonsafety-related

equipment within the scope of license renewal

• maintain integrity of nonsafety-related structural components so they do not affect safety 

functions

• provide support and protection for safety-related equipment and nonsafety-related

equipment within the scope of license renewal. Manholes and duct banks house cable

covered under the Appendix R safe shutdown analysis (10 CFR 50.48) and provisions 

for SBO (10 CFR 50.63). Manhole seals are credited for fire protection (10 CFR 50.48)

Radioactive Waste Building Pipe Tunnels. The applicant stated that the radioactive waste 

building pipe tunnels are underground structures that run from the auxiliary building to the 

radwaste building. The applicant also stated that the tunnels consist of reinforced concrete 
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walls and a base slab. The tunnel at the outside of the radwaste building has a box shape with 

a monolithic top cover. The tunnels’ base slabs rest on compacted structural fill supported by 

the Catahoula Formation, and the sides are covered with either compacted backfill or mass 

concrete. The tunnel sumps are lined with stainless steel plates and the entire system is 

waterproofed.

The applicant further stated that the radioactive waste building pipe tunnels have the following 

intended function under 10 CFR 54.4(a)(2): Maintain the integrity of nonsafety-related structural 

components in such a way that they do not affect safety functions.

Refueling Water Storage Tank Foundation. The applicant stated that the RWST foundation is 

located adjacent to the CST north of the auxiliary building. It is supported on a reinforced 

concrete slab on grade integral with the retaining basin. The applicant also stated that the 

RWST has no safety function. Failure of the tank foundation will not compromise any 

safety-related system or component and will not prevent safe reactor shutdown. However, 

since it is integral to the retaining basis, failure of the foundation could compromise the intended 

functions associated with the retaining basin.

The applicant further stated that the RWST foundation has the following intended function under 

10 CFR 54.4(a)(2): Maintain structural integrity of nonsafety-related structural components for 

the support and protection of the CST and RWST.

Transformer and Switchyard Support Structures and Foundations. The applicant stated that the 

purpose of the transformer and switchyard support structures and foundations is to provide 

physical support to the startup and emergency station service transformers and the other 

transformer and switchyard components in the SBO offsite power recovery path. These support 

structures include the transformer foundations and foundations for the associated transformer 

and switchyard breakers, switchyard bus, and fused disconnect.

The applicant also stated that the transformer and switchyard support structures and 

foundations have the following intended function under 10 CFR 54.4(a)(3): Provide support for 

equipment credited for SBO (10 CFR 50.63).

The applicant further stated that structural commodities support or protect plant equipment, 

including system components, piping, and electrical conductors. Structural commodities that 

are unique to the turbine building, process facilities, and yard structures are included in this 

review. Those that are common to inscope systems and structures (e.g., anchors, 

embedments, equipment supports, instrument panels, racks, cable trays, and conduits) are 

reviewed in Section 2.4.4.

LRA Table 2.4-3 identifies the components subject to an AMR for the turbine building, process 

facilities, and yard structures by component type and intended function.

2.4.3.2 Staff Evaluation

The staff reviewed LRA Section 2.4.3 and the UFSAR 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 delineated under 10 CFR 54.4(a). The staff then reviewed those 
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SCs the applicant included 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 also reviewed the following fire protection documents cited in the CLB listed in the 

GGNS Operating License Condition 41:

• NRC SERs dated August 23, 1991, and September 29, 2006

Based on the documents above, the staff reviewed the GGNS commitment to 10 CFR 50.48

(i.e., approved Fire Protection Program). The review consisted of a point-by-point comparison 

with Appendix A to BTP Auxiliary Systems Branch 9.5-1, documented in the UFSAR

Table 9.5-11.

The staff confirmed that the fire barriers and associated components (beams, columns, floor 

and roof slabs, interior and exterior walls, fire proofing, fire wraps, fire dampers, fire doors, and 

fire penetration seals and components [manways, hatches, manhole covers, and hatch covers]) 

are included in LRA Tables 2.4-3 and 2.4-4 results of scoping and screening of structures, 

including fire barriers as subject to an AMR. On the basis of the information in the LRA 

drawings, UFSAR, and CLB documents the staff did not identify any omissions by the applicant 

in scoping of the fire barriers and components in accordance with 10 CFR 54.4(a).

2.4.3.3 Conclusion

Based on its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the turbine building, process facilities, yard structures, and fire barrier 

commodities components within the scope of license renewal, as required by 10 CFR 54.4(a). 

The staff also finds 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).

2.4.4 Bulk Commodities

2.4.4.1 Summary of Technical Information in the Application

In LRA Section 2.4.4, the applicant stated that the bulk commodities subject to an AMR are 

structural components or commodities that perform or support intended functions of inscope 

SSCs. Bulk commodities unique to a specific structure are included in the review for that 

structure (Sections 2.4.1, 2.4.2, and 2.4.3). Bulk commodities common to inscope SSCs 

(e.g., anchors, embedments, pipe and equipment supports, instrument panels and racks, cable 

trays, conduits) are addressed in this section. Seismic Category I and Category II supports also 

are addressed. Insulation may have the specific intended functions of (1) maintaining local area 

temperatures within design limits, or (2) maintaining integrity so that falling insulation does not 

damage safety-related equipment. The applicant also stated that bulk commodities evaluated in 

this section are designed to support both safety-related and nonsafety-related equipment during 

normal and accident conditions in the event of external events (e.g., tornadoes, earthquakes, 

floods, or missiles) and internal events (e.g., LOCA or pipe breaks).

The applicant further stated that bulk commodities support the various intended functions 

performed by the structures in which they are located. Therefore, it is within the scope of 

license renewal based on the criterion of 10 CFR 54.4(a)(1), (a)(2), and (a)(3) to include the 

support and protection for equipment covered in the Appendix R safe shutdown analysis and 
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provisions for fire protection (10 CFR 50.48), for anticipated transients without scram 

(10 CFR 50.62), and for SBO (10 CFR 50.63).

LRA Table 2.4-4 identifies the components subject to an AMR for the bulk commodities by 

component type and intended function.

LRA Table 2.4-4 identifies bulk commodities component types that are within the scope of 

license renewal and subject to an AMR.

2.4.4.2 Staff Evaluation

The staff reviewed LRA Section 2.4.4 and the UFSAR 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 delineated under 10 CFR 54.4(a). The staff then reviewed those 

SCs the applicant included as within the scope of license renewal to verify that the applicant has 

not omitted any passive and long-lived SCs subject to an AMR, in accordance with the 

requirements of 10 CFR 54.21(a)(1).

2.4.4.3 Conclusion

Based on its review of the LRA and UFSAR, the staff concludes that the applicant has 

appropriately identified the bulk commodities within the scope of license renewal, as required by 

10 CFR 54.4(a). The staff also finds 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).

2.5 Scoping and Screening Results: Electrical and Instrumentation and Control 

Systems

This section documents the staff’s review of the applicant’s scoping and screening results for 

electrical and I&C systems. Specifically, this section discusses electrical and I&C systems.

In accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must list passive, 

long-lived SSCs within the scope of license renewal and subject to an AMR. To verify that the 

applicant properly implemented its methodology, the staff’s review focused on the 

implementation results. This focus allowed the staff to confirm that there were no omissions of 

electrical and I&C system components that meet the scoping criteria and are subject to an AMR.

The staff’s evaluation of the information in the LRA was the same for all electrical and I&C 

systems. The objective was to determine whether the applicant has identified, in accordance 

with 10 CFR 54.4, components and supporting structures for electrical and I&C systems that 

appear to meet the license renewal scoping criteria. Similarly, the staff evaluated the 

applicant’s screening results to verify that all passive, long-lived components were subject to an 

AMR in accordance with 10 CFR 54.21(a)(1).

In its scoping evaluation, the staff reviewed the applicable LRA sections and the RAI 2.5-1 

response, focusing on components that have not been identified as within the scope of license 

renewal. The staff reviewed the UFSAR for each electrical and I&C system to determine 
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whether the applicant has omitted from the scope of license renewal components with intended 

functions delineated under 10 CFR 54.4(a).

After its review of the scoping results, the staff evaluated the applicant’s screening results. For 

those SSCs with intended functions, the staff sought to determine whether (1) the functions are 

performed with moving parts or a change in configuration or properties or (2) the SSCs are 

subject to replacement after a qualified life or specified time period, as described in 

10 CFR 54.21(a)(1). For those meeting neither of these criteria, the staff sought to confirm that 

these SSCs were subject to an AMR, as required by 10 CFR 54.21(a)(1).

2.5.1 Electrical and Instrumentation and Control 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 considers all 

plant electrical and I&C systems including components in the recovery path for loss of off-site 

power in the event of a SBO. The scoping method includes identifying the electrical and I&C 

systems and their design functions and reviewing them against criteria contained in 

10 CFR 54.4. Those electrical and I&C components that were identified to be within the scope 

of license renewal have been grouped by the applicant into component commodity groups. The 

applicant has applied the screening criteria in 10 CFR 54.21(a)(1)(i) and 10 CFR 54.21(a)(1)(ii) 

to this list of component commodity groups to identify those that perform their intended functions 

without moving parts or without a change in configuration or properties and to remove the 

component commodity groups that are subject to replacement based on a qualified life or 

specified time period. The following table identifies the component commodity groups that are 

subject to an AMR and their intended functions:

Component Type Intended 

Functions

Cable connections - Metallic Parts Conducts 

Electricity

Electrical cables and connections not subject to 10 CFR 50.49 

environmental qualifications (EQ) requirements

Conducts 

Electricity

Electrical cables not subject to 10 CFR 50.49 EQ requirements used in 

instrumentation circuits

Conducts 

Electricity

Electrical and I&C penetration cables and connections not subject to 

10 CFR 50.49 EQ requirements

Conducts 

Electricity

Fuse Holders – Insulation Material, Metallic Clamp Conducts 

Electricity

Inaccessible Power Cables (400 V to 35 kV) not subject to 10 CFR 50.49 

EQ requirements

Conducts 

Electricity

Inaccessible Power Cables (115 kV) not subject to 10 CFR 50.49 EQ 

requirements (for SBO recovery)

Conducts 

Electricity

High-voltage Insulators (for SBO recovery) Insulation 

(Electrical)

Switchyard Bus (for SBO recovery) – Bus and Connections Conducts 

Electricity
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Component Type Intended 

Functions

Transmission Conductors and Connections (transmission conductors for 

SBO recovery)

Conducts 

Electricity

LRA Table 2.5-1 identifies electrical and I&C system component types that are within the scope 

of license renewal and subject to an AMR.

2.5.1.2 Staff Evaluation

The staff reviewed LRA Section 2.5 and 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 has identified as within the scope of license renewal to verify that the applicant has not 

omitted any passive and long-lived components subject to an AMR in accordance with the 

requirements of 10 CFR 54.21(a)(1).

General Design Criteria 17 of 10 CFR Part 50, Appendix A, requires that electric power from the 

transmission network to the onsite electric distribution system be supplied by two physically 

independent circuits to minimize the likelihood of their simultaneous failure. In addition, the staff 

noted that the guidance provided by letter dated April 1, 2002, “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 into SRP-LR Section 2.5.2.1.1:

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.

The applicant included the complete circuits between the onsite circuits and up to and including 

switchyard breakers (including the associated controls and structures) within the scope of 

license renewal. The scoping boundary consists of the 34.5 kV breakers (552 1104 and 552

2104) and 115 kV breaker (J1365). The 34.5 kV offsite recovery path components consist of 

the switchyard bus and connections, high-voltage insulators, control circuit cables and 

connections, medium voltage cables and connections, and inaccessible medium-voltage cables 

and connections to manholes. The 115 kV offsite recovery path components consist of control 

circuit cables and connections, high-voltage insulators, overhead transmission conductors and 

connections, underground 115 kV transmission conductors and connections with manholes, 

switchyard bus and connections, and medium-voltage cables and connections. Consequently, 

the staff concludes that the scoping is consistent with the guidance issued in April 1, 2002, and 

later incorporated into SRP-LR, Section 2.5.2.1.1.
2-95

In RAI 2.5-1 dated May 29, 2012, the staff requested the applicant to explain how it manages

the aging of cable tie-wraps and justify why they are not included within the scope of license 

renewal.

In its response dated June 22, 2012, the applicant stated that cable tie-wraps have no license 

renewal function and are not included as an electrical commodity in the scope of license 

renewal. The applicant also stated that the cable tie-wraps are used as an aid during cable 

installation to establish power cable spacing in cable trays and the cable tie-wraps do not 

function as cable support in raceway support analyses. Furthermore, the applicant is not 

crediting the use of cable tie-wraps in the seismic qualification of cable trays. Based on the 

review of this information and the UFSAR, the staff finds the applicant’s exclusion of cable 

tie-wraps from the SSC’s subject to an AMR acceptable.

The applicant did not include metal-enclosed bus and uninsulated ground connectors in the 

commodity groups subject to an AMR because the applicant determined that they do not 

perform any license renewal functions. The staff reviewed the UFSAR and found that metal 

enclosed bus and uninsulated ground conductors are not credited in GGNS’s design basis. 

Therefore, the staff concludes that the exclusion of metal enclosed bus and uninsulated ground 

conductors from the commodity groups subject to an AMR is acceptable.

2.5.1.3 Conclusion

On the basis of its review of the LRA, UFSAR, and the RAI response, the staff concludes that 

the applicant appropriately identified the electrical and I&C commodity groups components 

within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant has 

adequately identified all the components subject to an AMR in accordance with the 

requirements stated in 10 CFR 54.21(a)(1).

2.6 Conclusion for Scoping and Screening

The staff reviewed the information in LRA Section 2, “Scoping and Screening Methodology for 

Identifying Structures and Components Subject to Aging Management Review and 

Implementation Results,” and determines that the applicant’s scoping and screening 

methodology was consistent with 10 CFR 54.21(a)(1) and the staff’s positions on the treatment 

of safety-related and nonsafety-related SSCs within the scope of license renewal and on SCs 

subject to an AMR is consistent with the requirements of 10 CFR 54.4 and 10 CFR 54.21(a)(1).

On the basis of its review, the staff concludes that the applicant has adequately identified those 

systems and components within the scope of license renewal, as required by 10 CFR 54.4(a), 

and those subject to an AMR, as required by 10 CFR 54.21(a)(1).

The staff concludes that there is reasonable assurance that the applicant will continue to 

conduct the activities authorized by the renewed license in accordance with the CLB and any 

changes to the CLB in order to comply with 10 CFR 54.21(a)(1), in accordance with the Atomic 

Energy Act of 1954, as amended, and NRC regulations.

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 Grand Gulf Nuclear Station, Unit 1 (GGNS), 

by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff). In 

Appendix B of its license renewal application (LRA), Entergy Operations, Inc. (Entergy or the 

applicant) described the 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 2, “Generic Aging Lessons 

Learned (GALL) Report,” dated December 2010. The GALL Report contains the staff’s generic 

evaluation of the existing plant programs and documents the technical basis for determining 

where existing programs are adequate without modification, and where existing programs 

should be augmented for the period of extended operation. The evaluation results documented 

in the GALL Report indicate that many of the existing programs are adequate to manage the 

aging effects for particular license renewal SCs. The GALL Report also contains 

recommendations on specific areas for which existing programs should be augmented for 

license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that its 

programs correspond to those reviewed and approved in the report.

The purpose of the GALL Report is to provide a summary of staff-approved AMPs to manage or 

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

staff-approved AMPs, the time, effort, and resources for LRA review will be greatly reduced, 

improving the efficiency and effectiveness of the license renewal review process. The GALL 

Report also serves as a quick reference for applicants and staff reviewers to AMPs and 

activities that the staff has determined will adequately manage or monitor aging during the 

period of extended operation.

The GALL Report identifies: (1) systems, structures, and components (SSCs), (2) SC materials, 

(3) environments to which the SCs are exposed, (4) the aging effects of the materials and 

environments, (5) the AMPs credited with managing or monitoring the aging effects, and 

(6) recommendations for further applicant evaluations of aging management for certain 

component types.

The staff’s review was in accordance 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), and consistent with the guidance of NUREG-1800, Revision 2, “Standard 

Review Plan for Review of License Renewal Applications for Nuclear Power Plants” (SRP-LR)

and the GALL Report.

In addition to its review of the LRA, the staff conducted an onsite audit of selected AMPs, during 

the weeks of January 23 and January 30, 2012. The onsite audits are designed for maximum 

efficiency of the staff’s LRA review. The applicant can respond to questions, the staff can 
3-2

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.

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.

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 corresponding tables in the 

SRP-LR. The tables are essentially the same as Tables 1 through 6 in the SRP-LR, except that 

the “Type” column has been replaced by an “Item Number” column and the “Item Number in 

GALL” column has been replaced by a “Discussion” column. The “Item Number” column is a 

means for the staff reviewer to cross-reference Table 2s with Table 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 where that information is 

located

• the name of a plant-specific program

• exceptions to GALL Report assumption

• discussion of how the item is consistent with the corresponding item in the GALL Report 

when the consistency may not be obvious

• discussion of how the item is different from the corresponding item in the GALL Report 

(e.g., when an exception is taken to a GALL Report AMP)

The format of each Table 1 allows the staff to align a specific row in the table with the 

corresponding SRP-LR table row so that the consistency can be checked easily.

3.0.1.2 Overview of Table 2s

Each Table 2 provides the detailed results of the AMRs for components identified in LRA 

Section 2 as subject to an AMR. The LRA has a Table 2 for each of the systems or structures 

within a specific system grouping (e.g., reactor coolant system (RCS), engineered safety 
3-3

features (ESF), auxiliary systems). For example, the ESF group has tables specific to the 

containment spray system, containment isolation system, and emergency core cooling system

(ECCS). Each Table 2 consists of nine columns:

• 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.

• Aging Management Programs – The sixth column lists the AMPs that the applicant uses 

to manage the identified aging effects.

• NUREG-1801 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 leaves the column blank.

• 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 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 are based on NEI 95-10, Table 4.2-2. Any plant-specific notes 

identified by numbers provide additional information about the consistency of the 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 are 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 are 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 a technical review of the 

applicant’s technical justifications for the exceptions or the adequacy of the 

enhancements.
3-4

The SRP-LR states that an applicant may take one or more exceptions to specific 

GALL Report AMP elements; however, any exception to the GALL Report AMP should 

be described and justified. Therefore, the staff considers exceptions as being portions of 

the GALL Report AMP that the applicant does not intend to implement.

In some cases, an applicant may choose an existing plant program that does not meet 

all the program elements defined in the GALL Report AMP. However, the applicant may 

make a commitment to augment the existing program to satisfy the GALL Report AMP 

prior to the period of extended operation. Therefore, the staff considers these 

augmentations or additions to be enhancements. Enhancements include, but are not 

limited to, activities needed to ensure consistency with the GALL Report 

recommendations. Enhancements may expand, but not reduce, the scope of an AMP.

(3) For other items, the staff conducted a technical review to verify conformance with 

10 CFR 54.21(a)(3) requirements.

Staff audits and technical reviews of the applicant’s AMPs and AMRs determine whether the 

aging effects on SCs will 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.

3.0.2.1 Review of AMPs

For AMPs for which the applicant claimed consistency with the GALL Report AMPs, the staff 

conducted either an audit or a technical review to verify the claim. For each AMP with one or 

more exceptions, the staff evaluated each exception to determine whether the exception 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 Program – Scope of program should include the specific SCs subject to an 

AMR for license renewal.

(2) Preventive Actions – Preventive actions should prevent or mitigate aging degradation.

(3) Parameters Monitored or Inspected – Parameters monitored or inspected should be 

linked to the degradation of the particular structure or component intended function(s).

(4) Detection of Aging Effects – Detection of aging effects should occur before there is a 

loss of structure or component intended function(s). This includes aspects such as 

method or technique (i.e., visual, volumetric, surface inspection), frequency, sample 

size, data collection, and timing of new/one-time inspections to ensure timely detection 

of aging effects.

(5) Monitoring and Trending – Monitoring and trending should provide predictability of the 

extent of degradation, as well as timely corrective or mitigative actions.

(6) Acceptance Criteria – Acceptance criteria, against which the need for corrective action 

will be evaluated, should ensure that the structure or component’ intended function(s) 

are maintained under all CLB design conditions during the period of extended operation.

(7) Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.
3-5

(8) Confirmation Process – Confirmation process should ensure that preventive actions are 

adequate and that appropriate corrective actions have been completed and are effective.

(9) Administrative Controls – Administrative controls should provide for a formal review and 

approval process.

(10) Operating Experience – Operating experience of the AMP, including past corrective 

actions resulting in program enhancements or additional programs, should provide 

objective evidence to support the conclusion that the effects of aging will be adequately 

managed so that the SC intended function(s) will be maintained during the period of 

extended operation.

Details of the staff’s audit evaluation of program elements (1) through (6) and (10) are 

documented in SER Section 3.0.3.

The staff reviewed the applicant’s quality assurance (QA) program and documented its 

evaluations in SER Section 3.0.4. The staff’s evaluation of the QA program included 

assessment of the “corrective actions,” “confirmation process,” and “administrative controls” 

program elements.

The staff reviewed the information on the “operating experience” program element and 

documented its evaluation in SER Section 3.0.3.

3.0.2.2 Review of AMR Results

Each LRA Table 2 contains information concerning whether or not the AMRs identified by the 

applicant align with the GALL Report AMRs. For a given AMR in a Table 2, the staff reviewed 

the intended function, material, environment, AERM, and AMP combination for a particular 

system component type. Item numbers in column seven of the LRA, “NUREG-1801 Item,” 

correlate to an AMR combination as identified in the GALL Report. 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.

For component groups evaluated in the GALL Report for which the applicant claimed 

consistency and for which the report does not recommend further evaluation, the staff’s review 

determined whether the plant-specific components of these GALL Report component groups 

were bounded by the GALL Report evaluation.

The applicant noted for each AMR 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 item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP is consistent with the GALL Report AMP. 

The staff audited these items to verify consistency with the GALL Report and validity of the AMR 

for the site-specific conditions.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and confirmed 
3-6

that the identified exceptions to GALL Report AMPs have been reviewed and accepted. The 

staff also determined whether the applicant’s AMP was consistent with GALL Report AMP and 

whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR 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 Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified 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 items to verify consistency with 

the GALL Report. The staff also determined whether the AMR 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 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 Report AMP. The staff audited these items to verify consistency 

with the GALL Report. The staff confirmed whether the AMR item of the different component 

was applicable to the component under review and whether the identified exceptions to GALL 

Report AMPs have been reviewed and accepted. The staff also determined whether the 

applicant’s AMP was consistent with the GALL Report AMP and whether the AMR was valid for 

the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff audited these 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 Report AMP and whether the AMR 

was valid for the site-specific conditions.

3.0.2.3 UFSAR Supplement

Consistent with the SRP-LR for the AMRs and AMPs that it reviewed, the staff also reviewed 

the final safety analysis report (FSAR) 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 and UFSAR supplements, the SRP-LR, and the GALL 

Report.

During the onsite audit, the staff also examined the applicant’s justifications to verify that the 

applicant’s activities and programs will adequately manage the effects of aging on SCs. The 

staff also conducted detailed discussions and interviews with the applicant’s license renewal 

project personnel and others with technical expertise relevant to aging management.

Note B indicates that the AMR item is consistent with the GALL Report for component, material, 

environment, and aging effect. In addition, the AMP takes some exceptions to the GALL Report 

AMP. The staff audited these items to verify consistency with the GALL Report and verified that 

the identified exceptions to the GALL Report AMPs have been reviewed and accepted. The 
3-7

staff also determined whether the applicant’s AMP was consistent with the GALL Report AMP 

and whether the AMR was valid for the site-specific conditions.

Note C indicates that the component for the AMR 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 Report AMP. This note indicates that the applicant was unable to find 

a listing of some system components in the GALL Report; however, the applicant identified 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 items to verify consistency with 

the GALL Report. The staff also determined whether the AMR 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 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 Report AMP. The staff audited these items to verify consistency 

with the GALL Report. The staff verified whether the AMR item of the different component was 

applicable to the component under review and whether the identified exceptions to the GALL 

Report AMPs have been reviewed and accepted. The staff also determined whether the 

applicant’s AMP was consistent with the GALL Report AMP and whether the AMR was valid for 

the site-specific conditions.

Note E indicates that the AMR item is consistent with the GALL Report for material, 

environment, and aging effect, but credits a different AMP. The staff audited these 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 Report AMP and whether the AMR 

was valid for the site-specific conditions.

3.0.3 Aging Management Programs

SER Table 3.0-1 presents the AMPs credited by the applicant and described in LRA 

Appendix B. The table also indicates the GALL Report 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 3.0-1 Aging Management Programs

AMP LRA 

Section(s)

New or 

Existing AMP

GALL Report

Comparison GALL Report AMPs Staff’s SER Section

115 kV Inaccessible 

Transmission Cable

B.1.1 New Plant specific Plant-specific program 3.0.3.2.1

Aboveground Metallic 

Tanks

B.1.2 New Consistent XI.M29, “Aboveground 

Metallic Tanks”

3.0.3.1.1

Bolting Integrity B.1.3 Existing Consistent with 

enhancements

XI.M18, “Bolting Integrity” 3.0.3.1.2

Boraflex Monitoring B.1.4 Existing Consistent with 

enhancement

XI.M22, “Boraflex 

Monitoring”

3.0.3.1.3

Buried Piping and 

Tanks Inspection

B.1.5 New Consistent XI.M41, “Buried and 

Underground Piping and 

Tanks”

3.0.3.1.4

BWR CRD Return Line 

Nozzle

B.1.6 Existing Consistent with 

enhancement

XI.M6, “BWR Control Rod 

Drive Return Line Nozzle”

3.0.3.1.5
3-8

AMP LRA 

Section(s)

New or 

Existing AMP

GALL Report

Comparison GALL Report AMPs Staff’s SER Section

BWR Feedwater

Nozzle

B.1.7 Existing Consistent XI.M5, “BWR Feedwater 

Nozzle”

3.0.3.1.6

BWR Penetrations B.1.8 Existing Consistent with 

enhancement

XI.M8, “BWR 

Penetrations”

3.0.3.1.7

BWR Stress Corrosion 

Cracking

B.1.9 Existing Consistent with 

exception

XI.M7, “BWR Stress 

Corrosion Cracking”

3.0.3.1.8

BWR Vessel ID 

Attachment Welds

B.1.10 Existing Consistent XI.M4, “BWR Vessel ID 

Attachment Welds”

3.0.3.1.9

BWR Vessel Internals B.1.11 Existing Consistent with 

enhancement

XI.M9, “BWR Vessel 

Internals”

3.0.3.1.10

Compressed Air 

Monitoring

B.1.12 Existing Consistent with 

enhancements

XI.M24, “Compressed Air 

Monitoring”

3.0.3.1.11

Containment Inservice 

Inspection – IWE

B.1.13 Existing Consistent XI.S1, “ASME Section XI, 

Subsection IWE”

3.0.3.1.12

Containment Inservice 

Inspection – IWL

B.1.14 Existing Consistent XI.S2, “ASME Section XI, 

Subsection IWL”

3.0.3.1.13

Containment Leak 

Rate

B.1.15 Existing Consistent with 

exception

XI.S4, “10 CFR 50, 

Appendix J”

3.0.3.1.14

Diesel Fuel Monitoring B.1.16 Existing Consistent with 

enhancements

XI.M30, “Fuel Oil 

Chemistry”

3.0.3.1.15

Environmental 

Qualification (EQ) of 

Electric Components

B.1.17 Existing Consistent X.E1, “Environmental 

Qualification (EQ) of 

Electric Components”

3.0.3.1.16

External Surfaces 

Monitoring

B.1.18 Existing Consistent with 

enhancements

XI.M36, “External 

Surfaces Monitoring of 

Mechanical Components”

3.0.3.1.17

Fatigue Monitoring B.1.19 Existing Consistent with 

exception and 

enhancements

X.M1, “Fatigue Monitoring” 3.0.3.1.18

Fire Protection B.1.20 Existing Consistent with 

enhancements

XI.M26, “Fire Protection” 3.0.3.1.19

Fire Water System B.1.21 Existing Consistent with 

enhancements

XI.M27, “Fire Water 

System”

3.0.3.1.20

Flow-Accelerated 

Corrosion

B.1.22 Existing Consistent with

exception and

enhancement

XI.M17, “Flow-Accelerated 

Corrosion”

3.0.3.1.21

Inservice Inspection B.1.23 Existing Consistent XI.M1, “ASME Section XI 

Inservice Inspection, 

Subsections IWB, IWC, 

and IWD”

3.0.3.1.22

Inservice Inspection –

IWF

B.1.24 Existing Consistent with 

enhancements

XI.S3, “ASME Section XI, 

Subsection IWF”

3.0.3.1.23

Inspection of Overhead 

Heavy Load and Light 

Load (Related to 

Refueling) Handling 

Systems

B.1.25 Existing Consistent with 

enhancements

XI.M23, “Inspection of 

Overhead Heavy Load 

and Light Load (Related to 

Refueling) Handling 

Systems”

3.0.3.1.24

Internal Surfaces in 

Miscellaneous Piping 

and Ducting 

Components

B.1.26 New Consistent XI.M38, “Inspection of 

Internal Surfaces in 

Miscellaneous Piping and 

Ducting Components”

3.0.3.1.25

Masonry Wall B.1.27 Existing Consistent with 

enhancements

XI.S5, “Masonry Walls” 3.0.3.1.26
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AMP LRA 

Section(s)

New or 

Existing AMP

GALL Report

Comparison GALL Report AMPs Staff’s SER Section

Non-EQ Cable 

Connections

B.1.28 New Consistent XI.E6, “Electrical Cable 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.1.27

Non-EQ Inaccessible 

Power Cables (400 V 

to 35 kV)

B.1.29 Existing Consistent with 

enhancements

XI.E3, “Inaccessible 

Power Cables Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.1.28

Non-EQ 

Instrumentation 

Circuits Test Review

B.1.30 New Consistent XI.E2, “Insulation Material 

for Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation Circuits”

3.0.3.1.29

Non-EQ Insulated 

Cables and 

Connections

B.1.31 New Consistent XI.E1, “Insulation Material 

for Electrical Cables and 

Connections Not Subject 

to 10 CFR 50.49 

Environmental 

Qualification 

Requirements”

3.0.3.1.30

Oil Analysis B.1.32 Existing Consistent with 

enhancements

XI.M39, “Lubricating Oil 

Analysis”

3.0.3.1.31

One-Time Inspection B.1.33 New Consistent XI.M32, “One-Time 

Inspection”

3.0.3.1.32

One-Time Inspection –

Small-Bore Piping

B.1.34 New Consistent XI.M35, “One-Time 

Inspection of ASME Code 

Class 1 Small-Bore 

Piping”

3.0.3.1.33

Periodic Surveillance 

and Preventive 

Maintenance

B.1.35 Existing Plant specific

with 

enhancements

Plant-specific program 3.0.3.2.2

Protective Coating 

Monitoring and 

Maintenance

B.1.36 Existing Consistent with 

enhancements

XI.S8, “Protective Coating 

Monitoring and 

Maintenance Program”

3.0.3.1.34

Reactor Head Closure 

Studs

B.1.37 Existing Consistent with 

exception

XI.M3, “Reactor Head 

Closure Stud Bolting”

3.0.3.1.35

Reactor Vessel 

Surveillance

B.1.38 Existing Consistent with 

exception and 

enhancement

XI.M31, “Reactor Vessel 

Surveillance”

3.0.3.1.36

RG 1.127, “Inspection 

of Water-Control 

Structures Associated 

with Nuclear Power 

Plants”

B.1.39 Existing Consistent with 

enhancements

XI.S7, “RG 1.127, 

Inspection of 

Water-Control Structures 

Associated with Nuclear 

Power Plants”

3.0.3.1.37

Selective Leaching B.1.40 New Consistent XI.M33, “Selective 

Leaching”

3.0.3.1.38

Service Water Integrity B.1.41 Existing Consistent with 

enhancements

XI.M20, “Open-Cycle 

Cooling Water System”

3.0.3.1.39
3-10

AMP LRA 

Section(s)

New or 

Existing AMP

GALL Report

Comparison GALL Report AMPs Staff’s SER Section

Structures Monitoring B.1.42 Existing Consistent with 

enhancements

XI.S6, “Structures 

Monitoring”

3.0.3.1.40

Water Chemistry 

Control – BWR

B.1.43 Existing Consistent XI.M2, “Water Chemistry” 3.0.3.1.41

Water Chemistry 

Control – Closed 

Treated Water 

Systems

B.1.44 Existing Consistent with 

enhancements

XI.M21A, “Closed Treated 

Water System”

3.0.3.1.42

3.0.3.1 AMPs Consistent with the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as consistent, with or without 

exceptions and/or enhancements, with the GALL Report:

• Aboveground Metallic Tanks

• Bolting Integrity

• Boraflex Monitoring

• Buried Piping and Tanks Inspection

• BWR [Boiling Water Reactor] CRD Return Line Nozzle

• BWR Feedwater [FW] Nozzle

• BWR Penetrations

• BWR Stress Corrosion Cracking

• BWR Vessel ID Attachment Welds

• BWR Vessel Internals

• Compressed Air Monitoring

• Containment Inservice Inspection – IWE

• Containment Inservice Inspection – IWL

• Containment Leak Rate

• Diesel Fuel Monitoring

• Environmental Qualification (EQ) of Electric Components

• External Surfaces Monitoring

• Fatigue Monitoring

• Fire Protection

• Fire Water System

• Flow-Accelerated Corrosion

• Inservice Inspection

• Inservice Inspection–IWF
3-11

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems

• Internal Surfaces in Miscellaneous Piping and Ducting Components

• Masonry Wall

• Non-EQ Cable Connections

• Non-EQ Inaccessible Power Cable (400 V to 35 kV)

• Non-EQ Instrumentation Circuits Test Review

• Non-EQ Insulated Cables and Connections

• Oil Analysis

• One-Time Inspection

• One-Time Inspection – Small-Bore Piping

• Protective Coating Monitoring and Maintenance

• Reactor Head Closure Studs

• Reactor Vessel Surveillance

• RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

• Selective Leaching

• Service Water Integrity

• Structures Monitoring

• Water Chemistry Control – BWR

• Water Chemistry Control – Closed Treated Water Systems

For AMPs that the applicant claimed are consistent with the GALL Report, with or without

exceptions and/or enhancements, 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, are indeed consistent. The staff reviewed the exceptions to the GALL Report to 

determine whether they are acceptable and adequate. The staff also reviewed the 

enhancements to determine if they will make the AMP consistent with the GALL Report AMP to

which it is compared. The results of the staff’s audits and reviews are documented in the 

following sections.

3.0.3.1.1 Aboveground Metallic Tanks

Summary of Technical Information in the Application. LRA Section B.1.2 describes the new

Aboveground Metallic Tanks Program as consistent with GALL Report AMP XI.M29, 

“Aboveground Metallic Tanks,” as modified by LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” 

The LRA states that the AMP addresses certain indoor and outdoor aboveground metallic tanks 

constructed on concrete or soil. The aging effects managed by the AMP are loss of material 

and cracking of both the inside and outside surfaces of the tanks. The LRA states that the AMP

will manage these aging effects through periodic visual inspections, thickness measurements of 

the tank bottoms, and preventive measures such as protective coatings and sealants.
3-12

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M29.

Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, which revises several 

GALL Report AMPs including the guidance for AMP XI.M29. Because it was unclear whether 

the applicant incorporated the updated guidance into its AMPs, by letter dated January 2, 2014, 

the staff issued RAI 3.0.3-1 requesting that the applicant provide details on how the updated 

guidance of LR-ISG-2012-02 had been incorporated in its AMPs.

In its response dated May 13, 2014, the applicant revised the Aboveground Metallic Tanks 

Program to include (a) cracking as an aging effect, (b) the inside surfaces of tanks as areas to 

be inspected, and (c) certain indoor tanks in the program. The staff finds the applicant’s 

response acceptable because the inclusion of these three items makes the program consistent 

with the updated guidance in the GALL Report.

Based on its audit of the applicant’s Aboveground Metallic Tanks Program and review of the 

applicant’s response to RAI 3.0.3-1, the staff finds that program elements one through six for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M29, as modified through 

LR-ISG-2012-02.

Operating Experience. LRA Section B.1.2 summarizes operating experience related to the 

Aboveground Metallic Tanks. The applicant stated that a visual inspection of the condensate 

storage tank (CST) conducted in 2007 found no indications of age-related degradation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience, were reviewed by the applicant. As discussed in the staff’s “Aging Management 

Program Audit Report Regarding the Grand Gulf Nuclear Station, Unit 1” (AMP Audit Report), 

dated June 8, 2012, the staff conducted an independent search of the plant operating 

experience information to determine whether the applicant had adequately evaluated and 

incorporated operating experience related to this program. During its review, the staff identified 

operating experience for which it determined the need for additional clarification, resulting in the 

issuance of RAIs, as discussed below.

During the audit, the staff’s walkdown of the stainless steel CST revealed extensive rust stains 

(i.e., encompassing 360 degrees around the tank). These rust stains appeared to originate from 

the tank roof to shell weld. The applicant could not state the cause of the rust stains on this 

stainless steel tank. By letter dated April 16, 2012, the staff issued RAI B.1.2-1 requesting that 

the applicant state the cause of the rust stains on the side of the CST and state the basis for 

why the cause of the rust stains does not indicate the presence of an aging effect that would 

require a methodology, other than visual inspections, for managing aging of the tank.

In its response dated May 14, 2012, the applicant stated that based on an engineering 

evaluation conducted subsequent to a structural maintenance rule walkdown, the rust stains are 

superficial in that they are the result of initial corrosion of uncoated carbon steel angles installed 

at the springline of the tank. The carbon steel angles were evaluated for loss of material, 

cleaned, and coated as a result of the walkdown.

The staff finds the applicant’s response acceptable because the stains were a result of carbon 

steel members corroding before being coated; the carbon steel members were evaluated, 
3-13

cleaned, and coated and therefore further corrosion should not occur, or it would be detected 

during periodic visual inspections conducted by this program. The staff’s concern described in

RAI B.1.2-1 is resolved.

Based on the staff’s review of plant-specific operating experience related to the fire water 

storage tanks, there are a considerable number of condition reports documenting inspection 

findings from 2002, 2006, 2007, 2008, and 2009 identifying rust stains, coating damage and 

holidays on the bottom of the tanks. In addition, during its audit walkdown, the staff noted 

several locations on both tanks where the top edge of the sealant between the tank and tank 

foundation had separated from the tank surface. These gaps could allow water to enter 

between the tank bottom and foundation. By letter dated April 16, 2012, the staff issued

RAI B.1.2-2 requesting that the applicant state the basis for why one volumetric inspection of 

the tank bottom within 5 years of the period of extended operation and then whenever the tank 

is drained is sufficient to manage the aging of the fire water storage tanks.

In its response dated May 14, 2012, the applicant stated that:

(a) to date, the tanks have maintained the ability to perform their intended function

(b) if no significant degradation is found during the volumetric examination that occurs no 

earlier than 35 years, then increasing the number of volumetric examinations would not 

be warranted

(c) if significant degradation is found, the inspection results and industry operating 

experience would be used to determine the acceptability of the findings and the need for 

subsequent inspections

(d) appropriate design specifications will be used to evaluate the findings

(e) the condition of the sealant has been documented in the corrective action program and a 

work request for refurbishment has been initiated

(f) LRA Sections A.1.2 and B.1.2 have been revised to state that, “[t]anks are inspected 

externally at least once every refueling cycle. In addition, ultrasonic examination (UT) 

thickness measurements of the tank bottoms will be performed at least once within the 

5 years prior to the period of extended operation and whenever the tanks are drained 

during the period of extended operation.”

The staff finds the applicant’s response acceptable because:

(a) to date, the coating damage, holidays and rust stains have not resulted in loss of 

function of the tanks

(b) design specifications will be used to evaluate the volumetric results

(c) if significant degradation is found, the evaluation will include the need for subsequent 

volumetric examinations

(d) during the walkdown, the staff noted that the majority of the sealant circumference 

adhered to the side of the tank and the gaps at the localized defective areas were not 

large, the condition of the sealant has been documented in the corrective action 

program, a work request for refurbishment has been initiated, and potential corrosion 

caused by leakage past the sealant would be detected by the volumetric examination
3-14

(e) the program and updated final safety analysis report (UFSAR) supplement were revised 

to include the external inspections and ultrasonic thickness measurement of the tank 

bottoms

The staff’s concern described in RAI B.1.2-2 is resolved.

The applicant identified that the CST base seal was leaking in December 2010. The work order 

to correct this adverse condition is currently not scheduled to be completed until May 2013. 

Given the span of time during which the tank is susceptible to corrosion due to this leaking seal, 

it is not clear to the staff that one volumetric inspection of the tank bottom within 5 years of the 

period of extended operation and then whenever the tank is drained is sufficient to manage the 

aging of the CST. By letter dated April 16, 2012, the staff issued RAI B.1.2-3 requesting that the 

applicant state the basis for why one volumetric inspection of the tank bottom within 5 years of 

the period of extended operation and then whenever the tank is drained is sufficient to manage 

the aging of the CST.

In its response dated May 14, 2012, the applicant stated that:

(a) to date, the tank has shown no significant degradation and it has maintained its ability to 

perform its intended function

(b) if no significant degradation is found during the volumetric examination that occurs no 

earlier than 35 years, then increasing the number of volumetric examinations would not 

be warranted

(c) if significant degradation is found, the inspection results and industry operating 

experience would be used to determine the acceptability of the findings and the need for 

subsequent inspections

(d) appropriate design specifications will be used to evaluate the findings

(e) LRA Sections A.1.2 and B.1.2 have been revised to state that, “[t]anks are inspected 

externally at least once every refueling cycle. In addition, UT thickness measurements 

of the tank bottoms will be performed at least once within the 5 years prior to the period 

of extended operation and whenever the tanks are drained during the period of extended 

operation”

The staff finds the applicant’s response acceptable because:

(a) design specifications will be used to evaluate the volumetric results

(b) if significant degradation is found, the evaluation will include the need for subsequent 

volumetric examinations

(c) the program and UFSAR supplement were revised to include the external inspections 

and ultrasonic thickness measurement of the tank bottoms

(d) the staff noted that, without a volumetric examination, it is not possible to determine if

significant degradation due to the leaking tank base seal has occurred; however, the 

volumetric examination performed within 5 years of entering the period of extended 

operation will provide a basis for the tank being able to perform its CLB function(s) or 

demonstrate the need for repairs

The staff’s concern described in RAI B.1.2-3 is resolved.
3-15

Based on its audit and review of the application, and review of the applicant’s responses to RAIs 

B.1.2-1, B.1.2-2, and B.1.2-3, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which the corresponding GALL 

Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.2, as modified by letter dated May 13, 2014, provides 

the UFSAR supplement for the Aboveground Metallic Tanks Program. In its response dated 

May 13, 2014, the applicant revised the UFSAR supplement to include (a) surface exams to 

detect cracking, (b) tank internal visual and surfaces examinations, and (c) the inspection of 

external surfaces of insulated tanks. An inspection table with accompanying notes was also 

added that includes inspection techniques, frequency of inspections, and minimum surface area 

to be examined for the relevant material, environment, aging effect combinations. The applicant 

only has stainless steel tanks in scope; therefore, stainless steel was the only material 

considered in the inspection table. The applicant does not have any in-scope indoor tanks; 

therefore, indoor tanks were not included in the UFSAR supplement.

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1, as modified by 

LR-ISG-2012-02. The staff also noted that the applicant committed (Commitment No. 2) to 

implement the new Aboveground Metallic Tanks Program prior to entering the period of 

extended operation for managing aging of applicable components. The staff finds that the 

information in the UFSAR supplement, as modified by letter dated May 13, 2014, is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Aboveground Metallic Tanks 

Program, the staff concludes that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M29. 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).

3.0.3.1.2 Bolting Integrity

Summary of Technical Information in the Application. LRA Section B.1.3 describes the existing

Bolting Integrity Program as consistent, with enhancements, with GALL Report AMP XI.M18, 

“Bolting Integrity.” The LRA states that the program includes management of loss of preload, 

cracking, and loss of material for closure bolting for pressure-retaining components using 

preventive and inspection activities. The program incorporates NRC and industry 

recommendations delineated in NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting 

Degradation or Failure in Nuclear Power Plants,” issued June 1990; Electric Power Research 

Institute (EPRI) TR-104213, “Bolted Joint Maintenance and Applications Guide,” and EPRI 

NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M18. For the “preventive 

actions” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

The “preventive actions” program element in GALL Report AMP XI.M18 recommends that the 

program include preventive actions, including the use of bolting material that has an actual 
3-16

measured yield strength limited to less than 150 ksi. The program further states that if used, 

high-strength closure bolting (actual yield strength greater than or equal to 150 ksi) should be 

monitored for cracking since it may be subject to stress-corrosion cracking (SCC). During the 

audit, the staff reviewed the Bolting Integrity Program plant basis document and other 

supporting documents and interviewed the plant staff and was unable to determine whether or 

not high-strength closure bolts are in use at the plant. LRA Section B.1.3 states that the 

program is consistent with GALL Report AMP XI.M18; however, statements the applicant made 

appear to contradict the information presented in the LRA. By letter dated April 11, 2012, the 

staff issued RAI B.1.3-1 requesting that the applicant clarify whether high-strength closure bolts 

are in use at the plant, and provide an explanation of the plant processes or procedures used to 

identify the high-strength closure bolts.

In its response dated May 9, 2012, the applicant stated that the only high-strength bolting 

identified at GGNS is the reactor vessel (RV) closure bolting, which is discussed in LRA 

Section B.1.37. The applicant also stated that the enhancement to the “detection of aging 

effects” program element for high-strength bolting is included to manage high-strength bolting 

that may be placed into use in the future and clarified that any potential future use of 

high-strength bolting is managed through the design change process when component material 

specifications are reviewed.

The staff finds the applicant’s response acceptable because the applicant confirmed that (1) the 

only high-strength bolting identified at GGNS is the RV closure bolting, which is managed by the 

Reactor Head Closure Studs or Bolting Integrity Programs, (2) the enhancement to the 

detection of aging effects program element provides inspection techniques to manage aging in 

high-strength bolting that may be used in the future, and (3) any future use of high-strength bolts 

will be identified in the design process. The staff’s concern described in RAI B.1.3-1 is resolved.

The staff also reviewed the portions of the “preventive actions” and “detection of aging effects”

program elements associated with the enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows.

Enhancement 1. LRA Section B.1.3 states an enhancement to the “preventive actions” program 

element. In this enhancement, the applicant stated that the Bolting Integrity Program will be 

enhanced to clarify the prohibition on use of lubricants containing molybdenum disulfide (MoS2) 

for bolting and to specify that proper gasket compression will be visually confirmed following 

assembly. GALL Report AMP XI.M18 states that selection of bolting materials, lubricants, and 

sealants should be in accordance with EPRI NP-5769 and NUREG-1339. It also states that the 

use of MoS2 as a lubricant has been shown to be a potential contributor to SCC and should not 

be used. GALL Report AMP XI.M18 further states that bolting replacement activities include 

checking for uniformity of the gasket compression after assembly. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M18 and 

finds it acceptable because when it is implemented it will make the program consistent with the 

recommendations in the GALL Report AMP.

Enhancement 2. LRA Section B.1.3 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the Bolting Integrity Program

will be enhanced to include consideration of the guidance applicable for pressure boundary 

bolting in NUREG-1339, EPRI NP-5769, and EPRI TR-104213. GALL Report AMP XI.M18 

states that bolting inspections should include consideration of the guidance applicable for 

pressure boundary bolting in NUREG-1339, EPRI NP-5769, and EPRI TR-104213. During the 
3-17

audit, the staff reviewed the implementing procedures and found that although the 

recommended guidance documents were not consistently referenced in the implementing 

procedures, the specific guidance from the recommended guidance documents already had 

been included and proper actions were already in place. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M18 and finds it 

acceptable because it will confirm that the program remains consistent with the 

recommendations in the GALL Report AMP by ensuring that the proper specifications are used.

Enhancement 3. LRA Section B.1.3 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the Bolting Integrity Program

will be enhanced to include volumetric examination per American Society of Mechanical 

Engineers (ASME) Code Section XI, Table IWB-2500-1, Examination Category B-G-1, for 

high-strength closure bolting, regardless of code classification. High-strength closure bolting is 

bolting with actual yield strength greater than or equal to 150 ksi. GALL Report AMP XI.M18 

states that bolting material should be limited to an actual measured yield strength of 1,034 MPa 

(150 ksi) and that high-strength closure bolting (regardless of code classification) should be 

subjected to volumetric examination in accordance with that of ASME Code Section XI,

Table IWB-2500-1, Examination Category B-G-1. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M18 and finds it acceptable 

because when it is implemented it will make the program consistent with the recommendations 

in the GALL Report AMP.

Summary. Based on its audit and review of the applicant’s response to RAI B.1.3-1, the staff 

finds that program elements one through six for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report

AMP XI.M18. In addition, the staff reviewed the enhancements associated with the “preventive 

actions” and “detection of aging effects” program elements and finds that when implemented,

the AMP will be adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.3 summarizes operating experience related to the 

Bolting Integrity Program. In one operating experience example, the LRA states that during 

examinations of core spray (CS) sparger bolts in 2005, a tack weld on one bolt was found to be 

cracked. The tack weld is provided to prevent de-tensioning of the bolt. The remaining 

configuration, including another tack weld on this bolt, was found to provide an adequate locking 

mechanism. During the audit, the staff further reviewed this incident, and found that an 

engineering evaluation had been conducted to determine that the necessary torque was still 

maintained, and also found that the inspection interval for the bolt was increased to every 

refueling outage.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI as 

discussed below.

GALL Report AMP XI.M18 manages aging of closure bolting for pressure retaining components. 

The program includes periodic inspection of closure bolting for indication of loss of preload, 

cracking, and loss of material due to corrosion, etc. LRA Section B.1.3 describes an operating 
3-18

experience example in which corrosion was discovered on bolting located in the service water

system basin under approximately 5 feet of water. The flange studs, nuts, and portions of the 

flange were observed to be covered with an iron-colored deposit. When the deposit was 

removed from the studs and nuts on this flange, most of the protective coating was found to be 

deteriorated and there was noticeable metal loss from the studs. However, there were no signs 

of system leakage at this location nor were there any signs of previous leakage. It is not clear to 

the staff how the corrosion described in the LRA was discovered since it would be difficult to 

identify loss of preload, cracking, and loss of material for bolting in a submerged environment 

through system walkdowns and visual indications of leakage, which are the only inspection 

methods used in the applicant’s Bolting Integrity Program. By letter dated April 11, 2012, the 

staff issued RAI B.1.3-2 requesting that the applicant clarify the inspection technique used to 

discover the corrosion identified and to describe the frequency of the inspection for this example 

as well as all other bolting in submerged environments.

In its response dated May 9, 2012, the applicant stated that the operating experience listed in 

LRA B.1.3 was identified during an underwater visual inspection of A and B standby service 

water (SSW) basin bolting that is performed by divers at least once every refueling cycle. The 

applicant also stated that other similar locations were also examined and corrosion was not 

found. The applicant further stated that visual inspections that will detect cracking and loss of 

material in bolting is conducted for submerged bolting at least once every refueling cycle.

The staff finds the applicant’s response acceptable because (1) underwater inspections 

performed by divers will be able to detect corrosion such as loss of material and cracking on 

submerged bolting, and (2) the loss of preload aging effect is primarily managed through the 

proper selection of bolting material, the use of appropriate lubricants, proper torquing, and 

uniform gasket compression. However, the applicant will have the opportunity to look for loose 

or missing nuts and bolts during visual inspections and also identifies it in its AMR tables as 

items that will be age managed by its Bolting Integrity Program. The staff’s concern described 

in RAI B.1.3-2 is resolved.

Based on its audit and review of the application, and review of the applicant’s response to

RAI B.1.3-2, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.3 provides the UFSAR supplement for the Bolting 

Integrity Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 3), to enhance the program prior to 

the period of extended operation to provide guidance to ensure proper specification of bolting 

material, lubricants and sealants, storage, installation torque or tension; prohibit the use of 

lubricants containing molybdenum disulfide; and include volumetric examination for 

high-strength closure bolting regardless of code classification. The staff finds that the 

information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Bolting Integrity Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 3 prior to the period of extended operation will 
3-19

make the AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.3 Boraflex Monitoring

Summary of Technical Information in the Application. LRA Section B.1.4 describes the existing

Boraflex Monitoring Program as consistent, with enhancement, with GALL Report AMP XI.M22, 

“Boraflex Monitoring.” In the LRA the applicant stated that the program “manages the change in 

materials properties (neutron-absorbing capacity) in the Boraflex material affixed to spent fuel 

racks using silica sampling, areal density testing, and other monitoring activities. Inspection 

frequency and acceptance criteria are based on the GGNS response to NRC Generic Letter

(GL) 96-04, ‘Boraflex Degradation in Spent Fuel Pool Storage Racks’ and the GGNS technical 

specifications.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M22. For the “scope of 

program,” “detection of aging effects,” and “monitoring and trending,” program elements, the 

staff determined the need for additional information, which resulted in the issuance of RAIs, as 

discussed below.

The scope of the program element in GALL Report AMP XI.M22 recommends that the scope 

should be the sheets of neutron-absorbing material made of Boraflex affixed to spent fuel racks. 

However, during its audit the staff found that the applicant’s Boraflex Monitoring Program was 

unclear whether the upper containment pool that contains Boraflex was included in the Boraflex 

Monitoring Program. By letter dated June 22, 2012, the staff issued RAI B.1.4-1a requesting 

that the applicant clarify whether the upper containment pool was part of the Boraflex Monitoring 

Program.

In its response dated July 23, 2012, the applicant stated that it is revising the program to include 

the upper containment pool.

The staff finds the applicant’s response acceptable because it was clarified that the upper 

containment pool that contains Boraflex will be managed under the Boraflex Monitoring 

Program. The staff’s concern described in RAI B.1.4-1a is resolved.

The “detection of aging effects” and “monitoring and trending” program elements in 

GALL Report AMP XI.M22 do not recommend the use of the coupon monitoring technique for 

aging management of the Boraflex. They do recommend the use of RACKLIFE or its equivalent 

for monitoring and trending. However, during its audit, the staff found that the applicant’s 

Boraflex Monitoring Program still uses the coupon monitoring technique and was not clear about 

the frequency at which RACKLIFE predictions would be performed. By letter dated 

June 22, 2012, the staff issued RAI B.1.4b and c requesting that the applicant clarify whether 

the applicant would still perform the coupon monitoring technique in the period of extended 

operation and clarify the frequency at which RACKLIFE is being performed.
3-20

In its response dated July 23, 2012, the applicant stated that it would not be relying on the 

coupon monitoring technique in the period of extended operation. In the period of extended 

operation, the applicant will be relying on the RACKLIFE predictions and BADGER testing for 

the Boraflex Monitoring Program. In addition, the applicant would also be performing and 

updating the RACKLIFE model every cycle. The applicant also states that “Updating the 

RACKLIFE model once each cycle is sufficient as the Boraflex degradation is a slowly varying, 

long-term process.”

The staff finds the applicant’s response acceptable because it is not relying on the coupon 

monitoring technique in the period of extended operation and will be relying on the RACKLIFE 

model and BADGER testing. Since the RACKLIFE model will be performed and updated every 

cycle, this provides the staff with reasonable assurance that the degradation of Boraflex will be 

monitored for degradation in the period of extended operation. Although the staff does not 

agree with the applicant’s assertion that Boraflex degradation is always slow, the staff 

recognizes that with the frequencies proposed by the applicant, the degradation will be able to 

be monitored in the period of extended operation. The staff’s concern described in RAI B.1.4-1b 

and c is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” program elements associated with enhancements 

to determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement. LRA Section B.1.4 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In this 

enhancement, the applicant stated that BADGER testing on the Boraflex material will be 

performed at least once every 5 years, RACKLIFE will be performed every cycle, the plant silica 

data results would be compared to the RACKLIFE predicted silica values, and there will be 

projections of the degradation until the next RACKLIFE analysis is performed to ensure that the 

storage locations do not need to be reclassified. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M22 and finds it acceptable 

because when it is implemented it will provide reasonable assurance that the BADGER testing 

and RACKLIFE model will be performed on a frequency consistent with the GALL Report and 

that the applicant will be predicting the degradation between surveillance intervals to ensure that 

the Boraflex will be able to perform its intended function.

Based on its audit of the applicant’s Boraflex Monitoring Program, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M22. In addition, 

the staff reviewed the enhancement and finds that when implemented, it will make the AMP 

adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.4 summarizes operating experience related to the 

Boraflex Monitoring Program. The applicant stated:

[t]he results of spent fuel storage pool neutron transmission testing in 1999 

revealed boraflex gaps in the test area exceeding those assumed in the criticality 

safety analysis. Engineering disposition of these results was used to prohibit 

storage of any fuel in the spent fuel pool boraflex test area.
3-21

In-situ measurement of the boron-10 areal density of the neutron absorber 

material in 2007 identified no immediate actions or concerns for the spent fuel 

pool rack criticality safety analysis, although future limitations on the use of the 

spent fuel pool storage areas were indicated.

The Boraflex Monitoring Program has been effective in identification of conditions 

and program deficiencies. Appropriate corrective actions have been 

implemented. This provides assurance that the program will remain effective for 

managing loss of material. The history of identification of degradation and 

initiation of corrective action prior to loss of intended function provide assurance 

that the program is effective for managing aging effects for passive components.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.4 provides the UFSAR supplement for the Boraflex 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed (Commitment No. 4) to ongoing implementation of 

the existing Boraflex Monitoring Program for managing aging of applicable components during 

the period of extended operation. The staff finds that the information in the UFSAR supplement 

is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Boraflex Monitoring Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed 

that their implementation through Commitment No. 4 prior to the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. The staff concludes that 

the applicant has demonstrated that the effects of aging will be adequately managed so that the 

intended function will be maintained consistent with the CLB for the period of extended 

operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the 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 Buried Piping and Tanks Inspection

Summary of Technical Information in the Application. LRA Section B.1.5 describes the new

Buried Piping and Tanks Inspection Program as consistent with GALL Report AMP XI.M41, 

“Buried and Underground Piping and Tanks.” The LRA states that the AMP addresses buried 
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and underground piping and tanks constructed of any material exposed to soil to manage the 

effects of loss of material from the external surfaces of the component. In its annual update 

letter dated October 25, 2013, the applicant amended its Buried Piping and Tanks Inspection 

Program to address LR-ISG-2011-03, “Changes to the Generic Aging Lessons Learned (GALL) 

Report Revision 2 Aging Management Program (AMP) XI.M41, ‘Buried and Underground Piping 

and Tanks,’” which was issued in its final version on August 2, 2012. In this amendment, the 

applicant stated that the program will be consistent with GALL Report AMP XI.M41, as modified 

by LR-ISG-2011-03.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M41, as modified by 

LR-ISG-2011-03. For the “preventive actions,” “detection of aging effects,” and “acceptance 

criteria” program elements, the staff determined the need for additional information, which 

resulted in the issuance RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.M41 recommends that 

underground piping be age managed by AMP XI.M41. However, during its audit, the staff noted 

that LRA Section B.1.18, External Surfaces Monitoring Program, states an enhancement to its 

“detection of aging effects” program element to include underground components within the 

scope of the External Surfaces Monitoring Program. In addition, during the audit, the staff 

reviewed a partial list of components that appear to be under the scope of the External Surfaces 

Monitoring Program instead of the Buried Piping and Tanks Inspection Program such as the 

residual heat removal (RHR) pump suction barrels, high-pressure core spray (HPCS) pump 

suction barrels, and fuel oil transfer pump discharge stop check valves. By letter dated 

April 16, 2012, the staff issued RAI B.1.5-1 requesting that the applicant provide a list of all 

underground (i.e., below grade but contained within a tunnel or vault such that they are in 

contact with air and are located where access for inspection is restricted) in-scope components, 

state which AMP will be used to manage the aging of these underground in-scope components, 

and if a program other than Buried Piping and Tanks Inspection Program will be used to age 

manage any of the underground components, state which recommendations contained in 

AMP XI.M41 will not be met and provide justification for not meeting those recommendations.

In its response dated May 14, 2012, the applicant stated that:

(a) the RHR pump suction barrels, HPCS pump suction barrels, and fuel oil transfer pump 

discharge stop check valves are the only underground components within the scope of 

license renewal

(b) the components are managed by the External Surfaces Monitoring Program, “because 

they are neither piping nor tanks but are valves and pump columns that don’t fall under 

the scope of the XI.M41, ‘Underground Piping and Tanks Program’”

(c) the components are constructed of carbon steel and are coated

(d) the components will be inspected every 5 years starting 10 years prior to entry into the 

period of extended operation, and

(e) the inspection frequencies and preventive actions meet or exceed the recommendations 

of AMP XI.M41

The staff finds the applicant’s response acceptable because the inspection frequency of every 

5 years starting 10 years prior to the period of extended operation (confirmed by the staff in LRA 
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Section B.1.18, enhancement to the “detection of aging effects” program element) will result in 

more inspections than recommended by AMP XI.M41. Further, the external surfaces of the 

components are coated, and therefore, meet the preventive action recommendations of 

AMP XI.M41. Therefore, the applicant is meeting all applicable underground piping 

recommendations from AMP XI.M41. The staff disagrees with the applicant’s statement in 

relation to the scope of AMP XI.M41 (see (b) above) because Section IX.B of the GALL Report

defines piping, piping components, piping elements, and tanks as, “examples include piping, 

fittings, tubing, flow elements/indicators, demineralizers, nozzles, orifices, flex hoses, pump 

casings and bowls, safe ends, sight glasses, spray heads, strainers, thermowells, and valve 

bodies and bonnets,” and therefore, pump suction barrels and valves are in the scope of GALL 

Report AMP XI.M41. However, in its response (see (a) above), the applicant stated that it will 

manage aging of the external surfaces of all in-scope underground components with either its 

Buried Piping and Tanks Inspection or External Surfaces Monitoring Programs, both of which 

have appropriate preventive actions (i.e., coating), inspection method, and inspection frequency.

The staff’s concern described in RAI B.1.5-1 is resolved.

The “preventive actions” program element in GALL Report AMP XI.M41 recommends that 

coatings are in accordance with Table 1 of NACE SP0169-2007 or Section 3.4 of NACE 

RP0285-2002. However, during its audit, the staff found that a condition report stated that the 

Division II diesel fuel oil storage tank coatings had anomalies. It is not clear to the staff if these 

anomalies result in the coatings not meeting the recommendations of AMP XI.M41, and 

therefore the discrepancy should be justified by the applicant. By letter dated April 16, 2012, the 

staff issued RAI B.1.5-2 requesting that the applicant state whether the coating anomalies 

described in the condition report were corrected, and if not, state whether these anomalies are 

such that the coatings will meet specifications in Section 3.4 of NACE RP0285-2002 or not. If 

the coatings do not meet Section 3.4 of NACE RP0285-2002, state the basis for why there is a 

reasonable assurance that the tanks will meet their CLB function(s) throughout the period of 

extended operation.

In its response dated May 14, 2012, the applicant stated that the anomalies are on the internal 

surfaces of the tank, none of the anomalies are located on the tank bottom where water and 

sludge accumulate. Further, the applicant’s engineering evaluation determined that the 

anomalies were acceptable as-is based on their location and that no loss of wall thickness was 

observed, and a follow-on inspection is scheduled for 2016, which is prior to the period of 

extended operation.

The staff finds the applicant’s response acceptable because the anomalies are located on the 

inside of the tank and therefore not within the scope of AMP XI.M41. The staff noted that even 

though the coating anomalies were reported on the inside surface of the tank and not in the 

scope of AMP XI.M41, the staff finds the applicant’s disposition acceptable because no wall loss 

was noted at the locations, and the applicant’s engineering evaluation has indicated that the 

locations are acceptable. Further, the locations are not susceptible to significant degradation 

due to being above the tank bottom, and a follow-on inspection will occur prior to the period of 

extended operation. The staff’s concern described in RAI B.1.5-2 is resolved.

The “preventive actions” program element in GALL Report AMP XI.M41 recommends that 

protective coatings be provided (stainless steel piping is not required to be coated if soil 

conditions will not degrade the external surfaces of the piping) and backfill be consistent with 

NACE SP0169-2007 and RP0285-2002. However, during its audit, the staff could not verify that 

(a) steel in-scope systems are coated, (b) initial backfill specifications are consistent with 

recommendations in AMP XI.M41, and (c) in-scope stainless steel components were coated, or 
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if they have not been coated, if sufficient soil samples were obtained that demonstrated that the 

soil environment would not result in aging of the external surfaces of the piping. By letter dated 

April 16, 2012, the staff issued RAI B.1.5-4 requesting that the applicant (a) state whether 

buried in-scope steel piping components and tanks are coated and what coating material was 

used, (b) describe the specifications for initial backfill in the vicinity of buried in-scope piping 

components and tanks, and (c) state if buried in-scope stainless steel components are coated

and with what coating material, or if they have not been coated, if sufficient soil samples were 

obtained that demonstrated that the soil environment would not result in aging of the external 

surfaces of the piping. The RAI also requested that—if the stainless steel components are not 

coated and soil sampling results are not available or acceptable—the applicant state the basis 

for why there is a reasonable assurance that the piping will meet its CLB function(s) throughout 

the period of extended operation.

In its response dated May 14, 2012, the applicant stated that (a) buried in-scope steel piping is 

coated with coal tar enamel and tanks are coated with coal tar epoxy, (b) backfill meets a grain 

size range of 0.1 to 5 mm, and no organic perishable or deleterious materials (e.g., roots, snow, 

ice, debris) are permitted, and (c) there are two stainless steel pipe lines that are routed in close 

proximity to each other, neither of which is coated, there is no soil testing data to demonstrate 

that the soil does not contain deleterious compounds that could degrade the stainless steel 

material; and one visual inspection will be conducted in the 10-year period prior to the period of 

extended operation to determine if additional inspections are required.

The staff finds the applicant’s response to parts (a) and (b) above, acceptable because the 

coatings and backfill meet the recommendations of AMP XI.M41. The staff’s concerns

described in RAI B.1.5-4 parts (a) and (b) are resolved. However, the staff did not find the 

response to part (c) acceptable because the stainless steel piping is not coated, no soil sample 

results are available, and despite not meeting the preventive action recommendation of 

AMP XI.M41, no further inspections beyond those recommended in the AMP are proposed. 

Based on this, the staff lacked sufficient information to complete its evaluation of the buried 

uncoated stainless steel piping.

By letter dated July 17, 2012, the staff issued RAI B.1.5-4a requesting that the applicant revise 

the Buried Piping and Tanks Inspection Program to include a method to determine the condition 

of the buried uncoated in-scope stainless steel piping prior to the period of extended operation, 

or include soil testing with possible augmented inspections prior to and during the period of 

extended operation.

In its response dated August 13, 2012, the applicant stated that it will perform soil testing prior 

to the period of extended operation consisting of two samples near the stainless steel piping. 

The samples will be analyzed for soil resistivity, bacteria, pH, moisture, chlorides and redox 

potential. If the soil is determined to be corrosive, the applicant will increase inspections from 

one to two, prior to and during the period of extended operation. The applicant revised LRA 

Section A.1.5, UFSAR Supplement, to reflect the response.

The staff finds the applicant’s response acceptable because:

• Multiple soil samples will be taken to determine soil corrosivity.

• The soil sample parameters are consistent with LR-ISG-2011-03, with the exception of 

sulfate testing.
3-25

• The lack of sulfate testing is acceptable because “Corrosion Resistance of Stainless 

Steels in Soils and in Concrete,” paper presented at the Plenary Days of the Committee 

on the Study of Pipe Corrosion and Protection, Ceocor, Biarritz, October 2001 by 

Pierre-Jean Cunat states, “[c]ompared to the aggressivity of chloride ion levels, 

sulphates are generally considered to be less aggressive. The presence of sulphates 

may pose a risk for some stainless steels in the sense that sulphates can be converted 

to highly corrosive sulphides by anaerobic sulphate reducing bacteria.” Given that the 

applicant will test for bacteria, the likelihood of sulfates causing degradation of the 

stainless steel piping is low.

• If the soil is determined to be corrosive, the number of inspections will be doubled from 

one to two. This is consistent with LR-ISG-2011-03, Table 4a, “Inspections of Buried 

Pipe,” where the inspection quantities are doubled for steel piping when nonconforming 

coatings, adverse plant-specific OE, or unacceptable soil testing results are obtained.

• The applicant updated its UFSAR supplement, thereby ensuring that the augmented 

inspection requirements, if the soil is corrosive, become part of the current licensing 

basis during the period of extended operation.

The staff’s concern described in RAI B.1.5-4a is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M41 recommends 

that buried and underground piping inspection locations are selected based on risk. However, 

during its audit, the staff noted that the applicant’s fleet procedure states that, “[i]n general, 

inspections should be performed at the segments that have the highest risk ranking as 

determined above.” It is not clear to the staff that the “in general” and “should be” modifiers in 

the procedure are consistent with AMP XI.M41 because they could lead to lower risk inspection 

locations being selected based on criteria not presented to the staff. By letter dated 

April 16, 2012, the staff issued RAI B.1.5-5 requesting that the applicant state how the “in 

general” and “should be” modifiers quoted above are consistent with AMP XI.M41, which 

provides no such alternatives.

In its response dated May 14, 2012, the applicant stated that the Buried Piping and Tanks 

Inspection Program is a new program and when procedures are developed, they will be 

consistent with AMP XI.M41. The applicant also stated that, “[t]he intent of the phrases ‘[i]n 

general’ and ‘should be’ in EN-DC-343 was to allow some latitude for not inspecting a location 

with the highest risk ranking if factors such as inaccessibility would preclude an effective 

inspection. In those cases, a segment from the next highest risk category would be inspected.”

The staff reviewed the applicant’s response and noted that GALL Report AMP XI.M41 does not 

provide specific inspection locations when the highest risk-ranked piping is not accessible. The 

staff agrees that there may be cases in which the highest risk-ranked piping is not sufficiently 

accessible to ensure an effective inspection. The staff finds the applicant’s proposal acceptable 

because if the highest risk-ranked piping is not accessible, it will inspect the next highest 

risk-ranked piping and therefore, the selection of piping inspection locations will be biased to the 

highest available risk-ranked locations. The staff’s concern described in RAI B.1.5-5 is 

resolved.

The “acceptance criteria” program element in GALL Report AMP XI.M41 recommends that the 

criteria for pipe-to-soil potential be consistent with NACE SP0169-2007 for which 

paragraph 6.2.2.3.3 states that the use of excessive polarization potential can result in coating 

disbondment. During its audit, the staff reviewed a recent survey report and noted that the test 
3-26

demonstrated that 93 percent of the in-scope buried piping was receiving adequate cathodic 

protection; however, the only acceptance criterion was a 100 mV of cathodic polarization of the 

piping and soil potential. The staff was not able to verify whether the cathodic protection 

criterion the applicant used would not lead to pipe-to-soil potentials more negative 

than -1,200 mV with respect to a saturated copper/copper sulfate reference electrode. In 

addition, given that the in-scope piping is within a mixed metal environment, the staff lacked 

sufficient information to conclude that the singular 100 mV of cathodic polarization criterion is 

sufficient to establish that adequate cathodic protection has been applied. By letter dated 

April 16, 2012, the staff issued RAI B.1.5-6 requesting that the applicant (a) state the maximum 

negative potential that will be accepted for steel and stainless steel buried in-scope 

components, (b) if as-left pipe-to-soil potentials are more negative than -1200 mV with respect 

to a saturated copper/copper sulfate reference electrode, state why there is a reasonable 

assurance that the piping will meet its CLB function(s) throughout the period of extended 

operation, and (c) state the basis for the conclusion that the 100 mV of cathodic polarization 

criterion is sufficient to ensure that the most active buried in-scope piping material has achieved 

a sufficient cathodic polarization for corrosion protection.

In its response dated May 14, 2012, the applicant stated that when the program is implemented, 

a limit of -1,200 mV will be established. The applicant also stated that:

Adequacy of polarization can be indicated by both the 100 mV polarization 

criterion as well as the 850 mV instant “off” polarized criterion. Ohm’s law 

dictates that polarization at the cathode of a CP system circuit must occur, 

although possibly at different levels, simultaneously everywhere in the circuit. 

This means that the potentials measured at the ground surface for both the 

100 mV and the 850 mV criteria are representative of what is taking place at all 

locations on the bare surfaces of the buried piping and structures. Thus, any 

singular 100 mV polarization indication ensures that the most active buried piping 

material has achieved protection, as would be the case for a singular 850 mV 

polarized half-cell reading.

The staff finds the applicant’s response to parts (a) and (b) above acceptable because it will 

establish a -1200 mV limit for cathodic protection. The staff’s concerns described in RAI B.1.5-6 

parts (a) and (b) are resolved. However, the staff did not find the response to part (c) 

acceptable because it was insufficient to demonstrate that the most active (e.g., most anodic) 

buried in-scope piping material has achieved a sufficient polarization level to manage aging of 

the buried components, in that it did not address the mixed metal environment of the buried 

piping.

By letter dated July 17, 2012, the staff issued RAI B.1.5-6a requesting that the applicant state 

why a 100 mV polarization is adequate to protect steel and stainless steel buried components 

when there is a nearby bare wire copper grid and how the testing methodology ensures that the 

steel and stainless steel buried piping has achieved a sufficient level of polarization.

In its response dated August 13, 2012, the applicant cited three bases for the acceptability of 

100 mV polarization criteria. These bases are noted below, as are the staff’s positions on the 

bases. Staff did not agree with the first two bases and lacked sufficient information to complete 

the evaluation of the third.

• In the first basis, the applicant cited NACE Corrosion Engineer’s Reference Handbook 

and stated that since both steel and copper can be cathodically protected by applying a 
3-27

minimum of 100 mV polarization, then, “with the CP system raising the piping and 

grounding grid to an equipotential voltage of 100 mV, galvanic action is nullified.” The

staff reviewed the applicant’s source, “NACE Corrosion Engineer’s Reference Book,” 

Third Edition, Robert Baboian, editor, page 161. A 100 mV of cathodic protection 

polarization between the structure and a reference electrode does not raise the two 

components (i.e., steel piping and copper ground grid) to the same potential, but rather 

would raise each component’s potential relative to the reference electrode to which it is 

being measured. The staff noted that this could still result in the mixed metal free 

corrosion potential remaining in the oxidizing range for the steel piping.

• In the second basis, the applicant again cited the NACE Corrosion Engineer’s Reference 

Handbook and stated that the handbook specifies that a target current density is 

0.1 mA/ft2 to 0.2 mA/ft2

. The applicant also stated that the protected area at the station 

is 22.175 acres and the applied current from the rectifiers is 214.65 amps resulting in an 

average current density of 0.2 mA/ft2

. The staff reviewed page 162 of the reference and 

concluded that the cited target current density represents an approximate current 

requirement for steel piping. The staff believes that this target current density should not 

be considered as an acceptance criteria for cathodic protection because it does not 

address localized conditions and it could be met by buried components with degraded 

coatings, which result in greater current demand.

• In the third basis, the applicant stated that if buried steel components and the bare wire 

copper grounding grids were in close proximity or mixed metal couples were occurring, a 

plot of the native potential data would show a mean of 350 mV. The mean at the site is 

427 mV. The staff could not locate the source of the 350 mV criterion, and therefore, 

could not accept this basis.

The applicant also stated that area potential earth current (APEC) surveys would ensure that an 

adequate level of polarization would be achieved for buried steel and stainless steel 

components. The APEC survey defines significantly active corrosion cells, determines the plant 

piping coating condition, and evaluates the performance of all influencing CP systems from a 

detailed graphical representation. The staff noted that an APEC survey is usually conducted as 

a combination of close interval survey and direct current voltage gradient surveys. While the 

staff agrees that APEC surveys can provide information related to localized potentials and 

current flow, did not agree that use of the 100 mV minimum polarization coupled with APEC 

surveys is sufficient to demonstrate adequate cathodic protection, without the use of buried 

corrosion test coupons, because there is the potential for the survey technique to be affected by 

other buried components or structures.

By letter dated September 14, 2012, the staff issued RAI B.1.5-6b requesting that the applicant 

(a) provide the source documents which establish the basis for the mean 350 mV criterion,

(b) submit the complete last APEC survey report and, if APEC surveys will be used to confirm 

the effectiveness of the 100 mV polarization criterion, revise the Buried Piping and Tanks 

Inspection Program and UFSAR supplement to reflect its use, (c) state what methods will be 

used to confirm the results of the APEC surveys and revise the Buried Piping and Tanks 

Inspection Program and UFSAR supplement to reflect the use of this method, and (d) state what 

actions will be taken if the alternative method utilized to confirm the APEC surveys indicates that 

corrosion of in-scope buried components is occurring more rapidly than expected.

In its response dated October 15, 2012, the applicant stated that its program will be consistent 

with NACE SP0169 and the 100 mV criterion will not be used in lieu of the -850 mV criterion. 

The staff finds the applicant’s response acceptable because the use of the -850mV criterion is 
3-28

consistent with Table 6a, “Cathodic Protection Acceptance Criteria,” of LR-ISG-2011-03, the 

current staff position on cathodic protection acceptance criteria. Given this change in 

acceptance criteria, the applicant does not need to respond to the specific questions in 

RAI B.1.5-6b. The staff’s concerns described in RAIs B.1.5-6a and B.1.5-6b are resolved.

Based on its audit, review of the applicant’s responses to RAIs B.1.5-1, B.1.5-2, B.1.5-4, 

B.1.5-4a, B.1.5-5, B.1.5-6, B.1.5-6a, and B.1.5-6b, and review of the amended program 

submitted by letter dated October 25, 2013, the staff finds that the program elements for which 

the applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M41, as modified by LR-ISG-2011-03.

Operating Experience. LRA Section B.1.5 summarizes operating experience related to the 

Buried Piping and Tanks Inspection Program. The applicant stated that an area potential earth 

current survey was performed before installation of a new cathodic protection system in 

December 2009. The survey did not find any degraded conditions; however, two areas were 

noted to have a higher potential for coating degradation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification, and resulted in the issuance of RAI B.1.5-3, as 

discussed below in UFSAR supplement.

Based on its audit and review of the application, and review of the applicant’s response to

RAI B.1.5-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.5 provides the UFSAR supplement for the Buried Piping 

and Tanks Inspection Program.

The staff reviewed this UFSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0-1 and 

noted that the licensing basis for this program for the period of extended operation may not be 

adequate if the applicant does not incorporate information related to operation of the cathodic 

protections system into its UFSAR supplement.

The “preventive actions” and “monitoring and trending” program elements in GALL Report 

AMP XI.M41 recommend that a cathodic protection system be installed, monitored, annually 

tested, and potential differences and current measurements be trended to identify changes in 

the effectiveness of the system. However, during its audit, the staff identified six condition 

reports spanning 2006 through 2011 citing significant gaps in cathodic protection system 

performance. The plant-specific operating experience is not consistent with the AMP XI.M41 

recommendations because it demonstrates a long period of inadequate performance of the 

cathodic protection system; therefore, cathodic protection may not be consistent with

AMP XI.M41. By letter dated April 16, 2012, the staff issued RAI B.1.5-3 requesting that the 
3-29

applicant modify its UFSAR supplement to include the availability of the cathodic protection 

system, monitoring frequency for effectiveness, and trending parameters, or justify its exclusion.

In its response dated May 14, 2012, the applicant revised LRA Section A.1.5 to include the 

following statement: “cathodic protection is used for additional protection of buried piping and 

tanks. The cathodic protection system is monitored and trended annually in accordance with 

NACE standards SP-0169 and RP-0285.”

The staff finds the applicant’s response acceptable because the applicant’s UFSAR supplement 

now includes utilization of a cathodic protection system and its monitoring and trending during 

annual surveys conducted in accordance with the NACE standards recommended in 

AMP XI.M41. The staff’s concern described in RAI B.1.5-3 is resolved.

As amended by letter dated October 25, 2013, the applicant revised the UFSAR supplement to 

include a statement that preventive and mitigative actions include selection of materials, 

coatings, backfill quality, and cathodic protection. The staff finds this change acceptable 

because these preventive and mitigative actions are consistent with GALL Report AMP XI.M41 

as modified by LR-ISG-2011-03.

The staff also noted that the applicant committed (Commitment No. 5) to implement the new 

Buried Piping and Tanks Inspection Program prior to entering the period of extended operation 

for managing aging of applicable components. The staff finds that the information in the UFSAR 

supplement, as amended by letter dated October 25, 2013, is an adequate summary description 

of the program.

Conclusion. On the basis of its audit and review of the applicant’s Buried Piping and Tanks 

Inspection Program, the staff concludes that the program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M41, as modified by LR-ISG-2011-03. 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).

3.0.3.1.5 BWR CRD Return Line Nozzle

Summary of Technical Information in the Application. LRA Section B.1.6 describes the existing 

BWR Control Rod Drive (CRD) Return Line Nozzle Program as consistent, with enhancement,

with GALL Report AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle.”

The LRA states that the program manages cracking of the CRD return line nozzle using 

preventive, mitigative, and inservice inspection (ISI) activities, in accordance with the applicant’s 

commitments to GL 80-095, to implement the recommendations in NUREG-0619, “BWR 

Feedwater Nozzle and Control Rod Driven Return Line Nozzle Cracking,” issued 

November 1980.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M6. For the applicant’s “scope 

of program,” “parameters monitored or inspected,” “detection of aging effects,” “monitoring and 

trending,” and “acceptance criteria” program elements, the staff determined the need for 

additional information, which resulted in the issuance of an RAI, as discussed below.
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GALL Report AMP XI.M6, “BWR Control Rod Drive Return Line Nozzle,” states that this 

program is a condition monitoring program based on the staff’s recommended position in 

NUREG-0619 for thermal fatigue and the program is also intended to address SCC discussed in 

NRC Information Notice (IN) 2004-08, “Reactor Coolant Pressure Boundary Leakage 

Attributable to Propagation of Cracking in Reactor Vessel Nozzle Welds.” IN 2004-08 

addresses cracking due to SCC of capped CRD return lines. In addition, the GALL Report AMP 

“parameters monitored or inspected” program element also states that the AMP manages the 

effects of cracking on the intended function of the RV, the CRD return line nozzle, and for 

capped nozzles, the capped nozzle caps, and nozzle-to-cap welds. The GALL Report AMP 

further states that using the volumetric examinations (UT) that are performed in accordance with 

this AMP, the AMP monitors and evaluates signals that may indicate the presence of a planar 

flaw (crack). During its audit, the staff noted that the applicant’s CRD return line is capped and 

its current ISI plan includes the CRD return line nozzle in its scope and sample population for 

the ISI.

During the audit, the staff noted that the applicant’s current ISI plan does not have a specific 

inspection schedule for the CRD return line, which indicates that the CRD return line has not 

been selected for inspection during the current inspection interval. Therefore, the staff required 

additional information related to the lack of a specific inspection schedule for this component 

because it does not ensure adequate detection and management of cracking due to SCC of the 

CRD return line.

By letter dated April 3, 2012, the staff issued RAI B.1.6-1 requesting that the applicant provide 

additional information on the size, material, number of associated welds, and configuration of 

the applicant’s CRD line. The staff also requested clarification as to how the applicant’s boiling 

water reactor (BWR) Control Rod Drive Return Line Nozzle Program is consistent with the 

GALL Report AMP, given that the current ISI plan does not contain a specific inspection 

schedule for the CRD return line. In addition, the staff requested that the applicant clarify if the 

CRD return line nozzle-to-cap welds will be examined before or during the period of extended 

operation. Alternatively, in consideration of the industry experience of SCC described in NRC 

IN 2004-08, the staff requested that the applicant provide justification as to why it is not 

necessary to examine the CRD return line nozzle-to-cap welds to detect and manage cracking 

due to SCC.

In its response dated May 1, 2012, the applicant stated that the 3.5-inch outside diameter CRD 

return nozzle-to-cap weld to the carbon steel safe end is Inconel filler material with Alloy 182 

butter weld, and the cap material is Inconel 600. The applicant also stated that no recordable 

flaw indications were observed during ultrasonic examination performed in 2004 on its CRD 

return line nozzle-to-cap dissimilar metal (DM) weld. The applicant also stated that an 

enhancement would be added to the program to inspect the CRD return line nozzle weld once 

before the period of extended operation and every 10 years thereafter so that the integrity of the 

CRD return line nozzle-to-cap weld can be ensured for the period of extended operation.

The staff finds the applicant’s response acceptable because the applicant performed ultrasonic 

examination in 2004, which confirmed that there was no recordable flaw observed on the 

nozzle-to-cap dissimilar weld. Since the materials of construction for its nozzle-to-cap dissimilar 

weld may be susceptible to SCC, the applicant has appropriately enhanced the program to 

ensure that inspections will continue to be performed to verify that the preventive actions will 

continue to be effective during the period of extended operation. In addition, continued 

inspection will provide adequate assurance that SCC will be detected before loss of intended 

function during the period of extended operation. Therefore, the staff’s concern discussed in
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RAI B.1.6-1 is resolved. The evaluation of the applicant’s enhancement is discussed in the 

section for the enhancement.

Enhancement. By letter dated May 1, 2012, the applicant amended the LRA and identified an 

enhancement that inspections will be performed on the CRD return line nozzle-to-cap DM weld, 

once before the period of extended operation, and every 10 years thereafter. The applicant also 

revised LRA Section A.1.6 (UFSAR supplement) and LRA Section B.1.6 to reflect the 

enhancement, and identified the enhancement as Commitment No. 32.

The staff finds the applicant’s enhancement acceptable because it is consistent with 

GALL Report AMP XI.M6, and will address potential cracking of DM welds for the capped CRD 

return lines due to SCC, which is discussed in NRC IN 2004-08.

Summary. Based on its audit, and review of the applicant’s response to RAI B.1.6-1, the staff 

finds that elements one through six of the applicant’s program, with the enhancement, are 

consistent with the corresponding program elements of GALL Report AMP XI.M6, and therefore, 

acceptable. In addition, the staff reviewed the enhancement associated with the “detection of 

aging effects” program element and finds when implemented, it will enable the AMP to 

adequately manage the applicable aging effects.

Operating Experience. LRA Section B.1.6 summarizes operating experience related to the 

BWR CRD Return Line Nozzle Program. The applicant stated that ultrasonic examinations 

performed in 2004 on the return line nozzle-to-cap dissimilar weld metal did not reveal any crack 

indication. The applicant also stated that the absence of aging effects indicates that the 

preventive actions of the program have been effective.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.6 provides the UFSAR supplement for the BWR Control 

Rod Drive Return Line Nozzle Program. The staff reviewed the UFSAR supplement description 

of the program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0-1.

The staff also noted that the applicant committed (Commitment No. 32) to include inspection of 

the CRD return line nozzle end cap to carbon steel safe end DM weld once prior to the period of 

extended operation and every 10 years thereafter. The staff finds the information in the UFSAR 

supplement, as amended by letter dated May 1, 2012, is an adequate summary description of 

the program.
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Conclusion. On the basis of its audit and review of the applicant’s BWR Control Rod Drive 

Return Line Nozzle Program, the staff concludes that those program elements for which the 

applicant claimed consistency with the GALL Report are consistent. In addition, the staff 

reviewed the enhancement and confirmed that its implementation through Commitment No. 32 

prior to the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. 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).

3.0.3.1.6 BWR Feedwater Nozzle

Summary of Technical Information in the Application. Section B.1.7 describes the existing BWR 

Feedwater Nozzle Program as consistent with GALL Report AMP XI.M5, “BWR Feedwater 

Nozzle.” The program is designed to ensure that aging degradation due to cracking is 

adequately managed for the nozzle components, so that its intended function is maintained 

through the end of the period of extended operation.

The applicant stated that its BWR Feedwater Nozzle Program consists of ISI in accordance with 

the requirements of the American Society of Mechanical Engineers (ASME) Code, Section XI, 

Subsection IWB, and the recommendations of General Electric (GE) NE-523-A71-0594-A. The 

program specifies periodic ultrasonic inspection of critical regions of the FW nozzles.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M5.

In particular, the staff confirmed that the AMP addresses the detection and sizing of cracks by 

ISIs in accordance with ASME Code, Section XI, Subsection IWB. The staff also confirmed that 

the inspection schedule is in accordance with Table 6-1 of the GE-NE-523-A71-0594-A, 

Revision 1, consistent with the recommendation of GALL Report AMP XI.M5. In addition, it was 

confirmed that the AMP requires that any repair or replacement activities be implemented in 

accordance with the guidelines of the ASME Code, Section XI, IWA-4000.

Based on its audit of the applicant’s BWR Feedwater Nozzle, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M5.

Operating Experience. LRA Section B.1.7 summarizes operating experience related to the 

BWR Feedwater Nozzle Program. Indication was detected in 1995 and analysis of the 

ultrasonic examination data was performed and found to be acceptable. The applicant also 

stated that all six FW nozzle blend radii as well as two nozzle-to-safe end welds were inspected 

in 1998 and 2002, and no indications were recorded.

The staff reviewed operating experience information in the application and during the audit, to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 
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applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.7 provides the UFSAR supplement for the BWR 

Feedwater Nozzle. The staff reviewed this UFSAR supplement description of the program and 

noted that the program augments the examinations specified in the ASME Code Section XI, with 

the recommendation of GE NE-523-A71-0594, rather than GE-NE-523-A71-0594, Revision 1, 

which is the revision recommended in GALL Report AMP XI.M5.

By letter dated April 3, 2012, the staff issued RAI B.1.7-1 requesting that the applicant include 

the correct revision of the GE report in its UFSAR supplement for this program. In its response 

dated May 1, 2012, the applicant revised LRA Section A.1.7 to state that the program is based 

on the guidelines of GE NE-523-A71-0594, Revision 1. The staff finds the applicant’s response 

acceptable because the description of the BWR Feedwater Nozzle Program in the UFSAR 

supplement includes the correct version of the GE report, which will ensure the licensing basis 

will be adequately maintained during the period of extended operation. The staff’s concern 

described in RAI B.1.7-1 is resolved. The staff finds that the information in the UFSAR 

supplement, as amended by letter dated May 1, 2012, is an adequate summary description of 

the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Feedwater Nozzle 

AMP, the staff concludes 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).

3.0.3.1.7 BWR Penetrations

Summary of Technical Information in the Application. LRA Section B.1.8 describes the existing 

BWR Penetrations Program as consistent, with enhancement, with GALL Report AMP XI.M8, 

“BWR Penetrations.” The LRA states that the BWR Penetrations Program is an existing 

program that manages cracking of BWR vessel penetrations using inspection and flaw 

evaluation activities. The LRA states that applicable industry standards and staff-approved 

Boiling Water Reactor Vessel and Internals Project (BWRVIP) documents are used to manage 

cracking of the RV penetrations.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M8, “BWR Penetrations.” For 

the “parameters monitored or inspected” and “scope of program” program elements, the staff 

determined the need for additional information, which resulted in the issuance of RAIs as 

discussed below.
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The “parameters monitored or inspected” program element of GALL Report AMP XI.M8, “BWR 

Penetrations,” states that the program manages the effects of cracking due to SCC and 

intergranular stress-corrosion cracking (IGSCC) on the intended function of the BWR 

instrumentation nozzles, CRD housing, and in-core monitoring housing (ICMH) penetrations, 

and BWR standby liquid control (SLC) nozzles/Core ΔP nozzles. The GALL Report also states 

that the program accomplishes this by inspection for cracks in accordance with the guidelines of 

approved BWRVIP-49-A, BWRVIP-47-A, or BWRVIP-27-A and the requirements of the ASME 

Code, Section XI, Table IWB 2500-1.

In addition, Section 3.2.5, “Other Inspections,” in BWRVIP-47-A indicates that the BWRVIP has 

determined that removing or dismantling of internal components for the purpose of performing 

inspections is not warranted to assure safe operation; however, on occasion, utilities may have 

access to the lower plenum due to maintenance activities not part of normal refueling outage 

activities. BWRVIP-47-A further states that in such cases, utilities will perform a visual 

inspection to the extent practical for implementation of the examinations.

During the audit, the staff noted that the site documentation for the BWR Penetrations Program 

indicated that the baseline inspections for the CRD housing do not require access to the lower 

plenum area and that currently no additional inspections are recommended beyond the baseline 

inspections. In addition, the staff noted that the site documentation indicated that, if access is 

gained to the lower plenum (areas below the core plate), the accessible areas of the in-core flux 

monitor housing, guide tubes and guide tube stabilizer should be inspected using a visual VT-3 

inspection method. However, it was not clear to the staff whether the additional VT-3 

inspections would be applied to the monitoring of in-core flux monitoring housing penetrations.

By letter dated April 3, 2012, the staff issued RAI B.1.8-1 requesting that the applicant provide 

information on whether the lower plenum housings and penetrations would be accessible during 

maintenance activities that are scheduled outside of normal refueling outage maintenance 

activities. The staff also requested that the applicant justify why the BWR Penetrations Program 

does not include the additional inspections of the CRD housings and housing penetrations 

(including stub tubes) described in Section 3.2.5 of BWRVIP-47-A. In addition, the staff 

requested that the applicant clarify if the additional inspections are applied to the in-core flux 

monitoring housing penetrations.

In its response dated May 1, 2012, the applicant stated that the lower plenum housings and 

penetrations are not accessible during maintenance activities associated with a normal refueling 

outage, and there currently are no scheduled maintenance activities that will provide access to 

the lower plenum. The applicant also clarified that if the lower plenum housing and penetration 

area were to become accessible, Section 3.2.5 guidelines of BWRVIP-47-A for the inspections 

would be followed.

The applicant further clarified that, as stated in license renewal project documents, the BWR 

Penetrations Program manages cracking on the BWR instrumentation penetrations, CRD 

housing and ICMH penetrations, and BWR SLC nozzles/core ΔP nozzles using applicable 

ASME Section XI inspection and flaw evaluation, as required in accordance with 10 CFR 50.55a 

and applicable requirements in ASME Section XI, Table IWB-2500-1. These methods are 

discussed in the staff-approved BWRVIP-49-A, BWRVIP-47-A, and BWRVIP-27-A reports. In 

addition, the applicant stated that it has not taken any exception to the guidance in Section 3.2.5 

and as such will perform all applicable actions.
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The applicant also stated that the LRA indicates consistency of the BWR Penetrations Program 

with the methodology in the NRC-approved BWRVIP-47-A report; therefore, the AMP does not 

require any changes or modifications of its program elements. The applicant further stated that, 

as such, the program will perform the applicable inspections recommended in the 

BWRVIP-47-A report and are required to be implemented in accordance with ASME Code 

Section XI. The applicant stated that these inspections include inspections of the CRD 

housings and penetrations.

The applicant also indicated that the site procedures, which implement the guidelines of 

BWRVIP-47-A, will be modified to provide additional clarification on the use of BWRVIP-47-A 

guidance for the inspections of the RV penetrations. In addition, the applicant’s response 

identifies that an enhancement to the “parameters monitored or inspected” program element is 

needed based on its response to RAI B.1.8-1. The applicant stated that, under this 

enhancement, the applicant committed to enhancing the site procedures to clearly indicate that 

the BWRVIP-47-A guidelines will be applied without exceptions. The staff’s evaluation of this 

enhancement is further described in the evaluation section for the enhancement.

Based on this review, the staff finds the applicant’s response acceptable because the staff has 

confirmed that the applicant’s BWR Penetrations Program is consistent with the BWRVIP 

documents referenced in GALL Report AMP XI.M8, including the guidance in Section 3.2.5 of 

BWRVIP-47-A. The staff’s concern described in RAI B.1.8-1 is resolved.

The staff noted that LRA Table 3.1.2-1 addresses the applicant’s aging management of the RV, 

including RV nozzles and penetrations. The staff also noted that LRA Table 3.1.2-1 includes

Table 2 AMR items that credit the BWR Vessel Internals Program and Water Chemistry Control 

– BWR Program to manage cracking due to SCC, IGSCC, and cyclic loading in the CRD 

housing penetrations and in-core housing penetrations. The applicant’s AMR items are linked 

to LRA items 3.1.1-102 and 3.1.1-98, which are given in LRA Table 3.1.1.

The staff noted that the GALL-recommended scope of the BWR Penetrations Program and 

GALL Report Item IV.A1.RP-369 indicate that the BWR Penetrations Program and Water 

Chemistry Program should be used to manage cracking of these RV penetrations during the 

period of extended operation. Therefore, the staff noted that the applicant’s AMR results for 

cracking of the CRD housing penetrations and in-core housing penetrations were not consistent 

with the scope of GALL Report AMP XI.M8, “BWR Penetrations Program,” or with the AMR 

recommendations in GALL Report AMR Item IV.A1.RP-369.

By letter dated July 23, 2012, the staff issued RAI B.1.8-4 requesting that the applicant justify 

why cracking due to SCC, IGSCC and cyclic loading of the CRD housing penetrations and 

in-core housing penetrations is managed by the BWR Vessel Internals Program and Water 

Chemistry Control – BWR Program.

In its response dated August 15, 2012, the applicant stated inspection guidance for the CRD 

housings and in-core housings is provided in BWRVIP-47-A, “BWR Lower Plenum Inspection 

and Flaw Evaluation Guidelines,” and for the purposes of comparisons to the GALL Report, the 

BWR Penetrations Program described in GALL Report AMP XI.M8, which references 

BWRVIP-47-A, better represents the AMP requirements. In its response, the applicant also 

provided revisions to LRA Table 3.1.2-1 and LRA Table 3.1.1, item 3.1.1-98, to identify that the 

BWR Penetrations and Water Chemistry Control - BWR Programs manage cracking of the CRD 

housing penetrations and in-core housing penetrations, consistent with the GALL Report.
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The staff finds the applicant’s response acceptable because its revisions to the LRA are 

consistent with the GALL Report, which recommends the BWR Penetration Program in 

conjunction with the Water Chemistry Program to manage cracking of the CRD and in-core 

housing penetrations. The staff also finds that the BWR Penetrations Program includes the 

examinations specified in the BWRVIP-47-A and ASME Code Section XI, which are adequate to 

detect and manage cracking of these RV penetrations. The staff’s concern described in

RAI B.1.8-4 is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected” program 

element associated with an enhancement to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of this enhancement 

follows.

Enhancement. By letter dated May 1, 2012, the applicant provided its response to RAI B.1.8-1 

and amended LRA Sections A.1.8 (UFSAR supplement) and B.1.8 to include an enhancement 

of the “parameters monitored or inspected” program element for the BWR Penetration Program. 

The applicant also identified this enhancement as Commitment No. 33. In this enhancement, 

the applicant stated that site procedures, which implement the guidelines of BWRVIP-47-A, will 

be clarified to indicate that the guidelines of BWRVIP-47-A will be applied as the basis for the 

program without exception. The applicant also stated that the enhancement will be 

implemented prior to the period of extended operation.

In its review, the staff finds that the applicant’s program is consistent with GALL Report 

AMP XI.M8. In addition, the applicant’s enhancement will clearly indicate that the site 

procedures are consistent with the guidelines of Section 3.2.5, “Other Inspections,” in 

BWRVIP-47-A as referenced in the GALL Report. The staff also confirmed that the applicant 

has included this enhancement in UFSAR supplement Section A.1.8 of the LRA, “BWR 

Penetrations,” as amended in the applicant’s letter, dated May 1, 2012.

The staff reviewed the applicant’s BWR Penetrations Program, as subject to the applicant’s 

enhancement of the procedure that will be implemented by this program, against the

corresponding program element in GALL Report AMP XI.M8, “BWR Penetrations.” Based on 

this review, the staff finds that the enhancement is acceptable because the staff has confirmed 

the program is consistent with the GALL Report and the implementation of the enhancement will 

clearly indicate that the site procedures for the program are consistent with the recommended 

inspection and evaluation guidelines in BWRVIP-47-A.

Summary. Based on its audit, and review of the applicant’s responses to RAIs, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M8. In addition, the staff reviewed the enhancement associated with the “parameters 

monitored or inspected” program element and finds that when implemented, it will make the 

AMP adequate to manage the applicable aging effects.

Review of License Renewal Applicant Action Items. The staff’s safety evaluation (SE), dated 

September 1, 1999, for BWRVIP-49, “BWR Vessel and Internals Project, Instrument Penetration 

Inspection and Flaw Evaluation Guidelines,” addresses three license renewal applicant action 

items (AAIs). In addition, the staff’s SE, dated December 7, 2000, identifies four applicant

renewal AAIs for BWRVIP-47, “BWR Vessel and Internals Project, BWR Lower Plenum 

Inspection and Flaw Evaluation Guidelines (BWRVIP-47).” Furthermore, the staff’s SE, dated 

December 20, 1999, identifies four applicant renewal action items for BWRVIP-27, “BWR 
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Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate ΔP Inspection 

and Flaw Evaluation Guidelines (BWRVIP-27).”

Of these AAIs, three of them are common to the BWRVIP-27-A, BWRVIP-47-A, and 

BWRVIP-49 reports. The fourth action item in this evaluation is specific to the methodology in 

the BWRVIP-47-A report and the fifth action item in this evaluation is specific to the 

methodology in the BWRVIP-27-A report.

The applicant provided its responses to these AAIs in LRA Appendix C. The staff’s evaluation 

of the applicant’s responses to these AAIs is described in the paragraphs that follow.

The staff noted that AAI No. 1 states that the license renewal applicant is to verify that its plant 

is bounded by the BWRVIP reports and the applicant is to commit to programs described as 

necessary in the BWRVIP reports to manage the effects of aging during the period of extended 

operation. In its response to AAI No. 1, the applicant stated that the BWRVIP reports have 

been reviewed and GGNS has been confirmed to be bounded by the BWRVIP reports. The 

applicant also committed to programs described as necessary in the BWRVIP reports to 

manage the effects of aging during the period of extended operation. The applicant further 

stated that the implementation of these commitments is administratively controlled in 

accordance with the requirements of 10 CFR Part 50, Appendix B.

In its review, the staff finds that the applicant has adequately addressed AAI No. 1 because: 

(a) the applicant confirmed that its program is bounded by the BWRVIP reports, (b) the staff 

also found that the BWR Penetrations Program is an existing program that is both being 

implemented during the current operating period and will be implemented during the period of 

extended operation, and (c) the staff has confirmed that the BWR Penetration Program with the 

enhancement is consistent with the program elements recommended in GALL Report

AMP XI.M8.

The staff noted that AAI No. 2 states that the applicant for license renewal, referencing the 

applicable BWRVIP reports, shall ensure that the programs and activities specified as 

necessary in the applicable BWRVIP reports are summarized in the UFSAR supplement. In its 

response to AAI No. 2, the applicant stated that the UFSAR supplement for the BWR 

Penetrations Program is included in LRA Appendix A and includes a summary of the programs 

and activities specified as necessary for the BWR Penetrations Program. The staff confirmed

that the applicant has included its UFSAR supplement for the BWR Penetrations Program in 

LRA Appendix A, Section A.1.8. The staff also evaluated the adequacy of the applicant’s 

UFSAR supplement for the BWR Penetrations Program as described in the evaluation section 

for the UFSAR supplement. The evaluation includes the staff’s review and approval of

RAIs B.1.8-2 and B.1.8-2a regarding LRA Section A.1.8 (UFSAR supplement).

The staff noted that AAI No. 3 states that if the TS changes or additions result from the 

implementation of the BWRVIP reports, the applicant must ensure that those changes are 

included in its application for license renewal. In its response to AAI No. 3, the applicant 

indicated that it did not identify any TS that would need to be changed as a result of its 

implementation of the guidelines in BWRVIP-27-A, BWRVIP-47-A, and BWRVIP-49 reports. 

The staff reviewed the current set of TS for the facility and confirmed that the TS did not include 

any TS requirements based on the applicant’s implementation of the inspection and flaw 

evaluation protocols recommended in BWRVIP-27-A, BWRVIP-47-A, and BWRVIP-49 reports.
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The staff noted that the applicant implements these inspection and flaw evaluation protocols 

through the NEI 03-08, “Guideline for the Management of Materials Issues,” augmented 

inspection and evaluation process for addressing potential material degradation issues that may 

occur at the facility. Thus, the staff confirmed that the LRA would not need to generate any 

additional TS changes relative to the implementation of the recommended protocols in these 

BWRVIP reports. Therefore, the staff finds that the applicant has adequately addressed 

AAI No. 3 because the staff has confirmed that the LRA does not need to identify any changes 

of the existing set of TS in the CLB and does not need to generate any new TS for the facility 

based on the applicant’s BWRVIP-based augmented inspection program for the RV

penetrations at the facility.

The staff noted that AAI No. 4 specific to BWRVIP-47 states that due to fatigue of the subject 

safety-related components, the applicant referencing the BWRVIP-47 report for license renewal 

should identify and evaluate the projected cumulative usage factor as a potential time-limited 

aging analysis (TLAA) issue. In its response to AAI No. 4 specific to BWRVIP-47, the LRA 

indicates that the applicant evaluated its CLB to identify potential TLAAs for the components in 

the lower plenum area of the RV. The applicant also identified that the only cumulative usage 

factor (CUF)-based TLAAs applicable to RV lower plenum area penetration nozzles are those 

identified in LRA Section 4.3.1.1 for fatigue TLAAs.

The staff confirmed that the applicant provided the fatigue TLAAs for the CRD and in-core 

housing penetrations that need to be evaluated in accordance with the recommendation in 

BWRVIP-47-A. Based on this review, the staff finds that the applicant adequately addressed 

AAI No. 4 on the BWRVIP-47-A report because the staff confirmed that: (a) the applicant 

included the relevant fatigue TLAAs in the LRA that are applicable to penetration nozzles that 

are joined to the RV lower plenum area, and (b) LRA Section 4.3.1.1 and Table 4.3-2 describe 

the applicant’s CUF-based TLAAs for the CRD and in-core housing penetrations, which are 

included within the scope of the applicant’s BWR Penetrations Program.

The staff noted that AAI No. 4 specific to BWRVIP-27 states that due to the susceptibility of the 

subject components to fatigue, the applicant referencing the BWRVIP-27 report for license 

renewal should identify and evaluate the projected fatigue CUFs as a potential TLAA issue. In 

its response to AAI No. 4 specific to BWRVIP-27, the applicant stated that the fatigue analysis 

of the SLC/core ΔP line for 60 years of operation is a potential TLAA. The applicant also stated 

that at GGNS, the CS assembly provides the flow path for injection of boron for the SLC system. 

The applicant further stated that the SLC/core ΔP lines inside the RV have no license 

renewal-intended function and are not subject to an AMR. In addition, the applicant stated that 

there are not any TLAAs applicable to the CLB for the SLC/core ΔP lines at GGNS.

During the audit, the staff noted that the site documentation for the RV internals (RVI) program 

and inspection plan indicates that the design for the SLC/core ΔP penetration utilizes an 

Alloy 600 stub tube that is set into the bottom head and welded to an Alloy 600 housing. The 

staff also noted that the SLC/core ΔP nozzle and safe-end assembly form the reactor coolant 

pressure boundary (RCPB). In addition, the staff noted that LRA Table 4.3-2, “Cumulative 

Usage Factors for the Reactor Vessel,” includes a 40-year CUF for the SLC/core ΔP nozzle. 

Therefore, it was not clear to the staff why the CLB would not include an appropriate 

fatigue-based (i.e., CUF-based) TLAA that is applicable to the SLC/core ΔP penetration nozzle.

By letter dated April 3, 2012, the staff issued RAI B.1.8-3 requesting that the applicant provide 

additional information to clarify why the response to AAI No. 4 on the BWRVIP-27-A 

methodology did not identify any fatigue TLAA for the SLC/core ΔP nozzle. Specifically, the 
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staff asked the applicant to resolve the conflict between the applicant’s inclusion of the “liquid 

control- ΔP nozzle” in LRA Table 4.3-2 and the applicant’s statement that the CLB did not 

include any CUF-based TLAA for the SLC/core ΔP nozzle. The staff further requested that the 

applicant clarify which component is specifically referred to by the “liquid control- ΔP nozzle”

among the SLC/core ΔP penetration/nozzle and safe-end assembly. In addition, the applicant 

was requested to justify why the “liquid control-ΔP nozzle” is the representative component of 

the SLC/core ΔP penetration/nozzle and safe-end assembly for the fatigue TLAA.

In its response dated May 1, 2012, the applicant clarified that the ASME Code Class 1 RCPB for 

a BWR/6 Chicago Bridge and Iron Company-designed RV includes a stub tube that is set and 

welded into the RV bottom head at one end and is welded to a pressure boundary housing at its 

other end. The applicant further clarified that it is the nozzle that is identified as the “Liquid 

control-ΔP nozzle” vessel nozzle in LRA Table 4.3-2. The applicant also stated that the CUF 

value reported in LRA Table 4.3-2 for this nozzle represents the maximum (limiting) CUF that 

was identified for the nozzle assembly. The applicant further clarified that the applicant’s SLC 

system injects through the CS system.

Based on this review, the staff finds that the applicant has adequately addressed AAI No. 4 on 

the BWRVIP-27-A methodology because the applicant confirmed that the applicant’s SLC 

system injects through the CS system so that the SLC/core ΔP lines inside the reactor vessel do 

not have the function of distributing the SLC fluid. In addition, the applicant has appropriately 

identified a CUF-based TLAA for the core ΔP nozzle assembly as part of the reactor pressure 

vessel. The staff’s evaluation regarding the fatigue TLAA of the reactor pressure vessel, which 

includes the core ΔP nozzle, is documented in Section 4.3.1.1. The staff’s concern described in

RAI B.1.8-3 is resolved.

Operating Experience. LRA Section B.1.8 summarizes operating experience related to the 

BWR Penetrations Program. The LRA states that visual inspections of the instrument 

penetrations and extensions were performed during 1996 to 2006 with no indications of 

degradation noted. The LRA also states that absence of aging effects indicates that the 

preventive actions of the program have been effective. The LRA further states that the BWR 

Penetrations Program detects aging effects using nondestructive examination (NDE) techniques 

to detect and characterize flaws. In addition, the applicant stated that these techniques are 

widely used and have been demonstrated effective at detecting aging effects during inspections 

performed to meet ASME Code Section XI requirements.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff did not identify any operating experience events that 

might otherwise indicate that the applicant’s program would not be effective in adequately 

managing cracking or other applicable aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.
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UFSAR Supplement. LRA Section A.1.8 provides the UFSAR supplement for the BWR 

Penetrations Program. The staff reviewed this UFSAR supplement and needed additional 

information to confirm the adequacy of the summary description for the BWR Penetrations 

Program as described below.

SRP-LR, Table 3.0-1 includes an example of a UFSAR supplement summary description that 

may be used for AMPs that correspond to GALL Report AMP XI.M8, “BWR Penetrations.” The 

summary description for the BWR Penetrations Program in SRP-LR Table 3.0-1 states that the 

program includes inspection and flaw evaluation in conformance with the guidelines of 

staff-approved BWR vessel and internals project documents BWRVIP-47-A, BWRVIP-49-A, and 

BWRVIP-27-A, to ensure the long-term integrity and safe operation of BWR vessel internal 

components.

In comparison, the applicant’s summary description for the UFSAR supplement in LRA 

Section A.1.8 states that the BWR Penetrations Program manages cracking of BWR vessel 

penetrations using inspection and flaw evaluation activities, applicable industry standards, and 

staff-approved BWRVIP documents. The staff noted that, in contrast to the UFSAR supplement 

that is provided for these types of programs in SRP-LR Table 3.0-1, the applicant’s UFSAR 

supplement summary description for its program did not include a specific reference to relevant 

BWRVIP documents that are applicable to the program. Thus, the staff found that the 

applicant’s summary description for the UFSAR supplement may not be adequate to ensure the 

effectiveness of the program because of the omission of specific references to relevant 

BWRVIP documents for this program.

By letter dated April 3, 2012, the staff issued RAI B.1.8-2 requesting that the applicant justify 

why LRA Section A.1.8 (UFSAR supplement) did not reference the specific BWRVIP documents 

that are applicable to the implementation of the BWR Penetrations Program.

In its response dated May 1, 2012, the applicant stated that as stated in LRA Section B.1.8, the 

BWR Penetrations Program is consistent with the program described in GALL Report

AMP XI.M8, BWR Penetrations, without an exception. The applicant also stated that therefore, 

by reference, the BWR Penetrations Program incorporates the relevant staff-approved BWRVIP 

documents, consistent with the GALL Report guidance. The applicant further stated that the 

BWRVIP-based program is an industry program that provides for implementation of guidelines 

for inspection, evaluation, repair, water chemistry, and other activities to support continued 

assurance of the structural integrity of BWR RCPB components. In addition, the applicant 

stated that as indicated in the July 29, 1997, letter from Brian W. Sheron (NRC) to Carl Terry 

(BWRVIP Chairman), the U.S. BWR fleet, including the applicant’s unit, is committed to comply 

with BWRVIP guidelines.

In its review, the staff noted that the applicant clarified that its BWR Penetrations Program is 

consistent with GALL Report AMP XI.M8 without an exception so that the program incorporates 

the relevant staff-approved BWRVIP documents, consistent with the GALL Report. The staff 

found that this portion of the applicant’s confirmation is adequate to ensure that the applicant’s 

program is consistent with the GALL Report in terms of the use of the relevant staff-approved 

BWRVIP documents.

The staff noted that 10 CFR 54.21(d) requires that the UFSAR supplement contain a summary 

description of the programs and activities for managing the effects of aging. Without referencing 

specific BWRVIP documents credited for the BWR Penetrations Program, the staff could not 

determine whether the proposed UFSAR supplement in LRA Section A.1.8 contains an 
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adequate summary description of the programs and activities for managing the effects of aging 

in accordance with 10 CFR 54.21(d).

By letter dated July 23, 2012, the staff issued RAI B.1.8-2a requesting that the applicant justify 

why LRA Section A.1.8 (UFSAR supplement) does not identify specific references to the 

BWRVIP documents credited for the applicant’s BWR Penetrations Program.

In its response dated August 15, 2012, the applicant stated that LRA Section A.1.8 is revised to 

include a reference to BWRVIP-27-A, BWRVIP-47-A, and BWRVIP-49-A. In its response, the 

applicant also provided a corresponding revision to LRA Section A.1.8 (UFSAR supplement) 

that identifies BWRVIP-27-A, BWRVIP-47-A, and BWRVIP-49-A as BWR Penetrations Program

reference documents. The staff finds the applicant’s response acceptable because the 

applicant appropriately revised its UFSAR supplement to include specific references to the 

BWRVIP documents credited for the BWR Penetrations Program. Therefore, the UFSAR 

supplement for the BWR Penetrations Program is consistent with the corresponding program 

description in SRP-LR Table 3.0-1. The staff’s concern described in RAIs B1.8-2 and B1.8-2a is 

resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

August 15, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Penetrations Program, 

the staff determines that those program elements for which the applicant claimed consistency 

with the GALL Report are consistent. Also, the staff reviewed the enhancement and confirmed 

that its implementation through Commitment No. 33 prior to the period of extended operation 

will make the AMP adequate to manage the applicable aging effects. 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 BWR Stress Corrosion Cracking Program

Summary of Technical Information in the Application. LRA Section B.1.9 describes the existing 

BWR Stress Corrosion Cracking Program as consistent, with an exception, with GALL Report 

AMP XI.M7, “BWR Stress Corrosion Cracking.” The LRA states that the BWR Stress Corrosion 

Cracking Program is an existing program that manages cracking of the RCPB through the 

implementation of applicable preventive measures, inspection, and flaw evaluation program 

element criteria. The LRA also states that the program accomplishes its objectives through the

implementation of staff-approved BWRVIP documents and the applicant’s response bases to 

NUREG-0313, “Technical Report on Material Selection and Processing Guidelines for BWR 

Coolant Pressure Boundary Piping,” Revision 2, issued 1998, and NRC GL 88-01, “NRC 

Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless Steel 

Piping,” issued January 1988, and Supplement 1 to GL 88-01.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M7. For the “scope of 

program” and “detection of aging effects” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs as discussed below.
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The “scope of program” program element of GALL Report AMP XI.M7 identifies that the 

program is applicable to all BWR piping and piping welds made of austenitic stainless steel and 

nickel alloy that are 4 inches or larger in nominal diameter containing reactor coolant at a 

temperature above 93 °C (200 °F) during power operation, regardless of code classification.

During the audit, the staff noted that the site documentation, including the applicant’s report to 

evaluate AMP consistency, indicates that the applicant’s program includes the relevant piping 

and piping welds regardless of code classification. The staff noted that LRA Section B.1.9 

states that the BWR Stress Corrosion Cracking Program is an existing program that manages 

cracking of the RCPB through the implementation of applicable preventive measures, 

inspection, and flaw evaluation criteria. In addition, LRA Table 3.1.2-3 for the RCPB 

components indicates that the applicant credited the BWR Stress Corrosion Cracking Program 

to manage the aging effect of RCPB components only.

Therefore, the staff could not determine whether the scope of the applicant’s BWR Stress 

Corrosion Cracking Program includes the relevant piping and piping welds regardless of ASME 

Code classification, consistent with the GALL Report. Specifically, the staff noted that the LRA 

appeared to include only ASME Code Class 1 RCPB components in the program scope, but did 

not clearly address whether the scope of the program includes non-Class 1 piping and 

associated piping welds.

By letter dated April 3, 2012, the staff issued RAI B.2.1.9-1 requesting that the applicant clarify 

whether the scope of the BWR Stress Corrosion Cracking Program includes non-Class 1 piping 

and piping welds made of austenitic stainless steel and nickel alloy materials, consistent with 

GALL Report AMP XI.M7. The staff also requested that if the scope of the AMP did not include 

non-Class 1 piping, for the applicant to justify why non-Class 1 piping and piping welds were 

excluded from the scope of the applicant’s program. The staff further requested that if the 

scope of the program did include non-Class 1 piping and associated piping welds, that the 

applicant revise LRA Sections B.1.9 and A.1.9, as necessary, to clarify that the scope of the 

program includes the relevant piping and piping welds regardless of code classification.

In its response dated May 1, 2012, the applicant clarified that the BWR Stress Corrosion 

Cracking Program applies to relevant BWR piping and piping welds made of austenitic stainless 

steel and nickel alloy regardless of code classification, consistent with the GALL Report as 

described in LRA Section B.1.9. The applicant also clarified that non-Class 1 piping and piping 

welds were not excluded from the program and that, at GGNS, all components included in the 

scope of this AMP are part of the RCPB. The applicant further indicated that the results of the 

AMR of these RCPB components are documented in LRA Tables 3.1.2-1 and 3.1.2-3.

In its review, the staff noted that LRA Section 2.3.1.2 addresses the scoping of the RCPB and 

indicates that the components in the RCPB are classified as ASME Code Class 1 components. 

LRA Section 2.3.1.2 also indicates that the majority of the components that comprise the 

applicant’s RCPB are from the nuclear boiler and reactor recirculation systems and that the 

RCPB also includes the Class 1 portions of other systems. In addition, LRA items 3.2.1-54 and 

3.3.1-110 indicate that the components in the ESF systems and auxiliary systems within the 

scope of the BWR Stress Corrosion Cracking Program were reviewed as part of the RCPB. 

Therefore, the staff needed to confirm whether the program scope adequately includes RCPB 

components and other non-Class 1 components, consistent with the GALL Report.

By letter dated July 23, 2012, the staff issued RAI B.1.9-1a requesting that the applicant justify 

why LRA Sections B.1.9 and A.1.9 indicate that the BWR Stress Corrosion Cracking Program 
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manages only aging of the RCPB rather than the scope of the program recommended in the 

GALL Report that includes relevant piping and piping welds regardless of code classification. 

The staff also requested that the applicant clarify why LRA items 3.2.1-54 and 3.3.1-110 

indicate that the components in the ESF systems and auxiliary systems, subject to the program, 

were reviewed as part of the RCPB rather than against the relevant stainless steel and nickel 

alloy piping and piping welds, regardless of code classification. The staff further requested that,

if necessary, the applicant provide updates to LRA Sections B.1.9 and A.1.9 and LRA AMR 

items 3.2.1-54 and 3.3.1-110, consistent with the applicant’s response to RAI B.1.9-1a.

In its response dated August 15, 2012, the applicant stated that there are no piping components 

or piping welds made of austenitic stainless steel or nickel alloy that are 4 inches or larger in 

nominal diameter and contain reactor coolant at a temperature above 93°C (200°F) during 

power operation in the non-Class 1 portions of the ESF and auxiliary systems (i.e., outside the 

reactor coolant pressure boundary). The applicant also provided revisions to LRA 

Sections A.1.9 and B.1.9 to delete the reference to reactor coolant pressure boundary and to 

add reference to relevant piping and welds regardless of code classification. The applicant 

further provided revisions to LRA items 3.2.1-54 and 3.3.1-110 to clarify that there are no 

components outside the reactor coolant pressure boundary subject to the BWR Stress 

Corrosion Cracking Program requirements.

In its review, the staff finds the applicant’s basis, as amended in the response to RAI B.1.9-1a, 

to be acceptable because the applicant clarified that the non-Class 1 portions of the ESF and 

auxiliary systems do not include a stainless steel or nickel alloy piping component that should 

be included within the scope of BWR Stress Corrosion Cracking Program and the applicant’s 

program includes all the relevant piping and piping welds in the scope of the program. The staff 

also finds that the applicant’s revisions to LRA Sections A.1.9 and B.1.9 and items 3.2.1-54 

and 3.3.1-110 are appropriate, consistent with the acceptable response of the applicant. The 

staff’s concern described in RAIs B1.9-1 and B.1.9-1a is resolved.

During the audit, the staff noted that the site documentation for AMP’s consistency evaluation 

indicates that the applicant’s “detection of aging effects” program element is credited to manage 

cracking of stainless steel and nickel alloy piping and piping welds and the following additional 

stainless steel or nickel alloy components: (a) stainless steel thermal sleeves and nickel alloy 

thermal sleeve extensions of RV nozzles (recirculation inlet, CS inlet, and RHR/low-pressure 

coolant injection (LPCI) nozzles), and (b) stainless steel pump casings, valve bodies, and 

thermowells.

In its review, the staff noted that the guidance of GALL Report AMP XI.M7 for selection of 

IGSCC-resistant materials is applied to the components described above. The staff also noted 

that the inspections described in GALL Report AMP XI.M7 are mainly based on the guidance in 

GL 88-01 that addresses inspections of piping and piping welds. Therefore, it was not clear to 

the staff what types of inspections would be performed on the stainless steel thermal sleeves 

and nickel alloy thermal sleeve extensions for the recirculation inlet, CS inlet, and RHR/LPCI 

nozzles and on stainless steel pump casings, valve bodies, and thermowells as part of the 

applicant’s BWR Stress Corrosion Cracking Program.

By letter dated April 3, 2012, the staff issued RAI B.1.9-2 requesting the applicant to identify the 

types of inspections performed on the following components in accordance with the applicant’s 

BWR Stress Corrosion Cracking Program: (1) stainless steel thermal sleeves and nickel alloy 

thermal sleeve extensions of RV nozzles (recirculation inlet, CS inlet, RHR/LPCI nozzles), and 

(2) stainless steel pump casings, valve bodies, and thermowells. The staff also requested that 
3-44

the applicant identify the inspection methods, sample sizes, and inspection frequencies that 

would be applied to the inspections of these components during the period of extended 

operation. The staff further requested that the applicant justify why inspection methods, sample 

sizes, and inspection frequencies selected are considered to be capable of detecting and 

managing cracking in the components during the period of extended operation.

In its response dated May 1, 2012, the applicant clarified that the applicant selects components 

and piping for examination based on the staff-approved inspection schedule and methods 

described in BWRVIP-75-A. The applicant also clarified that welds adjacent to specific 

components are inspected because welds are the susceptible areas. In addition, the applicant 

stated that the program specifies that these welds shall be volumetrically examined using a UT 

examination method. In its review of the applicant’s response to RAI B.1.9-2, the staff finds that 

this portion of the applicant’s response is adequate to manage cracking due to SCC of the pump 

casings, valve bodies, thermowells, and their adjacent welds in scope of the program because 

the program examines the adjacent welds of these components, consistent with the 

GALL Report.

The staff noted that GALL Report item IV.B1.R-99 recommends the BWR Vessel Internals 

Program and Water Chemistry Program to manage cracking of the CS nozzle thermal sleeves. 

In addition, Section 3.2.4, “Other Locations,” of BWRVIP-18-A, “BWR Vessel and Internals 

Project BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines,” indicates that 

there is currently no technique available for inspecting the CS nozzle thermal sleeve welds. 

BWRVIP-18-A further indicates that inspection of thermal sleeve welds should be done when 

the capability exists. Therefore, it was not clear to the staff how the applicant’s BWR Stress 

Corrosion Cracking Program inspects the thermal sleeves and thermal sleeve extensions to 

manage cracking due to SCC and IGSCC.

In addition, the LRA does not include an AMR item for aging management of CS nozzle thermal 

sleeves, based on GALL Report item IV.B1.R-99. The staff needed to further clarify whether the 

BWR Vessel Internals Program (including BWRVIP-18-A) is used to manage cracking of the CS

nozzle thermal sleeves, consistent with the GALL Report.

By letter dated July 23, 2012, the staff issued RAI B.1.9-2a requesting that the applicant provide 

justification for using the BWR Stress Corrosion Cracking Program to manage the aging of 

thermal sleeves and thermal sleeve extensions, given that they are typically located within the 

RV or piping. The staff also requested that as part of the justification, the applicant describe 

how the BWR Stress Corrosion Cracking Program inspects these components (for example, 

using UT). In addition, the staff requested that the applicant describe the inspection results and 

operating experience in terms of occurrence of cracking in the thermal sleeves and sleeve 

extensions of the reactor nozzles.

In its response, the applicant stated that the thermal sleeves for the recirculation inlet, core 

spray inlet, and RHR/LPCI nozzles are, in part, formed by the internal leg of the Y-shaped safe 

ends for those nozzles. The applicant also stated that the thermal sleeves are welded to the 

safe end and extend into the vessel. The applicant further stated that the welds connecting the 

safe ends to the vessel nozzles and external piping are RCPB welds and the BWR Stress 

Corrosion Cracking and Water Chemistry Control - BWR Programs are credited to manage 

cracking of these safe end pressure boundary welds as evaluated in LRA Table 3.1.2-1.

In addition, the applicant stated that the components represented by the lines in LRA 

Table 3.1.2-1 for the thermal sleeves and extensions include the thermal sleeves starting from 
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the weld to the safe end and extending inward. The applicant stated that the thermal sleeves, 

starting from the weld to the safe end, are within the scope of the BWR Vessel Internals 

Program. In its response, the applicant also revised LRA Table 3.1.2-1 to indicate that the BWR 

Vessel Internals and Water Chemistry Control - BWR Programs are used to manage cracking of 

the thermal sleeves and thermal sleeve extensions.

The staff finds that the applicant’s proposal of using the BWR Vessel Internals Program to 

manage cracking in these thermal sleeve components is consistent with the scope of GALL 

Report AMP XI.M9, “BWR Vessel Internals.” SER Section 3.0.3.1.10 documents the staff’s 

evaluation regarding the applicant’s aging management for the thermal sleeve components 

using the BWR Vessel Internals Program. The staff’s concern described in RAI B.1.9-2a is 

resolved.

As part of its response to RAI B.1.9-2, the applicant also identified the use of its risk-informed 

inspection methodology as an exception to the “detection of aging effects” program element of 

GALL Report AMP XI.M7. The staff reviewed the portions of the “detection of aging effects”

program element associated with the exception to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of this 

exception follows.

Exception. By letter dated May 1, 2012, the applicant amended LRA Sections B.1.9 and A.1.9, 

and identified an exception to the “detection of aging effects” program element. In this 

exception, the applicant stated that its BWR Stress Corrosion Cracking Program uses 

inspection frequencies established in BWRVIP-75-A, Table 3-1, except those for Category A 

welds that are examined in accordance with the risk-informed inservice inspection (RI-ISI)

application. The applicant also stated that the use of an RI-ISI application for Category A welds 

is justified because the risk-informed application was authorized by the staff in a 2007 SER. 

The applicant further stated that this SER allowed the applicant to use a risk-informed approach 

in selecting components for inservice inspection (ISI) based on ASME Code Case N-716.

In its review, the staff noted that the NRC letter, dated September 21, 2007, states that the staff

authorizes the proposed alternative in accordance with 10 CFR 50.55a(a)(3)(i) for the remainder 

of the licensee’s second 10-year ISI interval and for its third 10-year ISI interval ending in 2017. 

The NRC letter also states that the staff’s approval of the licensee’s risk-informed inspection 

program does not constitute approval of ASME Code Case N-716.

As described above, the staff noted that the NRC approval for the applicant’s use of the ASME 

Code Case N-716 methodology, modified as described by the applicant’s previous submittals, is 

granted for a certain portion of the second ISI interval and the third interval only. If the applicant 

further pursues the continued use of its risk-informed inspection methodology, the applicant 

would be required to reapply for the use of its risk-informed methodology for any 10-year 

interval beyond the third interval, including the fifth and sixth 10-year intervals for the period of 

extended operation. Therefore, the staff needed clarification of the inspection scope and 

schedule the applicant would use in the BWR Stress Corrosion Cracking Program in the case 

the applicant could not get NRC approval for the use of the applicant’s risk-informed 

methodology.

By letter dated July 23, 2012, the staff issued RAI B.1.9-3 requesting that the applicant clarify 

what inspection scope and schedule the BWR Stress Corrosion Cracking Program would use 

for Category A welds in the case the applicant could not get NRC approval for the use of the 
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applicant’s RI-ISI methodology. The staff also requested that the applicant ensure that LRA 

Sections B.1.9 and A.1.9 are consistent with the applicant’s response.

In its response dated August 15, 2012, the applicant indicated that in the case that GGNS could 

not get NRC approval for the use of the RI-ISI methodology, the BWR Stress Corrosion 

Cracking Program will use the inspection scope and schedule, which are described in 

BWRVIP-75-A, for the Category A welds. The applicant also provided revisions to LRA 

Sections A.1.9 and B.1.9 accordingly. In its review, the staff finds that the applicant’s basis, as 

amended in the RAI response, acceptable because the applicant’s amended basis is consistent 

with GALL Report AMP XI.M7 and the applicant appropriately revised the LRA. The concern 

described in RAI B.1.9-3 is resolved.

Summary. Based on its audit and review of the applicant’s responses to RAIs B.1.9-1, B.1.9-2, 

B.1.9-3, B.1.9-1a, and B.1.9-2a of the applicant’s BWR Stress Corrosion Cracking Program, the 

staff finds that program elements one through six for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M7. The staff also reviewed the exception associated with the “detection of aging 

effects” program element, and its justification and finds that the AMP, with the exception, is 

adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.9 summarizes operating experience related to the 

BWR Stress Corrosion Cracking Program. The LRA states that a review of Owner’s Activity 

Reports for 2004 through 2009 showed no indications of cracking from inspections performed 

under this program and the absence of aging effects indicates that the preventive actions of the 

program have been effective.

The staff reviewed operating experience information in the LRA and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience, for which it determined the need for 

additional clarification, resulting in the issuance of an RAI, as follows. Event Notification Report 

No. 47880, dated April 30, 2012, indicates that the applicant detected an unacceptable flaw by 

UT in one of the RHR system to reactor pressure vessel (RPV) nozzles (N06B-KB weld) during 

the refueling outage. The dimension of the indication is approximately 0.9 inch in length and 

approximately 0.5 inch in depth. Nominal wall thickness of the weld is 1.3 inches.

The event notification also indicates that the flaw has been evaluated by Entergy Engineering 

and determined to meet the criteria for reporting as identified in NUREG-1022, “Event Reporting 

Guidelines: 10 CFR 50.72 and 50.73”: welding or material defects in the primary coolant 

system that cannot be found acceptable under ASME Code Section XI, IWB-3600, “Analytical 

Evaluation of Flaws,” or ASME Code Section XI, Table IWB-3410-1, “Acceptable Standards.” 

Therefore, the staff needed to further confirm that this operating experience does not affect the 

effectiveness of the applicant’s BWR Stress Corrosion Cracking Program.

By letter dated July 23, 2012, the staff issued RAI B.1.9-4 requesting that the applicant clarify 

whether the weld addressed in Event Notification Report No. 47880 is included in the scope of 

the BWR Stress Corrosion Cracking Program. The staff also requested that the applicant 
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identify the category of the weld in accordance with the IGSCC categories defined in GL 88-01. 

In addition, the staff asked the applicant to evaluate the data from this operating experience 

event in terms of its impact on the effectiveness of the applicant’s BWR Stress Corrosion 

Cracking Program, as follows:

• describe the results of the previous inspections performed on this weld (N06B-KB weld) 

as part of the BWR Stress Corrosion Cracking Program

• describe the root or apparent cause analysis results and the corrective action to be 

taken. In addition, identify the new weld category assigned after this event to confirm 

whether it is consistent with GL 88-01 as referenced in GALL Report AMP XI.M7

• justify why this operating experience does not affect the effectiveness of the applicant’s 

program. As part of the response, identify any impact of this operating experience on 

the program elements of the applicant’s BWR Stress Corrosion Cracking Program

In its response dated August 15, 2012, the applicant stated the N06B nozzle connects the 

residual heat removal C system to the RPV and the weld N06B-KB is included in the scope of 

the BWR Stress Corrosion Cracking Program. The applicant also stated that the 2012 

examination was performed to comply with BWRVIP-75-A for Category C welds. The applicant 

further stated that the Category C N06B-KB weld (RHR/LPCI inlet nozzle to safe end weld) is 

constructed of the following materials. The nozzle material is carbon steel A-508 Class 2. The 

safe end material is Inconel SB-166, which is considered Alloy 600. The weld butter is 

Inconel 182 weld metal. The weld is Inconel 82/182 weld metal.

In its response regarding the previous inspections, the applicant stated that prior to 2012, no 

IGSCC type indication had been observed in the N06B nozzle and previous exams were limited 

on the downstream side of the N06B-KB weld (nozzle side) due to the nozzle configuration, 

especially when performing a circumferential scan looking for axial flaws. The applicant also 

stated that the circumferential scan was limited due to the weld crown and nozzle configuration. 

The applicant further stated that during 2012, this nozzle received extensive weld crown 

reduction and surface preparation which enabled the examination to detect the subject flaw. In 

addition, the applicant stated that in 1990, an induction heating stress improvement (IHSI) 

process was performed on all DM welds to perform stress relieving and prevent or mitigate the 

occurrence of nozzle cracks, including those in the N6B nozzle. The applicant stated that a 

post-UT examination was completed after the IHSI process and no indications were identified in 

the N6B nozzle weld. The applicant also stated that however, as noted earlier, it did not 

perform any circumferential scan of the downstream side of the weld due to its design 

configuration.

In its response regarding the root cause analysis and corrective actions, the applicant stated 

that the apparent cause of the weld indication is that the weld and weld butter were fabricated 

with Inconel materials susceptible to IGSCC and in 1990, actions were taken to mitigate this 

condition through implementation of an IHSI process. The applicant also stated that after 

discovery of the weld indication in 2012, the weld was repaired by weld overlay. The applicant 

further stated that prior to this event, the weld was categorized as a Category C weld, as 

defined in BWRVIP-75-A and that future inspections of this weld will be conducted per 

BWRVIP-75-A for Category E welds, consistent with BWRVIP-75-A. In its review, the staff 

noted that the applicant appropriately identified IGSCC Category E for the N06B-KB weld 

because BWRVIP-75-A categorizes a cracked weld, which has been reinforced by weld overlay, 

as Category E.
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The applicant also stated that BWRVIP-61, "Induction Heating Stress Improvement 

Effectiveness on Crack Growth in Operating Plants," documents the results of an investigation 

into the most likely causes for post-IHSI-process IGSCC, and per the report, cracking reported 

after IHSI can be attributed to existing cracking that initially went undetected following 

application of IHSI. The applicant stated that the flaws existed at the time of IHSI treatment, but 

were later detected with better examination methods and better trained personnel.

In its response regarding the effectiveness of the applicant’s program, the applicant indicated 

that due to industry concerns with cracking in DM welds, the industry committed to an 

accelerated inspection program provided in BWRVIP-222, “Accelerated Inspection Program for 

BWRVIP-75-A Category C Dissimilar Metal Welds Containing Alloy 182,” July 2009. The 

applicant also stated that 20 DM Category C welds were inspected prior to 2012 to comply with 

the BWRVIP-222 requirements, and the remaining 14 welds in the program were inspected 

during 2012. The applicant further stated that all BWRVIP-75-A Category C welds have been 

inspected and the N06B nozzle was the last nozzle requiring inspection.

In addition, the applicant indicated that its BWR Stress Corrosion Cracking Program is based 

upon the guidelines of BWRVIP-75-A, and since GL 88-01 was issued, the BWR industry has 

performed several thousand weld examinations on piping subject to the GL requirements. The 

applicant also indicated that during this time, the industry has improved the water chemistry of 

reactor coolant thereby reducing initiation and growth of IGSCC, stress improvement has also 

been employed as an IGSCC remedy, and the examination procedures have been, and 

continue to be, improved. The applicant further stated that the detection of this indication as 

described above demonstrates the effectiveness of the program in identifying IGSCC using 

today's improved inspection techniques and procedures so that this operating experience has 

no impact on the program elements of the applicant’s BWR Stress Corrosion Cracking Program.

The staff found that portions of the applicant’s response were acceptable because the applicant 

clarified that (a) IGSCC Categories has been appropriately assigned to the N06B-KB weld 

based on the materials of the weld, mitigation actions, and operating experience, consistent with 

GL 88-01 and BWRVIP-75-A, so that inspections will be performed on the weld, consistent with 

GALL Report AMP XI.M7, (b) as a corrective action in response to the detection of the 

indication, the weld was repaired by weld overlay, which is also consistent with the GALL 

Report, (c) the previous issue with the limited inspection coverage of the weld was resolved by 

the weld crown reduction and surface preparation so that the flaw could be detected in the 

inspections, and (d) the applicant complies with the BWRVIP-222 requirements, consistent with 

the industry commitment. The staff identified its concerns as follows.

The applicant’s response did not provide justification for why the implementation of the 

accelerated inspections, which are specified in BWRVIP-222, is not identified as an 

enhancement to the existing BWR Stress Corrosion Cracking Program. In addition, the staff 

needed to confirm whether any other welds in the scope of the program have limited inspection 

coverage as was the case with the N06B-KB weld prior to the weld crown reduction. By letter 

dated October 3, 2012, the staff issued RAI B.1.9-4b requesting applicant’s clarification for 

these items.

In its response dated October 22, 2012, the applicant stated that during the refueling outage in 

2012, the applicant completed its UT of all Category C DM welds, as performed in accordance 

with the accelerated inspection schedule of BWR-222, Section 9. The applicant also stated that 

the use of BWRVIP-222 is not an enhancement to the BWR Stress Corrosion Cracking Program 
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because none of the applicant’s Category C DM welds will require an accelerated inspection per 

BWRVIP-222 for the period of extended operation.

In addition, the applicant stated that two Category C welds in the scope of the applicant’s 

program have limited inspection coverage because inspections of these welds could not 

achieve the 90 percent-by-volume inspection coverage criterion specified in ASME Code 

Case N-460. The applicant clarified that the reduced inspection coverage for the welds is due 

to the concavities on the outer weld surfaces that cannot result in reliable UT signals, but that 

the volumetric inspection coverage for each of these two welds is at least 75 percent. The staff 

finds that the applicant’s basis for aging management, as clarified in its response of 

October 22, 2012, is acceptable because the applicant does not have any additional 

accelerated inspection to be performed per BWRVIP-222 and the inspection coverage of at 

least 75 percent for the two Category C welds provides reasonable assurance cracking in these 

two welds will be detected and the structural integrity of the welds will be maintained. The 

concern described in RAI B.1.9 -4b is resolved.

Based on its audit and review of the application, and review of the applicant’s responses to 

RAIs, the staff finds that the applicant has appropriately evaluated plant-specific and industry 

operating experience and implementation of the program has resulted in the applicant taking 

corrective actions. In addition, the staff finds that the conditions and operating experience at the 

plant are bounded by those for which the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.9 provides the UFSAR supplement for the BWR Stress 

Corrosion Cracking Program. The staff reviewed this UFSAR supplement to determine whether 

the UFSAR supplement includes an adequate description for the program. In its initial review, 

the staff noted that the licensing basis for this program for the period of extended operation may 

not be adequate if the applicant does not provide sufficient information and clarification related 

to its UFSAR supplement.

As addressed in the staff’s evaluation related to RAI B.1.9-1a, the staff requested that the 

applicant justify why LRA Section A.1.9 indicates that the BWR Stress Corrosion Cracking 

Program manages only aging of the RCPB rather than the scope of the program recommended 

in the GALL Report that includes the relevant piping and piping welds regardless of code 

classification.

As described in the sections above, the applicant’s response to RAI B.1.9-1a confirms that there 

are no piping components or piping welds made of austenitic stainless steel or nickel alloy that 

are 4 inches or larger in nominal diameter and contain reactor coolant at a temperature above 

93°C (200°F) during power operation in the non-Class 1 portions of the ESF and auxiliary 

systems. The applicant also provided revisions to LRA Sections A.1.9 (UFSAR supplement) to 

delete the reference to reactor coolant pressure boundary and to add the reference to relevant 

piping and welds regardless of code classification.

In its review, the staff finds the applicant’s response acceptable because the applicant 

confirmed that all the relevant piping and piping welds included in the scope of the program are 

Class 1 components so that the non-Class 1 portions of the ESF and auxiliary systems do not 

have a component in the program scope. The staff also finds that the applicant’s revisions to 

LRA Section A.1.9 (UFSAR supplement) are appropriate and consistent with the applicant’s 

description in its response. The staff’s concern described in RAI B.1.9-1a is resolved. The staff 

finds that the information in the UFSAR supplement, as amended by letter dated 

August 15, 2012, is an adequate summary description of the program.
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Conclusion. On the basis of its audit and review of the applicant’s BWR Stress Corrosion 

Cracking Program, the staff determines that the program elements for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M7. In addition, the staff reviewed the program exception 

and its justification and determines that the AMP, with the program exception, is adequate to 

manage the applicable aging effects. 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 BWR Vessel Inside Diameter (ID) Attachment Welds

Summary of Technical Information in the Application. LRA Section B.1.10 describes the 

existing BWR Vessel ID Attachment Welds Program as consistent with GALL Report

AMP XI.M4, “BWR Vessel ID Attachment Welds.” The LRA states that the program manages 

the effects of cracking in the RV ID attachment welds by the inspection and evaluation 

recommendations of BWRVIP-48-A. The program provides for mitigation of cracking through 

management of reactor water chemistry and monitoring for cracking through in-vessel 

examinations of the RV internal attachment welds.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M4.

In particular, the staff confirmed that the AMP addresses the inspection of the welds in 

accordance with ASME Code Section XI, Subsection IWB, Examination Category B-N-2. The 

staff also confirmed that the inspection schedule is in accordance with ASME Code Section XI, 

Subsection IWB-2400, and Table 3-2 of the BWRVIP-48-A, consistent with the recommendation 

of GALL Report AMP XI.M4. In addition, it was confirmed that the AMP requires that any repair 

or replacement activities be implemented in accordance with the guidelines of the ASME Code 

Section XI, IWA-4000.

Based on its audit of the applicant’s BWR Vessel ID Attachment Welds Program, the staff finds 

that program elements one through six for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M4.

Operating Experience. LRA Section B.1.10 summarizes operating experience related to the 

BWR Vessel ID Attachment Welds Program.

The applicant indicated that the examinations of vessel internal attachment welds were 

performed using EVT-1 visual techniques. The applicant stated that the examinations included 

piping welds, piping brackets, and jet pump riser brace attachment welds. The applicant stated 

that visual examinations were performed on 16 CS brackets, and a tack weld on a bolt was 

identified as cracked. The applicant explained that the condition was found to be acceptable 

and the inspection interval for the bolt was shortened from every fourth refueling outage to each 

refueling outage. The applicant further stated that inspection of jet pump wedges and jet pump 

weld locations were performed using visual examination and no indications were identified. 

Examinations of the steam dryer support and holddown attachment welds were performed and 

no indications were identified.
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The staff reviewed operating experience information in the application and during the audit, to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.10 provides the UFSAR supplement for the BWR Vessel 

ID Attachment Welds Program. The staff reviewed the UFSAR supplement description of the 

program, which stated that applicable industry standards and staff-approved BWRVIP 

documents are used to delineate the program. The staff noted that the summary does not 

identify the use of the BWRVIP-48-A report, which is recommended by GALL Report 

AMP XI.M4. By letter dated April 3, 2012, the staff issued RAI B.1.10-1 requesting the applicant 

revise LRA Section A.1.10 to reference the use of the BWRVIP-48-A report, or justify its 

exclusion. In its response dated May 1, 2012, the applicant stated that LRA Section A.1.10 was 

not changed to include the reference of BWRVIP-48-A. The applicant stated that the 

Section A.1.10 reference “applicable industry standards and staff-approved BWRVIP 

documents” provides a more comprehensive definition of applicant guidance to ensure program 

effectiveness than to list only specific BWRVIP documents that may be revised or superseded in 

the future. However, the staff noted that this is inconsistent with SRP-LR Table 3.0-1, “FSAR 

Supplement for Aging Management of Applicable Systems,” for GALL Report AMP XI.M4, which 

specifically references BWRVIP-48-A.

By letter dated July 23, 2012, the staff issued follow-up RAI B.1.10-1a requesting the applicant 

revise LRA Section A.1.10 to indicate that the BWR Vessel Attachment Welds Program perform 

inspections and flaw evaluation in accordance with the guidelines in the BWRVIP-48-A report.

In its response dated August 15, 2012, the applicant revised LRA Sections A.1.10 and B.1.10 to 

include a reference to BWRVIP-48-A. The staff finds the applicant’s response to RAI B.1.10-1a 

acceptable because the revised LRA Section A.1.10 is an accurate summary description of the 

program and activities for managing the effects of cracking in the reactor vessel ID attachment 

welds, consistent with SRP-LR. The staff’s concerns identified in RAIs B.1.10-1 and B.1.10-1a 

are resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

August 15, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s BWR Vessel ID Attachment 

Welds Program, the staff concludes 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 
3-52

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 BWR Vessel Internals

Summary of Technical Information in the Application. LRA Section B.1.11 describes the 

existing BWR Vessel Internals Program as consistent, with an enhancement, with GALL Report 

AMP XI.M9, “BWR Vessel Internals.” The applicant stated that this program includes 

inspection, flaw evaluation and repair guidelines that are consistent with the guidelines 

addressed in relevant BWRVIP reports. No exceptions are taken by the applicant; and there is 

one enhancement, which affects the “detection of aging effects” program element. The 

enhancement will first evaluate the susceptibility to thermal and/or neutron embrittlement of cast 

austenitic stainless steel (CASS), X-750 alloy, precipitation-hardened (PH) martensitic stainless 

steel (e.g., 15-5 and 17-4 PH steel), and martensitic stainless steel (e.g., 403, 410, 431 steel). 

Collectively, these corrosion-resistant materials are referred to as the “subject, other 

corrosion-resistant materials” in the remainder of this section.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding elements of GALL Report AMP XI.M31. For the “scope of program,” 

”detection of aging effects,” and “monitoring and trending,” program elements, sufficient 

information was not available to determine whether they were consistent with the corresponding 

program elements of the GALL Report AMP. In order to obtain the information necessary to 

verify whether these program elements are consistent with the corresponding program elements 

of the GALL Report AMP, the staff issued the following RAIs.

The “scope of program” program element of GALL Report AMP XI.M9 recommends listing all of 

the relevant documents associated with the AMP. During its audit, the staff found that the 

applicant’s BWR Vessels Internals AMP states “Applicable industry standards and staffapproved BWRVIP documents are used to delineate the program.” By letter dated 

June 27, 2012, the staff issued RAI B.1.11-1 requesting that the applicant explain why an 

explicit list of BWRVIP programs is not provided.

In the July 25, 2012, response to RAI B.1.11-1, the applicant provided justification for why an 

explicit list is not necessary and proposed to modify LRA Section A.1.11 to emphasize that the 

scope of the GGNS Vessel Internals Program will comply with all BWRVIP guidelines. The staff 

has reviewed the applicant’s response and finds the applicant’s position and modification to 

Section A.1.11 acceptable because the applicant provided an explicit statement regarding the 

scope of the program. This resolves the issue related to RAI B.1.11-1.

The “monitoring and trending” program element of GALL Report AMP XI.M9 considers that each 

BWRVIP guideline recommends appropriate fracture toughness values to be used in flaw 

evaluations. However, during its audit, the staff found that LRA Appendix C references 

BWRVIP-76-A for core shroud flaw evaluations. By letter dated June 27, 2012, the staff issued 

RAI B.1.11-3 asking if the applicant will use the more conservative lower bound fracture 

toughness value reported in BWRVIP-100-A or the less conservative values found in 

BWRVIP-76-A for flaw evaluations of defects found in core shroud welds.

In the July 25, 2012, response to RAI B.1.11-3, the applicant stated, “the GGNS BWR Vessel 

Internals Program uses the appropriate toughness versus fluence relationships and flaw
3-53

evaluation methods from BWRVIP-100-A, for irradiated stainless steel reactor internals where 

applicable.”

The staff has reviewed the response and is no longer concerned that there could be confusion 

related to which fracture toughness value to use for the “monitoring and trending” activities. 

This resolves the issue related to RAI B.1.11-3.

The “scope of program” program element of GALL Report AMP XI.M9 includes BWRVIP-139 as 

one of the relevant documents. However, during its audit, the staff found that, as part of the 

extended power uprate (EPU) at GGNS, the applicant has a new steam dryer. By letter dated 

June 27, 2012, the staff issued RAI B.1.11-4 requesting that the applicant describe the new 

steam dryer and if it is within the scope and bounding criteria of the BWRVIP-139-A report.

In the applicant’s July 25, 2012, response to RAI B.1.11-4, the applicant stated:

1. BWRVIP-139-A provides broad inspection guidelines based on the 

general characteristics of the various dryer configurations, without 

establishing bounding criteria that would exclude dryers of similar design. 

A description of the new steam dryer was included in Attachment 11 B to 

GNRO-201 0/00056, License Amendment Request, Extended Power 

Uprate, Grand Gulf Nuclear Station, Unit 1, and dated 

September 8, 2010. Like the original dryer, the new dryer is a curved 

hood sixbank design. The inspection requirements of BWRVIP-139-A are 

directly applicable to the GGNS replacement steam dryer.

2. As described in the response to RAI 8, part b, in Attachment 1 of 

GNRO-2011/001 01, Request for Additional Information Regarding 

Extended Power Uprate Grand Gulf Nuclear Station, Unit 1, dated 

November 14, 2011, Entergy plans to follow the inspection 

recommendations of BWRVIP-139 Section 5.3.3 for curved hood steam 

dryers, and the re-inspection guidelines of Section 5.3.4.

In GNRO-2012/00031, Supplemental Information - License Conditions, 

Extended Power Uprate, Grand Gulf Nuclear Station, Unit 1, dated 

April 26, 2012, Entergy proposed license condition 46 which included the 

following.

(f) During the first two scheduled refueling outages after reaching full 

EPU conditions, Entergy shall conduct a visual inspection of all 

accessible, susceptible locations of the steam dryer in accordance 

with BWRVIP-139 and GE inspection guidelines. Entergy shall 

report the results of the visual inspections of the steam dryer to the 

NRC staff within 60 days following startup.

(g) At the end of the second refueling outage following the 

implementation of the EPU, the licensee shall submit a long-term 

steam dryer inspection plan based on industry operating experience 

along with the baseline inspection results for NRC review and 

approval.

Consistent with GALL Report AMP XI.M9, steam dryer inspection and evaluation 

will be based on BWRVIP-139-A. Following the second refueling outage after 

implementation of the extended power uprate, the BWRVIP-139-A 
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recommendations will be supplemented by any additional inspection 

requirements determined for the long-term steam dryer inspection plan submitted 

for NRC review and approval in accordance with License Condition 46 part (g). 

Consequently, GGNS LRA Section B.1.11 need not be modified to include an 

exception. GGNS LRA Section A.1.11 is modified to note the supplementary 

steam dryer inspection requirements that may result from License Condition 46 

part (g).

The staff has reviewed the response and considers that the details do support the use of 

BWRVIP-139-A for guidance on the inspection and evaluation of any flaws discovered in the 

new steam dryer. The interim requirements associated with License Condition 46 for the EPU 

do not change the AMP for the period of extended operation. The modification to LRA 

Section A.1.11, reflecting the information provided in this RAI response, is acceptable. This 

resolves the issue related to RAI B.1.11-4.

The staff also reviewed the portions of the “detection of aging effects,” program element 

associated with the one enhancement to determine whether the program will adequately

manage the aging effects for which it is credited. The staff’s evaluation of this enhancement 

follows.

Enhancement. LRA Section B.1.11 states an enhancement to the “detection of aging effects,” 

program element. This enhancement has two parts. In the first part, the applicant will evaluate 

the susceptibility of the subject materials and other corrosion resistant materials used for the RV 

internal components, to assess the loss of fracture toughness for the material due to thermal 

embrittlement, neutron embrittlement, and any synergistic effects of the two aging mechanisms. 

In the second part, suitable inspection procedures will be developed to address the susceptible 

components. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M9 and determined the need for additional information.

The “detection of aging effects” program element of GALL Report AMP XI.M9 states that 

portions of the susceptible components determined to be limiting will be inspected as part of the 

10-year ISI program during the period of extended operation. Furthermore, the sample size 

should be 100 percent of the accessible component population, excluding components that may 

be in compression during normal operations. However, during the staff’s review of the 

enhancement, the staff found that the description of the enhancement to the applicant’s BWR 

Vessels Internals AMP could be taken to be a sampling-based, condition monitoring program 

where 100 percent of the accessible and susceptible components would not be inspected. By 

letter dated June 27, 2012, the staff issued RAI B.1.11-2 requesting (1) information on which 

materials, other than austenitic stainless steel, are used in the RVI components exposed to a 

neutron fluence of 1x1017 n/cm2 (E > 1 MeV), and (2) more details of how the enhancement will 

help to manage the loss of fracture toughness so that the nature of the enhancement can be 

verified by a future license renewal audit.

In response to RAI B.1.11-2, dated July 25, 2012, the applicant stated:

The enhancement stated in LRA Section B.1.11, BWR Vessel Internals, for the 

management of loss of fracture toughness due to neutron irradiation and thermal 

aging embrittlement is consistent with the guidance provided in NUREG-1801, 

Rev. 2, Section XI.M9, BWR Vessel Internals. This guidance establishes the 

overall parameters of this aspect of the BWR Vessel Internals Program. Details 

of this aspect of the program remain to be determined, including:
3-55

a. the specific scope of components susceptible to neutron irradiation and 

thermal aging embrittlement,

b. the inspection techniques to be used,

c. sequence of inspections to be conducted, and

d. the methods for evaluating inspection results and extrapolating those results 

to inaccessible components.

These details will be developed as part of the implementation of the program 

enhancement described in LRA B.1.11. No revisions to UFSAR Supplement 

A.1.11 are warranted.

Based on its review of the applicant’s response, the staff needed additional information to find 

the applicant’s program acceptable. In a letter dated October 17, 2012, the staff issued a 

follow-up RAI B.1.11-2a where the staff requested the applicant to address the following items:

a. description of the components made from CASS, X-750 alloy, PH martensitic stainless 

steel, and martensitic stainless steel, and other corrosion resistant materials that are 

exposed to the reactor coolant and neutron flux environment

b. description of the sample size for the initial inspection of susceptible components; if only 

portions of susceptible components will be inspected, provide justification

c. clarification regarding the frequency off the augmented inspections

In the November 15, 2012, response to RAI B.1.11-2a, the applicant provided a revision of the 

enhancement to include a list that identifies components of the subject material and other 

corrosion resistant materials, along with revised wording to reflect that the initial sample size will 

be 100 percent of the susceptible components. The applicant confirmed that the intent is for the 

augmented inspection to be a one-time inspection unless the results of the initial inspections at 

GGNS and other industry experience identify a need for additional/periodic inspections.

The staff has reviewed the applicant’s response to RAI B.1.11-2a and finds the response 

acceptable because Entergy Nuclear participates in the BWRVIP and GGNS has committed to 

follow all updated guidance on the need for and timing of future inspections. This resolves the 

issues related to RAI B.1.11-2a.

By letter dated August 15, 2012, the applicant provided a response to RAI B.1.9-2a that 

amended the LRA and indicated that the BWRVIP, along with the Water Chemistry Control -

BWR Program, is credited to manage cracking due to SCC and IGSCC in the thermal sleeves 

and thermal sleeve extensions of the RV nozzles. The applicant also stated the recirculation 

inlet, CS inlet, and RHR/LPCI nozzles are in part, formed by the internal leg of the Y-shaped 

safe ends for those nozzles.

As described in Appendix C of the LRA, the applicant's response to Action Item No. 5 of 

BWRVIP-42-A states that the BWRVIP has developed strategies to ensure the integrity of 

inaccessible welds [associated with the LPCI nozzle and thermal sleeve]. The applicant also 

stated that these strategies are included in Section 3 of BWRVIP-42, Revision 1, and it has 

committed to programs described as necessary in the BWRVIP reports to manage the effects of 

aging during the period of extended operation.
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In its review, the staff noted that the applicant's AMR items for the thermal sleeve components 

in LRA Table 3.1.2-1 do not include the thermal sleeve and thermal sleeve extension of the 

reactor vessel feedwater nozzle. In addition, neither the LRA or applicant's RAI response 

provide a clear description of the “strategies” in BWRVIP-42, Revision 1, to manage the 

inaccessible thermal sleeve welds of the LPCI nozzle and other RV nozzles as applicable.

The staff also needed additional information to clarify how the applicant will inspect the thermal 

sleeves and thermal sleeve extensions. In case inspections are not performed on the thermal 

sleeve components, leakage analyses are necessary to ensure that the intended functions of 

the thermal sleeve components are adequately maintained in a consistent manner with the 

guidance in Section 3.2.4 of BWRVIP-18-A.

By letter dated October 3, 2012, the staff issued RAI B.1.11-6, in which the staff requested the 

applicant to clarify the following issues so that the BWR Vessel Internals AMP can be evaluated:

a. Clarify why the applicant’s AMR items for the thermal sleeve components 

in LRA Table 3.1.2-1 do not include the thermal sleeve and thermal 

sleeve extension of the reactor vessel feedwater nozzle.

b. Describe the “strategies” in BWRVIP-42, Revision 1, to clarify how the 

implementation of the strategies will manage cracking of the inaccessible 

thermal sleeve components of the LPCI nozzle and other reactor vessel 

nozzles as applicable. Include the following in the description, as 

applicable.

1. If the program includes leakage analyses to manage cracking of the 

thermal sleeve components (e.g., for inaccessible locations), describe 

the results of the leakage analyses to demonstrate that cracking of the 

thermal sleeve components does not affect the intended functions of 

these components.

2. If the program includes inspections to manage cracking of the thermal 

sleeve components, describe the method and frequency of the 

inspections to demonstrate the adequacy of the inspections. As part 

of the response, clarify whether any of the thermal sleeve welds of the 

recirculation inlet, core spray, RHR/LPCI and feedwater nozzles can 

be examined using UT that is applied on the outer surface of the 

associated piping and safe ends.

c. Ensure that the LRA is consistent with the response.

In the October 22, 2012, response to part (a), the licensee explained that the thermal sleeves 

are not welded to the nozzles so they are not part of the pressure boundary. With this design, 

the thermal sleeve has no safety functions and its failure would not significantly impact safetyrelated components within the vessel, the thermal sleeves have no intended functions for 

license renewal and are not subject to aging management review. As a result, no AMR items

are included in the LRA.

For part (b), the applicant’s response states that strategies for managing cracking of the 

inaccessible thermal sleeve components, which includes both leakage evaluation and 

inspection, are based on BWRVIP-168, BWR Vessel and Internals Project, Guidelines for 

Disposition of Inaccessible Core Spray Piping Welds in BWR Internals, which is the basis for 

inspection requirements for inaccessible core spray welds included in BWRVIP-18, Revision 1, 
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BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines. NRC review of 

BWRVIP-18, Revision 1, is complete. None of the thermal sleeve welds of the recirculation 

inlet, CS, or RHR/LPCI nozzles can be examined using UT that is applied on the outer surface 

of the associated piping and safe ends. As indicated in part (a) above, the feedwater thermal 

sleeves are not welded to the nozzles nor are they subject to aging management review.

Finally for part (c), the applicant stated that no changes to the LRA are needed.

The staff has reviewed the October 22, 2012, response and finds that the applicant has 

provided enough detail for the staff to evaluate the AMP. Because the thermal sleeves are not 

welded to the feedwater nozzle, the staff agrees that there are no additional items required in 

LRA Table 3.1.2 1. In addition, the staff noted that the details of the BWRVIP strategies for 

aging management of inaccessible core spray line welds are part of the staff review for 

BWRVIP-18 and do not require further consideration for the review of BWRVIP-42. The staff 

verified that the updated inspection and evaluation guidelines in BWRVIP-18, Revision 1, for 

core spray lines were approved in a safety evaluation dated January 30, 2012 (ML113620684 

and ML120230338). The staff’s concerns described in RAI B.1.11-6 are resolved.

Summary. Based on its audit and review of the applicant’s responses to RAIs, the staff finds 

that the program elements for which the applicant claimed consistency with the GALL Report 

are consistent with the corresponding program elements of GALL Report AMP XI.M11. In 

addition, the staff reviewed the enhancement associated with the “detection of aging effects” 

program element and finds that when the applicant submits a plant-specific description of the 

inspection procedures to be used for susceptible components, and gets approval from the NRC 

staff, the AMP will adequately manage the applicable aging effects.

Review of License Renewal Action Items – Appendix C. The applicant is also required to 

comply with the license renewal action items specified in the staff’s SEs for the following 

BWRVIP reports for the extended period of operation.

Several of the BWRVIP documents credited for GGNS license renewal have common action 

items in the NRC SE reports for license renewal that are not associated with a TLAA. The 

following paragraphs address the applicant’s responses to these common license renewal 

action items and the corresponding staff’s evaluation.

The applicant made the following response to the three license renewal action items which are 

listed in staff’s SEs for the aforementioned BWRVIP reports.

1. GGNS’s AMPs for the RVI components are bounded by the BWRVIP reports;

2. The UFSAR supplement addresses a summary of the programs and activities specified 

in the applicable BWRVIP reports; and

3. GGNS states that no TS changes have been identified as a result of implementing the 

AMP for the RVI components.

The staff reviewed the applicant’s disposition of these three license renewal action items and 

concludes that the applicant complied with the intent of the license renewal action items that

were specified by the staff in its SEs for the aforementioned BWRVIP reports.
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The following paragraphs address the applicant’s responses to report-specific license renewal 

action items and the corresponding staff’s evaluation.

For Action Item 5 in BWRVIP-25, the applicant is required to follow the inspection 

recommendation until an expanded technical basis is approved by the staff. The applicant’s 

response to Action Item 5 in BWRVIP-25 states that there are no requirements for BWR/6 

plants like GGNS. The staff reviewed the report and found that the BWRVIP does not 

recommend inspections for the rim hold-down bolts because BWR/6 vessels already have 

wedges installed. The staff finds the applicant’s response acceptable.

For Action Item 5 in BWRVIP-42 Revision 1, the BWRVIP committed in Section 2.2.2 of the 

original report, dated December 1997, to the development of technology to inspect inaccessible 

welds in the low-pressure coolant injection nozzle coupling to the reactor vessel and the shroud. 

Inspection is important because the environment for some inaccessible welds has a relatively 

high electrochemical potential where stress corrosion cracking can occur, leading to leakage. 

Bypass of LPCI flow to the annulus has significant safety consequences mainly for a 

recirculation line break because the diverted LPCI flow to the annulus would be lost through the 

break. Applicants using this report are required to identify this action as open and to be 

addressed once the BWRVIP’s response to this issue has been reviewed and accepted by the 

staff. The applicant’s response to Action Item 5 in BWRVIP-42-A says that the BWRVIP has 

developed strategies to ensure the integrity of inaccessible welds that are included in Section 3 

of BWRVIP-42, Revision 1. The staff addressed this issue in RAI B.1.11-6b discussed in the 

enhancement section. In its response dated October 22, 2012, the applicant described the 

strategies for managing cracking of the inaccessible thermal sleeve components as being the 

same as those found in BWRVIP-18, Revision 1, which is currently under staff 

review. Considering the progress that has been made regarding the inspection strategies for 

inaccessible welds, the staff accepts the RAI response and the staff’s concern for Action Item 5 

in BWRVIP-42, Revision 1, is resolved.

The license renewal action items specified in the staff’s SE dated October 18, 2001, for the 

BWRVIP-74-A report address the aging effects on the RVI components, and this report provides 

requirements to effectively manage the aging effects during the period of extended operation. 

The BWRVIP-74-A report also addresses the license renewal action items associated with 

TLAAs for the period of extended operation. The following paragraphs address the TLAAs and 

the AMP related to RVI components that are specified in the BWRVIP-74-A report, the 

applicant’s responses to these license renewal action items, and the corresponding staff’s 

evaluation of each item.

Per item 4 of the license renewal action item in the staff’s SE for the BWRVIP-74 report, the 

applicant acknowledges that the vessel flange leak detection (VFLD) line is included in the 

scope of license renewal. Cracking of the component is managed by the Water Chemistry 

Program, with the effectiveness verified by the One-Time Inspection Program. The staff 

accepts the applicant’s proposed AMP for the VFLD line because (a) controlling water chemistry 

will enable the applicant to effectively manage the occurrence of any cracking or loss of material 

in the VFLD line, and (b) the one-time inspection program will adequately determine if the aging 

degradation has occurred.

Item 5 of the license renewal action items in the staff’s SE for the BWRVIP-74 report requires 

that the applicant describe how each plant-specific AMP addresses the ten elements listed in 

GALL Report AMP XI.M9. The applicant stated that Appendix B of the LRA addresses the 
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required 10 elements. The staff reviewed Appendix B and accepts the applicant’s response 

because Appendix B adequately addresses the 10 elements of the GALL Report AMP.

Item 6 of the license renewal action items in the staff’s SE for the BWRVIP-74 report requires 

that the applicant shall include a water chemistry program in its LRA to ensure that it can 

effectively manage IGSCC in the RCS systems. The applicant in its response stated that it 

would comply with the BWRVIP-190 report which superseded the BWRVIP-29 report. The staff 

accepts this response as the applicant’s compliance with the requirements of the BWRVIP-190 

provides adequate mitigation to the occurrence of IGSCC.

Item 7 of the license renewal action items in the staff’s SE for the BWRVIP-74 report requires 

that the applicant identify its RPV surveillance program. The applicant stated that it has 

implemented the staff-approved BWRVIP Integrated Surveillance Programs (ISPs) for the 

period of extended operation. Compliance with the staff-approved ISP enables the applicant to 

effectively monitor neutron embrittlement of the RPV materials and, therefore, the staff finds the 

applicant’s response acceptable.

Operating Experience. During the staff audit, the applicant provided several inspection reports 

associated with the previous inspections that were performed on the RVI components. The staff 

reviewed the inspection reports and concluded that the applicant complied with the inspection 

requirements of the applicable BWRVIP reports which are consistent with the GALL Report 

AMP. The staff also reviewed the applicant’s implementation of its corrective action 

methodology for identifying nonconforming conditions and found the applicant’s corrective 

action methodology acceptable.

The “operating experience” program element of GALL Report AMP XI.M9 states that 

plant-specific and any relevant industry experience is to be summarized. However, during its 

audit, the staff noted that there would be a new steam dryer installed as part of the EPU and no 

summary of the industry experience with steam dryers operating under EPU conditions. By 

letter dated June 27, 2012, the staff issued RAI B.1.11-5 requesting that the applicant provide 

details of the industry experience with steam dryers operating under EPU conditions and how 

that has influenced the design and fabrication of the new steam dryer at GGNS.

In the applicant’s July 25, 2012, response to RAI B.1.11-5, the applicant stated that the 

inspection history at the Susquehanna Steam Electric Station (SSES), Units 1 and 2 was 

considered in the submitted license amendment request (LAR) for the EPU, and resulted in 

changes implemented for the GGNS replacement steam dryer, including revised fabrication 

procedures and the elimination of tack welds. Furthermore, in the response to RAI 12 in 

Attachment 1 to GNRO-2012/00011, Response to Request for Additional Information Regarding 

Extended Power Uprate, Grand Gulf Nuclear Station, Unit 1, dated February 20, 2012, the 

April 2011 inspections at SSES, Unit 2 resulted in corrective actions to the GGNS dryer 

manufacturing process.

The staff has reviewed the response and considers that the details demonstrate that relevant 

industry experience was used by the applicant in the new steam dryer for GGNS. This resolves 

the issue related to RAI B.1.11-5.

The staff, therefore, concludes that the applicant adequately implemented the inspection criteria 

of the BWRVIP reports for the RVI components and that the AMP is consistent with GALL 

Report AMP XI.M9. Based on the review of the operating experience for GGNS, the staff 

concludes that by implementing AMP B.1.11, the applicant adequately demonstrated its 
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capability in identifying the aging effects associated with the RVI components. The applicant 

also demonstrated that it will adequately monitor the aging degradation of the RVI components 

by using proper corrective actions to restore the structural integrity of the RVI components.

Based on its audit and review of the application, and review of the applicant’s responses to 

RAIs, the staff finds that the applicant has appropriately evaluated plant-specific and industry 

operating experience and implementation of the program has resulted in the applicant taking 

corrective actions. In addition, the staff finds that the conditions and operating experience at the 

plant are bounded by those for which the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. The applicant provided its UFSAR supplement summary for its BWR

Vessel Internals Program in LRA Section A.1.11. The staff confirms that the UFSAR 

supplement summary description for the BWR Vessel Internals Program conforms to the staff’s 

recommended UFSAR supplement described in SRP-LR Table 3.0-1. The staff finds that 

UFSAR Supplement Section A.1.11 provides an acceptable UFSAR supplement summary 

description of the applicant’s BWR Vessel Internals Program, as required by 10 CFR 54.21(d).

Conclusion. On the basis of its review of the applicant's BWR Vessel Internals, 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 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).

3.0.3.1.11 Compressed Air Monitoring

Summary of Technical Information in the Application. LRA Section B.1.12 describes the 

existing Compressed Air Monitoring Program as consistent, with enhancements, with 

GALL Report AMP XI.M24, “Compressed Air Monitoring.” The Compressed Air Monitoring 

Program manages loss of material in compressed air systems by monitoring air samples for 

moisture and contaminants and by inspecting internal surfaces within compressed air systems. 

The inspection frequency and acceptance criteria are based on the applicant’s response to NRC 

GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” 

issued August 1988, and industry standards and guidance documents.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M24. For the “detection of 

aging effects” and “monitoring and trending” program elements, the staff determined the need 

for additional information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M24 recommends 

that the program include periodic visual inspections of critical component internal surfaces 

(compressors, dryers, after-coolers, and filters) to detect signs of loss of material due to 

corrosion. Enhancement 2 to the LRA AMP identifies an enhancement to the “parameters 

monitored or inspected,” and “monitoring and trending” program elements, which states that the 

program will be enhanced to include periodic and opportunistic inspections of accessible 

internal surfaces of piping and components in certain compressed air systems. However, the 

staff determined that the LRA AMP “detection of aging effects” program element should also be 
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included in the enhancement. Additionally, it was not clear if the critical components 

(i.e., compressors, dryers, after-coolers, and filters) will be included in the periodic and 

opportunistic inspections, nor was it clear what specific types and frequency of inspections will 

be used. By letter dated April 11, 2012, the staff issued RAI B.1.12-1 requesting that the 

applicant clarify whether Enhancement 2 to the LRA AMP applies to the “detection of aging 

effects” program element and to clarify the types of components to be inspected and the specific 

inspection type and frequency that will be used.

In its response dated May 9, 2012, the applicant stated that LRA Sections A.1.12 and B.1.12 will 

be revised to include the “detection of aging effects” element as part of Enhancement 2 to the 

Compressed Air Monitoring Program. The applicant also stated that the internal surfaces of 

compressors, dryers, after-coolers, and filters will be inspected to detect signs of loss of 

material, and that the guidance in ASME Code O/M-S/G-1998, Part 17, will be used for 

inspection frequency and inspection methods for these components.

The staff reviewed the applicant’s response and changes to LRA Sections A.1.12 and B.1.12 

and finds the applicant’s response acceptable because the applicant has extended the 

enhancement to include the “detection of aging effects” program element. Additionally, the 

applicant clarified that the internal surfaces of the critical components will be inspected following 

the guidance in ASME O/M-S/G-1998, Part 17, which is consistent with the GALL Report. The 

staff’s concern described in RAI B.1.12-1 is resolved.

The staff also reviewed the portions of the “preventive actions,” “parameters monitored or 

inspected,” and “monitoring and trending” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.12 states an enhancement to the “preventive actions”

program element. In this enhancement, the applicant stated that the Compressed Air 

Monitoring Program will be enhanced to apply a consideration of the guidance of ASME 

OM-S/G-1998, Part 17; American National Standards Institute (ANSI)/ISA-S7.0.01-1996; 

EPRI NP-7079; and EPRI TR-108147 for air system contaminant limits. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.M24 and 

finds it acceptable because when it is implemented, the air contaminant limits will be informed 

by the cited standards, which is consistent with the GALL Report.

Enhancement 2. LRA Section B.1.12 states an enhancement to the “parameters monitored or 

inspected” and “monitoring and trending” program elements. In this enhancement, the applicant 

stated that the Compressed Air Monitoring Program will be enhanced to include periodic and 

opportunistic inspections of accessible internal surfaces of piping and components in certain 

compressed air systems. The “monitoring and trending” program element in GALL Report 

AMP XI.M24 recommends that the program include system dew point recording and trending, 

air quality analysis results review and trending, and trending of visual inspection results to 

ascertain if adverse long-term trends exist. Additionally, the program recommends that test 

data be analyzed and compared to data from previous tests to provide for the timely detection of 

aging effects on passive components. However, the enhancement does not describe any dew 

point recordings, air quality checks, or trending practices recommended for this program. By 

letter dated April 11, 2012, the staff issued RAI B.1.12-2 requesting that the applicant describe 

the monitoring and trending practices for the Compressed Air Monitoring Program and to clarify 

how the enhancement to the LRA AMP applies to the “monitoring and trending” program 

element.
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In its response dated May 9, 2012, the applicant stated that its implementing procedures include 

daily readings of system dew point. The applicant also stated that air quality analysis results 

are reviewed to determine if alert levels or limits have been reached or exceeded, and that this 

review also checks for unusual trends. The applicant clarified that the enhancement applies 

only to the GALL Report statement that “[v]isual inspection results are compared to previous 

results to ascertain if adverse long-term trends exist.”

The staff finds the applicant’s response acceptable because the applicant’s procedures include 

daily dew point readings, which is consistent with the guidance in the GALL Report AMP. The 

applicant also performs reviews of air quality analysis results, as well as reviews for unusual 

trends, which is consistent with the GALL Report AMP. The staff’s concern described in

RAI B.1.12-2 is resolved.

The staff reviewed this enhancement against the corresponding program element in 

GALL Report AMP XI.M24 and finds it acceptable because when it is implemented it will make 

the program consistent with the recommendations in the GALL Report AMP.

Summary. Based on its audit, and review of the applicant’s responses to RAIs B.1.12-1 and 

B.1.12-2 of the applicant’s Compressed Air Monitoring Program, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M24. In addition, 

the staff reviewed the enhancements, and response to RAI B.1.12-2, associated with the 

“preventive actions,” “parameters monitored or inspected,” and “monitoring and trending,”

program elements and finds that when implemented, they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B.1.12 summarizes operating experience related to the 

Compressed Air Monitoring Program. In 2003, the applicant found evidence of rust during 

internal inspection of the standby diesel generator starting air tanks. Actions were taken to 

remove the rust.

In 2009, the applicant identified a concern regarding high dew points for the Division 1, 2, and 3 

diesel generator starting air systems for the previous 2 years. Corrective actions included 

creating new repetitive tasks for maintenance on the air dryers and revising the procedure for 

desiccant replacement. The response to a high dew point reading now requires a check of the 

dryer tower crossover valves and a satisfactory dryer retest after replacement of the desiccant.

In 2010, the applicant collected instrument air samples that exceeded the procedural limit for 

particulate size. The cause was attributed to filters on temporary air compressors used during 

refueling outage 17. A system modification was implemented to remove the temporary air 

compressors from the system.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.
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Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.12 provides the UFSAR supplement for the Compressed 

Air Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.0-1 and noted that it does not include a summary description of the program nor does it 

reference the applicant’s crediting of its response to GL 88-14. The licensing basis for this 

program for the period of extended operation may not be adequate if the applicant does not 

incorporate this information into its UFSAR supplement. By letter dated April 11, 2012, the staff 

issued RAI B.1.12-3 requesting that the applicant provide further information on the summary 

description of the program and crediting of its response to GL 88-14.

In its response dated May 9, 2012, the applicant stated that it inadvertently omitted the following 

statement from the original LRA submission:

The Compressed Air Monitoring Program manages loss of material in 

compressed air systems by monitoring air samples for moisture and 

contaminants and by inspecting internal surfaces within compressed air systems. 

Inspection frequency and acceptance criteria are based on the GGNS response 

to NRC Generic Letter 88-14 and applicable industry standards and guidance 

documents.

In its response, the applicant provided a revision to LRA Section A.1.12, which now includes the 

above paragraph.

The staff finds the applicant’s response acceptable because the inclusion of the above 

information provides an adequate description of the program. Therefore, the UFSAR 

supplement for the Compressed Air Monitoring Program is consistent with the corresponding 

program description in SRP-LR Table 3.0-1. The staff’s concern described in RAI B.1.12-3 is 

resolved.

The staff also noted that the applicant committed (Commitment No. 7) to enhance the 

Compressed Air Monitoring Program to apply a consideration of industry guidance and to 

include periodic and opportunistic inspections of accessible internal surfaces of certain 

compressed air systems entering the period of extended operation.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 9, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Compressed Air Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 7 prior to the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. 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 
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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 Containment Inservice Inspection – IWE Program

Summary of Technical Information in the Application. LRA Section B.1.13 describes the 

existing Containment Inservice Inspection – IWE Program as consistent with GALL Report 

AMP XI.S1, “ASME Section XI, Subsection IWE.” The LRA also states that the program 

performs a general visual examination to assess the condition of the containment steel liner and 

to detect evidence of degradation that may affect structural integrity or leak tightness. This 

examination satisfies the requirements of the ASME Code (to include the 1998 edition with 1999 

and 2000 addenda, 2001 edition with 2003 addenda, and the 2004 Code Edition) Section XI, 

Subsection IWE Examination Category E-A. The LRA further states that the program is 

augmented by existing plant procedures to ensure that the selection of bolting material,

installation torque or tension, and the use of lubricants and sealants is appropriate for the 

intended purpose. These procedures reference guidance contained in EPRI TR-104213, 

NUREG-1339, and EPRI NP-5769 to ensure proper specification of bolting material, lubricant, 

and installation torque.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S1. For the “scope of 

program,” “preventive actions,” “parameters monitored or inspected” and “acceptance criteria”

program elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs.

The “acceptance criteria” program element in GALL Report AMP XI.S1 recommends that 

material loss exceeding 10 percent of the nominal containment wall thickness, or material loss 

that is projected to exceed 10 percent of the nominal wall thickness, before the next 

examination that is accepted by engineering evaluation, is to be reexamined during the next 

inspection period in accordance with IWE-3122 and IWE-2420(b). However, during its audit, the 

staff found that the applicant’s Containment Inservice Inspection – IWE Program identified flaws 

or degradation that exceeded 10 percent of the nominal wall thickness of the suppression pool 

liner plate during an inspection in 2007 that were accepted by engineering evaluation, and were 

not scheduled to be reexamined during the next inspection period. By letter dated May 9, 2012, 

the staff issued RAI B.1.13-1 requesting the applicant describe the basis for accepting pits 

greater than 10 percent of the liner thickness and for not performing augmented inspection.

In its response dated June 6, 2012, the applicant stated that the GGNS suppression pool liner 

plate, which is backed by concrete, is not a part of the containment pressure boundary and was 

not designed in accordance with ASME Code Section III, Division I. This area of the 

suppression pool is inspected under the Structures Monitoring Program, using a procedure that 

is also used for the Containment Inservice Inspection – IWE Program. The applicant further 

stated that it has evaluated the identified pits as documented in the GGNS corrective action 

process and site calculations. The evaluation states that the reduction in liner plate thickness is 

acceptable. The calculation concluded that with a liner plate thickness of 0.225 inch, a factor of 

safety of 3.17, based on ultimate stress, and a factor of safety of 10.54 based on yield stress,

was maintained. The thinnest wall thickness identified was 0.231 inch, which is bounded by this 

evaluation.
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The staff reviewed the applicant’s response to RAI B.1.13-1 and found it lacked specific 

information concerning consistency between the AMP and GALL Report AMP XI.S1 and 

IWE-1100. Both GALL Report AMP XI.S1 and IWE specifically include metallic shell liner of 

concrete containment pressure-retaining components and their integral attachments within the 

scope of the IWE inspection program. The applicant’s IWE inspection report of April 2007 for 

the suppression pool liner plate identified loss of thickness at more than 100 locations in the 

base slab and walls of the concrete containment portion of the suppression pool liner plate. The 

loss of thickness was up to 7.6 percent. Therefore, an augmented examination is required to be 

performed during the next inspection period in accordance with ASME Code Subsection IWE 

requirements even though the applicant has performed an evaluation that loss of thickness of 

up to 10 percent of the liner plate nominal thickness is acceptable. The staff issued 

RAI B.1.13-1a requesting the applicant to provide justification for inspecting the base slab and 

wall liner plate of the suppression pool, which is an integral part of the concrete containment, in 

accordance with the Structures Monitoring Program AMP. In addition, the RAI requested the 

applicant to provide a justification for not performing the augmented inspection of the flaws as 

required by IWE-2420 and Table IWE-2500-1, Examination Category E-C.

In its response to RAI B.1.13-1a, dated August 21, 2012, the applicant stated that the 

containment floor and cylinder wall portion of the suppression pool and the intersecting portion 

at the containment floor liner are inspected in accordance with the Containment Inservice 

Inspection – IWE Program. The applicant also stated that the April 2007 IWE inspection report 

for the suppression pool liner plate identified loss of thickness in one location, which was on the 

flat circular foundation base slab liner plate and multiple locations on the weir wall liner located 

within the drywell. The flaw located on the flat circular foundation base slab liner plate is within 

the containment pressure boundary, is subject to the requirements of ASME Code Section XI, 

Subsection IWE and is scheduled for inspection during the next inspection interval as required 

by IWE-2420 and Table IWE-2500-1, Examination Category E-C. The applicant also stated that 

the pitting on the weir wall liner is not part of the containment pressure boundary portion of the 

suppression pool liner plate. The pitting was determined to be punch marks made to the liner 

plate during its construction and was not a result of age-related degradation, structural 

deformation or displacement of the liner plate.

The staff reviewed the applicant’s response and found it acceptable because the applicant 

inspects the stainless steel liner in the suppression pool that is part of the concrete containment 

pressure retaining boundary in accordance with the Containment Inservice Inspection – IWE 

Program. The applicant has performed an engineering evaluation in accordance with 

IWE-3122.3 and determined that loss of metal thickness of up to 10 percent is acceptable. In 

addition, the applicant plans to perform augmented inspection of the one flaw in the suppression 

pool base slab that is located within the containment pressure retaining boundary in accordance 

with ASME Code Section XI, Subsection IWE, Examination Category E-C requirements. The 

staff also finds it acceptable that the applicant inspects the suppression pool liner plate that is 

not a part of the containment boundary, including the weir wall, in accordance with the 

Structures Monitoring Program. Furthermore, the staff agrees that the pitting in the weir wall is 

due to punch marks made to the liner during construction and are not due to age-related 

degradation, and that there is no need to perform additional evaluation or reexamination during 

the next inspection period. The staff’s concerns described in RAI B.1.13-1 and RAI B.1.13-1a 

are resolved.

GALL Report AMP XI.S1 states that 10 CFR 50.55a imposes the lSI requirements of the ASME 

Section XI, Subsection IWE for steel containments (Class MC [metal containment]) and steel 

liners for concrete containments [Class CC]). In accordance with 10 CFR 50.55a(b)(2)(ix)(B),
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visual examinations required by Subsection IWE shall be performed with the maximum direct 

examination distance specified in Table IWA-2210-1. However, Section 3.2 of the GGNS 

License Renewal Project, Aging Management Program Evaluation Report Civil/Structural for 

Containment lnservice Inspection – IWE, states that the requirements of IWA-2210 are not 

applicable to Subsection IWE visual examinations per IWE-2100. By letter dated May 9, 2012, 

the staff issued RAI B.1.13-2 requesting the applicant to describe the basis for not using the 

requirements of IWA Table 2210-1 as amended by 10 CFR 50.55(a).

In its response dated June 6, 2012, the applicant stated that Section 3.2 of the GGNS AMP

evaluation report for the Containment Inservice Inspection – IWE Program was intended to 

indicate that the GGNS Containment Inservice Inspection – IWE Program uses IWA

Table 2210-1 as amended by 10 CFR 50.55a(b)(2)(ix)(B), as required by 10 CFR 50.55(a). The 

applicant also reiterated that Containment Inservice Inspection – IWE Program is consistent 

with the program described in the GALL Report AMP XI.S1, ASME Section XI, Subsection IWE, 

with no exceptions. The staff finds the applicant’s response acceptable because the applicant’s 

program uses IWA Table 2210-1 as amended by 10 CFR 50.55a(b)(2)(ix)(B). The applicant’s 

AMP is consistent with GALL Report AMP XI.S1. The staff’s concern described in RAI B.1.13-2 

is resolved.

The “preventive actions” program element in GALL Report AMP XI.S1 recommends that the 

selection of bolting material installation torque or tension and the use of lubricants and sealants 

should be in accordance with the guidelines of EPRI NP-5769, EPRI TR-1 04213, and the 

additional recommendations of NUREG-1339 to prevent or mitigate degradation and failure of 

structural bolting. However, during the audit, the staff noted that Section 3.2 of the GGNS 

License Renewal Project, Aging Management Program Evaluation Report Civil/Structural for 

Containment Inservice Inspection – IWE, states that molybdenum disulfide lubricant was 

previously used in the torquing process during construction and maintenance activities. The 

staff is concerned that AMP or the associated evaluation report did not identify any plan for 

inspecting high-strength bolts that were previously torqued using molybdenum disulfide 

lubricant.

By letter dated May 9, 2012, the staff issued RAI B.1.13-3 requesting the applicant to describe 

the plan, including sample size and frequency, for inspecting high-strength bolts that were 

previously torqued using molybdenum disulfide lubricant. The staff noted that the plan should 

also describe the schedule for inspection to establish a trend for aging management of these 

high-strength bolts during the period of extended operation.

In its response dated June 6, 2012, the applicant stated that it assumed that molybdenum 

disulfide may have been used as a lubricant in the torquing process during construction with 

high-strength structural bolting material (i.e., American Society for Testing and Materials [ASTM]

A325 and A490). However, this bolting is not part of the containment liner construction and no 

Class MC component supports are integrally attached to the liner. However, as stated in 

Section 4.1 of the GGNS License Renewal Project, Aging Management Program Evaluation 

Report Non-Class I Mechanical, procedures will be enhanced to prohibit use of this lubricant, 

even though there is no ASTM A325 and A490 Class MC pressure-retaining component bolting 

integral to the GGNS containment liner plate. This enhancement is described in the LRA

Section B.1.3, Bolting Integrity, since the application and use of lubricants are governed by site 

procedures that are the implementing procedures for the Bolting Integrity Program.

The staff finds the applicant’s response acceptable because high-strength bolting material 

conforming to ASTM A325 and A490 has not been used during original containment liner 
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construction, and no Class MC component supports are integrally attached to the liner. In 

addition, the applicant plans to enhance procedures to prohibit use of molybdenum disulfide 

lubricant. The staff’s concern described in RAI B.1.13-3 is resolved.

The “parameters monitored or inspected” program element in GALL Report AMP XI.S1 

recommends that pressure-retaining surfaces of the containment be inspected for evidence of 

corrosion, cracking, and wear. However, during the audit, the staff reviewed the document 

Program Section No. CEP-CISI-102, “Program Section for ASME Code Section XI, Division 1, 

GGNS Containment Inservice Inspection Program.” Appendix A of this document lists CISI 

drawings for IWE Inspections. The drywell and weir wall liner plates between elevations 93 feet

and 117 feet that are located in the suppression pool and the steel drywell head were not listed 

in Appendix A. Therefore, by letter dated May 9, 2012, the staff issued RAI B.2.1.13-4 

requesting the applicant to provide justification for not inspecting the drywell and weir wall liner 

plates between elevations 93 feet and 117 feet that are located in the suppression pool and the 

steel drywell head.

In its response dated June 6, 2012, the applicant stated that drywell, drywell head, the 

suppression pool (above containment floor and not part of containment cylinder wall) and weir 

wall liner plates, including the area between elevations 93 feet and 117 feet located in the 

suppression pool, are not Class MC pressure-retaining components of the containment. The

applicant revised LRA Table 3.5.2-1 consistent with the response. The applicant also stated in 

response to RAI B.1.13-1 that the suppression pool is inspected under the Structures Monitoring 

Program using a procedure that is also used for the Containment Inservice Inspection – IWE 

Program.

The staff’s conclusion is based on a review of the description of the containment liner plate, weir 

wall, and suppression pool liner plate in Section 3.8 of the UFSAR. However, it is not clear how 

the drywell, drywell head, weir wall, and suppression pool can be inspected under the 

Structures Monitoring Program using the Containment Inservice Inspection – IWE procedure 

since “detection of aging effects” and “acceptance criteria” elements of the two programs are 

significantly different. In addition, the “scope of program” element of LRA B.1.42 does not 

include drywell, drywell head, weir wall, and suppression pool liner plates. Therefore, the staff 

issued RAI B.1.13-4a requesting the applicant to explain the basis for using the inspection 

procedures of Containment Inservice Inspection – IWE Program for inspecting components that 

are included in the scope of the Structures Monitoring Program. In addition, the applicant was 

asked to explain why the drywell, drywell head, weir wall, and suppression pool liner plates are 

not included in Enhancement 1 of the Structures Monitoring Program.

In its response to RAI B.1.13-4a, dated August 21, 2012, the applicant stated that the drywell, 

drywell head, weir wall, and suppression pool liner plates are included in the GGNS SMP 

procedure but they are not specifically listed as separate components. For clarification, the 

applicant revised LRA Sections A.1.42 and B.1.42 to explicitly identify the following additional 

structural components/commodities: drywell electrical penetration sleeves, drywell equipment 

hatch, drywell head, drywell head access manway, drywell liner plate, drywell mechanical 

penetration sleeves, drywell personnel access lock, and weir wall liner plate. The staff finds the 

applicant’s response acceptable because the applicant has revised the UFSAR supplement and 

AMP to identify that all drywell and suppression pool components that are not part of the 

containment pressure boundary that will be managed for aging in accordance with Structures 

Monitoring Program. The staff’s concerns described in RAI B.1.13-4 and RAI B.1.13-4a are 

resolved.
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The program description section of GALL Report AMP XI.S1 recommends the Containment 

Inservice Inspection – IWE Program to be implemented in accordance with the ASME Code,

2004 edition, as approved in 10 CFR 50.55a. In accordance with 10 CFR 50.55a(g)(4), ISI of 

components and system pressure tests conducted during successive 120-month inspection 

intervals must comply with the requirements of the latest edition and addenda of the Code 

referenced in the 10 CFR 50.55a(b), 12 months before the start of the 120-month inspection 

interval. However, during the audit, it was not clear to the staff that the Containment Inservice 

Inspection – IWE Program is consistent with GALL Report AMP XI.S1 because Section 3.2 of 

the GGNS License Renewal Project, Aging Management Program Evaluation Report 

Civil/Structural for the Containment Inservice Inspection – IWE states that IWE examination 

satisfies the requirements of the ASME Code Edition 1998 edition with 1999 and 2000 addenda, 

2001 edition with 2003 addenda, and the 2004 edition. By letter dated May 9, 2012, the staff 

issued RAI B.1.13-5 requesting the applicant to identify the ASME Code edition that is being 

used during the current inspection interval, and if this ASME Code edition is consistent with 

GALL Report recommendations and 10 CFR 50.55a(g)(4) requirements.

In its response dated June 6, 2012, the applicant stated that the third inspection interval for 

GGNS began in 2008. Consistent with 10 CFR 50.55a, the ASME Section XI Code of record for 

GGNS Containment Inservice Inspection – IWE Program for the third inspection interval is the 

2001 Edition with the 2003 Addenda.

The 10 CFR 50.55a was amended on October 1, 2004, to incorporate by reference the 

2001 Edition of ASME Section X Code, up to and including the 2003 Addenda. The 2004 

Edition of Section XI, Division 1, of the ASME Code was not endorsed by 10 CFR 50.55a until 

September 10, 2008. Therefore, the staff finds the applicant’s response acceptable because it 

is conducting the containment liner plate examination in accordance with the 2001 edition with 

2003 addenda of the ASME Code, and as specified in 10 CFR 50.55a to use of the latest edition 

and addenda of the Code referenced in 10 CFR 50.55a(b), 12 months before the start of the 

120-month inspection interval. The staff’s concern described in RAI B.2.13-5 is resolved.

Based on its audit, and review of the applicant’s response to RAIs B.1.13-1, B.1.13-1a,

B.1.13-2, B.1.13-3, B.1.13-4, B.1.13-4a, and B.1.13-5, the staff finds that the program elements 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S1.

Operating Experience. LRA Section B.1.13 summarizes operating experience related to the 

Containment Inservice Inspection – IWE Program. The applicant performed a general visual 

inspection of the containment liner plate in 2003 and identified a gouge. An engineering review 

concluded that the liner plate was still capable of performing its intended function to provide a 

leak-tight barrier after a design basis accident (DBA). The gouge was repaired in 2004. Visual 

examination of the containment liner in 2007 revealed flaking, blistering, peeling, and chipping 

conditions that were acceptable as is. Identification of degradation before loss of intended 

function provides evidence that the program is effective for managing aging effects. During its 

review, the staff found no operating experience to indicate that the applicant’s program would 

not be effective in adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.
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UFSAR Supplement. LRA Section A.1.13 provides the UFSAR supplement for the Containment 

Inservice Inspection – IWE Program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Containment Inservice 

Inspection – IWE Program, the staff concludes that the program elements for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.S1. 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).

3.0.3.1.13 Containment Inservice Inspection – IWL

Summary of Technical Information in the Application. LRA Section B.1.14 describes the 

existing Containment Inservice Inspection – IWL Program as consistent with 

GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL.” The LRA states that the 

Containment Inservice Inspection – IWL Program is an existing program that performs general 

visual examination to assess the overall condition of the containment concrete and to detect 

evidence of degradation that may affect structural integrity or leak tightness. These 

examinations meet the requirements of the ASME Code (to include 1998 Edition with 2000 

Addenda, 2001 Edition through the 2003 Addenda, and 2004 Edition) Section IWL Examination 

Category L-A.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S1. For the “parameters 

monitored or inspected” and “acceptance criteria” program elements, the staff determined the 

need for additional information, which resulted in the issuance of RAIs, as discussed below.

The “parameters monitored or inspected” program element of GALL Report AMP XI.S2, 

recommends that the containment concrete surfaces be examined for evidence of damage or 

degradation, such as those defined in American Concrete Institute (ACI) 201.1R, “Guide for 

Making a Condition Survey of Concrete in Service,” and ACI 349.3R. However, during the 

audit, the staff found that the applicant’s Aging Management Program Evaluation Report for 

Civil/Structural for Containment Inservice Inspection – IWL, only identifies ACI 349.3R criteria 

for the concrete containment surface examination. ACI 201.1R was not referenced for 

conducting containment concrete surface visual examination. By letter dated June 27, 2012, 

the staff issued RAI B.1.14-1 requesting that the applicant describe the methods that will be 

used for conducting containment concrete visual surface examination. In addition, the applicant 

was asked to describe if these methods are consistent with the guidance provided in 

ACI 201.1R.

In its response dated July 25, 2012, the applicant stated that GGNS Containment Inservice 

Inspection – IWL Program is consistent with the parameters monitored and inspected as 

outlined in ASME Code Section XI IWL-2500. GGNS performs a general visual examination 

either directly or remotely with sufficient illumination (natural or artificial) and resolution (suitable 

for the local environmental conditions) to assess the general condition of the accessible 

containment concrete surfaces from permanent vantage points. The objective of this 

examination is to detect evidence of degradation or distress of the concrete surfaces being 
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examined that could affect the structural integrity of the containment. Remote techniques, when 

used, are demonstrated to detect a 1/32-inch black line on a neutral gray card. Alternatively, 

the responsible engineer may approve the use of other remote examination techniques subject 

to the provisions of 10 CFR 50.55a. Examiners shall visually examine the surface areas to be 

inspected and document the results of the inspection on appropriate forms identified in the 

procedure. ACI 201.1R states that personnel conducting the condition survey must select those 

items important to the specific concerns relating to the reasons for the survey. The conduct of 

these inspections is in accordance with ASME Section XI IWL and the guidance of ACI 349.3R 

“Evaluation of Existing Nuclear Safety-Related Concrete Structures.” ACI 201.1 R is used as 

input to the Containment Inservice Inspection – IWL Program for establishing appropriate 

parameters to be monitored and inspected. Therefore, the inspection methods are consistent 

with the guidance in ACI 201.1 R.

The staff finds the applicant’s response acceptable because the applicant confirmed that 

ACI 201.1 R is used as input to the Containment Inservice Inspection – IWL Program for 

establishing appropriate parameters to be monitored and inspected. The staff’s concern 

described in RAI B1.14-1 is resolved.

The “acceptance criteria” program element of GALL Report AMP XI.S2 recommends that 

quantitative acceptance criteria based on the “Evaluation Criteria” provided in Chapter 5 of 

ACI 349.3R-02 may be used to augment the qualitative assessment of the Responsible 

Engineer. The applicant’s Containment Inservice Inspection Program Plan provides the 

examination process of IWL Program in Appendix B, “Containment Inservice Inspection 

Examination Process Flowchart,” and Appendix C, “GGNS Recording and Screening Criteria,”

in the applicant’s procedure of CEP-CII-004, Revision 302, “General and Detailed Visual 

Examinations of Concrete Containments.” However, the staff could not determine whether the 

quantitative acceptance criterion for containment concrete surface visual examination is 

considered in the applicant’s program. By letter dated June 27, 2012, the staff issued

RAI B.1.14-2 requesting that the applicant describe the acceptance criteria used for the 

containment concrete surface visual examination and describe if the acceptance criteria are 

consistent with the quantitative acceptance criteria recommended in Chapter 5 of the 

ACI 349.3R-02.

In its response dated July 25, 2012, the applicant stated:

The GGNS acceptance criteria used for the containment concrete surface visual 

examination state, if any of the conditions listed below are present, the condition 

must be recorded on the examination form and the form forwarded to the 

appropriate personnel for acceptance review.

1. active leaching or chemical attack to include areas of exudation, 

efflorescence, stalactites or stalagmites

2. active abrasion or erosion degradation

3. popouts or voids 50 mm (2 inches) or more in diameter (or of equivalent 

surface area)

4. scaling 30 mm (1 - 1/8 inches) or more in depth

5. spalling 20 mm (3/4 inch) or more in depth

6. spalling 200 mm (8 inches) or more in any dimension
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7. excessive corrosion of embedded metallic surfaces

8. corrosion staining from corrosion of reinforcing steel or from an unknown 

source on the concrete surface

9. cracks 1 mm (0.04 inch) in maximum width, measured below any surface 

enhanced widening

10. excessive deflection, settlement or other physical movement

11. conditions that indicate the presence of or cause degradation of inaccessible 

concrete

In addition, the indications listed above are considered active unless the 

indications have been previously reported and remain essentially unchanged, or 

the evaluated indications have been determined inactive. These acceptance 

criteria are consistent with the quantitative acceptance criteria recommended in 

Chapter 5 of ACI 349.3R-02.

The staff reviewed the applicant’s response to RAI B1.14-2 and noted that the detailed 

acceptance criteria described for the containment concrete surface is based on the quantitative 

limits of the second tier acceptance criteria in Subchapter 5.2.1 of ACI 349.3R-02. This did not 

appear to be consistent with the guidelines recommended in Chapter 5 of ACI 349.3R-02, which 

require further evaluation if concrete surface conditions did not meet the quantitative limits of 

first tier acceptance criteria in Subchapter 5.1.1. The applicant did not provide any justification 

for excluding the first tier evaluation criteria of ACI 349.3R-02 for the containment concrete 

surface examination. Therefore, by letter dated August 15, 2012, the staff issued follow-up

RAI B1.14-2a requesting the applicant to explain the reason for not using the first tier evaluation 

criteria as defined in Subchapter 5.1 of the ACI 349.3R-02 for the GGNS containment concrete 

surface examination.

In its response dated September 13, 2012, the applicant stated that GGNS Containment 

Inservice Inspection – IWL containment concrete surface examination recording criteria are 

consistent with first tier criteria as defined in Subchapter 5.1 of ACI 349.3R-02 and include the 

following:

1. appearance of leaching or chemical attack to include areas of exudation, 

efflorescence, stalactites or stalagmites

2. abrasion or erosion degradation

3. popouts or voids 20 mm (3/4 inch) or more in diameter (or of equivalent surface area)

4. scaling 5 mm (3/16 inch) or more in depth

5. spalling 10 mm (3/8 inch) or more in depth

6. spalling 100 mm (4 ~ inches) or more in any dimension

7. excessive corrosion of embedded metallic surfaces

8. corrosion staining on the concrete surface

9. cracks 0.4 mm (0.015 inch) in maximum width, measured below any surface enhanced 

widening

10. excessive deflection, settlement or other physical movement
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The applicant further stated that the concrete surfaces that exceed the above criteria are 

identified for further evaluation under second tier criteria as defined in ACI 349.3R-02.

The staff finds the applicant’s response acceptable because the applicant confirmed that 

ACI 349.3R-02 evaluation criteria are used to inspect and evaluate the condition of GGNS 

containment concrete surface. The staff’s concern described in RAI B1.14-2a is resolved.

Based on its audit and review of the applicant’s responses to RAIs B.1.14-1, B.1.14-2, and 

B.1.14-2a of the applicant’s Containment Inservice Inspection – IWL, the staff finds that the 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.S2.

Operating Experience. LRA Section B.1.14 summarizes operating experience related to the 

Containment Inservice Inspection – IWL. The applicant performed inspections of concrete 

consistent with the schedule outlined in the ISI program. The reports for 2004 through 2009 

showed no adverse indications from these inspections. The applicant provided the process for 

review of future plant-specific and industry operating experience for this program in LRA 

Section B.0.4, “Operating Experience.” The applicant also stated that the evaluations 

completed under the operating experience program and corrective action program (CAP)

ensure that AMPs continue to be effective in managing the aging effects of in-scope SCs.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff identified operating experience for which it determined the need for 

additional clarification, and resulted in the issuance of an RAI, as discussed below.

The “operating experience” program element of the GALL Report, AMP XI.S2 states that the 

implementation of Subsection IWL, in accordance with 10 CFR 50.55a, is a necessary element 

of aging management for concrete containments through the period of extended operation. 

However, during the walkdown of the containment structure on January 31, 2012, the staff 

noted embedded steel plates in the concrete containment’s exterior surface. These embedded 

steel plates had signs of corrosion and the concrete surface adjacent to these embedded plates 

had rust stains. It was not clear to the staff if those embedded steel plates are considered in the 

Containment Inservice Inspection – IWL Program or how the aging of the embedded steel 

plates will be managed. By letter dated June 27, 2012, the staff issued RAI B.1.14-3 requesting 

that the applicant describe how the aging of the embedded steel plates located on the exterior 

surface of the concrete containment will be managed.

In its response dated July 25, 2012, the applicant stated that the aging effect of the embedded 

steel plates located on the exterior surface of the concrete containment will be managed under 

the Containment Inservice Inspection – IWL Program in accordance with ASME Code 

Section XI IWL-1100. The containment dome surface area was evaluated during the last 

inspection interval and the inspection results indicated that the corrosion on the embedded 

plates did not exceed the screening criteria and would not jeopardize the structural integrity or 

leak tightness of the containment. The conditions were found acceptable without the need for 
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an engineering evaluation or other corrective action. These embeds are included as part of item

“Containment cylinder wall and dome” in LRA Table 3.5.2-1.

The staff finds the applicant’s response acceptable because the embedded steel plates located 

on the exterior surface of the concrete containment will be managed under the Containment 

Inservice Inspection – IWL Program in accordance with ASME Code Section XI IWL-1100, and 

the containment dome surface area was evaluated during the last inspection interval and the 

inspection results indicated that the corrosion on the embedded plates did not exceed the 

screening criteria and would not jeopardize the structural integrity or leak tightness of the 

containment. The staff’s concern described in RAI B1.14-3 is resolved.

Based on its audit and review of the application, and review of the applicant’s response to

RAI B.1.14-3, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.14 provides the UFSAR supplement for the Containment 

Inservice Inspection – IWL Program. The staff reviewed this UFSAR supplement description of 

the program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s the Containment Inservice 

Inspection – IWL Program, the staff concludes that the program elements for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.S2. 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).

3.0.3.1.14 Containment Leak Rate

Summary of Technical Information in the Application. LRA Section B.1.15 describes the 

existing Containment Leak Rate Program as consistent with GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J.” The LRA states that the program provides for detection of loss 

of material, cracking, and loss of function in various systems penetrating containment. The LRA 

states that the program also provides for detection of age-related degradation in material 

properties of gaskets, O-rings, and packing materials for the primary containment pressure 

boundary access points. Containment leakage rate tests (LRTs) are performed to assure that 

leakage through the containment and systems and components penetrating primary 

containment does not exceed allowable leakage limits specified in the plant TS. The LRA 

further states that an integrated leak rate test (ILRT) is performed during a period of reactor 

shutdown at the frequency specified in 10 CFR Part 50, Appendix J, Option B. Performance of 

the ILRT per 10 CFR Part 50, Appendix J, demonstrates the leak-tightness and structural 

integrity of the containment. Local leak rate tests (LLRT) are performed on isolation valves and 

containment access penetrations at frequencies that comply with the requirements of 

10 CFR Part 50, Appendix J, Option B.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S4. For the “scope of 

program” and “monitoring and trending” program elements the staff determined the need for 

additional information, which resulted in the issuance of RAIs as discussed below.

The “scope of program” program element recommends including all containment pressure 

boundary components. However, the staff noted that the applicant’s TS for 10 CFR Part 50,

Appendix J, testing, administered through the Containment Leak Rate program, indicate that the 

leakage rate program is implemented with approved exemptions. By letter dated 

August 15, 2012, the staff issued RAI B.1.15-1 requesting the applicant to identify all 

excluded/exempted components (valves, penetrations, and other components) from the 

10 CFR Part 50, Appendix J, testing and state for these components how it plans to manage 

their aging effects, or justify why an AMP is not necessary.

In its response dated September 13, 2012, the applicant listed components that have been 

exempted from 10 CFR Part 50, Appendix J, Type C testing but are classified as containment 

isolation valves per General Design Criterion 55 (i.e., RCPB penetrating containment) or 56 

(i.e., primary containment isolation). The applicant explained that the listed valves, although 

exempted from the requirements for Appendix J, Type C tests, will be managed by several 

AMPs during the period of extended operation. The applicant will manage the aging effects of 

the exempted/excluded valves through the following selected AMPs:

• External Surfaces Monitoring program, reviewed in SER Section 3.0.3.1.17 and selected 

to manage the effects of aging on external surfaces of the components

• Water Chemistry Control - BWR program, reviewed in SER Section 3.0.3.1.41 and 

selected to manage the effects of aging on internal surfaces of the components

• Compressed Air Monitoring program, reviewed in SER Section 3.0.3.1.11 and selected 

to manage the effects of aging on internal surfaces exposed to condensation

• Water Chemistry Control - Closed Treated Water Systems program, reviewed in SER 

Section 3.0.3.1.42 and selected to manage the effects of aging on internal surfaces

• Internal Surfaces In Miscellaneous Piping and Ducting Components program, reviewed 

in SER Section 3.0.3.1.25 and selected to manage the effects of aging on internal 

surfaces

• Service Water Integrity program, reviewed in SER Section 3.0.3.1.39 and selected to 

manage the effects of aging on internal surfaces

In addition, the applicant stated that some of the exempted/excluded components do not require 

management of aging effects because of their environment, method of construction, or materials 

used, such as:

• External/Internal surfaces of stainless steel components are exposed to indoor air 

(e.g., ILRT Drywell and Containment instrument inboard – outboard valves, associated 

with penetration 110).

• External surfaces of carbon steel components are exposed to temperatures greater than 

212°F.
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The staff reviewed the applicant’s response and found it acceptable because it is consistent with 

the information in Tables 6.2-44 and 6.2-49 of the UFSAR for Type C testing for containment 

isolation valves. The staff was concerned that the applicant did not provide any information in 

its response about the Type B tests required to measure leakage across each 

pressure-containing or leakage-limiting boundary of primary containment penetrations. The 

staff discussed this concern in a conference call with the applicant on November 20, 2012. 

During this conference call, the applicant stated that it would provide a supplemental response 

to RAI B.1.15-1 which lists the penetrations exempted from Type B tests and how aging 

management would be accomplished during the period of extended operation. By letter dated 

December 18, 2012, the applicant supplemented its response. The applicant identified the 

components that have been exempted from Type B testing and identified the AMPs that would 

provide aging management for the components during the period of extended operation. The 

staff reviewed the applicant’s supplemental response and found it acceptable based on the 

following:

a. The inspection ports integral to the guard pipes in containment penetrations are 

exempted from Type B tests because, as documented in UFSAR Section 3.6A.2.4.3, a 

weld located between the inner cover and the guard pipe provide part of the containment 

boundary.

b. The blind flanges in the personnel airlocks are exempted from Type B tests because 

they are an integral part of the personnel airlocks and are tested during the overall 

personnel airlock local leak rate test.

c. The double O-ring seals in the process lines associated with containment 

penetrations 23, 24, 27, 32, and 67 are exempted from Type B tests. UFSAR 

Table 6.2-49, Note 19, states that these O-rings are associated with restriction orifices 

and are not required to be Type B tested because the penetration is water sealed.

d. For the exempted components, the applicant identified additional AMPs that will provide 

aging management of the components during the period of extended operation.

The staff’s concern described in RAI B.1.15-1 is resolved, because the applicant provided a list 

of the components exempted from Type B and C testing, the justification for the exemptions, 

and an explanation of how aging management for the exempted components will be 

accomplished during the period of extended operation. Furthermore, the applicant inspects the 

external surfaces of all containment penetrations in accordance with AMP B.1.13, “Containment 

Inservice Inspection – IWE.”

The “monitoring or trending” program element recommends monitoring of the entire pressure 

boundary over time based on the option followed. The applicant in its LRA and its basis 

document indicated that the Containment Leak Rate program follows Option B for the 

10 CFR Part 50, Appendix J, testing and that the program is consistent with GALL Report 

AMP XI.S4. GALL Report AMP XI.S4 “monitoring and trending” program element states:

Because the LRT program is repeated throughout the operating license period, 

the entire pressure boundary is monitored over time. The frequency of these 

tests depends on which option (A or B) is selected. With Option A, testing is 

performed on a regular fixed time interval as defined in 10 CFR Part 50, 

Appendix J. In the case of Option B, the interval for testing may be adjusted on 

the basis of acceptable performance in meeting leakage limits in prior tests. 

Additional details for implementing Option B are provided in NRC RG [Regulatory 

Guide] 1.163 and NEI 94-01.
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The staff noted that the applicant’s TS, referencing the 10 CFR Part 50, Appendix J, Testing 

Program, state that the performance characteristics of the program are implemented in 

accordance with Amendment 135 to the Operating License. The staff’s SER for 

Amendment 135, dated April 6, 1998, states, contrary to the applicant’s basis and LRA 

documents, that the applicant does not use NRC RG 1.163, “Performance-Based Containment 

Leak-Test Program,” which establishes the performance criteria per GALL Report AMP XI.S4, 

for “10 CFR Part 50, Appendix J, Program,” for implementation of Option B. To resolve this 

inconsistency, by letter dated August 15, 2012, the staff issued RAI B.1.15-2 requesting that the 

applicant identify the exceptions and/or enhancements needed to make the program consistent 

with the GALL Report and further identify whether the program should be either evaluated as:

(1) consistent with exceptions,

(2) consistent with enhancements, or

(3) consistent with exceptions and enhancements.

In the event that the program is not consistent, consistent with exceptions, or consistent with 

enhancements with the GALL Report, the staff requested the applicant to expand the summary 

description of the program sufficiently, so it can be reviewed as a plant-specific program.

In its response dated September 13, 2012, the applicant stated that the Containment Leak Rate 

Program is in accordance with the provisions of 10 CFR Part 50, Appendix J, Option B. Its 

procedures delineate the requirements for Types A, B and C leakage rate testing based upon 

the criteria in RG 1.163, NEI 94-01, “Industry Guidance for Implementing Performance-Based 

Options of 10 CFR Part 50, Appendix J,” and ANSI 56.8-1994, “Containment System Leakage 

Testing Requirements.” The applicant also stated that the amendment request 

(Amendment 135) proposed to use the guidance described in an NRC SER rather than 

RG 1.163, as the method of implementing Appendix J, Option B. The applicant further stated 

that the NRC SER was for an exemption requested from Appendix J, Option A and granted on 

April 26, 1995. The approval of Amendment 135 permitted the applicant to implement the 

containment leak rate testing provisions using Option B in lieu of Option A.

The staff reviewed the applicant’s response and noted that the applicant stated that currently its 

plant procedures are in accordance with the provisions of 10 CFR Part 50, Appendix J, Option B 

for Types A, B and C leakage rate testing based upon the criteria in RG 1.163, NEI 94-01, and 

ANSI 56.8. The staff also reviewed the April 6, 1998, letter to Mr. Joseph Hagan of Entergy 

regarding the issuance of Amendment No. 135 and letter of April 26, 1995, to Mr. Randy 

Hutchinson, of Entergy, regarding the SER for the 10 CFR Part 50, Appendix J, requested 

exemption. The staff noted that the applicant addressed its “plant-specific needs” with a plantspecific submittal, which the NRC determined was consistent with the intent of RG 1.163 and,

therefore, was acceptable. GALL Report AMP XI.S4, to which the applicant claims consistency, 

recommends applicants follow RG 1.163, NEI 94-01, Revision 2-A, and the referenced 

ANSI/ANS-56.8-2002 as the current proper guidelines for acceptable 10 CFR Part 50, 

Appendix J, testing. Although the applicant’s response states that its program is based upon 

the criteria in RG 1.163, NEI 94-01, and ANSI 56.8, these documents are not in the UFSAR 

supplement. This level of detail is necessary in the UFSAR to ensure the program is properly 

implemented during the period of extended operation. The staff discussed this issue with the 

applicant in a conference call on November 20, 2012. The applicant stated that it would 

supplement the response to RAI B.1.15-2 to include a revised Section A.1.15 of the UFSAR 

supplement for the containment leak rate program. By letter dated December 18, 2012, the 

applicant supplemented its response to RAI B.1.15-2 and revised LRA Sections A.1.15 and 

B.1.15 to include references to RG 1.163, NEI 94-01, and ANSI 56.8.
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The staff finds the applicant’s response to RAI B.1.15-2 acceptable because the applicant’s

Containment Leak Rate Program is consistent with the GALL Report, RG 1.163, NEI 94-01, and 

ANSI 56.8R. In addition, the applicant has provided sufficient details of the program in the 

UFSAR supplement.

Based on its audit, and review of the applicant’s responses to RAI B.1.15-1 and RAI B.1.15-2, 

the staff finds that the program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.S4.

Operating Experience. LRA Section B.1.1.15 summarizes operating experience related to the 

10 CFR Part 50, Appendix J, Program. The LRA states that LLRTs during RF10 through RF15 

met test acceptance criteria. However, some components failed to meet the administrative 

limits. Some of these were repaired and retested as acceptable, while others were evaluated 

and deferred. In each of these cases, the containment leakage was within overall allowed 

limits. Noteworthy operating experience examples in the LRA include:

• A 2006 test of the containment isolation valves failed (penetration #35). Their LLRT 

indicated a flow of 3487 sccm leakage. The allowable limit was 3400 sccm. The 

leakage was found acceptable through additional engineering evaluation.

• A 2008 test of the filter/demineralizer system containment isolation valves (penetration 

#49). The test indicated a leakage rate approximately 12 times the administrative limit. 

After flushing the system, the valves were re-tested satisfactorily. For these valves, a 

new procedure was established ensuring that a system flush will be completed 

satisfactorily after future resin transfers.

• Successful ILRT performed in 2008 that confirmed the structural integrity of the 

containment.

The LRA states that operating experience indicates that the program is effective at identifying 

and managing aging effects on primary containment components. The LRA also states that a 

program self-assessment in 2009 revealed a decline in performance due to organizational 

weaknesses. The LRA further states that follow-up actions from the 2009 self-assessment, 

however, indicate improved data analyses and performance monitoring and that reviews against 

established program standards provide assurance that the program will remain effective for 

managing loss of material of components.

The staff also followed-up on the 2009 program self-assessment and reviewed a 2010 

assessment, "Cornerstone Rollup, Program: Appendix J,” which reaffirmed the decline and 

attributed it to knowledge gap, lack of experience of the program owner, declines in program 

personnel, and declines in infrastructure, implementation, and equipment. The staff, however, 

noted that the applicant has taken steps to assure satisfactory program performance, including:

• internal reviews of program’s performance against established standards to assure 

program effectiveness against loss of material of components

• plant-specific operating experience evaluation including the identification of degradation 

leading to corrective action(s) when necessary prior to loss of intended function 

providing evidence that the program is effective for managing aging effects of 

components

• program owner contributions identifying program success and weakness
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• applicable self-assessments, QA audits, peer evaluations, and NRC reviews

• event investigations, trending reports, lessons learned from in-house events, 

self-assessments, including the 10 CFR Part 50, Appendix B corrective action process

• industry operating experience evaluations and actions to mitigate the consequences 

where applicable

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.15 provides the UFSAR supplement for the Containment 

Leak Rate program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR 

Table 3.0-1 and noted that the applicant’s UFSAR needed to be augmented to indicate that the 

plant procedures for Types A, B and C leakage rate testing will be implemented in accordance 

with the criteria set in RG 1.163, NEI 94-01, Revision 2-A, and ANSI/ANS-56.8-2002, which are 

the most current guidelines for acceptable LRTs. The licensing basis for this program for the 

period of extended operation may not be adequate if the applicant does not incorporate this 

information in its UFSAR supplement. By letter dated December 18, 2012, the applicant revised 

its UFSAR supplement to include these documents. As discussed above in response to 

RAI B.1.15-2, the staff reviewed the supplement and found it acceptable because it includes an 

acceptable level of detail and incorporates the appropriate documents. The staff’s concern is 

resolved, and the staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Update to LRA AMP B.1.15.

By letter dated September 23, 2016, the applicant revised LRA Section B.1.15, “Containment 

Leak Rate,” aging management program. The letter summarized events that led to changes to 

the LRA AMP, Containment Leak Rate program, as follows:

On February 17, 2016, the NRC staff approved (ADAMS Accession No. 

ML16011A247) a Grand Gulf license amendment request [LAR] (ADAMS 

Accession No. ML15147A599) to adopt NEI 94-01, Revision 3-A, subject to 

specific conditions and with partial implementation of ANSI/ANS 56.8-2002, 

"Containment System Leakage Testing Requirements," as the implementing 

document for Type B and Type C leak rate testing (LRT). 
3-79

Following the NRC approval of the Grand Gulf LAR (License Amendment 209), and 

further discussions by the NRC staff with the applicant on this issue, NRC was notified of 

changes affecting LRA AMP B.1.15, “Containment Leak Rate” program. In its letter 

dated September 23, 2016, the applicant stated that approval and implementation of the 

LAR did not alter its conclusion of the program’s consistency with that of the GALL 

Report, Revision 2, AMP XI.S4, as was indicated in the original submittal of the LRA on 

October 28, 2011. However, by letter dated October 3, 2016, the applicant 

supplemented its September 23rd letter and submitted a revised LRA AMP B.1.15, which 

takes exceptions to the GALL Report AMP XI.S4 recommendations for the “monitoring 

and trending” and “corrective actions” program elements. 

The staff considers the stated exceptions to “monitoring and trending” and “corrective actions” 

program elements as being portions of the GALL Report AMP XI.S4 that the applicant does not 

intend to implement. The SRP-LR states that an applicant may take one or more exceptions to 

specific GALL Report AMP elements, and that any exception should be described and justified. 

The staff reviewed the technical justifications for the exceptions, including associated OE from 

the NRC-approved LAR, and assessed whether the revised LRA AMP B.1.15 is adequate to 

manage the effects of aging for SSCs within the scope of the Containment Leak Rate program. 

The staff’s evaluation of these exceptions is as follows:

Exception 1. The revised LRA Section (AMP) B.1.15 states an exception to the “monitoring and 

trending” program element. In this exception, the applicant stated the revised LRA AMP B.1.15 

follows NEI 94-01, Revision 3-A, subject to conditions specified in the safety evaluation (SE) 

report for Grand Gulf LAR dated May 27, 2015, to establish the local leak rate testing frequency 

for its Containment Leak Rate program instead of Revision 2-A of the NEI 94-01 referenced in 

the “monitoring and trending,” program element of the GALL Report AMP XI.S4. 

The noted difference between NEI 94-01, Revision 2-A and NEI 94-01, Revision 3-A is in the 

testing frequency of Type C (containment isolation valve [CIV] leakage rates) LLRTs. RG 1.163 

and NEI 94-01, Revision 2-A, limit the testing interval for Type C tests to 60 months with a grace 

period (permissible extension for non-routine emergent conditions) of up to 15 months, while 

NEI 94-01, Revision 3-A, extends the testing interval for Type C tests to 75 months and reduces 

the grace period to nine months. For Type B tests, although the maximum testing interval 

remains unchanged (120 months), the grace period under NEI 94-01, Revision 3-A is also 

reduced to nine months. 

The staff reviewed this exception to LRA AMP B.1.15, “monitoring and trending,” program 

element against the corresponding program element in GALL Report AMP XI.S4 and finds it 

acceptable because when NEI 94-01, Revision 3-A is implemented there would be no negative 

impact when adjusting the testing interval for Type B and Type C tests based on their past 

acceptable local leakage rate performance, other “performance factors,” and reduced grace 

periods as articulated in the SE of the approved LAR. 

The staff reviewed the methodology to increase the testing interval of CIVs for leakage rate 

tests and noted that the February 17, 2016, NRC approved LAR resulting in Amendment 209 to 

the Facility Operating License considered the limitations and conditions imposed by the May 8, 

2012, NRC approval of NEI 94-01, Revision 3-A in the context of 10 CFR Part 54. Specifically, 

when approving the LAR, the staff noted the “Performance Factors” (i.e., past performance, 

design and service life, safety impacts if failed, cause determination and programmatic controls) 

identified in Section 11.3.1 of NEI 94-01, Revision 3-A, that would contribute in adjusting the 

testing interval were considered. If reviews identified any age-related mechanisms contributing 

to leakage, “they were noted and recommendations were made concerning their impact on 

eligibility for the extended test interval of 75 months.”
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For the purposes of assessing and monitoring or trending the overall containment leakage 

potential, the as found minimum pathway leakage rates for the just tested penetrations are 

summed with the as-left minimum pathway leakage rates for penetrations tested during the 

previous 1, 2 or 3 refueling outages. For CIVs, the entire population subject to LLRT is 

evaluated based on three consecutive as-found leak rate tests to identify successful past 

performance when considering extensions to the testing interval. Furthermore, for each Type C 

component on a greater than 60-month test interval, the applicant will apply a potential leakage 

understatement adjustment factor of 1.25 to the actual as-left leak rate, which will increase the 

as-left leakage total. The staff noted in the SE of the approved LAR, that the applicant 

monitored the performance of the Type B and Type C tests over a nine year period (2005 

through 2014) and concluded based on compiled data the high of “as-found” minimum pathway 

and the “as-left” maximum pathway to have adequate margins of 12.35% and 47% respectively,

compared to the regulatory maximum leakage rate at calculated peak containment internal 

pressure related to design basis accidents. 

The staff also noted, implementation of the approved LAR does not change the periodic 

inspections of the external surfaces of containment penetrations performed in accordance with 

AMP B.1.13, “Containment Inservice Inspection – IWE,” or by any of the other proposed LRA 

AMPs selected by the applicant to manage the effects of aging of the components excluded 

from 10 CFR Part 50, Appendix J testing, as discussed above. Similarly, implementation of the 

approved LAR does not affect the scheduling of Type B tests as reflected in the approved LAR, 

unless affected by the aforementioned “Performance Factors.” Furthermore, the staff noted 

scheduling for Type C components currently not on an extended testing interval follows the 

current schedule until their eligibility for an extended testing interval based on leakage rate tests 

can be determined. 

The staff also noted that following a one time extension approved in 2004 (ADAMS Accession 

No. ML040300152) in the testing interval of Type A test (ILRT) to 15 years, the testing interval 

for Type A tests currently remains at 10 years, consistent with the guidance in RG 1.163. The 

staff therefore concludes that implementation of NEI 94-01, Revision 3-A in lieu of the NEI 94-

01, Revision 2-A poses no negative impact in the acceptance of the “monitoring and trending” 

program element.

Exception 2. The revised LRA Section (AMP) B.1.15 states an exception to the “corrective 

actions” program element. In this exception, the applicant stated corrective actions in the 

revised LRA AMP B.1.15 are taken in accordance with 10 CFR Part 50 Appendix J and NEI 94-

01, Revision 3-A, subject to the conditions specified in the safety evaluation (SE) report for 

Grand Gulf LAR dated May 27, 2015, when leakage rates do not meet those established in the 

plant’s Technical Specifications in lieu of Revision 2-A of NEI 94-01, referenced in the 

“corrective actions,” program element of the GALL Report AMP XI.S4. 

The staff verified that the NRC approval of the Grand Gulf LAR resulted in changes to Technical 

Specifications (initially discussed above in the main body of the AMP) affecting Type B and 

Type C tests. These recent changes to the Technical Specifications constitute a part of the 

plant’s CLB regarding the implementation of 10 CFR Part 50, Appendix J. 

The staff noted differences in NEI 94-01, Revision 3-A (now credited for the Containment Leak 

Rate Program) and NEI 94-01, Rev 2-A (recommended by the GALL Report, Revision 2, AMP 

XI.S4). Specifically, the staff noted that in addition to record keeping requirements of Section 

12.1, “Report Requirements,” of NEI 94-01, Rev 2-A, NEI 94-01, Revision 3-A augmented the 

record keeping to include adverse trends in leakage rate summation of Type B and Type C 

components and the development of a corrective action plan to restore the leakage rate 

summation margin to an acceptable level.
3-81

The staff reviewed this exception to LRA AMP B.1.15, “corrective actions,” program element 

against the corresponding program element in GALL Report, AMP XI.S4 and finds it acceptable 

because when NEI 94-01, Rev 3-A is implemented there would be no negative impact in the 

corrective actions program element considering the added review for adverse trends in leakage 

rate summation for Type B and Type C tests and existing “cause determination,” imposed by the 

“Performance Factors,” discussed in Exception 1 above, that includes identification of failures 

during an extended testing interval, and of the corresponding corrective actions to be taken.

The staff noted the NRC approval of the Grand Gulf LAR also addressed relevant OE 

associated with the “corrective action,” program element. Specifically, valves that failed to meet 

the LLRT administrative limits during two consecutive refueling outages (RF), RF-18 and RF-19

“would be tested on the minimum test interval until two successful tests were recorded 

... [and] the licensee created an action to investigate the cause of any failed LLRTs ... 

and documented corrective actions that will help ensure accurate record maintenance in 

the future.”

The staff also noted that the addition to section 12.1 of NEI 94-01, Revision 3-A of “the margin 

between the Type B and Type C leakage rate summation and its regulatory limit,” constitutes an 

enhancement to the “administrative controls,” program element that supports the 

implementation of the “corrective actions,” program element and further supports its 

acceptance. The staff therefore concludes for the purpose of corrective actions, implementation 

of NEI 94-01, Revision 3-A, in lieu of the NEI 94-01, Revision 2-A, poses no negative impact in 

the acceptance of the “corrective actions” program element.

Based on the above review of the exceptions associated with the “parameters monitored or 

inspected,” and “corrective actions,” program elements and their justifications, the staff finds that 

the LRA AMP B.1.15, with exceptions, is consistent with GALL Report AMP XI.S4, and 

adequate to manage the applicable aging effects. 

Update to LRA A.1.15 UFSAR.

The staff reviewed the revised UFSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0.1, “FSAR 

Supplement for Aging Management of Applicable Systems,” and noted that it is consistent with 

the implementing documents identified in the NRC staff approval of a Grand Gulf license 

amendment request dated February 17, 2016, and hence acceptable.

Conclusion. On the basis of its audit and review of the applicant’s Containment Leak Rate 

program, the staff concludes that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.S4. In addition, the staff reviewed the exceptions and their justifications 

and determines that the AMP, with exceptions, is adequate to manage the applicable aging 

effects. 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 Diesel Fuel Monitoring

Summary of Technical Information in the Application. LRA Section B.1.16 describes the 

existing Diesel Fuel Monitoring Program as consistent, with enhancements, with GALL Report
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AMP XI.M30, “Fuel Oil Chemistry.” The applicant stated that the program manages loss of 

material and fouling in piping and components exposed to an environment of diesel fuel oil by 

verifying the quality of fuel oil and controlling fuel oil contamination as well as periodic draining, 

cleaning, and inspection of tanks.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding elements of GALL Report AMP XI.M30.

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with enhancements to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.16 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to include a 10-year periodic cleaning and internal inspection of the fire water pump diesel fuel 

oil tanks (SP64A002A/B), the diesel fuel oil day tanks for Divisions I, II, and III, and the diesel 

fuel oil drip tanks for Divisions I and II. The applicant stated that the cleaning and internal 

inspections will be performed at least once during the 10-year period prior to the period of 

extended operation and at succeeding 10-year intervals. Furthermore, the applicant stated that 

if visual inspection is not possible, a volumetric inspection will be performed. After reviewing 

this enhancement, the staff determined the need for additional information, which resulted in the 

issuance of an RAI, as discussed below.

GALL Report AMP XI.M30 recommends draining and cleaning of diesel fuel oil tank internal 

surfaces at least once every 10 years during the period of extended operation. During its audit, 

the staff found that the applicant’s program did not include the procedures for performing 

cleaning and inspection of the above-mentioned tanks. That is, the staff was not clear on the 

cleaning and inspection approach for these tanks. By letter dated June 22, 2012, the staff 

issued RAI B.1.16-2 requesting that the applicant provide a summary of the process for 

performing cleanings and internal visual inspections of the fire water fuel oil tanks, the diesel 

fuel oil day tanks, and the diesel fuel oil drip tanks in scope of the program.

In its response dated July 23, 2012, the applicant stated that each diesel fuel oil tank is first 

emptied to perform inspections. Sediment or sludge is removed and the tank internal surfaces 

are cleaned to provide a surface capable of visual inspection by qualified personnel.

The applicant stated that the tanks are then visually inspected for rust deposits, corrosion, or 

any obvious physical defects such as blisters, peeling, or pinholes. The applicant also stated 

that physical defects are documented and if evidence of degradation is observed during 

inspection, the affected area of the diesel fuel tank is volumetrically inspected. In addition, the 

applicant stated that if visual inspection is not possible, the diesel fuel tank is volumetrically 

inspected.

The staff finds the applicant’s response acceptable because it is consistent with the 

recommendations in GALL Report AMP XI.M30 and will allow for the degradation to be 

evaluated. The staff’s concern described in RAI B.1.16-2 is resolved.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP XI.M30 and finds it acceptable because when it is implemented it will make the 

program consistent with the recommendations in GALL Report AMP XI.M30.
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Enhancement 2. LRA Section B.1.16 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to include a volumetric examination of affected areas of the diesel fuel tanks if evidence of 

degradation is observed during visual inspection. The scope of this enhancement includes the 

diesel fuel oil day tanks (Divisions I, II, III), the diesel fuel oil storage tanks (Division I, II, III), the 

diesel fuel oil drip tanks (Divisions I, II), and the diesel fire pump fuel oil storage tanks, and is 

applicable to the inspections performed during the 10-year period prior to the period of extended 

operation and at succeeding 10-year intervals. The staff reviewed this enhancement against 

the corresponding program elements in GALL Report AMP XI.M30 and finds it acceptable 

because when it is implemented it will make the program consistent with the recommendations 

in GALL Report AMP XI.M30.

Summary. Based on its audit, and review of the applicant’s response to RAI B.1.16-2 of the 

applicant’s Diesel Fuel Monitoring Program, the staff finds that program elements one through 

six for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M30. In addition, the staff reviewed 

the enhancements associated with the “detection of aging effects” program element and finds 

that when implemented the enhancements will make the AMP adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B.1.16 summarizes operating experience related to the 

Diesel Fuel Monitoring Program.

The applicant stated that in 2004, the standby diesel fuel oil storage tank (Division I, II) indicated 

tank internal surfaces were satisfactory. The applicant further stated that in 2005, sampling of 

the fire water diesel fuel oil storage tanks indicated no signs of water or foreign material in the 

tanks and that absence of aging effects indicates that the preventive actions of the program 

have been effective.

The applicant stated that in 2003, inspection of the HPCS (Division III) diesel fuel oil storage 

tank indicated small blemishes in the coating. The applicant stated that indications were 

corrected before the tank was returned to service.

The applicant reported that in 2005 samples from the fire water diesel fuel oil day tanks 

measured biological growth on day 3 of a 6-day incubation period. The applicant stated a 

biocide addition was performed.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation. Further, the staff found that routine sampling and biocide addition 

demonstrates the effectiveness of the program.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 
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that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.16 provides the UFSAR supplement for the Diesel Fuel 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.0-1 and noted that the LRA does not specify the industry standards used for this 

program. The licensing basis for this program for the period of extended operation may not be 

adequate if the applicant does not incorporate this information into its UFSAR supplement. By 

letter dated June 22, 2012, the staff issued RAI B.1.16-1, requesting that the applicant justify the 

absence of the industry standards used for the program in the UFSAR supplement and the 

program description in LRA Appendix B for the Diesel Fuel Monitoring Program.

In its response dated July 23, 2012, the applicant stated that the acceptance criteria for fuel oil 

quality parameters are as invoked or referenced in the plant’s TS. As result, the applicant

revised LRA Sections A.1.16 and B.1.16 to include the following statement: “Acceptance 

criteria for fuel oil quality parameters are specified in the GGNS [Grand Gulf Nuclear Station] 

technical specifications.” The staff’s concern described in RAI B.1.16-1 is resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

July 23, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Diesel Fuel Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation prior to the period of extended operation will make the 

AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.16 Environmental Qualification (EQ) of Electric Components

Summary of Technical Information in the Application. LRA Section B.1.17 describes the 

existing Environmental Qualification (EQ) of Electric Components Program as consistent with 

GALL Report AMP X.E1, “Environmental Qualification (EQ) of Electric Components.” The 

applicant stated that the GGNS EQ Program manages the effects of thermal, radiation, and 

cyclic aging through the use of aging evaluations based on 10 CFR 50.49(f) qualification 

methods.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding elements of GALL Report AMP X.E1.

The staff also reviewed a main steam isolation valve (MSIV) limit switch recalculation. The 

recalculation demonstrated the qualified life of limit switches associated with the MSIVs due to 

an extended power uprate. This recalculation is being issued to justify the deferral of the 

replacement of the MSIV limit switches from RF18 to RF19. The staff determined that the 

recalculation confirmed adequate safety margin exists in the qualified life of the limit switches.
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The staff questioned the applicant during the audit regarding the frequency and methodology for 

walkdowns to ensure EQ environments have not changed. The applicant provided the staff with 

its TS for containment average temperature to ensure that the environment in which EQ 

equipment are located are monitored to detect any adverse localized environment that may 

accelerate aging and reduce the qualified life of EQ equipment.

Based on its audit and review of the application, the staff finds that program elements one

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP X.E1.

Operating Experience. LRA Section B.1.17 summarizes operating experience related to the

Environmental Qualification (EQ) of Electric Components Program. The applicant stated a 

program assessment in 2009 confirmed compliance with 10 CFR 50.49 and measured the 

effectiveness of the program by evaluating the program’s overall infrastructure, records, 

documentation, program implementation, support personnel qualification and knowledge, and 

the program’s impact on plant equipment. According to the applicant, areas of weaknesses 

were addressed and follow-up actions were assigned to improve program effectiveness. During 

its audit, the staff reviewed EQ health reports dated back to 2006 and identified trends in the 

health reports that showed the applicant corrected the issues identified.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.17 provides the UFSAR supplement for the 

Environmental Qualification (EQ) of Electric Components Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1. The staff finds that the information in the 

UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Environmental Qualification 

(EQ) of Electric Components Program, the staff concludes 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).
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3.0.3.1.17 External Surfaces Monitoring

Summary of Technical Information in the Application. LRA Section B.1.18, as amended by 

letter dated May 13, 2014, describes the existing External Surfaces Monitoring Program as 

consistent, with enhancements, with GALL Report AMP XI.M36, “External Surfaces Monitoring 

of Mechanical Components,” as modified by LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” 

The LRA states that the AMP proposes to manage aging effects through visual inspections of 

external surfaces for evidence of loss of material, cracking, and change in material properties. 

The LRA also states that physical manipulation is used to detect hardening or loss of strength 

for elastomers and polymers. In the letter of May 13, 2014, the applicant amended the program 

description to indicate that, for a representative sample of indoor insulated components 

operated below the dew point, insulation will be removed for inspection of the component 

surface. The applicant stated that these inspections will be conducted during each 10-year 

period during the period of extended operation. There are no in-scope outdoor insulated 

mechanical components.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M36.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “monitoring and trending” program elements associated with enhancements 

to determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.18 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “monitoring and trending” program elements. In this 

enhancement, the applicant stated that the AMP will be enhanced to include instructions for 

monitoring aging effects for flexible polymeric components through manual or physical 

manipulation of the material, with a sample size for manipulation of at least 10 percent of 

available surface area. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M36 and finds it acceptable because when it is 

implemented it will ensure the program includes manual or physical manipulation of at least 

10 percent of the available surface area of polymeric materials, which is consistent with the 

GALL Report recommendations for managing changes in material properties for flexible 

polymeric materials.

Enhancement 2. LRA Section B.1.18 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that it will clearly identify 

underground components, which are in the scope of the program and have physical restrictions 

to access, in the program documents. The applicant also stated that instructions will be 

provided for inspection of all underground components within the scope of this program during 

each 5-year period, beginning 10 years prior to the entry into the period of extended operation. 

GALL Report AMP XI.M36 recommends that underground components be clearly identified in 

the program scope, and inspections of underground components be performed during each 

10-year period beginning 10 years prior to the period of extended operation. The staff reviewed 

this enhancement against the corresponding program element in GALL Report AMP XI.M36 and 

finds it acceptable because when it is implemented it will ensure underground components are 

clearly identified in the program, which is consistent with the GALL Report recommendations, 
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and ensure inspections of underground components are conducted at least as frequently as 

recommended in GALL Report AMP XI.M36.

Enhancement 3. By letter dated May 13, 2014, the applicant added an additional enhancement 

to the “detection of aging effects” program element in order to manage “corrosion under 

insulation.” The staff noted that the applicant adopted the recommended basis for managing 

“corrosion under insulation,” GALL Report AMP XI.M36, as modified in LR-ISG-2012-02. The 

staff finds this enhancement to the program acceptable because it is consistent with the 

condition monitoring basis for managing “corrosion under insulation” in the update of the 

“detection of aging effects” elements of GALL Report AMP XI.M36, “External Surfaces 

Monitoring,” as given in LR-ISG-2012-02.

The staff noted that, in the applicant’s response to RAI 3.0.3-1, as given in the letter of 

May 13, 2014, the applicant found that the design of the GGNS does not include: (a) any 

outdoor, in-scope, insulated piping or piping components (mechanical components), (b) any 

outdoor, in-scope insulated tanks, or (c) any indoor, in-scope, insulated tanks operated at 

temperatures below the dew point. The staff noted that the basis in LR-ISG-2012-02 for 

managing “corrosion under insulation” is only applicable to in-scope, indoor, insulated piping or 

piping components that are operated below the dew point, where condensation may occur 

between the external surfaces of the components and the internal surfaces of the associated 

insulating materials. The staff finds the applicant response to RAI 3.0.3-1 acceptable because 

the applicant’s basis is consistent with the recommendations for managing “corrosion under 

insulation” in Section E of LR-ISG-2012-02. RAI 3.0.3-1 is resolved.

Summary. Based on its audit of the applicant’s External Surfaces Monitoring Program, the staff 

finds that program elements one through six for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report

AMP XI.M36. In addition, the staff reviewed the enhancements associated with the “parameters 

monitored or inspected,” “detection of aging effects,” and “monitoring and trending,” program 

elements and finds that when implemented, they will make the AMP adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B.1.18 summarizes operating experience related to the 

External Surfaces Monitoring Program. The LRA states an operating experience example in 

which a loss of coating that resulted in surface corrosion was discovered on the tailpipe of a 

discharge safety relief valve during a walkdown. The LRA states that the corrosion did not 

affect the ability of the piping to perform its intended function and it was repaired using the 

normal work process. The LRA states another operating experience example in which pitting 

corrosion was detected on piping during replacement of the heat trace. The LRA states that the 

pitting did not threaten the integrity of the piping and was repaired. The LRA states another 

operating experience example in which build-up of scale and rust was found on an SSW valve 

bonnet. The LRA states that the rust and scale was removed during the inspection and the 

valve bonnet was found to be capable of performing its intended function.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 
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applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.18, as modified by letter dated May 13, 2014, provides 

the UFSAR supplement for the External Surfaces Monitoring Program. The staff reviewed this 

UFSAR supplement description of the program and noted that it is consistent with the 

recommended description in SRP-LR Table 3.0-1, as modified by LR-ISG-2012-02. The staff 

also noted that the applicant committed (Commitment No. 9) to enhancing the External Surfaces 

Monitoring Program to:

• include instructions for monitoring aging effects for flexible polymeric components 

through manual or physical manipulation of the material, with a sample size for 

manipulation of at least 10 percent of the available surface area

• identify underground components that are within the scope of the program in the 

program documents

• provide instructions for inspection of all underground components within the scope of the 

program during each 5-year period, beginning 10 years before entry into the period of 

extended operation

• address corrosion for insulated components by conducting periodic inspections of a 

representative sample during each 10-year period by considering the likelihood of 

corrosion under insulation,

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

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. Also, the staff reviewed the enhancements 

and confirmed that their implementation through Commitment No. 9 prior to the period of 

extended operation will make the AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.18 Fatigue Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.19 describes the 

existing Fatigue Monitoring Program as consistent, with an exception and enhancements, with 

GALL Report AMP X.M1, “Fatigue Monitoring.” The LRA states that the program ensures that 

fatigue usage remains within allowable limits by (a) tracking the number of critical thermal and 

pressure transients for selected components, (b) verifying that the severity of monitored 

transients are bounded by the design transient definitions for which they are classified and 
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(c) assessing the impact of the reactor coolant environment on a set of sample critical 

components.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through seven of the applicant’s 

program to the corresponding program elements of GALL Report AMP X.M1. For the program 

description and the “parameters monitored or inspected,” “monitoring and trending,” and 

“corrective actions” program elements, the staff determined the need for additional information, 

which resulted in the issuance of RAIs, as discussed below.

During its audit, the staff reviewed the applicant‘s program basis document and implementing 

procedure and noted that it relies on tracking the number of critical thermal and pressure 

transients to ensure that fatigue usage remains within allowable limits. The staff noted that the 

applicant’s program and implementing procedure uses several different methods for managing 

metal fatigue that are not described in LRA Sections B.1.19 and A.1.19 and the program basis 

document. The details of how the program manages metal fatigue, including environmental 

effects when applicable, are not clear to the staff. By letter dated April 4, 2012, the staff issued

RAI B.1.19-1 requesting the applicant to describe the monitoring methods used by its program 

to manage metal fatigue. The applicant was also asked to describe whether a particular 

monitoring method will be used for certain components and fatigue evaluations or whether the 

methods will be used collectively.

In its response dated May 3, 2012, the applicant described each monitoring method used by its 

program and confirmed that there are no plans to use any methods other than cycle counting, 

cycle-based fatigue monitoring, and stress-based fatigue monitoring. The staff’s review of each 

monitoring method is discussed below.

The applicant stated that for cycle-counting, plant data, such as reactor pressure, FW 

temperature, jet pump flowrate, and generator output, are monitored and saved in computer 

files for evaluation during periodic cycle tracking updates. During these updates, the number of 

transients that occurred during the time period between updates is determined and logged. The 

applicant stated that the logging of partial cycles is not used and only full cycles are recorded in 

the periodic cycle tracking updates. The staff finds it conservative that the applicant records 

transients as “full cycles” because the severity of actual transients is typically less than the 

design transient definition; thus, this equates to a lower actual accumulated fatigue usage than 

compared to the design assumption. The applicant stated that the numbers of cycles that have 

occurred are compared to limits corresponding to the allowable values used in associated 

fatigue analyses. The staff finds the use of cycle counting to be capable of managing metal 

fatigue because it ensures that the assumptions used in a fatigue evaluation remain valid; thus, 

ensuring the design limit is not exceeded.

The applicant stated that for cycle-based fatigue monitoring, it counts the cycles that have 

occurred and then computes the usage factor for a given location based on the design usage 

attributable to each individual transient cycle. The applicant stated that this method allows the 

determination of cumulative fatigue usage for a specific location based on the actual number of 

transient occurrences and the assumption that the fatigue usage contributed by each transient 

is equal to the design transient severity. Furthermore, the applicant indicated that events that 

are more severe than the design transients have been evaluated, and the resulting fatigue 

usage has been included in the cumulative fatigue usage at affected locations. The staff noted 

that the applicant’s program includes corrective actions that address the issue when actual 

transient severity exceeds design transient severity, which is consistent with the “detection of 
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aging effects” program element of GALL Report AMP X.M1. The staff finds the use of 

cycle-based fatigue monitoring to be capable of managing metal fatigue because it periodically 

calculates cumulative fatigue usage based on the cycle counts and design transient severity to 

ensure the design limit is not exceeded through the period of extended operation.

The applicant stated that stress-based fatigue monitoring is used where more refined fatigue 

estimates are necessary because of the more severe thermal duty specific components 

experience. This approach uses computer-based analyses and actual plant data to calculate 

the actual stress that occurs during each transient and the associated fatigue usage. The staff 

noted that the use of actual plant data such as local pressure and thermal condition to calculate 

actual fatigue usage is consistent with the “parameters monitored or inspected” program 

element of GALL Report AMP X.M1. The staff finds the use of stress-based fatigue monitoring 

to be capable of managing metal fatigue because it periodically calculates cumulative fatigue 

usage based on the conditions that are actually occurring at the applicant’s site during 

transients to ensure the design limit is not exceeded through the period of extended operation. 

The applicant addressed the concerns documented in Regulatory Issue Summary 

(RIS) 2008-30, “Fatigue Analysis of Nuclear Power Plant Components,” in its response to

RAI B.1.19-2, which the staff evaluated below.

The applicant stated that if cycle-counting alone does not demonstrate that an analysis will 

remain valid, cycle-based fatigue monitoring or stress-based fatigue monitoring will then be 

used. The applicant explained that specific types of analyses, such as environmentally-assisted 

fatigue (EAF) or high-energy line break (HELB) analyses, do not exclusively use one particular 

method of fatigue monitoring. The staff noted that cycle counting is the simplest monitoring 

method and it is typically relied upon because it is very effective in ensuring that fatigue 

evaluations remain valid. If this method is no longer the most efficient, the applicant can use 

more detailed determination of cumulative fatigue usage and CUF by cycle-based or 

stress-based fatigue monitoring. The applicant clarified that stress-based fatigue monitoring is 

only currently used for the FW nozzle, the HPCS nozzle, and the FW weldolets. The staff finds 

the applicant’s use of the combination of these monitoring methods for all components to be 

conservative because each method, starting with cycle-counting to cycle-based fatigue to 

stress-based fatigue, progressively provides a more refined monitoring approach to manage 

metal fatigue and ensures that the applicable allowable limits are not exceeded.

The staff finds the applicant’s response to RAI B.1.19-1 acceptable because the applicant 

(1) clarified how each monitoring method ensures that metal fatigue is managed through the 

period of extended operation, which the staff evaluated above, and (2) is conservatively using a 

combination of three monitoring methods to manage metal fatigue. The staff’s concern 

described in RAI B.1.19-1 is resolved.

The “parameters monitored or inspected” program element of GALL Report AMP X.M1 states 

that the program monitors all plant design transients that cause cyclic strains, which are 

significant contributors to the fatigue cumulative usage factor (CUFen). It is not clear to the staff, 

whether the “specific system/component cycles” referenced in the applicant‘s implementing 

procedures are or will be monitored. In addition, the staff noted that several documents 

(e.g., UFSAR, TS, and LRA) contain information related to the design transients and that in 

some instances the number of assumed cycles in these documents are not consistent. By letter 

dated April 4, 2012, the staff issued RAI B.1.19-6 requesting the applicant to confirm that the 

transient cycles monitored by its program include all transients with the most limiting cycle limit 

used in the determination of CUFs in ASME Code fatigue, HELB, and EAF evaluations. In 
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addition, the applicant was requested to justify any transients used in these calculations that will 

not be monitored and tracked by the Fatigue Monitoring Program.

In its response dated May 3, 2012, the applicant confirmed that the transient cycles that will be 

monitored and tracked by the Fatigue Monitoring Program include the transients used in the 

determination of CUFs, except those discussed below, in ASME Code fatigue evaluations and 

HELB evaluations and the transients that will be used in EAF evaluations. In addition, the 

applicant confirmed that the most limiting cycle limit for a particular design transient that was or 

will be used in any fatigue analysis will be monitored and tracked to ensure that action is taken 

before any applicable fatigue analysis becomes invalid. The staff’s evaluation of transients not 

monitored by the Fatigue Monitoring Program is discussed below.

The staff finds it appropriate that the applicant is monitoring and tracking the transients in the 

fatigue evaluations discussed above because this ensures that the assumptions used to 

calculate the CUF remain valid and that the transients that contribute to fatigue usage do not 

exceed the allowable limit during the period of extended operation. The staff finds it acceptable 

that the applicant is monitoring and tracking the most limiting cycle limit for a particular design 

transient that was or will be used in a fatigue analysis because this ensures that the 

assumptions in any fatigue analysis or an allowable limit will be exceeded without taking 

preemptive corrective actions.

The applicant stated that the design cyclic transients for Class 1 components are defined by 

applicable design specifications for each component and are included as part of each 

component stress report. Furthermore, the overall set of plant design transients may be 

augmented by component-specific design transients to adequately bound the cycles expected 

at a specific location. The transients identified in the applicant’s calculations that are not 

tracked but may contribute to fatigue usage are evaluated individually below.

The applicant stated that the daily reduction of 75 percent power and weekly reduction of 

50 percent power transients are not tracked because its plant is a base-loaded plant that does 

not perform these power reductions. The staff noted that the design number of events for a 

load-following plant was assumed to occur for these transients even though the applicant’s site 

does not practice load-following operation. Since these transients were meant for a plant 

designed for load-following operation, the staff finds it reasonable that the above-mentioned

transients are not monitored because the applicant’s site does not practice load-following 

operation and operates as a base-loaded plant.

The applicant stated that the control rod patterns change transient is a reduction of power and 

the total number of power reductions used in the analyses is far more than what is required to 

bound the actual plant operation. The staff noted that this transient does not cause a 

temperature or pressure change that would cause significant cyclic stress to the applicable 

components. The staff also finds it reasonable that this transient does not need to be monitored 

because, without significant cyclic stress caused by this transient, fatigue usage is not incurred.

The applicant stated that the CRD return nozzle hydraulic system return nozzle transient is not 

tracked because this nozzle was capped. The staff confirmed in UFSAR Section 5.3.3.1.1.4.5.1 

that the CRD return nozzle hydraulic system return nozzle has been capped; therefore, the staff 

finds it acceptable that the applicant does not monitor this transient because the return line and 

nozzle are no longer used. In addition, the applicant stated that the head cooling spray nozzle 

is not tracked because head cooling spray is not used at its site. The staff confirmed in the 

UFSAR and LRA Section 2.3.2.1 that the head spray line has been functionally abandoned; 
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therefore, the staff finds it acceptable that the applicant does not monitor this transient because 

this piping line and nozzle is no longer used to perform head cooling spray. Furthermore, the 

applicant stated that the core differential pressure and SLC nozzle transient is not tracked 

because its injection path has changed such that this nozzle is not used for this injection. The 

staff confirmed in UFSAR Section 3.9.5.1.2.7 that SLC injection has been rerouted to the HPCS

discharge line. Therefore, the staff finds it acceptable that the applicant does not monitor this 

transient because it no longer occurs at this nozzle originally designed for the occurrence of 

SLC injection.

The staff finds the applicant’s response to RAI B.1.19-6 acceptable because, consistent with the 

“parameters monitored or inspected” program element, the applicant is monitoring all plant 

design transients and the associated limiting number of cycles used in its fatigue evaluations 

(i.e., CUF, HELB, and CUFen) that are significant contributors to the CUFen. In addition, the staff 

finds the applicant’s response acceptable because the applicant justified not monitoring specific 

transients, as described above. The staff’s concern described in RAI B.1.19-6 is resolved.

The “monitoring and trending” program element of GALL Report AMP X.M1 states that trending 

is assessed to ensure that the CUFen remains below the design limit during the period of 

extended operation. During its audit, the staff reviewed the program implementing procedure 

and noted that it relies on several different monitoring methods and only provides direction to 

generate a condition report that is based on the projected cumulative fatigue usage for a 

component. It is not clear to the staff whether the program includes or will include appropriate 

trending of appropriate parameters (e.g., cycles, CUF, CUFen) based on the monitoring method. 

By letter dated April 4, 2012, the staff issued RAI B.1.19-3 requesting the applicant to discuss 

this discrepancy between the implementing procedure and the different monitoring methods of 

the program.

In its response dated May 3, 2012, the applicant stated that its program manages metal fatigue 

by tracking accrued transients against calculation assumptions and by calculating and trending 

CUFs by using cycle-based fatigue monitoring and stress-based fatigue monitoring. For cycle 

counting, the applicant stated the actual number of specific cycles that have occurred will be 

trended and action will be taken before the number of any individual transients exceeds the limit 

established in the analysis. The staff finds the applicant’s timing for taking action for this 

method to be conservative because for the fatigue usage of a component to be equal to the 

calculated CUF all transients must have occurred at the assumed design limits in terms of 

occurrence and severity, not just one individual transient. For the cycle-based and stress-based 

fatigue monitoring, the applicant stated the parameter tracked is the cumulative fatigue usage 

based on transients that have occurred and action will be taken when the CUF is projected to 

exceed the allowable limits within the next 6 years. The staff finds the applicant’s timing for 

taking action for these methods to be conservative because this approach provides sufficient 

time to plan and execute corrective actions based on the cumulative fatigue usage that is 

periodically calculated and projected to ensure an allowable limit is not exceeded.

The staff finds the applicant’s response to RAI B.1.19-3 acceptable. The parameters monitored 

and trended by the applicant are appropriate for the monitoring method used and the applicant 

has set conservative action limits to ensure sufficient time to identify, plan, and execute 

necessary corrective actions, as described above. The staff’s concern described in

RAI B.1.19-3 is resolved.

The “corrective actions” program element of GALL Report AMP X.M1 recommends specific 

corrective actions if the acceptance criteria are exceeded, in addition to the requirements of 
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10 CFR Part 50, Appendix B. The applicant claimed to be consistent with the GALL Report; 

however, during its audit, the staff noted the applicant’s corrective actions program is used to 

satisfy 10 CFR Part 50, Appendix B, but the recommendations from the GALL Report for repair, 

replacement, and reanalysis of the component and scope expansion were not included. In 

addition, since the applicant’s Fatigue Monitoring Program will be enhanced to address EAF, it 

is not clear whether the applicant’s program will ensure that if any changes or modifications 

occur in the future, the limiting locations will have been addressed for EAF. By letter dated 

April 4, 2012, the staff issued RAI B.1.19-4 requesting the applicant to justify the discrepancy 

between its claim of consistency with GALL Report AMP X.M1 and its program basis document. 

In addition, the applicant was requested to confirm that its program will continually ensure that 

the locations managed for EAF will remain limiting for its plant-specific configuration if any plant 

changes or modifications occur in the future.

In its response dated May 3, 2012, the applicant clarified that not specifically listing the 

acceptable corrective actions in GALL Report AMP X.M1 was not intended to eliminate them 

from consideration during evaluation of a condition that fails to meet the acceptance criteria. 

The applicant confirmed that repair, replacement, and re-evaluation are common corrective 

actions assigned under the CAP for many identified conditions at the plant. In addition, 

evaluation under the CAP is expected to consider scope expansion to include other locations 

with the highest expected CUFs when considering environmental effects. The applicant also 

stated that any additional cycle limits determined necessary to support EAF analyses will be 

added to the Fatigue Monitoring Program. The applicant confirmed that its modification 

procedures are relied upon to identify the appropriate design requirements for analysis of metal 

fatigue associated with plant changes or modifications. The applicant also confirmed that any 

additional cycle limits that must be monitored to support new design analyses will be added to 

the Fatigue Monitoring Program.

The staff finds the applicant’s response to RAI B.1.19-4 acceptable because the applicant 

described and confirmed that the measures it takes as part of its corrective actions program are 

consistent with the recommendations in the “corrective actions” program element of 

GALL Report AMP X.M1. In addition, the staff finds the applicant’s response acceptable 

because the applicant confirmed that its existing procedures would necessitate the evaluation of 

the design requirements, which include EAF, for analysis of metal fatigue if there are 

modifications to the plant. The staff’s concern described in RAI B.1.19-4 is resolved.

The staff also reviewed the portions of the “scope of program,” “detection of aging effects” and 

“corrective actions” program elements associated with the exception and enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of this exception and these enhancements follows.

Exception. LRA Section B.1.19 states an exception to the “corrective actions” program element. 

In this exception, the applicant stated that the GALL Report recommends use of a design code 

limit for CUFs; however, it applies a more stringent design limit of 0.1 CUFs at HELB locations. 

Also, the applicant includes an additional corrective action to evaluate the HELB analysis to 

address a HELB exclusion location with a CUF that increases to greater than 0.1. In addition, 

the applicant clarified that the use of a 0.1 limit for CUF at HELB locations is consistent with the 

criteria stated in UFSAR Section 3.6A.2.

The staff noted that one of the criterions for determining HELB locations is based on calculated 

CUF values being less than a value of 0.1. This criterion is specified in the applicant’s UFSAR 

for the determination of HELB locations.
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The staff reviewed this exception against the corresponding program element in GALL Report

AMP X.M1 and finds it acceptable because the Fatigue Monitoring Program is establishing a 

stricter acceptance criterion for HELB locations consistent with the applicant’s UFSAR. In 

addition, the staff finds it appropriate that the applicant is using its Fatigue Monitoring Program 

to manage these HELB locations because the determination of these locations are based on the 

design transients monitored by the program and on CUF values that are also managed by this 

program.

Enhancement 1. LRA Section B.1.19 states an enhancement to the “scope of program”

program element. In this enhancement, the applicant stated that a review of its HELB analyses 

and the corresponding tracking of associated CUFs will be performed to ensure that the 

program adequately manages fatigue usage for these locations.

This program element of GALL Report AMP X.M1 states that the scope includes those 

components that have been identified to have a fatigue TLAA and ensures the fatigue usage 

remains within the allowable limit. The staff noted that the determination of HELB locations are 

based on the design transients and cumulative fatigue usage being managed by the Fatigue 

Monitoring Program; thus, the staff finds it reasonable that these HELB analyses and locations 

are included in the scope of this program.

The staff reviewed this enhancement against the corresponding program element in GALL 

Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

program will include components that have a TLAA based on the design transients and 

cumulative fatigue usage and is being managed to ensure that the allowable limit of 0.1 is not 

exceeded, consistent with the “scope of program” program element.

Enhancement 2. LRA Section B.1.19 states an enhancement to the “scope of program”

program element. In this enhancement, the applicant stated that fatigue usage calculations that 

consider the effects of the reactor water environment will be developed for a set of sample 

reactor coolant system (RCS) components. This sample set will include the locations identified 

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

Nuclear Power Plant Components,” and additional plant-specific component locations in the 

RCPB if they are found to be more limiting than those considered in NUREG/CR-6260. 

Environmental fatigue (Fen) factors will be determined using the formulae sets listed in LRA 

Section 4.3.3. By letter dated May 3, 2012, in response to RAI B.1.19-1, the applicant amended 

this enhancement to include the following, “[i]f necessary following this analysis, revised cycle 

limits will be incorporated into the Fatigue Monitoring Program documentation.”

This program element of GALL Report AMP X.M1 states that for a set of sample sets of RCS

components, fatigue usage calculations should consider the effects of the reactor water 

environment. In addition, this sample set includes the locations identified in

NUREG/CR-6260 and additional plant-specific component locations in the RCPB if they may be 

more limiting than those considered in NUREG/CR-6260.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

program will include fatigue usage calculations that consider the effects of reactor coolant 

environment for a sample set of components, consistent with the “scope of program” program 

element. In addition, the staff finds it acceptable that revised cycle limits will be incorporated 

into the Fatigue Monitoring Program, if necessary, following the environmental fatigue analyses 
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because this will ensure appropriate cycle limits are incorporated into the applicant’s program to 

determine whether these analyses remain valid during the period of extended operation.

Enhancement 3. LRA Section B.1.19 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to revise program documents to provide updates of the fatigue usage calculations on an 

as-needed basis if an allowable cycle limit is approached, or in a case where a transient 

definition has been changed, unanticipated new thermal events are discovered, or the geometry 

of components has been modified.

During its audit, the staff reviewed the applicant‘s implementing procedures for the Fatigue 

Monitoring Program and noted that the relation between the different monitoring methods is not 

apparent. Therefore, it is not clear to the staff what aspects of the program and procedures will 

be revised to account for the enhancement to the “detection of aging effects” program element. 

In addition, the enhancement is specific about updates to calculations when an allowable cycle 

limit is approached; however, since the program relies on different monitoring methods, it is also 

not clear if and when updates to calculations will be required for other parameters that are 

monitored. By letter dated April 4, 2012, the staff issued RAI B.1.19-7 requesting the applicant 

to describe how the implementing procedures for the program will be revised to implement this 

enhancement, considering that the program relies on several monitoring methods.

In its response dated May 3, 2012, the applicant stated that its program manages metal fatigue 

by counting cycles and by the calculation of cycle-based fatigue and stress-based fatigue CUFs. 

In order to address allowable cycle limits, implementing procedures will provide for updates of 

the fatigue usage calculations based on the monitoring method, which are as follows. For 

specific cycle logging, update of the fatigue analysis will be done prior to the number of any 

individual transient exceeding the limit analyzed for in the analysis. As previously discussed in 

the evaluation of RAI B.1.9-3 for this method, the staff finds the timing is capable of identifying 

the need to update fatigue calculations before the analysis becomes invalid in order to manage 

fatigue. The applicant stated that for the determination of cumulative fatigue usage for 

cycle-based and stress-based fatigue monitoring, action will be taken when the CUF is 

projected to exceed the allowable within the next 6 years. Also, as previously discussed in the 

evaluation of RAI B.1.9-3 for these methods, the staff finds the timing is capable of identifying 

the need to update fatigue calculations before the allowable limit is exceeded in order to 

manage fatigue.

The staff finds the applicant’s response to RAI B.1.19-7 acceptable because (1) the parameters 

monitored and trended by the applicant are capable of determining when a fatigue evaluation 

may become invalid or if an allowable limit may be exceeded and (2) the action limits provide 

sufficient time for the applicant to identify, plan, and execute necessary corrective actions. The 

staff’s concern described in RAI B.1.19-7 is resolved.

The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP X.M1 and finds it acceptable because when it is implemented the applicant’s 

program will be capable of determining when a fatigue evaluation may become invalid or if an 

allowable limit may be exceeded and the action limits will be set to provide sufficient time to 

provide updates of the fatigue usage calculations on an as-needed basis, consistent with the 

“detection of aging effects” program element. In addition, the staff finds it acceptable because 

when it is implemented the applicant’s program will update its fatigue usage calculations if any 

inputs, such as a transient definition, new thermal events or component geometry, are changed, 

which is also consistent with this program element of the GALL Report.
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By letter dated June 21, 2012, the applicant amended this enhancement to include a program 

revision to provide for the consideration of the recirculation pump fatigue analysis exemption 

validity if cycles that were input into the exemption evaluation exceed their limits. The applicant 

provided this amendment in response to RAI 4.3-11 related to its fatigue analysis for the 

Byron-Jackson reactor recirculation pump casing. The staff’s evaluation of the applicant’s 

response to RAI 4.3-11 is documented in SER Section 4.3. The applicant stated in its response 

that this exemption determination considered the assumed number of fatigue transients 

specified by GE.

The staff finds this amended portion of the enhancement acceptable because the applicant’s 

Fatigue Monitoring Program will track the transients cycles assumed in the recirculation pump 

fatigue analysis exemption against the allowable numbers of cycles; thus, ensuring that this 

exemption for a fatigue analysis will remain valid during the period of extended operation. The 

staff noted that the applicant’s program also include corrective actions, consistent with 

GALL Report AMP X.M1, if an allowable number of cycles is approached.

Summary. Based on its audit of the applicant’s Fatigue Monitoring Program, and review of the 

applicant’s responses to RAIs B.1.19-1, B.1.19-3, B.1.19-4, B.1.19-6 and B.1.19-7, the staff 

finds that program elements one through seven for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report

AMP X.M1. The staff also reviewed the exception associated with the “corrective actions”

program element, and its justification, and finds that the AMP, with the exception, is adequate to 

manage the applicable aging effects. In addition, the staff reviewed the enhancements 

associated with the “scope of program” and “detection of aging effects” program elements and 

finds that when implemented, the AMP will adequately manage the applicable aging effects.

Operating Experience. LRA Section B.1.19 summarizes operating experience related to the 

Fatigue Monitoring Program. The LRA provides a discussion regarding an assessment the 

applicant performed in 2003, which found it to be effective in collecting plant operational data 

required for the calculation of fatigue usage factors. Data collected and trended through 1999 

confirmed that the number of cycles was not trending toward exceeding the allowable number of 

cycles. In addition, the applicant stated that a 2011 study of its plant data showed that the 

number of plant transients to date were within their design allowable limits.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs, as 

discussed below.

LRA Section 4.3.1.1 states that stress-based fatigue monitoring on the FW nozzle, the HPCS

nozzle, and the FW weldolets is being used. The staff noted that as discussed in RIS 2008-30, 

there were concerns with a methodology used to perform fatigue calculations and as input for 

online fatigue monitoring programs by license renewal applicants or licensees in the current 

operating term. It is not clear how stress-based fatigue monitoring is currently incorporated and 

how it will be used to manage metal fatigue by the Fatigue Monitoring Program. It is also not 

clear how the applicant addressed the concerns identified in RIS 2008-30. By letter dated 

April 4, 2012, the staff issued RAI B.1.19-2 requesting the applicant to justify the actions taken 
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for the period of extended operation to address the concerns described in RIS 2008-30 for any 

reanalysis that will use stress-based fatigue monitoring. In addition, the applicant was 

requested to justify the actions that have been taken to ensure that the potential 

nonconservative methods described in RIS 2008-30 have not challenged the ability to maintain 

the allowable limit for those locations that currently use stress-based fatigue monitoring.

In its response dated May 3, 2012, the applicant stated that EAF analyses will be completed 

before the period of extended operation and that any reanalysis to address the effects of the 

reactor coolant environment will use all six stress components for varying principal stress. The 

applicant confirmed that the issues discussed in RIS 2008-30 are being addressed in the CAP

as a CLB issue under 10 CFR Part 50. As part of the corrective actions, Entergy will upgrade 

the stress-based fatigue monitoring software to analyze fatigue using all six stress components; 

thus, during the period of extended operation, any locations that use the stress-based fatigue 

method for the analysis of fatigue will use all six stress components. The staff finds it 

appropriate that the applicant reviewed the concerns discussed in RIS 2008-30 for applicability 

to its site and entered it into its corrective actions program for evaluation and resolution. In 

addition, the staff finds it acceptable that the applicant’s use of stress-based fatigue monitoring 

will consider all six stress components as inputs for the varying principal stress because this is 

consistent with rules defined in ASME Code, Section III.

The applicant stated that based on its evaluation of RIS 2008-30 and industry experience, no 

immediate actions were found to have been needed to ensure that the allowable limit is 

maintained and that potential nonconservatisms in the analyses are not expected to result in 

significant changes to the extent that the calculated fatigue usage would be unacceptable. The 

staff noted that for the locations the applicant is using stress-based fatigue monitoring (i.e., FW 

nozzle, the HPCS nozzle, and the FW weldolets) the calculated CUF value is less than 1.0 and 

the current accumulated cycles for each transient is less than the number of occurrences 

postulated in the fatigue evaluations for these components. The staff noted that for the fatigue 

usage of a component to be to equal the calculated CUF, all transients must have occurred at 

the assumed design limits in terms of occurrence and severity, not just one individual transient. 

Therefore, the staff finds the applicant’s determination not to take immediate actions regarding 

RIS 2008-30 to be reasonable.

The staff finds the applicant’s response to RAI B.1.19-2 acceptable because its program was 

capable of (1) identifying and evaluating generic operating experience as being applicable to its 

site, (2) assessing the need as to whether any immediate actions were needed, as described 

above and (3) determining that long-term actions were needed to upgrade its fatigue monitoring 

software for the period of extended operation. The staff’s concern identified in RAI B.1.19-2 is 

resolved.

The “operating experience” program element of GALL Report AMP X.M1 recommends that the 

program review industry experience relevant to fatigue cracking. The staff noted that 

RIS 2011-14 was issued on December 29, 2011, and is associated with the implementation of 

computer software packages used to demonstrate the ability of nuclear power plant components 

to withstand the cyclic loads associated with plant transient operations. During its audit, the 

staff noted that the applicant uses the computer software, FatiguePro, and it is not clear if the 

data collected by FatiguePro is reviewed and modified before the determination of cumulative 

fatigue usage for a component or of an accrued transient cycle. By letter dated April 4, 2012, 

the staff issued RAI B.1.19-5 requesting the applicant to describe and justify any actions that 

have been or will be taken to address the concerns described in RIS 2011-14. In addition, the 

applicant was requested to describe the activities that are performed to the information and data 
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that is collected by FatiguePro before determining the cumulative fatigue usage for a component 

or an accrued transient cycle.

In its response dated May 3, 2012, the applicant stated that its Fatigue Monitoring Program is 

being upgraded under the CAP to use monitoring software that analyzes fatigue using all six 

stress components for locations that use stress-based fatigue monitoring and that this upgrade 

will include consideration of RIS 2011-14. The applicant explained that its procedures specify 

that the basis for engineering judgment must be documented in the body of the calculation and 

confirmed that its program does not perform NB-3600 analysis.

The staff finds it appropriate that the applicant reviewed the concerns discussed in RIS 2011-14 

for applicability to its site and entered it into its corrective actions program for evaluation and 

resolution. In addition, the staff finds it appropriate that no immediate actions were needed 

because the applicant’s procedures require the basis for engineering judgment to be 

documented, consistent with the principles defined in the “design control” and “quality 

assurance records” elements of Appendix B to 10 CFR Part 50.

The staff finds the applicant’s response to RAI B.1.19-5 acceptable because the applicant’s 

program was capable of (1) identifying and evaluating generic operating experience as possibly 

being applicable to its site, (2) ensuring that no immediate actions were needed in response to 

this RIS, as described above, and (3) determining that long-term actions were needed to 

upgrade its fatigue monitoring software. The staff’s concern identified in RAI B.1.19-5 is 

resolved.

Based on its audit and review of the application, and review of the applicant’s responses to 

RAIs B.1.19-2 and B.1.19-5, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which the corresponding GALL 

Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.19 provides the UFSAR supplement for the Fatigue 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.0-1 and noted that it does not include a description of the monitoring methods used to 

manage fatigue. The licensing basis for this program for the period of extended operation may 

not be adequate if the applicant does not incorporate this information into its UFSAR 

supplement. By letter dated April 4, 2012, the staff issued RAI B.1.19-1 requesting, in part, that 

the applicant include a description of the monitoring methods that the Fatigue Monitoring 

Program will use to manage cumulative fatigue damage.

In its response dated May 3, 2012, the applicant amended LRA Section A.1.19 to include a 

summary description of the monitoring methods it will use to manage cumulative fatigue 

damage during the period of extended operation. Specifically, the applicant included a 

description of how cycle counting, cycle-based fatigue monitoring and stress-based fatigue 

monitoring will be used to manage fatigue during the period of extended operation. The staff 

finds the applicant’s response acceptable because the applicant included a summary 

description that describes the three monitoring methods and how they will be used to manage 

fatigue. Therefore, the UFSAR supplement for the Fatigue Monitoring Program is consistent 

with the corresponding program description in SRP-LR Table 3.0-1 and describes how its 
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program will manage metal fatigue, including EAF, during the period of extended operation. 

This portion of the staff’s concern described in RAI B.1.19-1 is resolved.

The staff also noted that LRA Section A.1.19 includes the enhancements described above to 

make the applicant’s program consistent with GALL Report AMP X.M1 and make the program 

capable of managing fatigue before the period of extended operation.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 3, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fatigue 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 exception and its 

justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. Also, the staff reviewed the enhancements and confirmed that their 

implementation before the period of extended operation will make the AMP adequate to manage 

the applicable aging effects. 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 Fire Protection

Summary of Technical Information in the Application. LRA Section B.1.20 describes the 

existing Fire Protection Program as consistent, with enhancements, with GALL Report

AMP XI.M26, “Fire Protection.” The LRA states that the program manages cracking, loss of 

material, and change in material properties for components with a fire barrier intended function 

through the use of visual inspections. The LRA also states that the program manages loss of 

material for the halon and CO2 fire suppression systems using visual inspections and testing.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M26. For the “scope of 

program” program element, the staff determined the need for additional information, which 

resulted in the issuance of RAIs, as discussed below.

The “scope of program” program element of GALL Report AMP XI.M26, “Fire Protection,” states 

that the program includes visual inspections of fire barrier penetration seals, walls, ceilings, 

floors, doors, and other fire resistant materials that perform a fire barrier function. During its 

audit of the applicant’s Fire Protection Program, the staff noted that the applicant has fire 

barriers constructed of the materials Thermo-lag and 3M Interam. These materials are included 

in the fire barrier inspection procedures, but the LRA does not include aging management 

results for any components constructed of the materials Thermo-lag or 3M Interam. It is unclear 

to the staff why the Thermo-Lag and 3M Interam fire barrier materials are not included in the 

LRA given that the materials are used at the plant and are included in the plant’s inspection 

procedures. By letter dated April 17, 2012, the staff submitted RAI B.1.20-1 requesting that the 

applicant state why there are no fire barriers constructed of Thermo-Lag and 3M Interam being 

managed for aging in the LRA, or revise the LRA to include aging management of these 

materials.
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In its response dated May 15, 2012, the applicant stated that Thermo-lag and 3M Interam are 

materials used in fire wraps at the site and were included in the AMR item for fire wraps in LRA

Table 3.5.2-4. The applicant revised the LRA to add Thermo-lag and 3M Interam to the material 

column of the fire wrap AMR item in LRA Table 3.5.2-4 and to the materials section of LRA 

Section 3.5.2.1.4. The staff finds the applicant’s response acceptable because the applicant 

has revised the LRA to include aging management of Thermo-lag and 3M Interam fire wraps. 

The staff’s concern described in RAI B.1.20-1 is resolved.

The “scope of program” program element of GALL Report AMP XI.M26, “Fire Protection,” states 

that the program manages aging effects for the halon and CO2 fire suppression systems. 

GALL Report AMP XI.M26 relies on visual inspections and functional tests to manage aging for 

halon and CO2 fire suppression system components. During its audit of the applicant’s Fire 

Protection Program, the staff noted that the applicant’s CO2 fire suppression system includes an 

outdoor CO2 tank and that the exterior surface of the tank is not readily accessible for visual 

inspection, as it is covered with an outer steel housing and an intermediate insulation layer. 

However, based on the staff’s review of LRA Table 3.3.2-13 and a search of all tanks contained 

in the LRA, it appears that there is no AMR item for this tank. It is unclear to the staff why the 

LRA does not include the outdoor CO2 tank and how this tank will be managed for aging during 

the period of extended operation. By letter dated April 17, 2012, the staff submitted

RAI B.1.20-2 requesting that the applicant: (a) justify why there is no AMR item for the outdoor 

CO2 tank or include an AMR item for the tank; (b) if the tank sits directly on concrete or soil, 

state whether sealant or caulking is used at the external surface interface between the tank and 

concrete or earthen foundation, or state the basis for why sealant or caulking is not used; (c) if 

the tank sits directly on concrete or soil and the tank is not being managed for aging using the 

Aboveground Metallic Tanks Program, state the basis for why there is reasonable assurance 

that the tank will perform its current license basis functions throughout the period of extended 

operation; and (d) if the tank does not sit directly on concrete or soil, state the inspection 

methodology and frequency of inspections that will be used to manage aging given that the 

exterior surface of the tank is not readily accessible.

In its response dated May 15, 2012, the applicant stated for question (a) that the CO2 tank is 

included in the AMR item for carbon steel tank exposed to air indoor uncontrolled in LRA

Table 3.3.2-13. The applicant also stated that the environment is considered air indoor 

uncontrolled because the tank is inside an enclosure and is insulated. In its response to 

questions (b) and (c) the applicant stated that the tank is not in contact with concrete or soil. In 

its response to question (d) the applicant stated that the area around the tank inside the 

enclosure that is accessible will be monitored for moisture or rust stains emanating from the 

insulation using the Fire Protection Program to manage loss of material. The applicant revised 

the Fire Protection Program to include an enhancement to visually inspect the external surfaces 

of the CO2 tank for signs of corrosion at least once every fuel cycle.

The staff reviewed the applicant’s response to question (a) of RAI B.1.20-2 in the letter dated 

May 15, 2012, and noted that the GALL Report defines “air – indoor uncontrolled” as indoor air 

associated with systems whose temperatures are above the dew point such that condensation 

can occur, but only rarely. The GALL Report defines “air – outdoor” as outdoor air associated 

with components exposed to atmospheric air, ambient temperatures, humidity, and weather, 

including precipitation and wind. The CO2 tank is located outdoors surrounded by insulation 

and a metal housing. The staff noted that the metal housing will protect the CO2 tank from 

precipitation and wind, but the metal housing will not protect the CO2 tank from humidity or the 

temperature extremes experienced outdoors. The staff noted that, for the carbon steel CO2

tank, the inspection methods are the same regardless of whether the tank is exposed to indoor 
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or outdoor air. However, that may not be true for components constructed of other materials. 

By letter dated July 17, 2012, the staff issued RAI B.1.20-2a requesting, in part, that the 

applicant state whether there are any other components in the LRA that are outdoors but have 

been evaluated as exposed to indoor air.

In its response dated August 13, 2012, the applicant stated that there are no other components 

in the LRA that are outdoors but were evaluated as exposed to indoor air. The staff finds this 

part of the applicant’s response acceptable because there are no other outdoor items which 

have been evaluated as exposed to indoor air, and the CO2 tank will be managed for exposure 

to humidity using the Fire Protection Program, as discussed below.

The staff reviewed the applicant’s response to questions (b) and (c) of RAI B.1.20-2 in a letter 

dated May 15, 2012, and noted that use of sealants or caulking and the Aboveground Metallic 

Tanks Program is only applicable to tanks that sit on concrete or soil. The staff finds this part of 

the applicant’s response acceptable because the CO2 tank does not sit on concrete or soil.

The staff reviewed the applicant’s response to question (d) of RAI B.1.20-2 in the letter dated 

May 15, 2012, and noted that during the staff’s walkdown of the outdoor CO2 tank, there did not 

appear to be any accessible portions of the tank or its foundation since the metal housing 

surrounding the tank covers the base of the tank and did not appear to have any access ports. 

The staff finds the applicant’s response to question (d) unacceptable because it is unclear to the

staff what portion of the tank will be made accessible for visual inspection or how an inspection 

for moisture or rust stains emanating from the tank is sufficient to detect loss of material from 

the tank before loss of intended function. By letter dated July 17, 2012, the staff issued 

RAI B.1.20-2a requesting, in part, that the applicant state what portion of the tank will be made 

accessible for visual inspection or how an inspection for moisture or rust stains emanating from 

the tank is sufficient to detect loss of material from the tank prior to loss of intended function.

In its response dated August 13, 2012, the applicant stated that the metal housing surrounding 

the CO2 tank has a 3-foot diameter-bolted access cover which can be removed to perform the 

visual inspections. The applicant also stated that inspection techniques used for confined 

spaces, such as boroscopes and mirrors, will be used to examine a wide surface area of the 

tank. The applicant further stated that a bare metal inspection will be performed when the 

insulation is removed for maintenance, which is consistent with the guidance in GALL Report 

AMP XI.M36, “External Surfaces Monitoring of Mechanical Components.” However, the staff 

noted that GALL Report AMP XI.M36 states that insulated surfaces may be inspected when the 

external surface is exposed (i.e., during maintenance) at such intervals that would ensure that 

the components’ intended functions are maintained. The applicant’s response did not address 

the frequency at which the bare metal inspections of the tank would be performed or the 

percentage of bare metal that would be exposed during the inspections. By letter dated 

September 14, 2012, the staff issued RAI B.1.20-2b requesting that the applicant state what 

portion of the CO2 tank will be made accessible for bare metal inspection and the frequency or 

basis for the frequency at which bare metal inspections of the CO2 tank will be performed.

In its response dated October 15, 2012, the applicant stated that the metal housing is a welded 

steel enclosure which is an integral part of the tank skid and access to the bare metal tank is 

only available through the access cover. Since only a small portion of the tank is accessible 

through the access cover, the applicant stated that tank level and pressure will be monitored 

daily during the period of extended operation, in addition to the visual inspection of the exterior 

surface of the tank through the access cover every refuel cycle. The applicant revised the 

program description and the UFSAR supplement to include monitoring tank level and pressure 
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daily. The staff finds the applicant’s response to RAI B.1.20-2b acceptable because monitoring 

tank level and pressure daily will ensure any breach in the tank integrity is quickly identified and 

visual inspections of the accessible portions of the tank every refuel cycle will ensure any 

degradation of the tank exterior is identified. The staff’s concerns originally described in 

RAI B.1.20-2 are resolved.

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” program elements associated with the enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.20 states an enhancement to the “parameters monitored or 

inspected” and “detection of aging effects” program elements. In this enhancement, the 

applicant stated that the Fire Protection Program will be enhanced to require visual inspection of 

the halon and CO2 fire suppression systems for signs of corrosion at least once every fuel cycle. 

The “detection of aging effects” program element of GALL Report AMP XI.M26 states that visual 

inspections of the halon and CO2 fire suppression systems should be performed to identify signs 

of corrosion. During the audit the staff confirmed that the applicant’s proposed frequency of 

once every fuel cycle is in accordance with its existing NRC-approved fire protection program as 

documented in its Technical Requirements Manual. The staff reviewed this enhancement 

against the corresponding program elements in GALL Report AMP XI.M26 and finds it 

acceptable because when it is implemented it will make the program consistent with the GALL 

Report recommendations by requiring visual inspections of the halon and CO2 fire suppression 

systems.

Enhancement 2. LRA Section B.1.20 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to require visual inspection of fire damper framing at least once per refuel cycle for degradation. 

The “detection of aging effects” program element of GALL Report AMP XI.M26 states that visual 

inspections should be performed for fire barrier walls, ceiling, floors, doors, and other fire barrier 

materials on a frequency consistent with the applicant’s NRC-approved fire protection program. 

During the audit the staff confirmed that the applicant’s proposed frequency of once every fuel 

cycle is in accordance with its existing NRC-approved fire protection program as documented in 

its Technical Requirements Manual. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M26 and finds it acceptable because 

when it is implemented it will make the program consistent with the GALL Report

recommendations by requiring visual inspections of fire barriers.

Enhancement 3. LRA Section B.1.20 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to require visual inspections of concrete curbs, manways, hatches, manhole covers, hatch 

covers, and roof slabs at least once every fuel cycle to confirm aging effects are not occurring. 

The “detection of aging effects” program element of GALL Report AMP XI.M26 states that visual 

inspections should be performed for fire barrier walls, ceiling, floors, doors, and other fire barrier 

materials on a frequency consistent with the applicant’s NRC-approved fire protection program. 

During the audit, the staff confirmed that the applicant’s proposed frequency of once every fuel 

cycle is in accordance with its existing NRC-approved fire protection program as documented in 

its Technical Requirements Manual. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M26 and finds it acceptable because,

when it is implemented, it will make the program consistent with the GALL Report

recommendations by requiring visual inspections of various types of fire barriers.
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Enhancement 4. LRA Section B.1.20, as amended by letter dated May 15, 2012, states an 

enhancement to the “parameters monitored or inspected” and “detection of aging effects”

program elements. In this enhancement, the applicant stated that the Fire Protection Program

will be enhanced to require an external visual inspection of the CO2 tank at least once every fuel 

cycle. The “detection of aging effects” program element of GALL Report AMP XI.M26 states 

that visual inspections of the CO2 fire suppression system should be performed to detect any 

signs of corrosion. As discussed in the “Staff Evaluation” section above, the CO2 tank is mostly 

inaccessible for visual inspection because it is enclosed in a welded metal housing. Therefore, 

visual inspection of the accessible portions of the tank coupled with monitoring the level and 

pressure in the tank will be used to manage loss of material. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M26 and 

finds it acceptable because when it is implemented it will ensure any degradation of the tank 

exterior is identified consistent with the GALL Report recommendations.

Summary. Based on its audit and review of the LRA and the applicant’s responses to 

RAIs B.1.20-1, B.1.20-2, B.1.20-2a, and B.1.20-2b, the staff finds that the program elements for 

which the applicant claimed consistency with GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M26. In addition, the staff reviewed 

the enhancements and finds that when implemented, they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B.1.20 summarizes operating experience related to the 

Fire Protection Program. The LRA states that inspections have identified small tears in fire 

doors, rust on fire doors, cracks in fire doors, missing pieces of fireproofing, and missing 

Kaowool in penetration seals. The LRA also states that these deficiencies were repaired. The 

LRA further states that audits and self-assessments have been conducted to identify 

recommendations to upgrade the program to ensure its effectiveness.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.20 provides the UFSAR supplement for the Fire 

Protection Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.0-1 and noted that LRA Section A.1.20 does not state that the program includes 

functional tests of fire-rated doors. The licensing basis for this program for the period of 

extended operation may not be adequate if the applicant does not incorporate this information 

into its UFSAR supplement. By letter dated April 17, 2012, the staff issued RAI B.1.20-3 
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requesting that the applicant revise LRA Section A.1.20 to include functional tests of 

fire-rated doors.

In its response dated May 15, 2012, the applicant revised the UFSAR supplement to state that 

the program includes functional tests of fire-rated doors. The staff finds the applicant’s 

response acceptable because the applicant has amended the UFSAR supplement to include 

functional tests of fire-rated doors. Therefore, the UFSAR supplement for the Fire Protection 

Program is consistent with the corresponding program description in SRP-LR Table 3.0-1. The 

staff’s concern described in RAI B.1.20-3 is resolved.

The staff noted that the applicant committed (Commitment No. 11) to enhance the Fire 

Protection Program to require visual inspections at least once every fuel cycle of the halon and 

CO2 fire suppression systems for signs of corrosion; fire damper framing for degradation; and 

concrete curbs, manways, hatches, manhole covers, hatch covers, roof slabs to confirm aging 

effects do not occur; and the external surfaces of the CO2 tank for signs of corrosion.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

October 15, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Protection Program, the 

staff determines that the program elements for which the applicant claimed consistency with the 

GALL Report are consistent with the corresponding program elements of GALL Report

AMP XI.M26. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 11 prior to the period of extended operation will make 

the AMP adequate to manage the applicable aging effects. 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 Fire Water System

Summary of Technical Information in the Application. As amended by letters dated May 15, 

2012, June 27, 2012, August 13, 2012, May 13, 2014, November 6, 2014, May 20, 2015,

August 19, 2015, and November 23, 2015, LRA Section B.1.21 describes the existing Fire 

Water System Program as consistent, with exceptions and enhancements, with GALL Report 

AMP XI.M27, “Fire Water System,” as modified by LR-ISG-2012-02. The LRA states that the 

program manages loss of material, fouling, and loss of coating integrity for components in fire 

protection systems through the use of preventive, inspection, and monitoring activities, including 

flush tests and testing and replacement of sprinkler heads. The LRA also states that the system 

is maintained at required pressure and actions are taken upon a loss of system pressure.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M27. For the “scope of 

program” program element, the staff determined the need for additional information, which 

resulted in the issuance of RAIs, as discussed below.

GALL Report AMP XI.M27 applies to water-based fire protection systems that consist of 

sprinklers, nozzles, fittings, valves, fire pump casings, hydrants, hose stations, standpipes, 

water storage tanks, and aboveground, buried, and underground piping and components that 

are tested in accordance with the applicable National Fire Protection Association (NFPA) codes 

and standards. Buried fire main piping and sprinkler heads exposed to both air and water are 
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included within the scope of GALL Report AMP XI.M27. LRA Section 2.3.3.12 states that the 

applicant’s fire water system includes both wet-pipe and dry-pipe sprinkler systems. However, 

there are no AMR items for sprinkler heads and no AMR items for copper-alloy components 

exposed to air for which aging effects are being managed using the Fire Water System 

Program. LRA Section 2.3.3.12 states that the underground yard loop is constructed of 

cement-lined cast iron piping. However, there are no AMR items in the LRA for cast iron or 

carbon steel piping exposed to cement or for cement-lined piping.

It is not clear to the staff whether the aging effects associated with the cement-lined cast iron 

yard loop and sprinkler heads will be managed using the Fire Water System Program. There 

are activities in the Fire Water System Program capable of managing aging effects for these 

components, but there are no AMR items that reference the Fire Water System Program. By 

letter dated April 17, 2012, the staff issued RAI B.1.21-2 requesting that the applicant list AMR 

items for the sprinkler heads and cement-lined cast iron yard loop as stated above.

In its response dated May 15, 2012, the applicant stated that no credit is taken for the concrete 

lining in the cast iron yard loop to prevent aging effects; therefore, the yard loop is listed as 

carbon steel piping in LRA Table 3.3.2-12. The staff finds the applicant’s response acceptable 

because the buried fire main is being managed for aging of the internal surfaces using the Fire 

Water System Program consistent with the GALL Report recommendations. However, as 

amended by letter dated May 13, 2014, LRA Table 3.3.2-12 states that metallic piping with 

Service Level III or other internal coating exposed to raw water is managed for loss of coating 

integrity by the Periodic Surveillance and Preventive Maintenance Program. The staff’s 

evaluation of the use of the Periodic Surveillance and Preventive Maintenance Program to 

manage loss of coating integrity is documented in SER Section 3.0.3.3. The staff finds the use 

of this program to manage the internally coated surfaces of this fire protection piping acceptable 

because periodic visual examinations conducted in accordance with the Periodic Surveillance 

and Preventive Maintenance Program are capable of detecting loss of coating (inclusive of 

cement lining) integrity.

In its response dated May 15, 2012, the applicant also stated that sprinklers are listed as 

nozzles in LRA Table 3.3.2-12 and that they are managed by the Fire Water System and 

Selective Leaching Programs. However, the staff noted that the only entry for nozzles in LRA 

Table 3.3.2-12 that uses the Fire Water System Program to manage aging is the AMR item for 

nozzles exposed to raw water. The AMR items for nozzles exposed to indoor air state that the 

components have no AMR. As stated in RAI B.1.21-2, sprinkler heads exposed to both air and 

water are included within the scope of GALL Report AMP XI.M27. It is unclear to the staff why 

aging effects associated with the nozzles exposed to air do not require aging management. By 

letter dated July 17, 2012, the staff issued follow-up RAI B.1.21-2a requesting that the applicant 

state the basis for why the nozzles exposed to indoor air do not require aging management.

In its response dated August 13, 2012, the applicant stated that the nozzles exposed to indoor 

air have no aging effects identified, consistent with GALL Report item VII.J.AP-144. However, 

the applicant also stated that aging effects associated with all sprinkler heads within the scope 

of license renewal will be managed by the Fire Water System Program, regardless of whether 

aging effects are identified. The staff finds the applicant’s response acceptable because all 

sprinkler heads within the scope of license renewal will be replaced or tested consistent with the 

recommendations in GALL Report AMP XI.M27. The staff’s concerns described in 

RAIs B.1.21-2 and B.1.21-2a are resolved.
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Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, which revised several 

AMPs, including the guidance for AMP XI.M27, “Fire Water System.” By letter dated 

January 2, 2014, the staff issued RAI 3.0.3-1 requesting that the applicant provide details on 

how the updated guidance of LR-ISG-2012-02 has been accounted for in the LRA AMPs, or 

provide adequate justification for why incorporation is not required.

In its responses dated May 13, 2014; November 6, 2014; May 20, 2015; August 19, 2015; and 

November 23, 2015, the applicant modified existing enhancements and added exceptions.

The staff reviewed the portions of the “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” and “corrective actions” program 

elements associated with the exceptions and enhancements to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

these exceptions and enhancements follows.

Exception 1. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception the applicant 

stated that it will perform sprinkler inspections on a 24-month interval in lieu of annual testing 

required by NFPA 25, “Standard for the Inspection, Testing, and Maintenance of Water-Based 

Fire Protection Systems,” Section 5.2.1. The applicant also stated that the 24-month inspection 

interval has been effective at maintaining component-intended function. The staff noted that 

NFPA 25 was written for a broad range of facilities, including those with a few sprinklers (e.g., a 

small manufacturing facility with only a dozen sprinklers) and those with numerous sprinklers 

(as is typical for power plants). The staff reviewed this exception against the corresponding 

program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because the applicant 

stated that the 24-month inspection interval has not resulted in a loss of intended functions in 

the past, the staff’s independent search of plant-specific operating experience during the audit 

did not reveal any evidence that sprinkler degradation was occurring, and a sufficient number of 

sprinklers are installed in commercial nuclear power plants to establish an adverse performance 

trend, even with plant-specific inspections being completed on a 24-month basis rather than 

annually.

Exception 2. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that sprinklers will not be inspected for orientation, foreign material, physical damage, 

and loading due to dust or debris, as required by NFPA 25 Section 5.2.1.1. The staff noted that 

LR-ISG-2012-02 AMP XI.M27 Table 4a, “Fire Water System Inspection and Testing 

Recommendations,” footnote 1, states that: “[t]his table specifies those inspections and tests 

that are related to age-managing applicable aging effects associated with loss of material and 

flow blockage for passive long-lived, in-scope components in the fire water system.” The staff 

also noted that Enhancement No. 6 states that the Fire Water System procedures will be 

enhanced to include inspections of sprinklers in the overhead from the floor. The staff reviewed 

this exception against the corresponding program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because sprinkler inspections will be conducted to detect corrosion, this 

being the age-related aging effect identified in NFPA 25 Section 5.2.1.1.1, and inspecting 

sprinklers from the floor is consistent with NFPA 25 and therefore, LR-ISG-2012-02 

AMP XI.M27.

Exception 3. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it will not perform flow testing at the hydraulically most remote hose connections of 
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each zone of an automatic standpipe system to verify that the water supply provides the design 

pressure, as required by NFPA 25 Section 6.3.1. The applicant also stated that it alternatively: 

(a) performs main header flow testing every 3 years (reference response to RAI 3.0.3-1-FWS-1 

dated November 6, 2014) in seven loops that supply the standpipe system to verify that the 

water supply provides the design pressure and required flow, (b) tests the fire water hose 

stations, including approximately 43 fire water hose stations in the auxiliary building, 16 in the 

containment building, 2 in the emergency diesel generator (EDG) building, and 13 in the control 

building every 3 years to ensure that there is no blockage, and (c) performs an annual “version” 

of a main drain test in each building on a portion of the deluge and sprinkler systems. The 

applicant further stated that the acceptance criteria used to verify an open flow path includes 

verifying flow through the valve and connection and that there are no indications of obstruction 

or other undue restriction of water flow. The applicant stated that NFPA 25 (2014 Edition),

Section 6.3.1, has been revised to state that the testing is only applicable to Class I and 

Class III standpipe systems and its automatic standpipe system is Class II.

The staff noted the following:

• NFPA 25, Section 6.3.1, requires that flow testing be conducted every 5 years.

• The purpose of flow tests is to detect potential flow blockage.

• Exception No. 4 states that 30 main drain tests are conducted, encompassing testing in 

the auxiliary building, turbine building, control building, and EDG building.

• A Class II standpipe system is differentiated from Class I and Class III systems, based 

on the size of the hose stations supplied by the standpipe and its use (e.g., a Class I or 

Class III system supplies a larger volume of water for use by fire departments).

The staff reviewed this exception against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because the proposed alternative testing 

is sufficient to establish reasonable assurance that flow blockage will be detected prior to a CLB

intended function not being met. The staff based this conclusion on: (a) the alternative flow 

tests, both in number, breadth of locations, and frequency, provide insights concerning the 

potential accumulation of corrosion products that are comparable to those gained from the test 

recommended in LR-ISG-2012-02 AMP XI.M27, (b) in regard to the number of tests, main 

header flow testing is conducted every 3 years, 74 hose stations are tested every 3 years to 

verify no flow blockage, and multiple main drain tests are conducted on an annual basis, (c) in 

regard to the breadth of testing, the testing will encompass piping located in five different 

buildings, (d) in regard to the frequency of testing, the alternative tests are conducted more 

frequently than every 5 years, and (e) NFPA 25 (2014 Edition), an industry consensus 

document, has removed the requirement to conduct the test for the class of standpipe used at 

the station.

Exception 4. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that it does not perform main drain tests on all standpipes and risers as required by 

NFPA 25 Sections 6.3.1.5 and 13.2.5. The applicant stated that it performs more than 30 main 

drain tests throughout the plant associated with in-scope standpipes and risers, for example 6 in 

the auxiliary building, 10 in the turbine building, 2 in the control building, and 3 in the EDG 

building. The applicant also stated that the turbine building risers only have an intended 

function, as described in 10 CFR 54.4(a)(2).
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The staff noted the following:

• LR-ISG-2012-02 AMP XI.M38, “Inspection of Internal Surfaces of Miscellaneous Piping 

and Ducting Components,” provides insights related to an acceptable inspection 

sampling methodology to manage aging of components, materials, and environments 

comparable to that in fire water systems. LR-ISG-2012-02 AMP XI.M38 is a program 

based on opportunistic inspections with a recommended inspection of either 20 percent 

or a maximum of 25 components of each material, environment, and aging effect 

combination in each 10-year period of the period of extended operation.

• NFPA 25 (2014 Edition), Sections 13.2.5 and 13.2.5.1, allows a reduced number of main 

drain tests to be conducted. It states: “[a] main drain test shall be conducted annually 

for each water supply lead-in to a building water-based fire protection system to 

determine whether there has been a change in the condition of the water supply. Where 

the lead-in to a building supplies a header or manifold serving multiple systems, a single 

main drain test shall be permitted.”

The staff reviewed this exception against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable, in part, because, although the applicant 

has not proposed to conduct main drain tests in each water-based fire protection system riser, 

the proposed alternative testing is sufficient to establish reasonable assurance that flow 

blockage will be detected prior to a current licensing basis intended function not being met. The 

staff based this conclusion on the following: (a) the main drain tests, both in number and scope 

of locations, provide insights concerning the potential accumulation of corrosion products that 

are sufficient from a sampling basis, (b) in regard to the number of tests, the applicant has 

proposed to periodically perform 30 main drain tests, which exceeds the maximum of 

25 inspections cited in random sampling programs recommended in GALL Report 

AMPs XI.M32, XI.M33, and XI.M38, (c) in regard to the scope of locations, the testing will 

encompass piping located in four different buildings, and (d) given the intended function of risers 

in the turbine building, flow blockage is not an applicable aging effect and, therefore, main drain 

tests need not be conducted for license renewal purposes. However, given the use of the term 

“version” (associated with main drain tests in Exception No. 3), it is not clear to the staff how 

main drain tests are conducted and, as a result, whether the tests have the capability to detect 

potential flow blockage. In addition, Exception No. 4 did not state the periodicity of conducting 

the 30 main drain tests and header flow testing. By letter dated September 11, 2014, the staff 

issued RAI 3.0.3-1-FWS-1 requesting that the applicant state: (a) how main drain tests are 

conducted in comparison to NFPA 25 (2011 Edition) Sections 6.3.1.5 and 13.2.5, and (b) the 

periodicity of conducting the 30 main drain tests and header flow testing.

In its response dated November 6, 2014, the applicant stated that the main drain tests are 

conducted consistent with Section 13.2.5 of NFPA 25, 2011 Edition. The applicant described 

how the tests are conducted (i.e., test location, parameter monitored, test method). The 

applicant stated that a flow blockage evaluation is conducted if “the flowing pressure drops more 

than 10 percent from the previous test in the same location.” The applicant also stated that 

main drain tests are conducted annually and header flow testing is conducted every 3 years.

The staff finds the applicant’s response acceptable, in part, because, based on the staff’s review 

of the applicant’s main drain testing details, the test location, parameter monitored, test method, 

and frequency of testing are consistent with NFPA 25 Section 13.2.5. In addition, header flow 

testing is conducted more frequently than required by NFPA 25 Section 6.3.1, every 3 years 

versus every 5 years. However, the applicant’s acceptance criteria are not consistent with 

NFPA 25 Section 13.2.5, which states that the 10-percent reduction in full flow pressure should 
3-109

be compared to the original acceptance test or previously performed tests, not only the 

“previous test.” By comparing the result of the main drain test to only the previous test,

decreases in full flow pressure (indicative of potential flow blockage) could accumulate over time 

and exceed a 10-percent reduction in flow. By letter dated April 6, 2015, the staff issued 

RAI 3.0.3-1-FWS-1a, requesting that the applicant state the basis for how comparing the current 

test result to only the previous test result will be effective in determining whether potential flow 

blockage is occurring and how effective trending can be accomplished.

In its response dated May 20, 2015, the applicant revised LRA Section A.1.21, Enhancement 

No. 18, and Commitment No. 12, to state, “[r]evise Fire Water System procedures to perform a 

flow blockage evaluation if, during main drain testing, the flowing pressure drops more than 

10 percent from the flowing pressure observed during the original acceptance test or other 

previously performed tests at the same location.”

The staff finds the applicant’s response acceptable because the revised exception is consistent 

with LR-ISG-2012-02 AMP XI.M27 and NFPA 25 Section 13.2.5, which can ensure that an 

adequate number of data points are reviewed in order to determine a trend in performance. The 

staff’s concern described in RAIs 3.0.3-1-FWS-1 and 3.0.3-1-FWS-1a is resolved. The staff 

reviewed this exception against the corresponding program element in LR-ISG-2012-02 

AMP XI.M27 and finds it acceptable, based on the above staff finding statements.

Exception 5. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that the calibration of gauges (NFPA 25 Section 6.3.1.5.2) is part of ongoing operations 

and is not part of the Fire Water System Program. The staff reviewed this exception against the 

corresponding program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because the calibration of test equipment is not addressed in LR-ISG-2012-02 AMP XI.M27 and 

the staff recognizes that the calibration of gauges is controlled by plant-specific procedures.

Exception 6. As amended by letter dated August 19, 2015, LRA Section B.1.21 states an 

exception to the “detection of aging effects” program element. In this exception, the applicant 

stated that, in relation to testing in accordance with NFPA 25 Section 9.2.7 (1), “[a]lternate 

adhesion tests endorsed in Reg Guide 1.54 may apply.” The applicant also stated that, 

“[a]lternative adhesion testing endorsed by Reg. Guide 1.54 will be applied as alternative testing 

when required.” The applicant stated that when indications of coating degradation are identified 

in the fire water tank coating, the applicant performs holiday testing. In addition, GGNS 

performs ultrasonic thickness checks or mechanical measurements of any corroded areas.

The staff noted that NFPA 25 Sections 9.2.6.4 and 9.2.7.1 require adhesion testing when steel 

tanks exhibit signs of interior pitting, corrosion, or failure of coating. RAI 3.0.3-1-FWS-2 part (b) 

and RAI 3.0.3-1-FWS-2a (issued by letter dated April 6, 2015) became not applicable, based on 

the revisions to Exception No. 6 and Enhancement Nos. 9 and 23, and the addition of 

Enhancement No. 26, as described in the letter dated August 19, 2015. These two RAIs 

requested that the applicant state what alternatives it would use in regard to adhesion testing. 

The staff reviewed this exception against the corresponding program element in 

LR-ISG-2012-02 AMP XI.M27 and LR-ISG-2013-01, “Aging Management of Loss of Coating or 

Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat 

Exchangers, and Tanks,” and finds it acceptable, because RG 1.54, “Quality Assurance 

Requirements for Protective Coatings Applied to Water-Cooled Nuclear Power Plants,” includes 

staff-endorsed standards for conducting adhesion testing, in addition to the method cited in 

NFPA 25 Section 9.2.7 (1).
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Exception 7. As amended by letter dated November 6, 2014, Exception No. 7, originally cited in 

the letter dated May 13, 2014, was deleted. The exception had stated that the deluge valves 

associated with the charcoal filters, turbine building hydrogen seal oil reservoir, and recirculation 

feed pump turbine (RFPT) lube oil reservoir are not full flow tested as required by NFPA 25 

Section 13.4.3.2.2. The applicant stated that the turbine building hydrogen seal oil and RFPT 

lube oil reservoir deluge valves only have an intended function as described in 

10 CFR 54.4(a)(2). The applicant further stated that the deluge systems associated with the 

auxiliary building standby containment cooling system and containment vent charcoal filters are 

not trip tested due to the potential for water damaging the charcoal in the filter units. The 

applicant stated that the piping downstream of manual deluge trip valves is dry and the deluge 

nozzles are within the filter housing and not easily accessible. The applicant also stated that the 

nozzles are inspected when charcoal is replaced (Enhancement No. 10).

The staff noted that NFPA Section 13.4.3.2.2.5(A) states: “[w]here the nature of the protected 

property is such that water cannot be discharged, the nozzles or open sprinklers shall be 

inspected for correct orientation and the system tested with air to ensure that the nozzles are 

not obstructed.”

The staff concluded that, given the intended function of the turbine building hydrogen seal oil 

and RFPT lube oil reservoir deluge valves, flow blockage is not an applicable aging effect and 

therefore deluge valve testing need not be conducted for license renewal purposes. However, 

given that deluge valve flow testing can be conducted using air, it was not clear why full flow 

testing of deluge valves in the remaining systems cannot be conducted in accordance with 

NFPA 25. By letter dated September 11, 2014, the staff issued RAI 3.0.3-1-FWS-3 requesting 

that the applicant state the basis for why: (a) full flow testing of deluge valves cannot be 

conducted in accordance with NFPA 25, and (b) there is reasonable assurance that flow 

blockage will be detected when full flow deluge valve testing is not conducted.

In its response dated November 6, 2014, the applicant deleted Exception No. 7 and revised its 

Fire Water System program to include Enhancement No. 19. This enhancement states that air 

flow testing will be conducted to detect flow obstructions downstream of the deluge valves for 

the control room fresh air, auxiliary building standby gas, containment cooling system, and 

containment vent charcoal filter units on a refueling cycle interval.

The staff finds the applicant’s response and deletion of Exception No. 7 acceptable because 

conducting air flow testing in order to demonstrate the absence of flow blockage downstream of

deluge valves is an acceptable method as cited in NFPA 25. The staff’s concern described in 

RAI 3.0.3-1-FWS-3 is resolved.

Enhancement 1. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “parameters monitored or inspected” program element. In this 

enhancement, the applicant stated that the program will be enhanced to include periodic visual 

inspection of spray and sprinkler system internals for degradation. The staff noted that the 

wording, “[a]cceptance criteria will be enhanced to verify no unacceptable degradation,” was 

deleted in this amendment; however, it was replaced by Enhancement No. 13. The staff’s 

evaluation of this change is documented below. The staff reviewed this enhancement against 

the corresponding program element in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, it will enhance the program to include internal visual 

inspections of spray and sprinkler system piping consistent with LR-ISG-2012-02 AMP XI.M27 

recommendations.
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Enhancement 2. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that it will enhance the program to include periodic inspection of hose reels for 

degradation. GALL Report AMP XI.M27 recommends that water-based fire protection system 

components, including hose stations, be tested to ensure minimum functionality of the system is 

maintained. In its response to RAI 3.5.2.4-4, dated July 27, 2012, which is documented in SER 

Section 3.5.2.1.4, the applicant stated that the hose stations will be inspected annually. An 

annual hose station inspection frequency is consistent with the recommendations in NFPA 25 

and further clarifies the periodic inspection frequency this enhancement describes. The staff 

reviewed this enhancement against the corresponding program elements in GALL Report 

AMP XI.M27 and finds it acceptable because, when it is implemented, it will enhance the 

program to include inspection of hose reels to ensure minimum functionality is maintained, 

consistent with the GALL Report recommendations. The staff noted that the wording, 

“[a]cceptance criteria will be enhanced to verify no unacceptable degradation,” was deleted in 

this amendment. The staff finds this acceptable because the “acceptance criteria” program 

element in LR-ISG-2012-02 AMP XI.M27 does not include any recommendations related to 

acceptance criteria for hose reel inspections and therefore it is acceptable to use plant-specific 

inspection acceptance criteria.

Enhancement 3. LRA Section B.1.21 stated an enhancement to the “detection of aging effects” 

program element; however, as amended by letter dated May 13, 2014, this enhancement was 

deleted. In this enhancement, the applicant had stated that the program will be enhanced to 

include either wall thickness evaluations using nonintrusive techniques or visual inspections of 

the internal surfaces of fire protection piping upon each entry to the system for routine or 

corrective maintenance. The staff finds the deletion of this enhancement acceptable because 

LR-ISG-2012-02 AMP 27 does not recommend the use of wall thickness evaluations in lieu of 

internal inspections and the Fire Water System Program has been amended to be consistent, 

with exception, to LR-ISG-2012-02 AMP XI.M27. The staff noted that the responses to 

RAI B.1.21-3 and RAI B.1.21-3a, dated May 15, 2012, and August 13, 2013, respectively, are 

no longer applicable as they were related to the periodic performance of visual inspections 

based on GALL Report AMP XI.M27 and not LR-ISG-2012-02 AMP XI.M27.

Enhancement 4. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the program will be enhanced to include visual inspection of the interior 

surface of below grade fire protection piping for a representative number of locations at least 

once every 10 years during the period of extended operation. A representative sample will be 

20 percent of each population having the same material, environment, and aging effect 

combination, with a maximum of 25 inspections.

It was unclear to the staff whether flow testing will be conducted in addition to visual inspections 

to manage aging for the below grade fire protection piping. If only visual inspections will be 

performed, it is unclear to the staff whether the 10-year inspection frequency will be adequate. 

By letter dated April 17, 2012, the staff issued RAI B.1.21-4 requesting that the applicant clarify 

whether flow testing and visual inspections will be used to manage aging for the below grade 

fire protection piping; and, if only visual inspections will be performed, state the basis for the 

frequency of inspections, including any past inspection results that support the chosen 

inspection frequency.

In its response dated May 15, 2012, the applicant stated that both flow testing and visual 

inspections will be used to manage aging for the below grade fire protection piping. The 
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applicant stated that flow testing is performed every 3 years and includes below ground piping. 

The staff finds the applicant’s response acceptable because flow testing will be performed every 

3 years and visual inspections will be performed every 10 years to manage aging for the internal 

surfaces of below ground fire protection piping. The staff’s concern described in RAI B.1.21-4 is 

resolved.

The staff reviewed this enhancement against the corresponding program elements in GALL 

Report AMP XI.M27 and finds it acceptable because, when it is implemented, it will enhance the 

program to include visual inspections of the internal surfaces of below grade piping at a 

sufficient frequency on a reasonable number of locations, consistent with the GALL Report 

recommendations. The staff noted that the wording, “[a]cceptance criteria will be enhanced to 

verify no unacceptable degradation,” was deleted in this amendment; however, it was replaced 

by Enhancement No. 13. The staff’s evaluation of this change is documented below.

Enhancement 5. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the program will be enhanced to ensure that sprinkler heads will be tested 

or replaced in accordance with NFPA 25 Section 5.3.1. LR-ISG-2012-02 AMP XI.M27 

recommends that sprinklers that have been in place for 50 years be replaced or a 

representative sample of sprinklers be tested in accordance with NFPA 25. The staff noted that,

based on the changes in the May 13, 2014, letter, the response to RAI B.1.21-5, dated 

May 15, 2012, is no longer applicable. The staff reviewed this enhancement against the 

corresponding program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, it will enhance the program to include replacement or testing 

of sprinkler heads consistent with LR-ISG-2012-02 AMP XI.M27 recommendations.

Enhancement 6. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “parameters monitored or inspected” program element. In this 

enhancement, the applicant stated that the fire water system procedures will be revised to

include inspecting sprinklers in the overhead from the floor for signs of corrosion. The staff 

reviewed this enhancement against the corresponding program elements in LR-ISG-2012-02 

AMP XI.M27 and finds it acceptable because, when it is implemented, sprinkler inspections will 

be consistent with LR-ISG-2012-02 AMP XI.M27 recommendations and NFPA 25 

Section 5.2.1.1.

Enhancement 7. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to replace sprinklers that 

the tested sprinklers represented if the tested sprinkler fails its test. The staff reviewed this 

enhancement against the corresponding program elements in LR-ISG-2012-02 AMP XI.M27 

and finds it acceptable because, when it is implemented, sprinkler inspections will be consistent 

with LR-ISG-2012-02 AMP XI.M27 recommendations and NFPA 25 Section 5.3.1.3.

Enhancement 8. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to ensure that, during 

flushing, hydrant valves will be opened fully and ensure that the hydrant flows for not less than 

1 minute during flow testing. The staff reviewed this enhancement against the corresponding 

program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is 

implemented, hydrant flushing will be consistent with LR-ISG-2012-02 AMP XI.M27 

recommendations and NFPA 25 Sections 7.3.2.1 and 7.3.2.2.
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Enhancement 9. As amended by letter dated August 19, 2015, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant described changes to the fire water system procedures related to tests and 

inspections of the internal surfaces of fire tanks required by NFPA 25 Section 9.2.7. The staff 

noted that the list of tests and inspections includes all those required by NFPA 25 Sections 9.2.6 

and 9.2.7; except vacuum box testing. By letter dated September 11, 2014, the staff issued 

RAI 3.0.3-1-FWS-2 requesting that the applicant state whether vacuum box testing will be 

conducted.

In its response dated November 6, 2014, the applicant stated that the fire water tanks have 

domed bottoms and NFPA 25 Section 9.2.7 only requires vacuum box testing on flat bottom 

tanks.

The staff finds the applicant’s response acceptable because it is consistent with NFPA 25, in 

that the configuration of the tank bottom is not within the scope of Section 9.2.7 (6). The staff’s 

concern described in RAI 3.0.3-1-FWS-2 is resolved.

In addition, the staff noted that the applicant cited adhesion tests endorsed by RG 1.54 in lieu of 

the adhesion methodology cited in NFPA 25 Section 9.2.7 (1). The staff’s evaluation of 

adhesion testing associated with this enhancement is documented in Exception No. 6. The staff 

reviewed this enhancement against the corresponding program elements in LR-ISG-2012-02 

AMP XI.M27 and LR-ISG-2013-01 and finds it acceptable because, when it is implemented, it 

will enhance the program to include inspections and tests of fire water tank internals consistent 

with LR-ISG-2012-02 AMP XI.M27 recommendations.

Enhancement 10. As amended by letter dated August 19, 2015, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to ensure that there is no 

flow blockage of charcoal filter fire water distribution piping by conducting visual inspections 

when the charcoal is replaced. However, the staff noted that the enhancement was revised to 

state that the charcoal filter deluge piping in lieu of the nozzles would be inspected for flow 

blockage. No basis was provided for inspecting the fire water distribution piping in lieu of 

nozzles. By letter dated October 29, 2015, the staff issued RAI 3.0.3-1-FWS-9 requesting that 

the applicant state the basis for why the fire water distribution piping for the charcoal deluge 

system will be inspected instead of nozzles.

In its response dated November 23, 2015, the applicant stated that, “[i]t was determined that the 

phrase “fire water distribution piping” within the charcoal filter units was more appropriate than 

“nozzles” based on vendor manual wording.”

The staff finds the applicant’s response acceptable because the plant-specific configuration for 

the distribution piping includes fire water distribution components. The staff’s concern described 

in RAI 3.0.3-1-FWS-9 is resolved. The staff’s evaluation of the adequacy of tests and 

inspections associated with deluge valves is documented in Exception No. 7. The staff 

reviewed this enhancement against the corresponding program elements in LR-ISG-2012-02 

AMP XI.M27 and finds it acceptable because, when it is implemented, it will enhance the 

program to include charcoal filter deluge testing and inspections consistent with 

LR-ISG-2012-02 AMP XI.M27 recommendations.

Enhancement 11. As amended by letter dated August 19, 2015, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 
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applicant stated that, for preaction and dry pipe systems, the fire water system procedures will 

be revised to periodically open a flushing connection and remove a component toward the end 

of one branch line to perform a visual inspection in accordance with NFPA 25 Section 14.2.1. 

The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, when it is implemented, 

conducting internal inspections of preaction and dry pipe systems in accordance with NFPA 25 

Section 14.2.1, as well as the augmented inspections described in Enhancement No. 21, can be 

sufficient to detect potential flow blockage.

Enhancement 12. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to inspect the strainers 

upstream of the deluge valves every 3 years. The staff reviewed this enhancement against the 

corresponding program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable 

because, when it is implemented, it will enhance the program to include deluge valve strainer 

inspections consistent with LR-ISG-2012-02 AMP XI.M27 recommendations and NFPA 25 

Section 10.2.1.7.

Enhancement 13. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “acceptance criteria” program element. In this enhancement, the applicant 

stated that the fire water system procedures will be revised to state an acceptance criterion that, 

during flow testing, main drain testing, and internal inspections, no corrosion products sufficient 

to obstruct flow or clog downstream components are permitted. The staff reviewed this 

enhancement against the corresponding program elements in LR-ISG-2012-02 AMP XI.M27 

and finds it acceptable because, when it is implemented, along with Enhancement No. 15, it will 

enhance the program to include acceptance criteria consistent with the “acceptance criteria” 

program element of LR-ISG-2012-02 AMP XI.M27.

Enhancement 14. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

stated that the fire water system procedures will be revised to state that any sprinkler that 

exhibits signs of leakage or corrosion will be replaced. The staff reviewed this enhancement 

against the “detection of aging effects” program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because, when it is implemented, it will enhance the program to include 

replacement criteria for degraded sprinklers consistent with LR-ISG-2012-02 AMP XI.M27 

recommendations and NFPA 25 Section 5.2.1.1.2.

Enhancement 15. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

stated that the fire water system procedures will be revised to:

require an obstruction evaluation if any signs of abnormal corrosion or blockage 

are identified during flow testing, main drain testing, or internal inspection. Any 

signs of corrosion or blockage should be removed, its source determined and 

corrected, and the condition entered into the Corrective Action Program. Where 

corrosion or blockage is found, the obstruction evaluation should consider 

system valves, risers, cross mains and branch lines, and the performance of a 

complete flushing program by qualified personnel.

The staff reviewed this enhancement against the “detection of aging effects” and “acceptance 

criteria” program elements in LR-ISG-2012-02 AMP XI.M27 and finds it acceptable because, 
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when it is implemented, it will enhance the program to include appropriate actions when 

corrosion or blockages are identified during tests and inspections consistent with the 

LR-ISG-2012-02 AMP XI.M27 recommendations and NFPA 25 Section 14.2.1.3.

Enhancement 16. As amended by letter dated May 13, 2014, LRA Section B.1.21 states an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

stated that the fire water system procedures will be revised to: “require an obstruction 

evaluation in the event there is frequent false tripping of the dry pipe fire suppression system 

associated with the auxiliary building railroad access.” The staff reviewed this enhancement 

against the “detection of aging effects” program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because, when it is implemented, it will enhance the program to include a 

follow-up obstruction investigation in accordance with NFPA 25 Section 14.3.1, item (9).

Enhancement 17. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “parameters monitored/inspected” and “detection of aging effects” program 

elements to address RAI 3.0.3-1-FWS-5. The staff noted that the “parameters 

monitored/inspected” and “detection of aging effects” program elements of LR-ISG-2012-02 

AMP XI.M27 state that, when visual inspections are used to detect loss of material, the 

inspection technique should be capable of detecting surface irregularities that could indicate 

wall loss to below nominal pipe wall thickness due to corrosion and corrosion product deposition 

and, where such irregularities are detected, follow-up volumetric wall thickness examinations 

are performed. The staff also noted that there were no exceptions or enhancements associated 

with this recommendation. By letter dated September 11, 2014, the staff issued 

RAI 3.0.3-1-FWS-5 requesting that the applicant state how this recommendation has been 

incorporated into the Fire Water System program or provide justification for why incorporation is 

not required.

In its response dated November 6, 2014, the applicant enhanced its program to require followup volumetric wall thickness examinations when visual inspections detect, “excessive 

accumulation of corrosion products and appreciable localized corrosion (e.g., pitting) beyond a 

normal oxide layer.”

The staff finds the applicant’s response and enhancement acceptable because volumetric wall 

thickness examinations will be conducted when surface irregularities indicative of wall loss are 

detected. The staff’s concern described in RAI 3.0.3-1-FWS-5 is resolved.

Enhancement 18. As amended by letter dated November 6, 2014; and May 20, 2015, the 

applicant stated an enhancement to the “detection of aging effects” program element. In this 

enhancement, the applicant stated that the fire water system procedures will be revised to 

“perform a flow blockage evaluation if during main drain testing, the flowing pressure drops 

more than 10 percent from the flowing pressure observed during the original acceptance test or 

other previously performed tests at the same location.” The staff’s evaluation of this 

enhancement is documented above in Exception No. 4.

Enhancement 19. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to “perform air flow testing 

to ensure there are no obstructions downstream of the deluge valves for control room fresh air, 

auxiliary building standby gas, containment cooling system, and containment vent charcoal filter 

units each refueling cycle.” The staff’s evaluation of this enhancement is documented above in 

Exception No. 7.
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Enhancement 20. As amended by letter dated November 6, 2014, LRA Section B.1.21 states 

an enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated the following:

Revise Fire Water System Program procedures to require internal inspections at 

the end of one fire main and the end of one branch line on two of the wet pipe 

systems in the auxiliary building, two of the wet pipe systems in the control 

building, and one wet pipe system in the fire pump house every five years. 

During each five-year period, inspect different wet pipe sprinklers such that 

internal inspections are performed on all of the wet pipe sprinkler systems in the 

auxiliary and control buildings every 15 years and in the fire pump house every 

10 years. In the event internal obstructions are identified in a building wet pipe 

system, expand the number of inspections to include all of the wet pipe sprinkler 

systems in that building.

The staff noted that NFPA 25 Section 14.2.2 requires, on an alternating schedule, an internal 

inspection of every other wet-pipe system in buildings with multiple wet-pipe systems. The staff 

lacked sufficient information to complete its evaluation of the applicant’s proposal because it 

was not clear whether there are multiple wet-pipe systems in any of the structures containing 

in-scope fire water systems. By letter dated September 11, 2014, the staff issued 

RAI 3.0.3-1-FWS-4 requesting that the applicant state the basis for why testing is not conducted 

on every other system every 5 years.

In its response dated November 6, 2014, the applicant stated that: (a) the in-scope wet-pipe 

sprinkler systems in the auxiliary building, control building, and fire pump house are fabricated 

from the same material, and exposed to the same environment and (b) the auxiliary building has 

six in-scope wet-pipe sprinkler systems, the control building has five, and the fire pump house 

has two.

Although the applicant will be inspecting five wet-pipe systems in lieu of seven locations, as 

cited by NFPA 25, the staff finds the applicant’s response and Enhancement No. 20 acceptable 

because: (a) given that the wet systems are constructed of the same materials and exposed to 

the same environment, there is reasonable assurance that flow blockage occurring in any one of 

the systems would be indicative of the same conditions in the other systems, (b) if the applicant 

detects obstructions in any system within a building, it will inspect the other systems in that 

building, and (c) in each 5-year period, the applicant will inspect at least one system in each of 

the buildings with in-scope wet-pipe systems. The staff’s concern described in 

RAI 3.0.3-1-FWS-4 is resolved.

Enhancement 21. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “detection of aging effects” program element to address 

RAI 3.0.3-1-FWS-6. The staff noted that the “parameters monitored/inspected” and “detection 

of aging effects” program elements of LR-ISG-2012-02 AMP XI.M27 state that periodic visual 

inspections or flow tests and volumetric inspections should be conducted on portions of 

water-based fire protection system components that have been wetted but are normally dry, 

such as dry-pipe or preaction sprinkler system piping and valves. The staff also noted that there 

are no exceptions or enhancements associated with this recommendation. By letter dated 

September 11, 2014, the staff issued RAI 3.0.3-1-FWS-6 requesting that the applicant state how 

this recommendation has been incorporated into the Fire Water System program or provide 

justification for why incorporation is not required.
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In its response dated November 6, 2014, the applicant enhanced the program to conduct 

periodic visual inspections or flow tests and volumetric inspections on portions of water-based 

fire protection system components that have been wetted but are normally dry. The 

enhancement incorporates all of the recommended tests and inspections and the corresponding 

test parameters, extent of tests and inspections, and periodicity of testing.

The staff finds the applicant’s response and Enhancement No. 21 acceptable because it is 

consistent with AMP XI.M27 as modified by LR-ISG-2012-02, which ensures that sufficient tests 

or inspections of normally dry but periodically wetted portions of the fire water system that 

collect water will be conducted in order to detect flow blockage. The staff’s concern described 

in RAI 3.0.3-1-FWS-6 is resolved.

Enhancement 22. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “monitoring and trending” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to include requirements 

associated with the review of prior coating inspection results prior to the conduct of coating 

inspections and the information to be included in coating inspection reports. The staff reviewed 

this enhancement against the corresponding program elements in LR-ISG-2013-01 and finds it 

acceptable because, when it is implemented, it will enhance the program to include monitoring 

and trending requirements consistent with LR-ISG-2013-01, which ensures that adequate 

information in relation to coating degradation is provided for future inspections.

Enhancement 23. As amended by letter dated August 19, 2015, LRA Section B.1.21 states an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

described changes to the fire water system procedures related to tests and inspections of the 

internal surfaces of fire tanks required by NFPA 25 Section 9.2.7. The staff’s evaluation of 

these same enhancements to the “detection of aging effects” program element is documented in 

Enhancement No. 9.

Enhancement 24. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “acceptance criteria” program element. This enhancement was revised by 

letter dated May 20, 2015, and subsequently revised by letter dated August 19, 2015; however, 

the August 19, 2015, letter revised the November 6, 2014, version of this enhancement, not the 

May 20, 2015, version. By letter dated October 29, 2015, the staff issued RAI 3.0.3-1-FWS-10 

requesting that the applicant revise the enhancement to reflect the correct version of the 

proposed changes to the Fire Water System Program.

In its response dated November 23, 2015, the applicant revised this amendment to reflect the 

changes in the May 20, 2015, and August 19, 2015, letters.

The staff finds the applicant’s response acceptable because the revised version of 

Enhancement No. 24 reflects the changes in the May 20, 2015, and August 19, 2015, letters. 

The evaluation of this enhancement follows. The staff’s concern described in 

RAI 3.0.3-1-FWS-10 is resolved.

In this enhancement, the applicant stated that the fire water system procedures will be revised 

to include acceptance criteria when coating defects are identified, including, “(1) peeling and 

delamination are not acceptable, (2) cracking is not acceptable if accompanied by delamination 

or loss of adhesion, and (3) blisters are limited to a few intact small blisters that are completely

surrounded by sound coating bonded to the surface.” The staff noted that the applicant did not 

state acceptance criteria for flaking, rusting, wall thickness measurements, and adhesion test 
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results. In addition, the acceptance criteria did not include any details on the acceptable size of 

blisters or for changes in size or frequency of occurrence. By letter dated April 6, 2015, the staff 

issued RAI 3.0.3-1-FWS-8 requesting that the applicant state the acceptance criteria for flaking, 

rusting, wall thickness measurements, adhesion test results, size of blisters, and changes in the 

size or frequency of occurrence of blisters.

In its response dated May 20, 2015, as amended by letter dated November 23, 2015, the 

applicant revised this enhancement, LRA Section A.1.21, and Commitment No. 12, to state the 

same acceptance criteria as stated in the “acceptance criteria” program element of 

LR-ISG-2013-01, AMP XI.M42.

The staff finds the applicant’s response and this enhancement acceptable because the 

acceptance criteria are consistent with those stated in LR-ISG-2013-01, which can ensure that 

degraded coatings requiring repair, replacement, or removal are identified. The staff’s concern 

described in RAI 3.0.3-1-FWS-8 is resolved.

Enhancement 25. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “corrective actions” program element. In this enhancement, the applicant 

stated that the fire water system procedures will be revised to state that coatings that do not 

meet acceptance criteria will be repaired or replaced. The staff reviewed this enhancement 

against the corresponding program elements in LR-ISG-2013-01 and finds it acceptable 

because repairing or replacing coatings that do not meet acceptance criteria is consistent with

LR-ISG-2013-01, which ensures that unacceptable coatings will not affect the intended function 

of the fire water tank.

Enhancement 26. As amended by letter dated August 19, 2015, the applicant stated an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to include requirements 

associated with follow-up coating inspections, actions, and tests prior to returning a fire water 

tank to service with degraded coatings (i.e., delamination, peeling, blistering). These include: 

(a) removal of blisters in excess of a few small intact blisters or blisters not completely 

surrounded by coating bonded to the substrate, (b) removal of delaminated or peeled coatings,

(c) adhesion testing conducted in accordance with standards cited in RG 1.54, (d) feathering of 

the outermost coating and adhesion testing of the surface surrounding the feathering,

(e) ultrasonic testing when there is evidence of pitting or crevice corrosion, (f) an evaluation to 

ensure that downstream flow blockage is not an issue, and (g) follow-up inspections within 

2 years and every 2 years until the coating is repaired, replaced, or removed. The applicant 

stated that the requirements are not applicable to blisters consisting of, “a few small intact 

blisters surrounded by coating bonded to the substrate as determined by a qualified coating 

inspector.” The enhancement states that a qualified coating inspector will determine the 

acceptability of blisters. The “acceptance criteria” program element of AMP XI.M42, “Internal 

Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks,” 

recommends that a coating specialist, not a coating inspector, evaluate the acceptability of 

blisters. A coating inspector might be qualified to lesser requirements than those for a coatings 

specialist. By letter dated October 29, 2015, the staff issued RAI 3.0.3-1-FWS-11 requesting 

that the applicant state the basis for using a qualified coating inspector in lieu of a coatings 

specialist to determine the acceptability of blisters.

In its response dated November 23, 2015, the applicant revised LRA Section A.1.21, 

Commitment No. 12, and this enhancement to state that a coatings specialist will determine the 

acceptability of blisters.
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The staff finds the applicant’s response acceptable because an individual with the appropriate 

qualifications will determine the acceptability of blisters. The staff’s concern described in 

RAI 3.0.3-1-FWS-11 is resolved.

The staff reviewed this enhancement against the corresponding program elements in 

LR-ISG-2013-01 and finds it acceptable because the inspections, actions, and tests are 

consistent with the “corrective action” program element of AMP XI.M42 and are capable of 

ensuring that the degraded coating does not result in a loss of intended function of the 

component or downstream components. Allowing the return to service of a few small intact 

blisters surrounded by coating bonded to the substrate is consistent with the “acceptance 

criteria” program element of AMP XI.M42.

Enhancement 27. As amended by letter dated August 19, 2015, the applicant stated an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to conduct one or more 

inspections or tests whenever coating conditions such as cracking, peeling, blistering, 

delamination, rust, or flaking are identified during inspections. The tests include lightly tapping 

the coating to detect degraded conditions, dry film thickness measurements, wet-sponge 

testing, adhesion testing, and ultrasonic examinations. The staff reviewed this enhancement 

against the “detection of aging effects” program element in LR-ISG-2012-02 AMP XI.M27 and 

finds it acceptable because the inspections and tests will be part of or supplement the minimum 

level of tests and inspections for degraded coatings and returning a fire water tank to service 

with degraded coatings as documented in Exception No. 6.

Enhancement 28. As amended by letter dated November 6, 2014, the applicant stated an 

enhancement to the “detection of aging effects” program element. In this enhancement, the 

applicant stated that the fire water system procedures will be revised to incorporate: 

(a) inspections for possible voids beneath the fire water tanks, (b) inspection of the vortex 

breaker in the fire water tanks, (c) qualification requirements for coating inspectors 

(ANSI 45.2.6, “Qualifications of Inspection, Examination, and Testing Personnel for Nuclear 

Power Plants”), (d) qualification requirements for nuclear coatings specialist (ASTM D7108-05, 

“Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist), and (e) a 

requirement for the nuclear coatings specialist to evaluate inspection findings and prepare 

post-inspection reports.

The staff reviewed this enhancement against the “detection of aging effects” program element in 

LR-ISG-2012-02 AMP XI.M27 and finds it acceptable based on the following. Inspections for 

voids underneath the fire water tanks and the vortex breaker are consistent with NFPA 25 

Sections 9.2.6.5 and 9.2.6.7, respectively. The staff noted that examiner qualifications meeting 

the recommendations in RG 1.54 are consistent with draft LR-ISG-2013-01. The staff finds the 

use of ANSI N45.2.6 to qualify examiners acceptable because the ANSI N45.2.6 certification is 

an acceptable basis for qualifying coatings inspectors based on RG 1.54, June 1973, 

Section C.1., which mandates conformance to the ANSI N45.2 QA standards. The staff finds 

the use of ASTM D7108-05 to qualify nuclear coatings specialist, because it is cited as an 

appropriate standard for this purpose in RG 1.54. Having the nuclear coatings specialist 

evaluate inspection findings and prepare post-inspection reports is consistent with 

LR-ISG-2013-01.

Summary. Based on its audit and review of the application, and review of the applicant’s 

responses to RAIs B.1.21-2, B.1.21-2a, B.1.21-4, B.1.21-5, 3.0.3-1-FWS-1, 3.0.3-1-FWS-1a, 

3.0.3-1-FWS-2, 3.0.3-1-FWS-3, 3.0.3-1-FWS-4, 3.0.3-1-FWS-5, 3.0.3-1-FWS-6, 3.0.3-1-FWS-8, 
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3.0.3-1-FWS-9, 3.0.3-1-FWS-10, and 3.0.3-1-FWS-11, the staff finds that the program elements 

are consistent with the corresponding program elements of LR-ISG-2012-02 AMP XI.M27 and 

LR-ISG-2013-01. The staff also reviewed the exceptions associated with the “detection of aging 

effects” program element, and their justifications, and finds that the AMP, with the exceptions, is 

adequate to manage the applicable aging effects. In addition, the staff reviewed the 

enhancements associated with the “parameters monitored or inspected,” “detection of aging 

effects,” “monitoring and trending,” “acceptance criteria,” and “corrective actions” program 

elements and finds that, when implemented, they will make the AMP adequate to manage the 

applicable aging effects.

Operating Experience. LRA Section B.1.21 summarizes operating experience related to the 

Fire Water System Program. The LRA states that sprinkler system functional testing has been 

performed in 2004, 2006, and 2008 with no significant discrepancies noted. The LRA also 

states that yard hydrant flow tests in 2005 and 2007 identified a stuck-closed valve and a 

broken handwheel on a hose isolation valve, which were repaired and returned to service. The 

applicant further states that deluge system inspections have identified nozzle blockages that 

were cleaned and returned to service. LRA Section B.1.2, “Aboveground Metallic Tanks,” 

Program describes visual inspections of the fire water tanks that were conducted in 2007, 2008, 

and 2009. These inspections detected indications of degradation that were resolved prior to 

any loss of intended function.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. As amended by letters dated August 19, 2015, and November 23, 2015, 

LRA Section A1.21 provides the UFSAR supplement for the Fire Water System Program. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 

with the recommended description in LR-ISG-2012-02 and LR-ISG-2013-01 SRP-LR 

Table 3.0-1. The staff also noted that the applicant committed (Commitment No. 12) to enhance 

the program as described above prior to May 1, 2024, or the end of the last refueling outage 

prior to November 1, 2024, whichever is later. Based on the changes to LRA Section A1.21 

dated August 19, 2015, the previous RAIs related to the USFAR supplement (RAI B.1.21-1 and 

RAI 3.0.3-1-FWS-7) are no longer applicable. The staff finds that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Fire Water System Program, 

the staff determines that the program elements for which the applicant claimed consistency with 

the GALL Report are consistent with the corresponding program elements of GALL Report 

AMP XI.M27. Also, the staff reviewed the enhancements and confirmed that their 
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implementation through Commitment No. 12 prior to the period of extended operation will make 

the AMP adequate to manage the applicable aging effects. 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 Flow-Accelerated Corrosion

Summary of Technical Information in the Application. LRA Section B.1.22, as modified by letter 

dated December 20, 2013, describes the existing Flow-Accelerated Corrosion Program as 

consistent, with an exception and enhancements, with GALL Report AMP XI.M17, 

“Flow-Accelerated Corrosion.” The LRA states that this program manages wall thinning for 

piping and components by performing appropriate analysis and baseline inspections, 

determining the extent of thinning, performing follow-up inspections, and taking corrective 

actions as necessary. The LRA also states that the program follows the guidance in 

NSAC-202L.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M17. For the “scope of 

program,” “detection of aging effects,” and “monitoring and trending,” program elements, the 

staff determined the need for additional information, which resulted in the issuance of RAIs, as 

discussed below.

The “program description” program element in SRP-LR Section A.1.2.3.1 states that the scope 

of the program should include the specific components that are being managed by the program. 

The program basis documents reviewed during the audit state that this program is being used to 

manage aging effects of components in the RCS, the RHR system, the reactor core isolation 

cooling (RCIC) system, and nonsafety-related systems. During the audit, the staff reviewed 

calculation MC-Q1111-0811, “Evaluation of RF16 Flow-Accelerated Corrosion Wall Thickness 

Data,” which states that this program also manages wall thinning in the low-pressure core spray 

(LPCS) and HPCS systems. However, LRA Tables 3.2.2-2 and 3.2.2-3, which address these 

two systems, do not list the Flow-Accelerated Corrosion Program as an applicable AMP. By 

letter dated April 25, 2012, the staff issued RAI B.1.22-1 requesting that the applicant either 

revise the appropriate tables and sections in the LRA to reflect the Flow-Accelerated Corrosion 

Program as an AMP that manages components in the LPCS and HPCS systems or provide the 

appropriate AMP that manages the aging effect being trended in calculation MC-Q1111-08011 

for these systems.

In its response dated May 25, 2012, the applicant stated that calculation MC-Q1111-0811 listed 

the time in service for the LPCS and HPCS systems as less than 2 percent of the time, which 

results in these systems not being susceptible to flow-accelerated corrosion. The applicant 

concluded that wall thinning due to this aging effect was not required to be managed for these 

systems and no revision to the LRA was required. The applicant further stated that no other 

systems have aging effects being managed by the Flow-Accelerated Corrosion Program that 

were not identified in the LRA.

However, during its audit, the staff identified that there are six items associated with the LPCS 

and eight items associated with the HPCS system that have been or are currently being 

monitored for wall thinning in the Flow-Accelerated Corrosion Program. In addition, the staff 

identified several items associated with the RHR system that are being monitored for wall 

thinning in portions of the system that were determined to be not susceptible to flow-accelerated 
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corrosion. It was not clear to the staff whether the susceptibility evaluation had improperly 

excluded systems or portions of systems that were susceptible to flow-accelerated corrosion, or 

whether the flow-accelerated corrosion program is monitoring wall thinning for components that 

are susceptible to an aging mechanism other than flow-accelerated corrosion. In order to 

resolve this issue, by letter dated September 5, 2012, the staff issued RAI B.1.22-1a requesting 

the applicant to explain why components in the LPCS, HPCS, and RHR systems are being 

monitored for wall thinning through the Flow-Accelerated Corrosion Program.

In its response dated October 2, 2012, the applicant stated that various components in the 

LPCS and HPCS are included in the Flow-Accelerated Corrosion Program for monitoring and 

evaluations in future outages. The applicant stated that these components had been added to 

the program based on GGNS operating experience with a pinhole leak in a minimum flow line of 

the RHR system in 2001. The applicant further stated that GGNS also includes components in 

the Flow-Accelerated Corrosion Program that had initially been excluded through the program’s 

system susceptibility evaluation, but had since been included based on operating experience, 

heavily throttled piping regions, cavitation concerns, and EPRI suggestions. Since the GGNS 

Flow-Accelerated Corrosion Program also addresses loss of material due to mechanisms other 

than flow-accelerated corrosion, the applicant stated that this is considered an exception to 

GALL Report AMP XI.M17. Consequently, the applicant modified LRA Sections A.1.22 and 

B.1.22 to reflect this new position. In addition, the applicant modified LRA Tables 3.2.2-2, 

3.2.2-3, 3.2.2-8-2, 3.2.2-8-3, 3.3.2-1, 3.3.2-6, 3.3.2-19-1, 3.3.2-19-8, 3.3.2-19-20, 3.4.2-2-4, 

3.4.2-2-6, and 3.4.2-2-11 by adding a new item for piping components exposed to treated water 

in the associated systems that are managed for loss of material by the Flow-Accelerated 

Corrosion Program.

In reviewing the above response, the staff noted that the applicant only cited an exception to the 

“scope of program” program element by stating that the program also includes loss of material 

due to erosion mechanisms. The staff did not consider this to be a comprehensive evaluation of 

the changes needed to describe the current program. In addition, the item added to the LRA 

tables by the applicant applies to wall thinning due to flow-accelerated corrosion, and as noted 

by the applicant, the associated components are being managed for wall thinning due to 

mechanisms other than flow-accelerated corrosion. The staff did not consider this to be an 

appropriate change. In order to address this, by letter dated November 20, 2012, the staff 

issued RAI B.1.22-1b requesting that the applicant provide additional bases to justify the 

exception to the program by addressing any needed changes to the aging management 

program elements and to provide additional detail in the LRA for these components such that 

the AMR items associated with the erosion aging mechanism are identified.

In its response dated December 18, 2012, the applicant stated that it had reviewed the program

elements in GALL Report AMP XI.M17 and provided a more comprehensive discussion for the 

“detection of aging effects,” “monitoring and trending,” and “corrective action” program 

elements. The applicant concluded that, in addition to the “scope of program” program element, 

it needed to address an exception to the “monitoring and trending” program element because it 

discusses the use of predictive computer code, CHECWORKS, which does not consider erosion 

mechanisms. The staff evaluated this exception to GALL Report AMP XI.M17 as discussed 

below in the Exception section. In addition, the applicant provided further revisions to the LRA 

tables, which are discussed above for RAI B.1.22-1a. The applicant deleted the existing aging 

management review item and instead cited items with generic note H and plant-specific notes to 

indicate that the Flow-Accelerated Corrosion Program also manages carbon steel piping 

components for loss of material due to erosion mechanisms other than flow-accelerated 

corrosion. For the “corrective action” program element, the applicant stated, if degradation is 
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due to erosion, that it is not acceptable to only replace the component with more resistant 

material and that monitoring of the replaced component at an appropriate frequency is 

warranted.

In its review of the above response, the staff finds portions of the applicant’s response 

acceptable because the applicant accurately described the differences between the program 

elements described in GALL Report AMP XI.M17 and the corresponding elements in its 

Flow-Accelerated Corrosion Program. In addition, to clearly reflect the aging mechanism being 

managed by its Flow-Accelerated Corrosion Program, the applicant provided revised AMR

items, which are not addressed in the GALL Report. However, the staff noted that, although the 

implementing procedure, EN-DC-315, “Flow-Accelerated Corrosion Program,” states that it can 

be used as a guide for evaluating systems and components that are not included in the 

Flow-Accelerated Corrosion Program, there is no guidance regarding management of nonflow-accelerated corrosion wall-thinning mechanisms. In addition, the staff noted that the 

applicant’s response to RAI B.1.22-1a states that flow-accelerated corrosion location No. 662, 

which was being managed for erosion, “was replaced in 2004 with FAC-resistant material 

(stainless steel) and is no longer monitored for FAC.” This was contrary to the applicant’s 

above statement regarding the “corrective action” program element. In order to address this 

discrepancy, by letter dated November 21, 2013, the staff issued RAI B.1.22-1c requesting that 

the applicant provide additional bases to justify the use of its Flow-Accelerated Corrosion

Program to manage components susceptible to non-flow-accelerated corrosion mechanisms.

In its response dated December 20, 2013, the applicant provided an additional enhancement to 

revise Flow-Accelerated Corrosion Program documentation to specify that components subject 

to non-flow-accelerated corrosion wall-thinning mechanisms, that are replaced with alternative 

materials, will continue to be periodically monitored at a frequency commensurate with their 

post-replacement wear rates and operating times. The staff finds the applicant’s response 

acceptable because the applicant revised LRA Sections A.1.22 and B.1.22 to reflect that the 

Flow-Accelerated Corrosion Program will be enhanced to specifically address how the program 

manages components with non-flow-accelerated corrosion-related wall-thinning mechanisms. 

The staff’s concerns described in RAI B.1.22-1, RAI B.1.22-1a, RAI B.1.22-1b, and 

RAI B.1.22-1c are resolved.

The “monitoring and trending” program element in GALL Report AMP XI.M17 states that 

inspection results are evaluated to determine if additional inspections are needed to ensure that 

corrective actions are adequately identified. Procedure EN-DC-315, “Flow-Accelerated 

Corrosion Program,” Section 5.11, “Components Failing to Meet Initial Screening Criteria,”

states that a condition report shall be generated when “significant wall thinning,” as defined in 

the procedure, is detected. However, during the audit, a search of condition reports generated 

during recent outages only identified condition reports where wall thinning was reported to be 

below the minimum acceptable wall thickness, and none appeared to report “significant wall 

thinning,” which is a precursor condition when the wall thickness is above the minimum 

acceptable value. By letter dated April 25, 2012, the staff issued RAI B.1.22-2 requesting the 

applicant to confirm that significant wall thinning, as defined in EN-DC-315, had not been 

detected and condition reports were not required to be generated in recent outages, or provide 

actions taken if the activities prescribed in EN-DC-315 were not conducted.

In its response dated May 25, 2012, the applicant stated:

A review of program documentation and data from the fall 2008 and spring 2010 

refueling outages determined that no significant wall thinning has been detected 
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other than the wall thinning documented in the condition reports referenced in the 

background of this request for information, which had resulted in wall thickness 

below the minimum acceptable wall thickness. Thus no additional condition 

reports on significant wall thinning as defined in EN-DC-315 were required to be 

generated.

However, during its audit, the staff identified several instances, specifically item 314a, item 353, 

and item 795, where the measured wall thickness was less than 60 percent of nominal pipe wall 

thickness, which meets the criteria for “significant wall thinning” in EN-DC-315. Based on this, 

the applicant did not appear to be implementing the program in accordance with the controlling 

procedures. In order to resolve this issue, by letter dated September 5, 2012, the staff issued 

RAI B.1.22-2a, requesting the applicant to re-verify that significant wall thinning, as defined in 

EN-DC-315, had not been detected and condition reports were not required to be generated in 

recent outages, or to provide actions taken if the activities prescribed in EN-DC-315 were not 

conducted.

In its response dated October 2, 2012, the applicant stated that it had performed a further 

review of program documentation and had identified an incorrect interpretation of the procedural 

requirements to generate condition reports with respect to significant wall thinning for the items 

cited in the RAI. The applicant stated that the incorrect interpretation had been documented in 

the CAP. The applicant further stated that all of the associated components had been replaced 

with “FAC-resistant” material during either the 2010 or 2012 refueling outages. The applicant 

concluded that the material replacements indicate that the program remains effective for 

managing the effects of aging and that corrective actions to address the incorrect procedure 

interpretation will ensure that the program will be implemented in accordance with the 

controlling procedures during the period of extended operation. The staff finds the applicant’s 

response acceptable because the applicant acknowledged its incorrect interpretation of the 

procedural requirements in EN-DC-315 and documented the issue in its CAP. The staff notes 

that the applicant has taken measures to ensure that the intended function of the components in 

question will be maintained in accordance with the CLB by replacing them with material that is 

resistant to flow-accelerated corrosion. The concerns described in RAI B.1.22-2a are resolved.

The “program description” program element in GALL Report AMP XI.M17 states that the 

flow-accelerated corrosion program addresses carbon steel components containing high-energy 

fluids. However, during the audit, the staff identified several condition reports that referred to 

GGNS MS-46, “Program Plan for Monitoring Internal Erosion/Corrosion in Moderate Energy 

Piping Components, (Safety Related).” Since this program defines “erosion/corrosion” almost 

the same as EN-DC-315 defines “flow-accelerated corrosion” for high-energy systems, it was 

not clear whether GGNS MS-46 also monitors flow-accelerated corrosion. By letter dated 

April 25, 2012, the staff issued RAI B.1.22-3 requesting the applicant to provide information 

regarding the aging effects being managed by GGNS MS-46 and how it relates to or integrates 

with the Flow-Accelerated Corrosion Program in the LRA.

In its response dated May 25, 2012, the applicant stated that it does not credit the inspections 

described in GGNS MS-46 as a separate AMP and that the Flow-Accelerated Corrosion 

Program does not credit the inspections conducted in GGNS MS-46. The applicant stated, 

however, that the inspections conducted in GGNS MS-46 are credited as part of the AMPs for 

managing loss of material in the Fire Water System and Service Water Integrity Programs. The 

staff finds the applicant’s response acceptable because the applicant clarified that it does not 

credit GGNS MS-46 within the Flow-Accelerated Corrosion Program; however, it does credit the 

inspections conducted with this procedure for loss of material due to erosion and corrosion in 
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AMPs for raw water systems. The staff’s concern described in RAI B.1.22-3 is resolved. SER 

Section 3.0.3.1.39 documents additional discussion regarding the use of GGNS MS-46 in the 

Service Water Integrity Program.

The “detection of aging effects” program element in GALL Report AMP XI.M17 states that the 

schedule of inspections ensures detection of wall thinning before the loss of intended function. 

Procedure EN-DC-315 states that a 10 percent safety factor should be applied to account for 

inaccuracies in the wear rate evaluations. However, calculation MC-Q1111-08011 states that 

for systems which only operate part-time, it is acceptable to use grid-synchronized hours in 

calculating the wear rate, because it “...provides a valid relative measure of wear for whatever 

number of hours each system actually operated....” The calculation also states that the 

infrequently operated systems “...are expected to be operated in the future similar to how they 

have been operated in the past...” and states that the RCIC system is assumed to operate 

12 hours per year. Since relatively small increases in operating times (i.e., 1.2 hours for the 

RCIC system) could “consume” all of the uncertainty being applied in the 10 percent safety 

factor, which would not leave any margin for other uncertainties (e.g., UT inaccuracies), it was 

not clear to the staff whether the 10 percent safety factor is adequate for systems operating 

infrequently. By letter dated April 25, 2012, the staff issued RAI B.1.22-4 requesting the 

applicant to provide information to assure that the 10 percent safety factor, used in the wearrate evaluations, accounts for wear-rate-measurement uncertainties due to variations in 

assumed operating times for systems operating infrequently.

In its response dated May 25, 2012, the applicant stated that although the RCIC system 

operates less than 2 percent of the time, it has conducted inspections at multiple locations in 

that system under the Flow-Accelerated Corrosion Program and has confirmed that wear is not 

a concern for infrequently-operated systems. The applicant also stated that the 10 percent 

safety factor is used in conjunction with other considerations, including personnel safety and 

consequence of failure, and that the lack of wear identified in infrequently-operated systems 

provides reasonable assurance that variation in system operating time is not a concern. The 

staff finds the applicant’s response acceptable because although the system usage may exceed 

the values assumed in the calculation, the applicant has inspected infrequently-operated 

systems and has confirmed that the wear rates are low, which compensates for the 

uncertainties due to potential underestimation of the overall wear. The staff’s concern described 

in RAI B.1.22-4 is resolved.

The “monitoring and trending” program element in GALL Report AMP XI.M17 states that, based 

on the results of a predictive code such as CHECWORKS, the inspection schedule the applicant 

developed provides reasonable assurance that structural integrity will be maintained between

inspections. During the audit, the staff reviewed condition report, CR 2010-00823, which 

described an error, reported by the Electric Power Research Institute (EPRI) in its 

CHECWORKS model software, regarding the use of incorrect hours to calculate the predicted 

wear. The condition report stated that of the 122 instances where the specific software feature 

was used, only 7 wear rate analyses were potentially affected due to the error and that further 

evaluations concluded there was no impact on the wear-rate calculations. The condition report 

also stated that CHECWORKS is only one tool the flow-accelerated corrosion engineer used to 

determine component wear. It was not clear to the staff what other tools are used to determine 

component wear such that errors in the CHECWORKS software model will be detected. By 

letter dated April 25, 2012, the staff issued RAI B.1.22-7 requesting the applicant to describe 

any in-place process or verification method, which is used to determine component wear that 

validates and could compensate for errors in the CHECWORKS software, such that structural 

integrity will be maintained between inspections.
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In its response dated May 25, 2012, the applicant stated that the results of component 

inspections are the primary input used in the calculation to schedule the next inspection, and 

that as more actual inspection data are acquired, the already limited reliance on CHECWORKS 

becomes less. The applicant also stated that this approach provides reasonable assurance that 

an error in the CHECWORKS model software will not prevent the program from providing 

reasonable assurance that the intended function of components will be maintained. In its review 

of the applicant’s response, however, it was unclear to the staff whether the applicant 

independently calculated wear rates without CHECWORKS since the CHECWORKS-calculated 

wear rates can be based on the component inspection data. In addition, the RAI response did 

not describe the other tools discussed in the condition report that are used to determine 

component wear. In order to address this concern, by letter dated August 21, 2012, the staff 

issued RAI B.1.22-7a, requesting the applicant to describe the other tools used to determine 

component wear, and to explain how the use of component inspection results reduces the 

effects of any errors in CHECWORKS.

In its response dated September 13, 2012, the applicant provided the factors it uses to select 

locations for outage inspections and stated that the measured wall thickness is compared to the 

predicted value for every component where the CHECWORKS prediction is the basis of the 

selection. The applicant also stated that the actual measured wall thickness data can be used 

to detect errors in the CHECWORKS software. The applicant also provided its process steps 

for determining component wear, which included calculating the projected wear rate by using 

the change in measured wall thickness data and the operating time between measurements. 

The staff finds the response acceptable because the applicant’s process, which independently 

calculates wear rates and compares the predicted values to actual measured wall thickness 

data, is capable of compensating for the type of CHECWORKS software error discussed in the 

condition report, thereby providing reasonable assurance that effects of aging will be adequately 

managed to maintain intended functions consistent with the CLB. The staff’s concerns

described in RAIs B.1.22-7 and B.1.22-7a are resolved.

The staff also reviewed the portions of the “scope of program” and “corrective actions” program 

elements associated with the exception and enhancement to determine whether the program 

will be adequate to manage the aging effects for which it is credited. The staff’s evaluation of 

the exception and enhancement follows.

Exception. The applicant acknowledged an exception to the “scope of program” and 

“monitoring and trending” program elements in responses to RAIs B.1.22-1a and B.1.22-1b, 

dated October 2, and December 18, 2012, respectively. In this exception, the applicant stated 

that the GGNS Flow-Accelerated Corrosion Program addresses loss of material due to 

mechanisms other than flow-accelerated corrosion that are identified through plant-specific and 

industry operating experience. The applicant justified this exception by stating that, although a 

predictive model is not applicable, the program provisions for identifying inspection locations 

based on operating experience are applicable and appropriate for mechanisms other than flowaccelerated corrosion. The applicant noted in its response to RAI B.1.22-1b that it does not 

remove components from the program that have been replaced with “FAC-resistant” or “erosionresistant” materials and that inspections of replaced components continue on a schedule that 

ensures wall thinning does not exceed acceptable values. However, the staff noted that the 

applicant’s response to RAI B.1.22-1a states that flow-accelerated corrosion location No. 662, 

which was being managed for erosion, “was replaced in 2004 with FAC-resistant material 

(stainless steel) and is no longer monitored for FAC.” This discrepancy between how the 

program is intended to work compared to how it appears to be implemented was addressed in 
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RAI B.1.22-1c, previously discussed above, and resulted in an additional enhancement to the 

program, as discussed below.

The staff reviewed this exception against the corresponding program element in GALL Report 

AMP XI.M17 and finds it acceptable because the current industry guidance, NSAC-202L, 

contains provisions for a category of components that are susceptible to flow-accelerated 

corrosion, but cannot be accurately modeled by the predictive software due to various 

complicating factors. NSAC-202L designates this category as susceptible-not-modeled. In 

addition, the staff agrees that the applicant can manage components that are susceptible to 

wall-thinning mechanisms other than flow-accelerated corrosion, which cannot be modeled by 

the predictive software, similar to the way it manages susceptible-not-modeled components that 

are included in the Flow-Accelerated Corrosion Program.

Enhancement 1. LRA Section B.1.22 states an enhancement to the “corrective actions”

program element. In this enhancement, the applicant stated that, when upstream components 

are replaced with resistant material, such as high chromium material, the downstream 

components will be closely monitored for any increased wear. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.M17 and 

finds it acceptable because when implemented, it will detect any increase in wear rate that has 

been noted in the industry on components downstream of those replaced with stainless steel.

Enhancement 2. As a result of RAI B.1.22-1c, by letter dated December 20, 2013, the applicant 

revised LRA Section B.1.22 to implement an additional enhancement to the “corrective actions” 

program element. In this enhancement, program documentation will be revised to specify that 

components subject to wall-thinning mechanisms other than FAC, which are replaced with 

alternate materials, shall continue to be periodically monitored at a frequency commensurate 

with their post-replacement wear rates and operating times. The staff reviewed this 

enhancement against the guidance in LR-ISG-2012-01, “Wall Thinning Due to Erosion 

Mechanisms,” and finds it acceptable because corrective actions will require periodic monitoring 

for components replaced with an alternate material, since a material completely resistant to a 

non-FAC mechanism such as erosion is not available.

Summary. Based on its audit of the applicant’s Flow-Accelerated Corrosion Program and 

review of the applicant’s responses to RAIs B.1.22-1, B.1.22-1a, B.1.22-1b, B.1.22-1c, B.1.22-2, 

B.1.22-2a, B.1.22-3, B.1.22-4, B.1.22-7, and B.1.22-7a, the staff finds that the program 

elements for which the applicant claimed consistency with the GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.M17. The staff also reviewed the 

exception and its justification associated with the “scope of program” and “monitoring and 

trending” program elements and finds that the AMP, with the exception, is adequate to manage 

the applicable aging effects. In addition, the staff also reviewed the enhancement associated 

with the “corrective actions” program element and finds that when implemented they will make 

the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.22 summarizes operating experience related to the 

Flow-Accelerated Corrosion Program. The LRA discusses the evaluation of wall thickness data 

from refueling outage 14 (RF14) in 2005 and noted that all items inspected were acceptable for 

continued service beyond RF15. The LRA also discussed the evaluation of wall thickness data 

from RF16 in 2008 and noted that, except for three components, all items inspected were 

acceptable for continued service beyond RF17. The LRA states that condition reports were 

issued for each of the three components and each was repaired. The LRA also cited a 
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2009 program assessment report that stated the identification of program deficiencies and 

subsequent corrective actions provide assurance that the program will remain effective.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs, as 

discussed below.

SRP-LR Section A.1.2.3.10, “Operating Experience,” states that operating experience, which 

results in program enhancements or additional programs, should be considered. In its review of 

Calculation MC-Q1111-08011, item 809 states that the reactor water cleanup bottom head drain 

lines are an operating experience issue and that BWRVIP-205, “Bottom Head Drain Line 

Inspection and Evaluation Guidelines,” changed GGNS to a category that requires an inspection 

within two outages of November 2008. The staff noted that BWRVIP-205 was not listed in LRA 

Appendix C, “Responses to BWRVIP Applicant Action Items,” and it was unclear whether the 

inspections prescribed in BWRVIP-205 will be performed and whether they are being tracked 

under the Flow-Accelerated Corrosion Program or the Reactor Vessel Internals Management 

program. By letter dated April 25, 2012, the staff issued RAI B.1.22-5, requesting the applicant 

to provide the status of the prescribed inspections and to either provide an enhancement to the 

Flow-Accelerated Corrosion Program to include these inspections or provide the bases for 

concluding these inspections do not need to be performed.

In its response dated May 25, 2012, the applicant stated that it had performed the inspections 

prescribed in BWRVIP-205 during the refueling outage in spring 2012 and had projected the 

limiting location to be acceptable until at least spring 2022. The applicant also stated that the 

drain line is included in the Flow-Accelerated Corrosion Program, which ensures the future 

inspections will be conducted. The staff finds the applicant’s response acceptable because the 

bottom head drain line was inspected as prescribed by BWRVIP-205, and this line had been 

added to the Flow-Accelerated Corrosion Program. The staff’s concern described in

RAI B.1.22-5 is resolved.

SRP-LR Section A.1.2.3.10, “Operating Experience,” states that operating experience should 

result in appropriate program enhancements and show where an existing program has failed in 

intercepting aging degradation in a timely manner. The staff’s review of 

Calculation MC-Q1111-08011, item 355, and item 553 identified that the measured wall 

thickness was less than minimum wall thickness, and the projected life for each item indicated 

that the minimum wall thickness criterion was not met more than 3 years prior to the inspection. 

Although condition reports were initiated and the inspection scope was appropriately increased, 

based on the calculated wear rates, the staff questioned the effectiveness of the program 

because inspections are typically planned prior to violating the minimum wall thickness criterion. 

By letter dated April 25, 2012, the staff issued RAI B.1.22-6 requesting the applicant to discuss 

the circumstances surrounding the apparent weakness in scheduling inspections for item 355 

and item 553 and to include corrective actions or enhancements to the program taken as a 

result of these plant-specific operating experiences.

In its response dated May 25, 2012, the applicant stated that item 355 addressed a shell drain 

nozzle of a moisture separator reheater and that the low thickness reading was at a localized 
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area. The applicant stated that the nozzle was repaired using a weld overlay and that based on 

the nozzle’s average wall thickness being well-above the minimum code required thickness, 

there was no need for a specific program enhancement. The applicant also stated that 

item 553, pertains to a socket welded fitting downstream of an orifice in a 2-inch bypass line to 

the high-pressure condenser shell. The applicant stated that the inspections in fall 1999 and fall 

2005 had concluded that wear at this location remained fairly constant; however, the wear rate 

increased significantly between the inspections in fall 2005 and fall 2008 inspections. The 

applicant further stated that it had replaced this bypass line and another line that experienced 

similar operating conditions with stainless steel material during the fall 2010 refueling outage to 

manage the effects of aging. The staff finds the applicant’s response acceptable because the 

circumstances surrounding these apparent weaknesses in inspection scheduling are not 

straightforward such that the wear could not be reasonably foreseen. In addition, the staff 

considers the applicant’s corrective actions to be sufficient to preclude the need for specific 

enhancements to the program. The staff’s concerns described in RAI B.1.22-6 are resolved.

Based on its audit and review of the application, and review of the applicant’s responses to 

RAIs B.1.22-5 and B.1.22-6, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience and implementation of the program has 

resulted in the applicant taking corrective actions. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which the corresponding GALL 

Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.22, as amended by letter dated October 2, 2012, in 

response to RAI B.1.22-1a, and by letter dated December 20, 2013, in response to 

RAI B.1.22-1c, provides the UFSAR supplement for the Flow-Accelerated Corrosion Program. 

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted that 

the applicant committed (Commitment No. 13 and No. 36) to enhance the Flow-Accelerated 

Corrosion Program prior to November 1, 2024, (a) to specify that downstream components are 

monitored closely to mitigate increased wear when susceptible upstream components are 

replaced with resistant materials such as high chromium, and (b) to require periodic monitoring 

for components replaced with an alternate material when they are subjected to a 

non-flow-accelerated corrosion wall-thinning mechanism. The staff finds the information in the 

UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Flow-Accelerated Corrosion 

Program, the staff determined that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program element of 

GALL Report AMP XI.M17. In addition, the staff reviewed the exception and its justification and 

determined that the AMP, with the exception, is adequate to manage the applicable aging 

effects. The staff also reviewed the enhancements and confirmed that their implementation 

through Commitments No. 13 and No. 36 prior to the period of extended operation will make the 

AMP adequate to manage the applicable aging effects. 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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3.0.3.1.22 Inservice Inspection

Summary of Technical Information in the Application. LRA Section B.1.23 describes the 

existing Inservice Inspection (ISI) Program as consistent with GALL Report AMP XI.M1, “ASME 

Section XI Inservice Inspection, Subsections IWB, IWC, and IWD.” It states that this program 

manages aging effects for ASME Class 1, 2, and 3 pressure-retaining components within the 

scope of license renewal. The LRA also states that this program includes volumetric, surface, 

and visual examinations of Class 1, 2, and 3 pressure-retaining components, including welds, 

pump casings, valve bodies, integral attachments, and pressure-retaining bolting.

The applicant further stated that this program is updated every 10 years to the latest ASME 

Code Section XI edition and addendum the NRC approved in 10 CFR 50.55a.

In addition, the applicant stated that its ISI Program summary reports between 2004 and 2010 

reveal compliance (including evaluation or repair of indications/flaws) and provide evidence that 

the program is effective for managing aging effects in accordance with the ASME Boiler 

Pressure Vessel Code Section XI.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared elements one through six of the applicant’s program to the 

corresponding elements of GALL Report AMP XI.M1. For the “detection of aging effects” 

program element, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M1 states that ASME 

Code Section XI Table IWB-2500-1 is used to determine the examination of Categories B-F and 

B-J welds. The staff noted that the applicant implemented risk-informed inservice inspection 

(RI-ISI) with Examination Category R-A in lieu of Categories B-F and B-J for the current 10-year 

ISI interval as approved by the NRC. The RI-ISI provides alternate inspection requirements for 

a subset of Class 1 piping welds. The staff noted that the use of RI-ISI is only approved for the 

current 10-year ISI interval. Future implementation of RI-ISI is subject to the NRC approval in 

accordance with 10 CFR 50.55a for each subsequent 10-year ISI interval including the period of 

extended operation. The staff confirmed during the onsite audit that the applicant’s ISI Program 

Plan calls for a review of the RI-ISI implementation for future inspection intervals. The staff 

finds this acceptable because the applicant will have to seek NRC approval for use of this RI-ISI 

relief request for future inspection intervals.

The staff noted that the applicant updates its program every 10 years (120 months) to the latest 

ASME Code Section XI as approved by the NRC before the start of the inspection interval. The 

applicant’s ISI Program is currently in its third 10-year ISI interval, which began on July 1, 2005. 

The current Code of record for the applicant’s ISI Program is the 2001 Edition through the 

2003 Addenda of the ASME Code.

During its review, the staff noted Event Notification Report No. 47880, dated April 30, 2012, 

indicating that the applicant detected an unacceptable indication in one of the RHR systems to 

reactor pressure vessel nozzles (weld area of N06B-KB nozzle) during its refueling outage in 

May 2012. The defect has a size of 0.9 inch in length and 0.5 inch in depth. Nominal wall 

thickness of the weld is 1.3 inches. The staff needed clarification on the effectiveness of the 

applicant’s AMP (e.g., detection of aging effects and directing corrective actions in a timely 

manner). By letter dated June 27, 2012, the staff issued RAI B.1.23-2 requesting that the 

applicant clarify whether the defect detected in the RHR nozzle is age-related. The RAI also 
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requested the applicant to clarify when the previous UT examination was performed on the 

subject RHR weld and describe adequacy of its corrective actions and extent of condition 

performed. The RAI further requested that the applicant provide justification that the current 

inspection schedule for all affected components is adequate for timely detection of aging effects.

In its response dated July 26, 2012, the applicant stated that the indication detected was 

attributed to the aging mechanism of IGSCC, similar to IGSCC cracks found in DM welds at 

other BWRs. Regarding previous UT examination performed on this weld, the applicant stated 

that the previous examination was performed during the fall 2002 refueling outage and no 

indications were identified at the time. Regarding its corrective actions and extent of condition, 

the applicant stated that there are thirty-four DM welds that require inspection under 

BWRVIP-75-A. Twenty DM welds were inspected prior to RF18. The remaining 14 welds in the 

program were inspected during RF18. All welds of this type have been inspected with no other 

flaws detected. The applicant further stated that the corrective action implemented to correct 

the indication identified during RF18 included a full structural weld overlay. The staff noted that 

the applicant performed a full structural weld overlay to mitigate the flaw, an industry repair 

methodology approved by the staff. The staff also noted that the applicant followed 

BWRVIP-75-A, a staff-approved industry program, and performed UT examinations on all its 

required DM welds. The staff finds the applicant’s response acceptable because the applicant 

performed appropriate corrective action to mitigate the flaw and performed adequate extent of 

condition that resulted in the applicant inspecting all DM welds of the same type, a total of 34

DM welds. In addition, no other indications were detected from the UT examinations of all other 

similar DM welds. Therefore, the staff’s concern described in RAI B.1.23-2 is resolved.

Based on its audit and review of the LRA and the applicant’s responses to RAIs, the staff finds 

that elements one through six of the applicant’s Inservice Inspection Program are consistent 

with the corresponding program elements of GALL Report AMP XI.M1 and, therefore, 

acceptable.

Operating Experience. LRA Section B.1.23 summarizes operating experience related to the 

Inservice Inspection Program. The applicant indicated that this program is based on the ASME 

Code Section XI, Subsections IWB, IWC, and IWD, which is based on industry-wide operating 

experience, research data, and technical evaluations.

The staff noted that GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD,” states that the program “has been shown to be generally 

effective in managing aging effects in Class 1, 2, or 3 components and their integral 

attachments in light-water cooled power plants.” It also provides industry operating experience 

cases in the “operating experience” program element. However, the LRA does not provide any 

detailed discussion to demonstrate the effectiveness of the program in detecting and managing 

the aging effects of Class 1, 2, or 3 components in a timely manner. In addition, the applicant’s 

ISI Program summary reports between 2004 and 2010 provide brief inspection results to 

establish the program’s compliance with the ASME Code, but do not provide any discussion to 

demonstrate the program effectiveness in the context of monitoring, detecting, and correcting 

aging degradation. Therefore, by letter dated April 3, 2012, the staff issued RAI B.1.23-1 

requesting that the applicant provide detailed representative operating experience related to the 

applicant’s Inservice Inspection Program to demonstrate the program’s effectiveness in 

managing aging effects during the period of extended operation.

In its response dated May 1, 2012, the applicant provided specific operating experience cases 

related to the implementation of its ISI Program. For example, as part of the ISI Program 
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inspection in 2004, the applicant’s examinations identified linear indications in numerous CRD 

cap-screws. As a result, the applicant performed a metallographic examination and engineering 

evaluation on five CRD cap screws with the most significant indications and determined the 

condition of the cap-screws were acceptable for continued service. In addition, as CRDs were 

replaced, they were inspected by VT-1 and those with unacceptable indications were subjected 

to eddy current examination to verify the surface indication did not extend beyond the 

acceptable depth. Furthermore, for cap screws with indications that exceeded the established 

limit on flaw depth, a condition report was initiated by the applicant to evaluate the condition and 

effect appropriate corrective actions. This experience demonstrated that the applicant’s ISI 

Program is able to detect minor indications of potential degradation before a loss of the 

component’s license renewal-intended function. In its response, the applicant provided a 

second example. During the same outage inspection, deficiencies were found in pipe supports 

in the SSW cooling tower basin, which resulted in engineering evaluations, extent of condition, 

and repairs. In addition, follow-up inspections by the applicant’s ISI Program confirmed that 

repairs were made in satisfactory condition. The staff finds the applicant’s response acceptable 

because the applicant provided discussion of plant-specific operating experience that 

demonstrates the effectiveness of the program by detection of aging effects and directing 

corrective actions in a timely manner. Therefore, the staff’s concern described in RAI B.1.23-1 

is resolved.

Based on its audit and review of the application, and review of the applicant’s response to

RAI B.1.23-1, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.23 provides the UFSAR supplement for the Inservice 

Inspection Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description for this type of program as 

described in SRP-LR Table 3.0-1. The staff determines that the information in the UFSAR 

supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inservice Inspection 

Program, the staff concludes 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).

3.0.3.1.23 Inservice Inspection – IWF

Summary of Technical Information in the Application. LRA Section B.1.24 describes the 

existing Inservice Inspection – IWF Program as consistent, with enhancements, with GALL 

Report AMP XI.S3, “ASME Section XI, Subsection IWF.” The LRA states that the Inservice 

Inspection – IWF Program manages aging effects for ASME Class 1, 2, and 3 and component 

supports. The LRA also states that the scope of inspection for component supports is based on 

sampling of piping supports and 100 percent of component supports other than piping as 

specified in Table IWF-2500-1. The applicant’s AMP basis document, which the staff reviewed 
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on site, states that the AMP manages aging through visual inspection in accordance with ASME 

Section XI, Subsection IWF. During its audit, the staff confirmed that the applicant does not 

have any ASME Code Class MC supports.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S3. For the “preventive 

actions” and “monitoring and trending” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The “preventive actions” program element in GALL Report AMP XI.S3 recommends that the 

selection of bolting material installation torque or tension and the use of lubricants and sealants 

be in accordance with the guidelines of EPRI NP-5769, EPRI TR-104213, and the additional 

recommendations of NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting 

Degradation or Failure in Nuclear Power Plants,” to prevent or mitigate degradation and failure 

of structural bolting. These EPRI documents and NUREG-1339 discuss the detrimental effects 

of using molybdenum disulfide lubricant because lubricants containing molybdenum disulfide 

have been shown to contribute to SCC. The GALL Report states that if the structural bolting 

consists of ASTM A325, ASTM F1852, and/or ASTM A490 bolts, the preventive actions for 

storage, lubricants, and SCC potential discussed in Section 2 of RCSC (Research Council for 

Structural Connections) publication “Specification for Structural Joints Using ASTM A325 or 

A490 Bolts,” need to be considered.

During its audit, the staff reviewed the applicant’s Inservice Inspection – IWF AMP, which states 

that the site maintenance procedures that provide technical guidance to torquing procedures 

recommend using molybdenum disulfide. The AMP states that it is assumed that all 

high-strength structural bolting material (i.e., ASTM A325 and A490) has used this lubricant in 

the torquing process during construction and maintenance activities for the life of the plant so 

far. During its onsite review, the staff noted that the AMP states that plant procedures will be 

enhanced to prohibit the use of molybdenum disulfide; however, the AMP does not address how 

and when bolts previously torqued using molybdenum disulfide lubricant will be inspected for 

degradation. The AMP also does not specify that the program will require that the selection of 

bolting material installation torque or tension and the use of lubricants and sealants will be in 

accordance with EPRI NP-5769, EPRI TR-104213, and NUREG-1339. The staff questioned 

whether the applicant’s program will be in accordance with the above guidance for bolting 

material, as well as the guidance of RCSC “Specification for Structural Joints Using ASTM A325 

or A490 Bolts” for structural bolts. Therefore, by letter dated May 9, 2012, the staff issued

RAI B.1.24-5 requesting that the applicant describe the plan, including sample size and 

frequency, for inspecting high-strength bolts previously torqued using molybdenum disulfide 

lubricant.

In its response dated June 6, 2012, the applicant stated that the ISI-IWF Program addresses the 

potential for SCC for high-strength bolts for nuclear steam supply system component supports 

by including sample size and frequency for bolts that may have been previously torqued using 

molybdenum disulfide. The applicant also stated that it is augmenting its program to include 

volumetric examination of high-strength structural bolting. The staff noted that the applicant’s 

response did not indicate whether the applicant’s procedures will implement the guidance 

recommended in the GALL Report or follow the preventive actions for storage, lubricants, and 

SCC potential discussed in the RCSC “Specification for Structural Joints using ASTM A325 or 

A490 Bolts” for high-strength structural bolts. In a letter dated September 5, 2012, the staff 

issued follow-up RAI B.1.24-5a requesting that the applicant clarify (a) if its program will 
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implement the guidelines of EPRI NP-5769, EPRI TR-104213, and NUREG-1339 to prevent or 

mitigate degradation and failure of structural bolting; and (b) if it will follow the RCSC guidance 

for ASTM A325 and A490 bolts.

The applicant responded by letter dated October 2, 2012. Part (a) of the applicant’s response 

stated that the existing ASME Section XI Inservice Inspection – IWF Program is a condition 

monitoring program that does not include guidance for the selection of bolting material, 

installation torque or tension, and use of lubricants and sealants, but instead is augmented by 

plant procedures that address that guidance. The applicant stated that it will include an 

enhancement to incorporate recommendations delineated in NUREG-1339, and EPRI NP-5769 

and TR-104213 for high strength structural bolting. The enhancement also states that the 

recommendations will address proper selection of bolting material, proper installation torque or 

tension, and the use of appropriate lubricants and sealants. In part (b) of its response, the 

applicant clarified that site procedures include the guidance of Section 2 of RCSC publication, 

“Specification for Structural Joints Using ASTM A325 or A490 Bolts” for ASTM A325, ASTM 

F1852 and A490 bolting.

The staff finds the applicant’s response acceptable because procedures for implementation of 

the ASME Section XI Inservice Inspection – IWF Program include the guidance of the RCSC 

publication, which discusses preventive actions for storage, lubricants, and stress corrosion 

cracking potential for high strength structural bolts. In addition, the implementing procedures for 

the ASME Section XI Inservice Inspection – IWF Program will incorporate the guidance 

recommended in GALL Report AMP XI.S3. The staff’s concerns described in RAIs B.1.24-5 

and B.1.24-5a are resolved.

The “monitoring and trending” program element in GALL Report AMP XI.S3 recommends that 

examinations that reveal indications that exceed the acceptance criteria of ASME IWF-3410 and 

require corrective measures are extended to include additional examinations in accordance with 

IWF-2430. The applicant’s AMP basis documentation states that the acceptance criteria are in 

accordance with ASME IWF-3410. However, during its audit, the staff reviewed results of the 

2011 ISI-IWF inspection in which a bolt in the SSW system was found to have degradation that 

exceeded the acceptance criteria, and the applicant did not provide documentation to indicate 

that the examination would be extended to include additional examinations or that such 

examinations had been performed consistent with the GALL Report recommendations and in 

accordance with the requirements of ASME IWF-2430.

By letter dated May 9, 2012, the staff issued RAI B.1.24-2 requesting that the applicant provide 

documentation that demonstrates that the Inservice Inspection – IWF Program, as implemented, 

is consistent with ASME IWF-2430 and Section XI.S3, ASME Section XI, Subsection IWF of the 

GALL Report, regarding increase in sample size when deficiencies are identified during 

examination of supports. If additional inspections were not performed, the staff requested that 

the applicant provide the basis for the statement in LRA Section B.1.24 that the IWF Program is 

consistent with ASME Code and Section XI.S3 for GALL Report.

In its response dated June 6, 2012, the applicant stated that during the 2003 ISI-IWF inspection, 

one of the underwater supports was documented as not meeting the acceptance criteria in 

ASME Section IWF-3000 and the condition was documented in the CAP. The applicant 

increased the scope of the ISI-IWF inspection in accordance with ASME Section XI, 

Subsection IWF-2430. The applicant further stated that subsequent ISI-IWF inspections 

performed after 2004 identified additional supports that did not meet the acceptance criteria 

requirements in ASME Section IWF-3400, and the conditions were entered into the CAP. The 
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applicant determined that it needed to increase the frequency of the inspections of the 

underwater supports to include all underwater supports. The applicant finally stated that, since 

100 percent of the underwater supports in the SSW basins are inspected, the degraded 

component found during the 2011 inspection did not result in an expansion of inspection scope.

The staff reviewed the applicant’s response and noted that the condition discovered in the 

2011 inspection was subsequent to the applicant’s previous corrective actions with regard to 

age-related degradation found in prior inspections. The staff also noted that when a degraded 

condition was found in 2003, the applicant expanded the inspection scope to include additional 

supports in the SSW basin and more frequent inspections and that it further expanded the 

inspection scope to include 100 percent of the supports on a yearly frequency. However, the 

staff questioned whether there are any IWF supports in other systems that may be subject to a 

similar material and environment combination and if the scope of additional inspections should 

be extended to areas beyond the SSW system. The staff needed more information to complete 

its review. Therefore, by letter dated September 5, 2012, the staff issued follow-up

RAI B.1.24-2a and requested that the applicant provide information on whether there are IWF 

supports in other areas of the plant that may be subject to similar age-related degradation. If 

so, the staff requested that the applicant provide information as to what additional examinations 

will be performed, if any.

In its response dated October 2, 2012, the applicant stated that it has not identified ASME 

Section XI-IWF supports in other areas of the plant that are subject to similar age-related 

degradation as the degraded supports identified in the SSW basin. The applicant explained that 

there are in-scope supports in other areas of the plant that are exposed to a fluid environment 

similar to the SSW basin, such as the suppression pool and spent fuel pool components; 

however, the materials for those supports are not carbon steel.

The staff finds the applicant’s response acceptable because the applicant has considered the 

susceptibility of IWF components of similar material and environment combination and 

concluded that there are no IWF components subject to similar aging effects other than those in 

the SSW system. Also, the applicant now includes 100 percent of underwater supports in the 

SSW system as a result of as-found degraded conditions in accordance with ASME IWF-2430. 

The staff’s concerns described in RAIs B.1.24-2 and B.1.24-2a are resolved.

During its audit, the staff also noted several cases in which conditions were found during ASME 

ISI-IWF examinations that appeared to be degraded, but where an engineering evaluation 

determined that the component was acceptable for continued service (i.e., did not violate the 

acceptance standards of ASME Code Section IWF-3410), and the applicant chose to re-work 

the component to its as-new condition. The ASME Code, Section XI, Subsection IWF Program

requires the inspection of the same sample of the total population of component supports each 

inspection interval. The staff determined that in order for effective aging management of the 

entire population, the condition of the component to be re-examined during each inspection 

interval should be representative of the aging of the entire population. If IWF supports that are 

part of the inspection sample are re-worked to as-new condition, that support is no longer typical 

of the other supports in the population that were not re-worked and in subsequent examinations 

would not represent the age-related degradation of that population. Therefore, by letter dated 

May 9, 2012, the staff issued RAI B.1.24-3 requesting that the applicant explain, when 

corrective actions are not required per the ASME Code Section IWF acceptance criteria, but a 

support within the IWF inspection sample is found degraded and repaired to as-new condition 

without an expansion or revision of the IWF sample population, how the IWF Program will be 
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effective in managing aging of similar/adjacent components in that population that are not 

included in the IWF Program sample.

In its response dated June 6, 2012, the applicant stated that, for conditions when corrective 

actions are not required per the ISI-IWF acceptance criteria but the support is within the 

inspection sample, the repair activity is evaluated to determine whether it is a repair or 

replacement activity or is considered a maintenance activity. The applicant stated that 

maintenance activities may require the performance of a new ASME Section XI Code 

examination or test. The applicant also stated that, if a maintenance activity is performed and 

the activity affects an existing preservice or inservice examination record, then a new preservice 

examination will be performed.

The staff did not find the applicant’s response acceptable because it does not address how the 

applicant will address age-related degradation of the IWF component population when a support 

is repaired to a condition that is as-new and then not representative of the rest of the component 

support population. The GALL Report recommends that the IWF Program use the sampling 

methodology stated in ASME Table IWB-2500 to inspect and examine for the presence of and 

extent of aging effects to represent the total population of components, including those that are 

similar but are outside the inspection sample. Re-working a component or components in the 

sample before degradation to the ASME IWF-3000 limits, but not (1) replacing that component 

with one that shows aging representative of the rest of the population, or (2) expanding the 

inspection sample to include another component that shows aging representative of the 

remaining population, may make the program unable to detect more severe age-related 

degradation of components outside the inspection sample that are continuing to degrade. The 

staff determined that it needed further information to complete its review. Therefore, by letter 

dated September 5, 2012, the staff issued follow-up RAI B.1.24-3a requesting that the applicant 

explain how, without either changing the component inspected or expanding the inspection 

scope, if components determined to be degraded but not exceeding the ASME acceptance 

criteria for expansion in scope are selectively re-worked, it can ensure that components in the 

IWF inspection scope are a true representation of the age-related degradation of remaining 

components in the population.

In its response dated October 2, 2012, the applicant stated that when component support 

conditions are found to include minor age-related degradation that does not meet the threshold 

of “unacceptable for continued service” as defined in IWF-3400, an evaluation will be performed 

in accordance with the CAP. The applicant stated that if the evaluation determines that the 

component, without repair, will continue to perform its intended function until the next scheduled 

inspection, the component support will not be repaired but will be monitored for increased 

degradation. The applicant further stated that the evaluation will also consider which 

inspections or repairs may be required for similar/adjacent components not included in the ISI 

program sample population and assure that additional inspections are performed during the 

next scheduled inspection. As an alternative, the applicant stated that it may choose to repair 

the degraded component and replace it in subsequent inspection samples with a randomly 

selected component that is more representative of the general population. The applicant 

revised LRA Sections A.1.24 and B.1.24 to add this revision as an enhancement to the 

program.

The staff finds this response acceptable because the applicant’s program will ensure that the 

component supports being examined in the IWF inspection sample are representative of the 

aging of the total population, thus allowing the program to adequately manage aging of IWF 
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supports and bolting. The staff’s concern described in RAIs B.1.24-3 and B.1.24-3a are 

resolved.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.24 states an enhancement to the “scope of program,”

program element. In this enhancement, the applicant stated that the ISI-IWF Program will be 

enhanced to address inspections of accessible sliding surfaces. The staff reviewed this 

enhancement against the corresponding program elements in GALL Report AMP XI.S3 and 

finds it acceptable because, when it is implemented, it will make the program consistent with the 

recommendations in the GALL Report AMP.

Enhancement 2. LRA Section B.1.24 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that the ISI-IWF 

Program will be enhanced to clarify that parameters monitored or inspected will include 

corrosion; deformation; misalignment of supports; missing, detached, or loosened support 

items; improper clearances of guides and stops; and improper hot or cold settings of spring 

supports and constant load supports. The applicant also stated that accessible areas of sliding 

surfaces, elastomeric vibration isolation elements, and structural bolts will be monitored for all 

applicable aging effects, which the staff confirmed is consistent with the recommendations of 

the GALL Report AMP XI.S3. In addition, high-strength structural bolting susceptible to SCC 

will be monitored for SCC. The staff reviewed these enhancements against the corresponding 

program elements in GALL Report AMP XI.S3 and finds them acceptable because, when they 

are implemented, they will make the program consistent with the recommendations in the 

GALL Report AMP.

Enhancement 3. LRA Section B.1.24 states an enhancement to the “detection of aging effects”

program element. In Enhancement 3, the applicant stated that structural bolting (ASTM A325, 

ASTM F1852, and ASTM A490 bolts) and anchor bolts will be monitored for loss of material, 

loose or missing nuts, loss of preload, and cracking of concrete around the anchor bolts. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report

AMP XI.S3 and finds it acceptable because, when it is implemented, it will make the program 

consistent with the recommendations in the GALL Report AMP.

The applicant also states another enhancement to the “detection of aging effects” program 

element, that it will perform volumetric examination comparable to that of ASME Code 

Section XI, Table IWB-2500-1, Examination Category B-G-1 for high-strength structural bolting 

in addition to the VT-3 examination. During its audit, the staff asked the applicant how it will 

implement the provisions for volumetric examinations, specifically to give the sample size, 

sampling method, and frequency of volumetric examinations. The applicant stated that it would 

perform volumetric examinations of any high-strength bolts identified on the component 

supports that are in the scope of the IWF sample for each inspection interval. The staff noted 

that the applicant’s Inservice Inspection – IWF Program selects component supports for 

examination in accordance with the ASME Code, which requires 25 percent of Class 1 piping 

supports, 15 percent of Class 2 supports, and 10 percent of Class 3 supports. The staff 

determined that the applicant’s plans to perform volumetric examination on only the 

high-strength bolting that is identified on supports that are already within the IWF sample does 

not necessarily ensure that an adequate number of bolts will be examined in order to effectively 
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manage aging of high-strength bolting. The staff noted that the applicant’s original sample 

selection for the IWF Program did not include high-strength bolting, so there is no assurance 

that there will be enough bolts identified within the scope of the current IWF sample to ensure a 

representative sample of the entire population of high-strength structural bolting will be subject 

to volumetric examination. The staff determined the need for additional information, which 

resulted in the issuance of an RAI. By letter dated May 9, 2012, the staff issued RAI B.1.24-1 

requesting that the applicant describe how the volumetric inspections for the Inservice 

Inspection – IWF Program will manage cracking for the entire population of high-strength bolts 

for the period of extended operation.

In its response dated June 6, 2012, the applicant stated that it will enhance the ISI-IWF Program

to identify the component supports that contain high-strength bolting (actual yield strength 

greater than or equal to 150 ksi) in sizes greater than 1-inch nominal diameter and that the 

frequency and extent of examination for support types that contain high-strength bolting will be 

as specified in ASME Code Section XI, Table IWF-2500-1. The staff reviewed the applicant’s 

response and could not determine if the applicant plans on identifying the entire population of 

the high-strength structural bolting in scope for license renewal and then using the sampling 

provisions of ASME Table IWB- 2500-1. The staff found that the applicant’s response was not 

acceptable because it was not clear that the sampling percentages specified in ASME 

IWF-2500-1 would be followed for the high-strength bolts as an individual population or if the 

applicant’s plan is to identify high-strength bolts that exist on component supports already 

identified in the IWF inspection sample. The staff determined that it needed additional 

clarification to complete its review. Therefore, by letter dated September 5, 2012, the staff 

issued follow-up RAI B.1.24-1a requesting that the applicant clarify whether it will identify all of 

the high-strength bolts in the plant that are eligible to be part of the IWF inspection population 

and establish a sample based on the ASME Table IWF-2500-1 or if it will identify high-strength 

bolts from the already-established set of IWF supports. If the latter, the staff requested that the 

applicant explain how that approach will ensure that the ASME Code criteria for sample size will 

be met.

In its response dated October 2, 2012, the applicant clarified that it will identify all of the 

component supports that contain high-strength bolting and will examine high-strength structural 

bolting on the frequency specified in the ASME Code Section XI, Table IWF-2500-1. The staff 

finds this acceptable because the applicant will define an IWF inspection sample for 

high-strength bolts that is representative of the high-strength structural bolting components that 

exist in the plant and because the number of high-strength bolts inspected will be in accordance 

with ASME IWF-2500-1. The staff’s concerns described in RAIs B.1.24-1 and B.1.24-1a are 

resolved.

Enhancement 4. LRA Section B.1.24 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that the program will add the 

following as unacceptable conditions:

• loss of material due to corrosion or wear, which reduces the load-bearing capacity of the 

component support

• debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces 

as intended in the design basis of the support

• cracked or sheared bolts, including high-strength bolts, and anchors
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The staff reviewed this enhancement against the corresponding program elements in GALL

Report AMP XI.S3 and finds it acceptable because when it is implemented it will make the AMP 

consistent with the GALL Report recommendations to manage the applicable aging effects.

Summary. Based on its audit, and review of the applicant’s responses to RAIs B.1.24-5 

B.1.24-2, and B.1.24-3, the staff finds that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.S3. In addition, the staff reviewed the enhancements associated with the 

“scope of program,” and “parameters “acceptance criteria,” program elements as well as one 

enhancement associated with the “detection of aging effects,” program element and finds that 

when implemented, they will make the AMP consistent with the GALL Report recommendations 

to manage the applicable aging effects. In addition, the staff reviewed Enhancements 1–4 and 

finds them acceptable, as discussed above.

Operating Experience. LRA Section B.1.24 summarizes operating experience related to the 

Inservice Inspection – IWF Program. The applicant stated that results of ISI examinations for 

pipe hanger and supports for the RCIC system during RF16 in 2008 were acceptable. The 

applicant also stated that results of ISI examinations for component supports in the reactor 

recirculation system during RF17 in 2010 were acceptable.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

The staff’s onsite review indicated that there may be age-related degradation of underwater 

bolting of component supports and bolting in the SSW basins. During the audit, the applicant 

stated that the degraded bolting was not found during IWF inspections and is thus not subject to 

IWF requirements for expansion of scope per ASME Section IWF-2430. In all cases, the 

applicant entered the conditions into the corrective action process. The staff noted that 

although these were not IWF inspections, it is possible that bolts that are within the scope of the 

IWF Program may have been identified as degraded during these inspections. The staff 

determined that it needed additional information to complete its review. Therefore, by letter 

dated May 9, 2012, the staff issued RAI B.1.24-4 requesting that the applicant provide 

information as to whether any evaluation that was performed to determine if any of the 

degraded bolts found in the SSW basin are part of the IWF sample. The staff also requested 

that the applicant state whether it plans to do any additional examinations of component 

supports. Finally, the staff requested that the applicant provide information on whether the 

latest ISI IWF inspection conducted in July 2011 included any bolts in the SSW basins and the 

results of the inspection of those bolts.

The applicant responded by letter dated June 6, 2012. The applicant stated that there are a 

number of IWF supports in the SSW basin and the sample population for the ISI-IWF inspection 

included the identified deficient component supports. The applicant also stated that, during the 

July 2011 inspection of the SSW basin, a hanger was found degraded and the applicant 

performed an evaluation in accordance with ASME IWF-3112.3 to accept the component as-is 

in its degraded state. The applicant reworked the component and replaced degraded bolting 
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and stated that the IWF Program includes provisions to re-inspect the degraded support during 

the next inspection period in accordance with ASME IWF-2420. The applicant finally stated that 

examinations performed on the remaining population of supports found no degraded bolting that 

failed to meet acceptance criteria.

The staff noted in its review of the applicant’s response to RAI B.1.24-2 that because of the 

identified degradation the applicant has expanded the scope of inspection of the SSW basin to 

100 percent of the underwater supports. The staff also noted that the applicant’s response to 

RAI B.1.24-2a stated that there are no other areas subject to the same age-related degradation 

of this material and environment combination in the IWF program. Therefore, the staff finds the 

applicant’s response acceptable because it appropriately applied the provisions of the ASME 

IWF Code for expansion of scope and frequency of inspection due to discovery of a degraded 

condition. The staff’s concern described in RAI B.1.24-2 is resolved.

Based on its audit and review of the application, and review of the applicant’s response to

RAI B.1.24-4, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.24 provides the UFSAR supplement for the Inservice 

Inspection – IWF Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it is consistent with the recommended description in SRP-LR

Table 3.0-1. The staff finds that the information in the UFSAR supplement is an adequate 

summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s ISI-IWF, the staff determines 

that those program elements for which the applicant claimed consistency with the GALL Report

are consistent. Also, the staff reviewed the enhancements and confirmed that their 

implementation through Commitment No. 14 prior to the period of extended operation will make 

the AMP adequate to manage the applicable aging effects. 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 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) 

Handling Systems

Summary of Technical Information in the Application. LRA Section B.1.25 describes the 

existing Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems Program as consistent, with enhancements, with GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems.”

The LRA states that the program manages loss of material of cranes and hoists, based on 

applicable industry standards and guidance documents. The activities rely on visual 

examinations and functional testing to ensure that cranes and hoists are capable of sustaining 

their rated loads. The program implements the guidance provided in NUREG-0612, “Control of 

Heavy Loads at Nuclear Power Plants,” issued July 1980.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through seven of the applicant’s 

program to the corresponding program elements of GALL Report AMP XI.M23. The staff also 

reviewed the portions of the “scope of program” and “acceptance criteria” program elements 

associated with enhancements to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.25 states an enhancement to the “scope of program”

program element. In this enhancement, the LRA states that the program will be enhanced to 

include monitoring of rails in the rail system for the aging effect of wear and structural 

connections and bolting for loose or missing bolts, nuts, pins, or rivets. Additionally, the 

program will be clarified to include visual inspection of structural components and structural 

bolts for loss of material due to various mechanisms and structural bolting for loss of preload 

due to self-loosening. GALL Report AMP XI.M23 recommends that the bridge, bridge rails, and 

trolley structural components be visually inspected for loss of material due to corrosion; rails be 

visually inspected for loss of material due to wear; and bolted connections be inspected for 

signs of loss of preload. The staff reviewed this enhancement against the corresponding 

program elements in GALL Report AMP XI.M23 and finds it acceptable because, when it is 

implemented, it will make the program consistent with the GALL Report AMP.

Enhancement 2. LRA Section B.1.25 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the LRA states that the program will be revised to state 

that any significant loss of material for structural components and structural bolts, and significant 

wear of rails in the rail system, is evaluated in accordance with ASME B30.2 or other applicable 

industry standard in the ASME B30 series. GALL Report AMP XI.M23 recommends that crane 

rails and structural components be visually inspected for loss of material due to corrosion and 

wear and that bolted connections be inspected for loss of preload at a frequency in accordance 

with the appropriate ASME B30 series standard and that any indication of loss of material or 

loss of preload be evaluated in accordance with ASME B30.2 or other applicable industry 

standard in the ASME B30 series. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M23 and finds it acceptable because,

when it is implemented, it will ensure any indication of aging is evaluated in accordance with the 

ASME B30 series standards to make the program consistent with the recommendations in the 

GALL Report AMP.

Summary. Based on its audit, and review of the applicant’s Inspection of Overhead Heavy Load 

and Light Load (Related to Refueling) Handling Systems Program, the staff finds that program 

elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.M23. In addition, 

the staff reviewed the enhancements associated with the “scope of program” and “acceptance 

criteria” program elements and finds that, when implemented, they will make the AMP adequate 

to manage the applicable aging effects.

Operating Experience. LRA Section B.1.25 summarizes operating experience related to the 

Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems 

Program. In one operating experience example, the LRA states that during a turbine building 

crane inspection, the bridge girder junction bolts, the bridge cross tie bolts, and the bridge drive 

coupling bolts were found to be loose. The LRA states that corrective actions were taken to 

tighten all of the bolting. During the audit, the staff reviewed this operating experience example 

and noted that no additional loose bolts have been discovered on the turbine building crane 

since the repair was completed. In another operating experience example, the LRA states that 
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during an inspection of the polar crane rail clips, a broken stud was found at azimuth 90. The 

rail clips were replaced and further analysis was completed to confirm that the broken stud was 

a result of inadvertent impact, as opposed to an aging issue.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.25 provides the UFSAR supplement for the Inspection of 

Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 

with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the 

applicant committed (Commitment No. 15) to enhance the program prior to May 1, 2024, to 

revise the acceptance criteria to be consistent with the ASME B30 series standards and to 

include monitoring of rails in the rail system for the aging effect of wear and structural 

connections and bolting for loose or missing bolts, nuts, pins, or rivets. Additionally, the 

program will be clarified to include visual inspection of structural components and structural 

bolts for loss of material due to various mechanisms and structural bolting for loss of preload 

due to self-loosening. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Inspection of Overhead 

Heavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff 

determines that those program elements for which the applicant claimed consistency with the 

GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation through Commitment No. 15 prior to the period of extended operation will 

make the AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.25 Internal Surfaces in Miscellaneous Piping and Ducting Components

Summary of Technical Information in the Application. LRA Section B.1.26 describes the new

Internal Surfaces in Miscellaneous Piping and Ducting Components Program as consistent with 

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

Components,” as modified by LR-ISG-2012-02, “Aging Management of Internal Surfaces, Fire 

Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation.” The LRA states 
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that the AMP includes opportunistic visual inspections of internal surfaces of piping and 

components, performed during periodic surveillances or maintenance activities when the 

surfaces are made accessible, to manage the effects of aging within the program. As modified 

in its response dated May 13, 2014, the program includes an assessment of the opportunistic 

inspections every 10 years during the period of extended operation for each combination of 

material, environment, and aging effect to ensure a representative sample of components is 

inspected. Metallic components will be managed for loss of material and fouling. Elastomeric 

components will be managed for cracking and change in material properties. The LRA also 

states that visual examinations will be accompanied by physical manipulation or pressurization 

to detect changes in material properties for elastomeric components within the program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M38. For the program 

description and “scope of program,” “parameters monitored or inspected,” “detection of aging 

effects,” and “acceptance criteria” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The program description for GALL Report AMP XI.M38 states that the program includes internal 

inspections of metallic ducting. The program description also states that the program includes

components exposed to air-indoor uncontrolled, air outdoor, condensation and water systems 

other than fire water, open-cycle cooling water, and closed treated water systems. However, 

the applicant’s description of its Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program does not discuss whether metallic ducting will be included in the program 

or the environments covered by the program. By letter dated April 12, 2012, the staff issued

RAI B.1.26-1 requesting that the applicant clarify if metallic ducting is included in the program 

and to describe the environments covered by the program.

In its response dated May 9, 2012, the applicant stated that the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program is consistent with GALL Report

AMP XI.M38, without exception, and that the components and environments covered by the 

program are listed in the AMR items. The applicant revised the UFSAR supplement in LRA 

Section A.1.26 to clarify that metallic ducting is managed by the program. However, the 

applicant did not revise LRA Section A.1.26 to describe the environments managed by the 

program. The staff’s concern regarding the UFSAR supplement is associated with 

RAI B.1.26-1a, which is discussed in the UFSAR supplement section of the staff’s evaluation of 

this program. The staff finds the applicant’s response acceptable because metallic ducting is 

included within the scope of the program, which is consistent with GALL Report AMP XI.M38

and the environments listed in the AMR items for the components managed by this program are 

consistent with the environments managed by GALL Report AMP XI.M38. The staff’s concerns 

described in RAI B.1.26-1 regarding the program description are resolved. RAI B.1.26-1 also 

addresses concerns with the “detection of aging effects” program element, which is discussed 

later in this section.

The “scope of program” program element of GALL Report AMP XI.M38 states that the program 

manages the aging effects of hardening, loss of strength, cracking, and loss of material for 

polymeric and elastomeric components. GALL Report AMP XI.M38 also states that metallic 

components are managed for the aging effect of loss of material. The applicant also applies the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage fouling 

for metallic components. The staff issued RAIs B.1.26-2, B.1.26-3, and B.1.26-4, as discussed 

below, regarding the “scope of program” program element.
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LRA Table 3.3.2-16 includes an AMR item for copper alloy with greater than 15 percent zinc 

(inhibited) heat exchanger tubes exposed to air-indoor (external) that are not being managed for 

reduction of heat transfer. By letter dated April 12, 2012, the staff issued RAI B.1.26-2 

requesting that the applicant justify why LRA Table 3.3.2-16 does not include an AMR item for 

copper alloy with greater than 15 percent zinc (inhibited) heat exchanger tubes exposed to 

air-indoor (external) with an intended function of heat transfer. In its response dated 

May 9, 2012, the applicant stated that the heat exchanger tubes do not have a heat transfer 

function because they are covered by aluminum fins and that the aluminum fins have a heat 

transfer function that is being managed for fouling by the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The staff reviewed the applicant’s response and 

finds it acceptable because the heat exchanger tubes do not have a heat transfer function and 

therefore do not need to be managed for reduction of heat transfer, and the aluminum fins, 

which do have a heat transfer function, are being managed for fouling using the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff’s concern 

described above in RAI B.1.26-2 is resolved.

The LRA states that the Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program manages hardening and loss of strength for elastomers and polymers. However, the 

elastomer AMR items in the LRA that credit the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage aging, state that they are being managed for change 

in material properties and cracking. By letter dated April 12, 2012, the staff issued RAI B.1.26-3 

requesting that the applicant include all of the aging effects managed by the program and to 

provide justification for any aging effects that are not consistent with those listed in GALL Report

AMP XI.M38. In its response, dated May 9, 2012, the applicant stated that the program will 

manage change in material properties and cracking for elastomeric components because 

hardening and loss of strength are examples of changes in material properties and can result in

cracking of elastomers. The applicant also stated that metallic components will be managed for 

loss of material and fouling. The staff reviewed the applicant’s response and finds it acceptable 

because the program will manage loss of material and fouling for metallic components and 

cracking and change in material properties for elastomers, which is consistent with the 

recommendations in GALL Report AMP XI.M38. The staff’s concern described in RAI B.1.26-3 

is resolved.

LRA Table 3.2.1, item 3.2.1-43 states that the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program manages hardening and loss of strength for elastomer seals and 

components exposed to air-indoor (internal). However, LRA Table 3.2.2-6 states that duct 

flexible connections and elastomers exposed to air-indoor (internal) will be managed for 

cracking and change in material properties. By letter dated April 12, 2012, the staff issued

RAI B.1.26-4 requesting that the applicant justify why the aging effects of hardening and loss of 

strength discussed in LRA Table 3.2.1, item 3.2.1-43 are reflected as cracking and change in 

material properties aging effects in LRA Table 3.3.2-6. In its response dated May 9, 2012, the 

applicant stated that the program will manage change in material properties and cracking for 

these components as these are aging effects reflective of hardening and loss of strength. The 

staff reviewed the applicant’s response and finds it acceptable because the program will 

manage cracking and change in material properties for elastomers, which is consistent with the 

recommendations in GALL Report AMP XI.M38. The staff’s concern described in RAI B.1.26-4 

is resolved.

The “parameters monitored or inspected” program element in GALL Report AMP XI.M38 

recommends that the inspection parameters for metallic components include surface 

discontinuities, such as corrosion and material parameters wastage, leakage from or onto 
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internal surfaces, and worn, flaking or oxide-coated surfaces. GALL Report AMP XI.M38 also 

recommends that the inspection parameters for polymers include surface cracking, crazing, 

scuffing, dimensional change, discoloration, exposure of internal reinforcement for reinforced 

elastomers, and hardening as evidenced by a loss of suppleness during manipulation. 

However, LRA Section B.1.26 does not provide a description of the inspection parameters that 

the program will use to identify aging for metallic components and polymers. By letter dated 

April 12, 2012, the staff issued RAI B.1.26-5 requesting that the applicant justify why the 

program does not include the parameters monitored and their related aging effects or amend 

the LRA to include this information.

In its response dated May 9, 2012, the applicant revised LRA Section B.1.26 to state that 

elastomeric components will be visually inspected for cracking and changes in material 

properties, including surface discontinuities, and metallic components will be visually inspected 

for surface conditions indicative of loss of material. The staff finds the applicant’s response 

acceptable because the program now includes inspection parameters for metallic and 

elastomeric components consistent with the recommendations in the GALL Report. The staff’s 

concern described in RAI B.1.26-5 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M38 states that the 

program’s inspections are opportunistic, applied when surfaces become accessible during the 

performance of periodic surveillances, maintenance activities or scheduled outages, and that if 

visual inspections of internal surfaces are not possible, then a plant-specific program should be 

developed. GALL Report AMP XI.M38 also recommends that the available surface area for 

physical manipulation of flexible polymeric components be at least 10 percent. However, LRA 

Sections A.1.26 and B.1.26 do not describe if the program is opportunistic or if there are internal 

surfaces that are not accessible, and does not state the available surface area to be used with 

physical manipulation. The staff issued RAIs B.1.26-1 and B.1.26-8, discussed below, 

regarding the “detection of aging effects” program element.

By letter dated April 12, 2012, the staff issued RAI B.1.26-1 requesting that the applicant identify 

if the program is opportunistic and what the available surface area is that will be used with 

physical manipulation. In its response dated May 9, 2012, the applicant stated that the program 

is opportunistically applied whenever the components are opened for any reason and that the 

sample size for manipulation of flexible polymeric components is at least 10 percent of the 

available surface area. The staff finds the applicant’s response acceptable because the 

program is opportunistically applied and the sample size for physical manipulation of 

elastomeric components is at least 10 percent of the available surface area, which is consistent 

with the GALL Report recommendations. The staff’s concern described in RAI B.1.26-1 

regarding the “detection of aging effects” program element is resolved.

By letter dated April 12, 2012, the staff issued RAI B.1.26-8 requesting that the applicant identify 

if any of the program’s components are inaccessible. In its response dated May 9, 2012, the 

applicant stated that the program has no inaccessible components. The staff finds the 

applicant’s response acceptable because the program does not include any inaccessible 

components; therefore, a plant-specific program is not recommended by the GALL Report. The 

staff’s concern described in RAI B.1.26-8 is resolved.

The “acceptance criteria,” program element in GALL Report AMP XI.M38 states acceptance 

criteria for the metallic and polymeric (both rigid and flexible) components in the program. 

However, LRA Section B.1.26 does not describe the program’s acceptance criteria. By letter 

dated April 12, 2012, the staff issued RAI B.1.26-6 requesting that the applicant amend LRA 
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Section B.1.26 to include the acceptance criteria for this program. In its response dated

May 9, 2012, the applicant revised LRA Section B.1.26 to include the following acceptance 

criteria:

• stainless steel: clean surfaces, shiny, no abnormal surface conditions

• metals: no abnormal surface condition

• flexible polymers: a uniform surface texture and color with no cracks, no unanticipated 

dimensional change, and no abnormal surface conditions

• rigid polymers: no surface changes affecting performance such as erosion and cracking

The staff finds the applicant’s response acceptable because the program includes acceptance 

criteria against which the need for corrective actions can be evaluated to ensure that the 

component’s intended functions are maintained consistent with the GALL Report

recommendations. The staff’s concern described in RAI B.1.26-6 is resolved.

Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, “Aging Management 

of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under 

Insulation,” which revises several GALL Report AMPs including the guidance for AMP XI. M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components.” By letter 

dated January 2, 2014, the staff issued RAI 3.0.3-1, noting that the applicant may not have 

incorporated the updated guidance, and requesting that the applicant provide information on 

how the updated guidance of LR-ISG-2012-02 has been accounted for in its AMPs. In its 

response dated May 13, 2014, the applicant revised LRA Sections A.1.26 and B.1.26 for the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program to state that an 

assessment will be made of the opportunistic visual inspections completed during each 10-year 

period to ensure a representative sample is inspected. Directed inspections will be conducted 

to ensure that a sample size of 20 percent with a maximum of 25 inspections for each 

combination of material, environment, and aging effect during each 10-year period of extended 

operation. The applicant also stated that, where practical, inspections will be conducted at 

locations that are most susceptible to the effects of aging.

The staff finds the applicant’s response acceptable because the representative minimum 

sample size is consistent with the guidance in the GALL Report. The staff’s concern relating to 

this AMP in RAI 3.0.3-1 is resolved.

Based on its audit and review of the applicant’s responses to RAIs B.1.26-1, B.1.26-2, B.1.26-3, 

B.1.26-4, B.1.26-5, B.1.26-6, B.1.26-8, and 3.0.3-1 the staff finds that the program elements for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M38.

Operating Experience. LRA Section B.1.26 summarizes operating experience related to the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program. The LRA states 

that the Internal Surfaces in Miscellaneous Piping and Ducting Components Program is a new 

program for which program-specific operating experience will be gained as the program is 

implemented, but that the elements of the inspections used in this program are consistent with 

industry practice. The LRA also states that the inspection techniques that will be used as part of 

the Internal Surfaces in Miscellaneous Piping and Ducting Components Program have been 

proven effective at identifying aging effects in other existing site programs. During the audit, the 

staff reviewed operating experience examples where internal inspections were performed on 

motors and sparger end caps in which aging effects were identified before loss of the 

component’s intended function.
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The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, industry, and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated industry and plant-specific operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.26 provides the UFSAR supplement for the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. The staff reviewed this 

UFSAR supplement description of the program against the recommended description for this 

type of program as described in SRP-LR Table 3.0-1 and noted that the LRA UFSAR 

supplement description does not include a complete description of the components, 

environments, aging effects, and systems included in the program; does not discuss how the 

program intends to retain a component’s intended function; and does not include a provision to 

use a plant-specific program when visual inspections of internal surfaces are not possible. The 

licensing basis for this program for the period of extended operation may not be adequate if the 

applicant does not incorporate this information into its UFSAR supplement.

By letter dated April 12, 2012, the staff issued RAIs B.1.26-1 and B.1.26-7 requesting that the 

applicant include key elements of the program in the UFSAR supplement consistent with the 

description for this program in SRP-LR Table 3.0-1. In its response dated May 9, 2012, the 

applicant revised LRA Sections A.1.26 and B.1.26 to state that the program includes metallic 

ducting, the aging effects of loss of material, fouling, cracking, and change in material 

properties; that the program’s inspections will be opportunistic; and that there are no 

inaccessible components in the program. However, the applicant did not revise the UFSAR 

supplement to include a description of the environments managed by the program.

The staff reviewed the applicant’s response and found it unacceptable because there is no 

description in the applicant’s revised UFSAR supplement of the environments managed by the 

program. By letter dated July 17, 2012, the staff issued RAI B.1.26-1a requesting that the 

applicant amend LRA Section A.1.26 to fully describe the program’s applicable environments, 

consistent with the minimum UFSAR supplement description for this program found in the 

SRP-LR, Table 3.0-1.

In its response dated August 13, 2012, the applicant stated that the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program is consistent with GALL Report 

AMP XI.M38, without exception; therefore, the environments described in the UFSAR 

supplement are consistent with those in GALL Report AMP XI.M38. The applicant revised the 

UFSAR supplement in LRA Section A.1.25 to clarify that the program manages the effects of 

aging for piping and components exposed to environments of air-indoor, air-outdoor, 

condensation, exhaust gas, lube oil, raw water, waste water, and treated water. The staff finds 

the applicant’s response acceptable because the UFSAR supplement in LRA Section A.1.25 

has been revised to include the environments within the scope of the program, which are also 
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consistent with the environments listed in GALL Report AMP XI.M38. The staff’s concerns 

described in RAI B.1.26-1a are resolved.

As amended by letter dated October 25, 2013, the applicant revised the UFSAR supplement to 

include a reference to plastic components in conjunction with the statement that elastomeric 

components will be visually inspected to detect potential cracking and change in material 

properties. The staff finds this change acceptable because the use of visual inspections to 

detect cracking and change in material properties is consistent with the “parameters 

monitored/inspected” program element of GALL Report AMP XI.M38.

In its response dated May 13, 2014, the applicant also revised the UFSAR supplement to 

include a representative minimum sample size for the visual inspections being performed. 

During each 10-year period of extended operation, the applicant will ensure that inspections are 

conducted on a sample of 20 percent, up to a maximum of 25, for each combination of material, 

environment, and aging effect. The staff finds the applicant’s revised UFSAR supplement to be 

consistent with the corresponding program description in SRP-LR Table 3.0-1, as modified by 

LR-ISG-2012-02.

The staff also noted that the applicant committed by letter dated October 28, 2011,

(Commitment No. 16) to implement the new Internal Surfaces in Miscellaneous Piping and 

Ducting program prior to entering the period of extended operation for managing aging of 

applicable components.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 13, 2014, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Internal Surfaces in 

Miscellaneous Piping and Ducting Components, the staff concludes that those program 

elements for which the applicant claimed consistency with the GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.M38. 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).

3.0.3.1.26 Masonry Wall

Summary of Technical Information in the Application. LRA Section B.1.27 describes the 

existing Masonry Wall Program as consistent with enhancements with GALL Report AMP XI.S5, 

“Masonry Walls.” The LRA states that the AMP proposes to manage aging effects, for masonry 

walls within the scope of license renewal, including 10 CFR 50.48-required masonry walls, 

radiation-shielding walls, and masonry walls with the potential to affect safety-related 

components. The LRA also states that structural steel components are managed by the 

Structures Monitoring Program, and that masonry walls are visually inspected at a frequency 

selected to ensure there is no loss of intended function between inspections.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S5. For the “detection of aging 
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effects” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.S5 recommends 

inspection of masonry walls every 5 years, with provisions for more frequent inspections in 

areas where significant loss of material or cracking is observed to ensure there is no loss of 

intended function between inspections. However, during its audit, the staff found that the 

applicant’s Masonry Wall Program, when enhanced, proposes to inspect masonry walls every 

5 years, unless technical justification is provided to extend the inspection to a period not to 

exceed 10 years. By letter dated May 3, 2012, the staff issued RAI B.1.27-1 requesting that the 

applicant clarify whether masonry walls will be inspected every 5 years, and if not, to identify 

their location, environment to which they are exposed, and provide the technical justification and 

basis for exceeding the recommended 5-year inspection frequency.

In its response dated May 30, 2012, the applicant stated that the masonry walls within the scope 

of license renewal will be inspected every 5 years, and the enhancement identified in LRA 

Section B.1.27 Element 4, “detection of aging effects,” will be revised to remove the provision to 

extend the inspection interval up to 10 years.

The staff finds the applicant’s response acceptable because the revision to the “detection of 

aging effects” enhancement removes the provision for the applicant to extend the inspection 

interval to a period not to exceed 10 years. The enhancement now clearly indicates that 

masonry walls within the scope of license renewal will be inspected every 5 years, consistent 

with the recommendations in GALL Report AMP XI.S5. The staff also noted that, during its 

review of the masonry wall AMRs, those walls that are also fire barriers are visually inspected 

using the Fire Protection Program consistent with the recommendations in the GALL Report. 

The staff’s concern described in RAI B.1.27-1 is resolved.

The staff also reviewed the portions of the “parameters monitored or inspected” and “detection 

of aging effects” program elements associated with enhancements to determine whether the 

program will be adequate to manage the aging effects for which it is credited. The staff’s 

evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.27 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that the Masonry Wall 

Program will be enhanced to clarify that parameters monitored or inspected will include 

monitoring gaps between the supports and masonry walls that could potentially affect wall 

qualification. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S5 and finds it acceptable because when it is implemented, it 

will make the program consistent with the GALL Report AMP.

Enhancement 2. LRA Section B.1.27 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the Masonry Wall Program will 

be enhanced to clarify that detection of aging effects requires masonry walls to be inspected 

every 5 years unless technical justification is provided to extend the inspection to a period not to 

exceed 10 years. However, in response to RAI B.1.27-1, the applicant revised this 

enhancement to remove the provision for extending the inspection to a 10-year interval and 

clarify that masonry walls within the scope of license renewal will be inspected every 5 years. 

The staff reviewed the revised enhancement against the corresponding program elements in 

GALL Report AMP XI.S5, noted that the masonry walls that are fire barriers are also visually 
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inspected by the Fire Protection Program, and finds it acceptable because, when it is 

implemented, it will make the program consistent with GALL Report AMP XI.S5.

Summary. Based on its audit, and review of the applicant’s response to RAI B.1.27-1 of the 

applicant’s Masonry Wall Program, the staff finds that program elements one through six for 

which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.S5. In addition, the staff reviewed 

the enhancements associated with the “parameters monitored or inspected” and “detection of 

aging effects” program elements and finds that when implemented, they will make the AMP 

adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.27 summarizes operating experience related to the 

Masonry Wall Program. The applicant stated that program assessments covering the period 

from 2001 to 2007 identified no problems with masonry walls and concluded the structure 

inspection program is adequate and effective. The applicant also stated that reviews against 

established program standards provide assurance that the program will remain effective for 

managing loss of material of components. Furthermore, the applicant will consider future 

plant-specific operating experience per LRA Section B.0.4.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.27 provides the UFSAR supplement for the Masonry 

Wall Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 17) to enhance the Masonry Wall 

Program prior to the period of extended operation to:

• clarify that parameters monitored or inspected will include monitoring gaps between the 

supports and masonry walls that could potentially affect wall qualification

• clarify that detection of aging effects require masonry walls to be inspected every 

5 years

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

July 3, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Masonry Wall Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 
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their implementation through Commitment No. 17 prior to the period of extended operation will 

make the AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.27 Non-EQ Cable Connections

Summary of Technical Information in the Application. LRA Section B.1.28 describes the new 

Non-EQ Cable Connections Program as consistent with GALL Report AMP XI.E6, “Electrical 

Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.” 

The applicant stated that the Non-EQ Cable Connections Program is a one-time inspection 

program that provides reasonable assurance that the intended functions of the metallic parts of 

electrical cable connections are maintained consistent with the CLB through the period of 

extended operation. The applicant also stated that cable connections included are those 

connections susceptible to age-related degradation resulting in increased resistance of 

connection due to thermal cycling, ohmic heating, electrical transients, vibration, chemical 

contamination, corrosion, or oxidation that are not subject to the EQ requirements of 

10 CFR 50.49. The applicant further stated that this program provides for one-time inspections 

that will be completed prior to the period of extended operation on a sample of connections.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared elements one through six of the applicant’s program to the 

corresponding elements of GALL Report AMP XI.E6. For the “parameters monitored or 

inspected,” and “detection of aging effects” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The “parameters monitored or inspected” program element in GALL Report AMP XI.E6 

recommends that the following factors are considered for sampling: voltage level (medium and 

low voltage), circuit loading (high load), connection type, and location (high temperature, high 

humidity, vibration, etc.). Most connections used in nuclear power plants include splices (butt or 

bolted), crimp-type ring lugs, connectors, and terminal blocks. However, during its audit, the 

staff found that the applicant’s program basis document, GGNS-EP-08-LRD08, Revision 1, 

states that the representative sample of electrical cable connections will be tested, and the 

factors considered for sample selection will be application (medium and low voltage), circuit 

loading (high voltage), and location (high temperature, high humidity, vibration, etc.). The 

“parameters monitored or inspected” program element of the applicant’s basis document 

GGNS-EP-08-LRD08, Revision 1, does not consider or address connection types in the sample 

selection criteria. By letter dated April 30, 2012, the staff issued RAI B.1.28-1 requesting that 

the applicant clarify how the Non-EQ Cable Connections Program is consistent with 

GALL Report AMP XI.E6 with respect to sample selection criteria including connection type.

In its response dated May 25, 2012, the applicant stated that as stated in LRA Section B.1.28, 

the GGNS Non-EQ Cable Connections Program is consistent with the program described in the 

GALL Report AMP XI.E6, Electrical Cable Connections Not Subject to 10 CFR 50.49 

Environmental Qualification Requirements, without exception. In addition, the applicant stated 

that LRA Section B.1.28 states, “The factors considered for sample selection will be application 

(medium and low voltage, defined as < 35 kilovolts (kV)), circuit loading (high loading), 

connection type, and location (high temperature, high humidity, vibration, etc.).” Therefore, 
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connection type is a factor that will be considered in sample selection. The staff found the 

applicant’s response unacceptable because the applicant has not revised the basis document. 

The basis document under “parameters monitored or inspected” program element was not 

consistent with those in GALL Report AMP XI.E6 because it did not consider connection types 

as part of the sampling basis. In a letter dated July 17, 2012, the staff requested the applicant 

to revise the basis document to include connection type as part of the sampling basis or explain 

how the “parameters monitored or inspection” program element is consistent with those in GALL

Report AMP XI.E6. In response to the staff’s request, in a letter dated August 13, 2012, the 

applicant stated that the GGNS AMP evaluation report (basis document) for the Non-EQ Cable 

Connections Program was revised to indicate that connection type will be included in the 

sample selection. The staff found the applicant’s response acceptable because the applicant 

changed the basis document to include connection type as a factor in sample selection. The 

selection sample criteria are consistent with those in GALL Report AMP XI.E6. The staff’s 

concern in RAI B.1.28-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.E6 recommends that 

testing may include thermography, contact resistance testing, or other appropriate testing 

methods without removing the connection insulation, such as heat shrink tape, sleeving, 

insulation boots, etc. However, during its audit, the staff found that the applicant’s program 

basis document, GGNS-EP-08-LRD08, for the same program element states that inspection 

methods may include thermography, contact resistance testing, or other appropriate quantitative 

methods based on plant configuration and industry guidance. Based on the program 

description in the program basis document, it appears that the applicant may be using other 

quantitative methods that may include removing the connection insulation. By letter dated 

April 30, 2012, the staff issued RAI B.1.28-2 requesting the applicant to clarify if there are other 

appropriate quantitative methods, which may include removing connection insulation that will be 

used at GGNS. If there are other methods, the staff requested the applicant to justify why this 

practice is consistent with the recommendations in GALL Report AMP XI.E6.

In its response dated May 25, 2012, the applicant stated that the AMP evaluation report for the 

GGNS Non-EQ Cable Connections Program (GGNS-EP-08-LRD08) statement for “Detection of 

Aging Effects” will be clarified to state that, “[i]nspection methods may include thermography, 

contact resistance testing, or other appropriate quantitative test methods without removing the 

connection insulation such as heat shrink tape, sleeving, insulating boots, etc., based on plant 

configuration and industry guidance.”

The staff finds the applicant response acceptable because, if the applicant uses other testing 

methods besides thermography and contact resistance, it will not remove the connection 

insulation such as heat shrink tape, sleeving, insulation boots, etc. This practice is consistent 

with the recommendation from GALL Report AMP XI.E6. The staff’s concern described in

RAI B.1.28-2 is resolved.

Based on its audit, and review of the applicant’s responses to RAIs B.1.28-1 and B.1.28-2, of 

the applicant’s Non-EQ Cable Connections Program, the staff finds that program elements one 

through six for which the applicant claimed consistency with GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.E6.

Operating Experience. LRA Section B.1.28 summarizes operating experience related to the 

Non-EQ Cable Connections Program. The applicant stated that the Non-EQ Cable Connections 

Program is a new program. Industry operating experience was considered in the development 

of this program. The applicant also stated that plant operating experience will be gained as the
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program is implemented and will be factored into the program through the confirmation and 

corrective action elements of the GGNS 10 CFR Part 50, Appendix B, quality assurance 

program. The applicant stated that this inspection program applies to potential aging effects for 

which there is currently no operating experience at GGNS indicating the need for an AMP. The 

applicant further stated that elements of the program inspections (e.g., the scope of the 

inspections and inspection techniques) are consistent with industry practice and have been 

used effectively at GGNS in other programs.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.28 provides the UFSAR supplement for the Non-EQ 

Cable Connections Program.

The staff reviewed this UFSAR supplement description of the program against the 

recommended description for this type of program as described in SRP-LR Table 3.0-1 and 

noted that in SRP-LR Table 3.0.1, UFSAR supplement for Aging Management of Applicable 

Systems, under GALL Report AMP XI.E6, recommends that the program consists of a 

representative sample of electrical connections within the scope of license renewal, which is 

tested at least once before the period of extended operation to confirm that there are no AERM

during that period. Testing may include thermography, contact resistance testing, or other 

appropriate testing methods without removing the connection insulation, such as heat shrink 

tape, sleeving, insulating boots, etc. In the LRA Appendix A.1.28, the applicant stated that the 

Non-EQ Cable Connection Program is a one-time inspection program that provides reasonable 

assurance that the intended function of the metallic parts of electrical connections are 

maintained with the CLB through the period of extended operation. It further states that cable 

connections included are those connections susceptible to age-related degradation resulting in 

increased resistance of connection due to thermal cycling, ohmic heating, electrical transients, 

vibration, chemical contamination, corrosion, or oxidation that are not subject to the EQ

requirements of 10 CFR 50.49. This program provides for a one-time quantitative inspection 

that will be completed before the period of extended operation on a sample of connections. In 

this LRA, the applicant stated that the program is consistent with GALL Report AMP XI.E6. 

However, the UFSAR supplement description does not describe the type of test it will perform. 

The licensing basis for this program may not be adequate if the applicant does not incorporate 

this information into its UFSAR supplement. By letter dated April 30, 2012, the staff issued

RAI B.1.28-3, requesting that the applicant justify why the UFSAR supplement description does 

not describe the type of testing that may be performed, consistent with that in SRP-LR

Table 3.0-1 for GALL Report AMP XI.E6.
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In its response dated May 25, 2012, the applicant stated that the type of testing is described in 

the AMP evaluation report for the GGNS Non-EQ Cable Connections Program. This description 

will be added to LRA Section A.1.28 as shown below.

A.1.28 Non-EQ Cable Connections Program

The Non-EQ Cable Connections Program is a one-time inspection program that 

provides reasonable assurance that the intended functions of the metallic parts of 

electrical cable connections are maintained consistent with the current licensing 

basis through the period of extended operation. Cable connections included are 

those connections susceptible to age-related degradation resulting in increased 

resistance of connection due to thermal cycling, ohmic heating, electrical 

transients, vibration, chemical contamination, corrosion, or oxidation that are not 

subject to the environmental qualification requirements of 10 CFR 50.49.

This program provides for one-time quantitative inspections that will be 

completed prior to the period of extended operation on a sample of connections. 

The factors considered for sample selection will be application (medium and low 

voltage, defined as < 35 kV), circuit loading (high loading), connection type, and 

location (high temperature, high humidity, vibration, etc.). The representative 

sample size will be based on twenty percent of the connection population with a 

maximum sample of 25.

Inspection methods may include thermography, contact resistance testing, or 

other appropriate quantitative test methods without removing the connection 

insulation, such as heat shrink tape, sleeving, insulating boots, etc., based on 

plant configuration and industry guidance.

This program will be completed prior to the period of extended operation.

The staff finds the applicant’s response acceptable because the applicant describes the testing 

methods in the UFSAR supplement. The program description in UFSAR supplement for the 

Non-EQ Cable Connections Program is consistent with the corresponding program description 

in SRP-LR Table 3.0-1. The staff’s concern described in RAI B.1.28-3 is resolved.

The staff also noted that the applicant committed (Commitment No. 18) to implement the new 

Non-EQ Cable Connections Program prior to entering the period of extended operation for 

managing aging of applicable components.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Cable Connections 

Program, the staff concludes 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).
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3.0.3.1.28 Non-EQ Inaccessible Power Cables (400 V to 35 kV)

Summary of Technical Information in the Application. LRA Section B.1.29 describes the 

existing Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program as consistent, with 

enhancements, with GALL Report AMP XI.E3, “Inaccessible Power Cables Not Subject To 

10 CFR 50.49 Environmental Qualification Requirements.” The applicant stated that the 

Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program includes periodic actions to 

prevent inaccessible cables from being exposed to significant moisture. The applicant also 

stated that cables exposed to significant moisture will be tested at least every 6 years with test 

frequencies adjusted based on test results and operating experience. In addition, the applicant 

stated that the program includes periodic inspections for water accumulation in manholes at 

least once every year and includes manhole inspections for water after events such as heavy 

rain or flooding. The applicant further stated that inspection frequencies will be increased as 

necessary based on evaluation of inspection results.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E3.

The staff also reviewed the portions of the “scope of program” and “preventive actions” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B.1.29 includes an enhancement to the “scope of program”

program element. In this enhancement, the applicant stated that the Non-EQ Inaccessible 

Power Cables (400 V to 35 kV) Program will be enhanced to include low-voltage (400 V to 2 kV) 

power cables. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.E3 and finds it acceptable because when implemented it will 

provide consistency with GALL Report AMP XI.E3 “scope of program” program element which 

includes low-voltage inaccessible power cables (400 V to 2 kV) and SRP-LR Table 3.6-1.

Enhancement 2. LRA Section B.1.29 includes an enhancement to the “preventive actions”

program element. In this enhancement, the applicant stated that the Non-EQ Inaccessible 

Power Cables (400 V to 35 kV) Program will be enhanced to include condition-based 

inspections of manholes that are not automatically dewatered by sump pumps following periods 

of heavy rain or potentially high water table conditions, as indicated by river level.

In addition, the program will be clarified to state that manhole inspections will include direct 

observation that the cables are not wetted or submerged and that cable/splices and cable 

support structures are intact and include verification that dewatering/drainage systems 

(i.e., sump pumps) and associated alarms, if applicable, operate properly. The staff reviewed 

this enhancement against the corresponding program elements in GALL Report AMP XI.E3 and 

finds it acceptable because when it is implemented it will provide consistency with GALL Report

AMP XI.E3 “preventive actions” program element that includes confirmation that drainage 

systems operate properly. The enhancement is also consistent with SRP-LR Table 3.6-1.

Summary. Based on its audit of the applicant’s Non-EQ Inaccessible Power Cables (400 V to 

35 kV) Program, the staff finds that program elements one through six for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.E3. In addition, the staff reviewed the enhancements 
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associated with the “scope of program” and “preventive actions” program elements and finds 

that when implemented, they will make the AMP adequate to manage the applicable aging 

effects.

Operating Experience. LRA Section B.1.29 summarizes operating experience related to the 

Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program. In the applicant’s response to 

GL 2007-01 (“Inaccessible or Underground Power Cable Failures that Disable Accident 

Mitigation Systems or Cause Plant Transients,” issued February 2007), dated May 4, 2007, the 

applicant stated that it had experienced one cable failure within the scope of the maintenance 

rule 10 CFR 50.65. The applicant identified the cable as service for the 480 V motor-driven fire 

pump and stated that the apparent cause of failure was age degradation attributed to moisture 

and possible damage during construction. The staff also reviewed several recent NRC 

inspection reports.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.29 provides the UFSAR supplement for the Non-EQ 

Inaccessible Power Cables (400 V to 35 kV) Program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1.

The staff also noted that the applicant committed (Commitment No. 19) to enhance the Non-EQ 

Inaccessible Power Cables (400 V to 35 kV) Program to include low-voltage power cables 

(400 V to 2 kV) and to include condition-based inspections of manholes not automatically 

dewatered by a sump pump to be performed following periods of heavy rain or potentially high 

water table conditions, as indicated by river level. The program will also be enhanced to clarify 

that the inspections will include direct observation that the cables are not wetted or submerged 

and that cable/splices and cable support structures are intact and that dewatering/drainage 

(i.e., sump pumps) and associated alarms, if applicable, operate properly. The commitment is 

to be implemented prior to November 1, 2024.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Inaccessible Power 

Cables (400 V to 35 kV) Program, the staff determines that those program elements for which 

the applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed 

the enhancements and confirmed that their implementation through Commitment No. 19 prior to 
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the period of extended operation will make the AMP adequate to manage the applicable aging 

effects. 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).

3.0.3.1.29 Non-EQ Instrumentation Circuits Test Review

Summary of Technical Information in the Application. LRA Section B.1.30 describes the new 

Non-EQ Instrumentation Circuits Test Review Program as consistent with GALL Report

AMP XI.E2 “Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.” The 

applicant stated that the program assures the intended functions of sensitive, high-voltage, 

low-signal cables exposed to adverse localized equipment environments caused by heat, 

radiation, and moisture can be maintained consistent with the CLB through the period of 

extended operation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E2.

Based on its audit of the applicant’s Non-EQ Instrumentation Circuits Test Review Program, the 

staff finds that program elements one through six for which the applicant claimed consistency 

with the GALL Report are consistent with the corresponding program elements of GALL Report

AMP XI.E2.

Operating Experience. LRA Section B.1.30 summarizes operating experience related to the 

Non-EQ Instrumentation Circuits Test Review Program. The applicant stated that a search of 

GGNS operating experience identified no age-related failures of neutron monitoring and high 

range radiation monitoring system cables and connections at GGNS, and no aging mechanism 

not considered in the GALL Report has been identified. During its audit, the staff inquired about

occurrence of local power range monitor spiking, which is common for Boiling Water Reactors. 

The staff noted that spiking events have occurred in the past and that the applicant took 

corrective actions by performing current-voltage characteristic tests in accordance with 

GE SIL 564, “Verification of SRM, IRM, or LPRM Detector Response.”

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 

finds that the conditions and operating experience at the plant are bounded by those for which 

the corresponding GALL Report AMP was evaluated.
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UFSAR Supplement. LRA Section A.1.30 provides the UFSAR supplement for the Non-EQ 

Instrumentation Circuits Test Review Program.

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted that 

the applicant committed (Commitment No. 20) to implement the new Non-EQ Instrumentation 

Circuits Test Review Program prior to entering the period of extended operation for managing 

aging of applicable components.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its review of the applicant’s Non-EQ Instrumentation Circuits Test 

Review Program, the staff concludes 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).

3.0.3.1.30 Non-EQ Insulated Cables and Connections

Summary of Technical Information in the Application. LRA Section B.1.31 describes the new 

Non-EQ Insulated Cables and Connections Program as consistent with GALL Report

AMP XI.E1, “Insulation Material for Electrical Cables and Connections Not Subject to 

10 CFR 50.49 Environmental Qualification Requirements.” The applicant stated a 

representative sample consisting of accessible insulated cables and connections within the 

scope of license renewal installed in an adverse localized environment will be visually inspected 

for cable and connection jacket surface anomalies such as embrittlement, discoloration, 

cracking, or surface contamination.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.E1. For the “scope of 

program” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

The “scope of program” program element in GALL Report AMP XI.E1 recommends the AMP 

applies to accessible electrical cables and connections within the scope of license renewal that 

are located in adverse localized environments caused by temperature, radiation, or moisture. 

However, as described in the AMP Audit Report, during the staff’s walkdown of cables from ESF 

transformer Nos. 11, 12, and 21, the staff observed cables in uncovered open trays that may be 

subject to ultraviolet radiation and moisture. It is not clear how the applicant’s Non-EQ Insulated 

Cables and Connections Program will be used to manage the aging effects of reduced 

insulation resistance in this open-air environment. By letter dated April 30, 2012, the staff 

issued RAI B.1.31-1 requesting applicant to explain how these components will be age 

managed, during the period of extended operation.

In its response dated May 25, 2012, the applicant stated that the ESF transformer cables will be 

managed by the GGNS Non-EQ Insulated Cables and Connections Program. Based on the 
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bounding approach, the scope of this program includes the engineered cable bus to the ESF 

transformers. The applicant further stated that these cables were specifically designed for the 

environment and application where they are used.

The staff finds the applicant’s response acceptable because the ESF transformer cables will be 

managed by the GGNS Non-EQ Insulated Cables and Connections Program. The staff’s 

concern described in RAI B.1.31-1 is resolved.

The “scope of program” program element in GALL Report AMP XI.E1 recommends the AMP 

applies to accessible electrical cables and connections within the scope of license renewal that 

are located in adverse localized environments caused by temperature, radiation, or moisture. 

An adverse localized environment exists based on the most limiting condition for temperature, 

radiation, or moisture for the insulation material of the electrical cables or connections. The 

“parameters monitored or inspected” program element in GALL Report AMP XI.E1 recommends 

that an adverse localized environment is a plant-specific condition; therefore the applicant 

should clearly define how this condition is determined. The parameters monitored or inspected”

program element also recommends that the applicant should determine and inspect for adverse 

localized environments for each of the most limiting temperature, radiation, or moisture 

conditions for the accessible cables and connections that are within the scope of license 

renewal. The applicant’s LRA states that Non-EQ Insulated Cables and Connections Program 

will be consistent with GALL Report AMP XI.E1. However, the LRA does not define how an 

adverse localized environment is determined or the limiting conditions to be applied. By letter 

dated April 30, 2012, the staff issued RAI B.1.31-2 requesting the applicant to describe how the 

Non-EQ Insulated Cables and Connections Program will identify an adverse localized 

environment or what limiting conditions for temperature, radiation, or moisture of insulation 

material of electrical cables and connections will be applied in the identification of an adverse 

localized environment.

In its response dated May 25, 2012, the applicant stated that the determination of an adverse 

localized environment will be based on the most limiting temperature, radiation, or moisture 

conditions for the cables and connection insulation material located within that plant space. The 

applicant also stated that LRA Section B.1.31 will be modified to include the following:

An adverse localized equipment environment is a plant-specific condition that will be determined 

based on a plant spaces approach. The plant spaces approach provides for a review of all 

buildings and rooms in the scope of license renewal to determine potential adverse localized 

environments. The determination of a potential adverse localized equipment environment will 

be based on the most limiting temperature, radiation, or moisture conditions for the cables and 

connection insulation located at GGNS. The evaluation of an adverse localized equipment 

environment will be based on the most limiting temperature, radiation, or moisture conditions for 

the cables and connection insulation material located within that plant space that has a potential 

adverse localized equipment environment.

The staff finds the applicant’s response acceptable because the applicant will determine an 

adverse localized environment by identifying the most limiting temperature, radiation, or 

moisture conditions based on cables and connections insulation material. The staff’s concern 

described in RAI B.1.31-2 is resolved.

Based on its audit, and review of the applicant’s responses to RAIs B.1.31-1 and B.1.31-2 of the 

applicant’s Non-EQ Insulated Cables and Connections Program, the staff finds that program 
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elements one through six for which the applicant claimed consistency with the GALL Report are 

consistent with the corresponding program elements of GALL Report AMP XI.E1.

Operating Experience. LRA Section B.2.1.31 summarizes operating experience related to the 

Non-EQ Insulated Cables and Connections Program. The applicant stated that cables for a 

nonsafety-related valve located in the feedwater (FW) heater room were found to have 

heat-related degradation. Though the valve has no license renewal-intended function, the issue

was identified, and the cables were replaced and rerouted to prevent future degradation.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, and review of the applicant’s response to 

RAIs B.1.31-1 and B.1.31-2, the staff finds that the applicant has appropriately evaluated 

plant-specific and industry operating experience. In addition, the staff finds that the conditions 

and operating experience at the plant are bounded by those for which the corresponding GALL 

Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.31 provides the UFSAR supplement for the Non-EQ 

Insulated Cables and Connections Program.

The staff reviewed this UFSAR supplement description of the program and noted that it is 

consistent with the recommended description in SRP-LR Table 3.0-1. The staff also noted that 

the applicant committed (Commitment No. 21) to implement the new Non-EQ Insulated Cables 

and Connections Program prior to entering the period of extended operation for managing aging 

of applicable components.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Non-EQ Insulated Cables 

and Connections Program, the staff concludes 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).

3.0.3.1.31 Oil Analysis

Summary of Technical Information in the Application. LRA Section B.1.32 describes the 

existing Oil Analysis Program as consistent, with enhancements, with GALL Report

AMP XI.M39, “Lubricating Oil Analysis.” The applicant stated that the program ensures that loss 

of material, cracking, and fouling do not occur by maintaining oil environments free of 
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contaminants (e.g., water and particulates). The applicant stated that testing activities include 

sampling and analysis of lubricating oil.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M39.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.32 states an enhancement to the “scope of program”

program element. In this enhancement, the applicant stated that the Oil Analysis Program will 

be enhanced to include piping and components within the main generator system (N41) with an 

internal environment of lube oil. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M39 and finds it acceptable because 

when it is implemented it will make the program consistent with the recommendations in GALL

Report AMP XI.M39.

Enhancement 2. LRA Section B.1.32 states an enhancement to the “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements. In this 

enhancement, the Oil Analysis Program will be enhanced to provide a formalized analysis 

technique for particulate counting. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M39 and finds it acceptable because 

when it is implemented it will make the program consistent with the recommendations in GALL

Report AMP XI.M39.

Summary. Based on its audit, the staff finds that program elements one through six for which 

the applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M39. In addition, the staff reviewed the 

enhancements associated with the “scope of program,” “parameters monitored or inspected,”

“detection of aging effects,” and “acceptance criteria” program elements and finds that when 

implemented, they will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.32 summarizes operating experience related to the Oil 

Analysis Program.

The applicant stated that the fire water diesel engine lubricating oil sample results for 2000 

through 2010 were satisfactory. However, the applicant stated that both fire water diesels had 

samples with high particle count. This was attributed to faulty lab equipment, and samples were 

taken at more frequent intervals to track the conditions. The applicant stated that particle count 

level remained below the limit and was evaluated to be satisfactory for continued service.

The applicant stated that samples of crankcase oil from the HPCS diesel generator (Division III) 

taken between 2005 and 2010 revealed possible high metal count. The applicant continued to 

observe the sample test results to determine if high count was caused by metal wear particles 

or malfunction of lab equipment. The applicant stated that, from 2008 on, the samples were 

normal, indicating a malfunction of lab equipment in the earlier samples.
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In 2007 the applicant stated that a sample of Division I diesel engine lubricating oil indicated 

trace amounts of moisture contamination. The oil viscosity and other parameters were within 

manufacturer specifications. The applicant stated that a contaminated sample tube was 

suspected to be the cause of the indication. A resample was performed with clean sampling 

apparatus to confirm that the previously used sample tube was contaminated.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and plant-specific and industry operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.32 provides the UFSAR supplement for the Oil Analysis 

Program. The staff reviewed this UFSAR supplement description of the program and noted that 

it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff finds that 

the information in the UFSAR supplement is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Oil Analysis Program, the 

staff determines that those program elements for which the applicant claimed consistency with 

the GALL Report are consistent. Also, the staff reviewed the enhancements and confirmed that 

their implementation prior to the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. 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).

3.0.3.1.32 One-Time Inspection

Summary of Technical Information in the Application. LRA Section B.1.33 describes the new 

One-Time Inspection Program as consistent with GALL Report AMP XI.M32, “One-Time 

Inspection.” The LRA states that the AMP verifies the effectiveness of the Diesel Fuel 

Monitoring, Oil Analysis, and Water Chemistry Control programs to prevent or minimize aging 

effects of loss of material, cracking, and fouling to assure that loss of intended functions will not 

occur during the period of extended operation. The LRA also states that the AMP will provide 

additional confirmation to verify the insignificance of aging effects. The LRA further states that a 

sample size of components based on an assessment of the material, environment, aging 

effects, and operating experience will be used in the program and that examination techniques 

will utilize established non-destructive examination techniques.
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Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M32. For the “detection of 

aging effects” program element, the staff determined the need for additional information, which 

resulted in the issuance of an RAI, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M32 recommends 

that the program state what inspection method will be associated with each aging effect, aging 

mechanism, and parameter monitored. However, during its audit, the staff noted that the 

applicant’s One-Time Inspection Program does not state what inspection methods are aligned 

with the aging effects of loss of material, cracking and fouling. By letter dated April 11, 2012, 

the staff issued RAI B.1.33-1 requesting that the applicant revise LRA Section B.1.33 to identify 

what inspection methods will be used in conjunction with each aging effect being managed by 

the program.

In its response dated May 9, 2012, the applicant revised the program description section of LRA 

Section B.1.33 to add a table that identifies the inspection methods associated with the aging 

effects for the program. The staff finds the applicant’s response acceptable because the 

inspection methods associated with the aging effects are now fully described, are consistent 

with those in GALL Report AMP XI.M32, and the inspection methods and techniques are 

adequate to identify and manage the aging effects associated with this program. The staff’s 

concern described in RAI B.1.33-1 is resolved.

Based on its audit and review of the applicant’s One-Time Inspection Program and review of the 

applicant’s response to RAI B.1.33-1, the staff finds that the program elements one through six 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M32.

Operating Experience. LRA Section B.1.33 summarizes operating experience related to the 

One-Time Inspection Program. The LRA states that the One-Time Inspection Program is a new 

program for which program-specific operating experience will be gained as the program is 

implemented, but that the elements of the inspections used in this program are consistent with 

industry practice. The LRA also states that the inspection techniques that will be used as part of 

the One-Time Inspection Program have been proven effective at identifying aging effects in 

other existing site programs. During the audit, the staff reviewed operating experience 

examples where visual inspections had been completed on condenser bay ventilation 

components and snubbers in which aging effects were identified prior to loss of the component’s 

intended function.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience. In addition, the staff 
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finds that the conditions and operating experience at the plant are bounded by those for which 

the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.33 provides the UFSAR supplement for the One-Time 

Inspection Program. The staff reviewed this UFSAR supplement description of the program 

against the recommended description for this type of program as described in SRP-LR

Table 3.0-1 and noted that the SRP-LR states that this program should not be used for 

structures or components with known age-related degradation or when the environment in the 

period of extended operation is not expected to be equivalent to that in the prior 40 years. 

However, LRA Section A.1.33 does not state the conditions for which SCs will be excluded from 

the scope of the AMP. The licensing basis for this program for the period of extended operation 

may not be adequate if the applicant does not incorporate this information in its UFSAR 

supplement. By letter dated April 11, 2012, the staff issued RAI B.1.33-2 requesting that the 

applicant revise the UFSAR supplement to fully describe this program consistent with the 

recommendations in the SRP-LR.

In its response dated May 9, 2012, the applicant revised LRA Section A.1.33 to state that the 

program cannot be used for structures or components with known age-related degradation or 

when the environment in the period of extended operation is not expected to be equivalent to 

that in the prior 40 years. The staff finds the applicant’s response acceptable because the 

UFSAR supplement has been revised to describe what structures or components cannot be age 

managed by the program consistent with the recommended description in SRP-LR Table 3.0-1. 

The staff’s concern described in RAI B.1.33-2 is resolved.

The staff also noted that the applicant committed (Commitment No. 23) to implement the new 

One-Time Inspection Program as described in LRA Section B.1.33 within the 10 years prior to 

entering the period of extended operation. The staff finds that the information in the UFSAR 

supplement, as amended by letter dated May 9, 2012, is an adequate summary description of 

the program.

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection 

Program, the staff concludes that the 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).

3.0.3.1.33 One-Time Inspection – Small-Bore Piping

Summary of Technical Information in the Application. LRA Section B.1.34 describes the new 

One-Time Inspection – Small-Bore Piping Program as consistent with GALL Report

AMP XI.M35, “One-Time Inspection of ASME Code Class 1 Small-Bore Piping.” The LRA 

states that the program augments the requirements of ASME Code, Section XI, and applies to 

small-bore ASME Code Class 1 piping and components with a nominal pipe size (NPS)

diameter less than 4 inches and greater than or equal to 1 inch in systems that have not 

experienced cracking of ASME Code Class 1 small-bore piping. The LRA also states that 

GGNS has not experienced cracking in this kind of piping due to stress corrosion, cyclical

loading (including thermal, mechanical, and vibration fatigue), or thermal stratification and 

thermal turbulence. The program provides for a one-time volumetric inspection of a sample of 
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locations that are susceptible to cracking, and this inspection will be performed within the 6-year 

period prior to the period of extended operation. The sample selection is based on susceptibility 

to stress corrosion, cyclic loading, or thermal stratification and thermal turbulence. In addition, 

the LRA states that if evidence of cracking is revealed by the one-time inspection, then a followup periodic inspection will be implemented through a plant-specific program.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M35. For the “detection of 

aging effects” program element, the staff determined the need for additional information, which 

resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M35 recommends an 

inspection sample size that is at least 3 percent of the weld population, or a maximum of 

10 welds of each weld type, if the unit (a) has never experienced a failure of its ASME Code 

Class 1 small-bore piping and (b) has more than 30 years of operating history at the time when 

the application is submitted. Otherwise, the inspection sample size should be at least 

10 percent of the weld population or a maximum of 25 welds of each weld type. The NRC 

issued the operating license for GGNS on November 1, 1984, and the applicant submitted the 

LRA on October 28, 2011; therefore, GGNS had less than 27 years of operating history at the 

time when the application was submitted. Based on the operating history of GGNS, the sample 

size for the one-time inspection should be at least 10 percent of the weld population or a 

maximum of 25 welds of each weld type to be consistent with GALL Report AMP XI.M35.

During its audit, the staff found that the applicant’s One-Time Inspection – Small-Bore Piping 

Program does not indicate the total population of welds of each weld type or the total number of 

these welds that will be included in the volumetric inspections. By letter dated April 18, 2012, 

the staff issued RAI B.1.34-1 requesting that the applicant characterize the inspection sample 

size by providing the total number of ASME Code Class 1 small-bore piping (1) full penetration 

or butt welds and (2) partial penetration or socket welds at GGNS and the total number of these 

welds that will be included in the inspection sample. The staff also requested the applicant to 

provide technical justification if the sample size is less than the sample size described in the 

GALL Report (i.e., 10 percent of the weld population or a maximum of 25 welds of each 

weld type).

In its response dated May 18, 2012, the applicant stated that, because the One-Time 

Inspection – Small-Bore Piping Program is a new program, the total number of welds that will be 

included in the volumetric inspections, based on the total population of welds of each weld type, 

had not been determined. The applicant stated that it would provide this information at a later 

date and did so in a letter dated August 23, 2012. In this letter the applicant stated that, under 

the One-Time Inspection – Small-Bore Piping program, 20 butt welds will be inspected, which 

represents over 10 percent of the total number of ASME Code Class 1 small-bore piping butt 

welds in the plant. In addition, 25 socket welds will be inspected under the program, which is 

the maximum number of ASME Code Class 1 small-bore piping socket welds to be inspected 

consistent with GALL Report AMP XI.M35. The staff reviewed the applicant’s response and 

finds it acceptable because the total number of small-bore butt and socket welds that will be 

inspected under the applicant’s program is consistent the inspection sample size described in 

GALL Report AMP XI.M35, given the operating history of the plant. The staff’s concern 

described in RAI B.1.34-1 is resolved.
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The “detection of aging effects” program element in GALL Report AMP XI.M35 states that the 

program does not apply to plants that have experienced cracking in ASME Code Class 1 

small-bore piping due to stress corrosion, cyclical loading (including thermal, mechanical, and 

vibration fatigue), or thermal stratification and thermal turbulence. LRA Section B.1.34 states 

that GGNS has not experienced this type of cracking; however, during its audit, the staff could 

not determine how or to what extent the applicant reviewed plant-specific operating experience 

information to demonstrate that GGNS has not experienced age-related cracking in ASME Code 

Class 1 small-bore piping. By letter dated April 18, 2012, the staff issued RAI B.1.34-2 

requesting that the applicant describe how operating experience was considered. Specifically, 

the staff requested the applicant to describe the process used to find potential instances of 

cracking in ASME Code Class 1 small-bore piping and to provide details on any such instances. 

In addition, if cracking of ASME Code Class 1 small-bore piping was identified, the staff 

requested the applicant to either provide a plant-specific program that includes periodic 

inspections or to explain and justify why the One-Time Inspection Small-Bore Piping Program

will adequately manage cracking.

By letter dated May 18, 2012, the applicant responded to RAI B.1.34-2. The applicant stated

that it reviewed the paperless condition reporting system, which is used to track items in the site 

CAP. The applicant reviewed 10 years of operating experience documented in the paperless 

condition reporting system, and keyword searches, including the words “crack,” “leak,”

“fracture,” and “spray,” were used in this review. Separately from the paperless condition 

reporting system, the applicant stated that it reviewed licensee event reports (LERs). The 

applicant also stated that another source of information was interviews with plant personnel on 

operating experience related to plant systems. The applicant explained that, over time, 

individuals involved in the day-to-day maintenance and operation of the plant acquire unique 

knowledge and experience regarding the performance history and degradation phenomenon 

affecting SSCs. For SSCs within the scope of license renewal, the applicant stated that system 

engineers were interviewed to reveal any potential AERM that would not otherwise be identified 

by the AMR process and operating experience document review. These interviews consisted of 

open discussions of system aging effects; aging mechanisms, aging effects, and adverse 

environments identified in industry guidance documents were also reviewed with the system 

engineers. The applicant further stated that the interviewers prompted the system engineers to 

discuss unusual or unique materials, environments, and aging effects and asked about system 

problems that may be age-related, which would include cracking of ASME Code Class 1 

small-bore piping. Based on these activities, the applicant stated that GGNS has not 

experienced age-related cracking in ASME Code Class 1 small-bore piping.

The staff reviewed the applicant’s response and determined that, although GGNS has been 

operating for approximately 27 years, the applicant’s search of plant-specific operating 

experience in the paperless condition reporting system was limited to just 10 years. Also, the 

applicant stated that it supplemented the search of the paperless condition reporting system 

with a review of information from LERs. However, the staff determined that this information may 

not be sufficient or complete because LERs only include events that meet the reporting criteria 

of 10 CFR 50.72 and 10 CFR 50.73, and these criteria may not include all instances of cracking 

in ASME Code Class 1 small-bore piping. The applicant also stated that it relied on interviews 

of plant personnel. The staff determined that, while these interviews may provide additional

context for previously documented information, they do not constitute an established repository 

of plant-specific operating experience information. By letter dated August 7, 2012, the staff 

issued RAI B.1.34-2a requesting the applicant provide a technical basis for limiting the review of 

plant-specific operating experience in the paperless condition reporting system, or other plant 

databases, to the previous 10 years of plant operation.
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The applicant responded to RAI B.1.34-2a by letter dated September 4, 2012. The applicant 

stated that operating experience relevant to the program would be associated with leakage of 

ASME Code Class 1 reactor coolant pressure boundary piping components because such a 

condition requires submission of an LER. Thus, the applicant stated that its LER search 

provides a complete source for identification of through-wall cracking of ASME Code Class 1 

small-bore piping. The applicant also stated that a review of records outside the paperless 

condition reporting system would provide no additional information. As to the technical basis for 

the plant-specific operating experience search, the applicant referenced the guidance in 

NEI 95-10, which states that a plant-specific operating experience review should include the 

prior 5 to 10 years of plant operating and maintenance history. The applicant stated that 

degradation due to aging mechanisms is a progressive phenomenon, so the rate of failures due 

to aging would be expected to increase with time, and a failure that may have occurred greater 

than 10 years ago and not recurred since would unlikely be attributed to age-related 

degradation.

The staff reviewed the applicant’s justification for the completeness of the plant-specific 

operating experience review. Although NEI 95-10 recommends a review only of the prior 5 to 

10 years of plant operating history, the staff determined that, in this case, following this general 

recommendation does not completely demonstrate that GGNS has not experienced cracking in 

ASME Code Class 1 small-bore piping. Industry operating experience shows that age-related 

cracking of small-bore piping can manifest even within the first 10 years of plant operation. In 

one example, described in LER 88-011-00, Byron Station, Unit 1 experienced age-related 

cracking within 4 years. The staff also determined that it is not evident as to why the LER 

reporting criteria of 10 CFR 50.73, given potential changes over the operating history of the 

plant, would capture all instances of non-through-wall cracking or would specifically apply to all 

instances of ASME Code Class 1 small-bore piping leakage. In addition, the staff determined 

that the applicant’s response to RAI B.1.34-2 does not fully describe the results of the keyword 

search or justify why a search based on the keywords would capture all potential instances of 

age-related cracking in ASME Code Class 1 small-bore piping.

Based on its review of the responses to RAIs B.1.34-2 and B.1.34-2a, the staff determined that 

the applicant has not shown GALL Report AMP XI.M35 to be applicable to GGNS. By letter 

dated November 5, 2012, the staff issued RAI B.1.34-2b requesting that the applicant 

demonstrate applicability of the program by fully describing the process for and providing the 

results of the plant-specific operating experience review that covers the complete operating 

history of the plant. With respect to the review of the prior 10 years of condition reports, the 

staff requested the applicant to identify the specific keywords and justify why a search based on 

these keywords would identify all potential instances of age-related cracking in ASME Code 

Class 1 small-bore piping. With respect to the LER review, the staff requested the applicant to 

justify why the LER reporting requirements, considering changes over the course of the 

operating history of the plant, would capture all instances of non-through-wall cracking and 

specifically apply to all leakage of ASME Code Class 1 small-bore piping. The staff also 

requested the applicant to describe and justify the process or methodology used to review the 

LERs. For the period of time not covered by the condition report search, the staff requested the 

applicant to identify and justify the specific sources of information reviewed and the process or 

methodology used to find potential instances of cracking. Any relevant items found through 

these reviews were requested to be described.

The applicant responded to RAI B.1.34-2b by letter dated November 29, 2012. The applicant 

described the extent of its condition report review, stating that the review covered over 

10,000 condition reports found through a search of 26 different keywords. Through this review 
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the applicant found no items relevant to cracking of ASME Code Class 1 small-bore piping. On 

the review of LERs, the applicant indicated that ASME Code Class 1 components are those 

components in the reactor coolant system pressure boundary whose failure could cause loss of 

reactor coolant at a rate exceeding the capability of the normal makeup system. Reactor 

coolant pressure boundary leakage is not allowed by GGNS Technical Specification 3.4.5; 

therefore, the applicant stated that any leakage of ASME Code Class 1 small-bore piping is 

required to be reported in an LER. The applicant did not provide additional information on the 

review of plant operating experience during the period of time not covered by the prior 10-year 

condition report review. Instead, the applicant stated that such a review will be completed prior 

to the period of extended operation.

The staff reviewed the applicant’s response to RAI B.1.34-2b and determined that the 

applicant’s review of the prior 10 years of condition reports partially demonstrates applicability of 

GALL Report AMP XI.M35 to GGNS. This determination is based on the staff’s finding that 

condition reports are an appropriate source for identifying potential instances of age-related 

cracking of ASME Code Class 1 small-bore piping. According to LRA Section 2.3.1.2 and the 

applicant’s response, components of the reactor coolant pressure boundary whose failure could 

cause a loss of reactor coolant at a rate in excess of the normal makeup system capability are 

ASME Code Class 1. As reactor coolant pressure boundary components, ASME Code Class 1 

small-bore piping components perform safety-related functions consistent with the definition in 

10 CFR 50.2, which states that safety-related SSCs are those SSCs that are relied upon to 

remain functional during and following design basis events to assure the integrity of the reactor 

coolant pressure boundary. The quality assurance requirements of 10 CFR Part 50, 

Appendix B, apply to activities affecting the safety-related functions of SSCs; ASME Code 

Class 1 small-bore piping would be subject to these quality assurance requirements. 

Criterion XVI, “Corrective Action,” of 10 CFR Part 50, Appendix B, requires measures to assure 

that conditions adverse to quality, such as failures, deficiencies, deviations, and 

nonconformances, are promptly identified and corrected, and Criterion XVII, “Quality Assurance 

Records,” requires identifiable and retrievable records to furnish evidence of activities affecting 

quality. Cracking of ASME Code Class 1 small-bore piping would be considered as a 

deficiency, for example, and thus require corrective action and documentation as part of the 

quality assurance program. At the applicant’s site, condition reports serve this purpose. The 

staff’s determination is also based on the results of the applicant’s search and review of 

condition reports. The keywords used in the applicant’s search are directly applicable to agerelated cracking of ASME Code Class 1 small-bore piping. For example, the direct effects of 

through-wall cracking would be evidenced by a leak, rupture, or spray, all of which were 

keywords used in the applicant’s search. Non-through-wall cracking could be documented as a 

crack, or as a degraded, deteriorated, or damaged condition. Derivatives of these words were 

also used in the applicant’s search. Several of the applicant’s keywords, such as “corrosion,” 

“rupture,” “leak,” “degrade,” “damage,” and “crack,” were also identical to or derivatives of 

keywords used by the staff in its independent review of operating experience during the audit of 

this program. This review is described in the AMP Audit Report. Through this independent 

review the staff found several potential condition reports, but none were determined to directly 

involve age-related cracking of ASME Code Class 1 small-bore piping. Based on the 

appropriateness of the records reviewed by the applicant, the methodology used to search 

those records, and the results, the staff determined that the applicant has demonstrated that 

GGNS has not experienced age-related cracking of ASME Code Class 1 small-bore piping 

during the 10 years before submittal of the LRA. Therefore, the staff’s concern in RAI B.1.34-2b 

on the methodology for reviewing the prior 10 years of condition reports is resolved.
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Notwithstanding the above determination, the staff also determined that the applicant’s 

response to RAI B.1.34-2b is incomplete because it does not fully cover the period of plant 

operation leading up to the 10-year period covered in the previously described condition report 

review. The applicant stated that it reviewed LERs from this period and found no instances of 

cracking in ASME Code Class 1 small-bore piping. However, the staff determined that the LER 

reporting requirements only capture instances where a crack resulted in reactor coolant 

pressure boundary leakage. Cracks in small-bore piping can also be detected before leakage 

occurs, for example, through examinations performed as part of applicant’s existing Inservice 

Inspection Program. This type of cracking would not be captured in an LER, but would be 

documented in quality assurance program records. Although the applicant indicated that it will 

complete a review of these records prior to the period of extended operation, the staff 

determined that the methodology and results of this review are needed to support the review of 

the LRA. This information is necessary to demonstrate that the one-time inspections

recommended by GALL Report AMP XI.M35 will ensure that the effects of aging will be 

adequately managed for ASME Code Class 1 small-bore piping. The staff identified this issue 

as Open Item 3.0.3.1.33-1.

By letter dated March 12, 2013, the staff issued RAI B.1.34-2c requesting that the applicant 

provide the results of a complete search and review of records in the condition reporting system. 

The staff requested that the applicant describe the methodology it used in this search to find 

potential instances of cracking in ASME Code Class 1 small-bore piping and to discuss any 

relevant items found. The applicant responded by letter dated April 15, 2013. The applicant 

stated that it completed an additional search of the condition reporting system for the period 

beginning from the start of licensed operation of the plant. The applicant searched the condition 

report records by using the key words “corrosion,” “corrode,” “rupture,” “leak,” “degrade,” 

“damage,” “fracture,” and “crack.” The applicant stated that it then reviewed each report 

generated from the keyword search results to identify any instances of cracking in ASME Code 

Class 1 small-bore piping. Based on this additional search, the applicant stated that it identified 

no instances of cracking.

The staff reviewed the response to RAI B.1.34-2c and determined that the applicant’s search 

and review methodology is consistent with the approach applied in the applicant’s review of the 

prior 10 years of condition reports, as described in the response to RAI B.1.34-2b. As 

previously discussed, the staff determined that this methodology is appropriate because these 

keywords are directly applicable to instances of age-related cracking of ASME Code Class 1 

small-bore piping. The staff reviewed the applicant’s LERs and a sample of inservice inspection 

summary reports for the period covered by the applicant’s additional operating experience 

search and review to confirm the results. The staff found that this information supports the 

applicant’s finding that there were no instances of age-related cracking of ASME Code Class 1 

small-bore piping during this period. Therefore, the staff determined that the applicant has 

satisfactorily completed the search and review of condition reports for the period of plant 

operation leading up to the 10-year period already reviewed. The staff’s concern described in 

RAI B.1.34-2c is resolved.

Because the applicant has completed a satisfactory review of plant-specific operating 

experience covering the complete operating history of the plant, and this review identified no 

instances of age-related cracking applicable ASME Code Class 1 small-bore piping, the staff 

determined that the applicant has demonstrated applicability of GALL Report AMP XI.M35 to 

GGNS. Open Item 3.0.3.1.33-1 is closed.
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The “detection of aging effects” program element in GALL Report AMP XI.M35 recommends 

inspections based on susceptibility, inspectability, dose considerations, operating experience, 

and the limiting locations of the total population of ASME Code Class 1 small-bore piping. The 

GALL Report also states that opportunistic destructive examinations of socket welds may be 

performed and a sampling basis should be used if more than one weld is removed from service. 

However, during its audit, the staff found that the applicant’s One-Time Inspection – Small-Bore 

Piping Program does not include a methodology for selecting sample locations. The staff also 

found that the applicant’s program credits opportunistic destructive examinations, but does not 

discuss a sampling basis for these examinations when more than one socket weld is removed 

from service. By letter dated April 18, 2012, the staff issued RAI B.1.34-3, requesting that the 

applicant describe the methodology for selecting the inspection sample locations and discuss 

how this methodology accounts for susceptibility to cracking, inspectability, dose considerations, 

operating experience, and the limiting locations of the total population of ASME Code Class 1 

small-bore piping. The staff also requested the applicant to describe the sampling basis that will 

be used to determine which welds will be destructively examined when more than one weld is 

removed from service.

In its response dated May 18, 2012, the applicant stated that the methodology for selecting the 

inspection sample locations will be consistent with GALL Report AMP XI.M35 and will be based 

on these factors:

• susceptibility to cracking, as determined by using industry guidance and operating 

experience, such as EPRI Report 1013389, “BWRVIP-155: BWR Vessel and Internals 

Project, Evaluation of Thermal Fatigue Susceptibility in BWR Stagnant Branch Lines”

(BWRVIP-155)

• inspectability of the weld, as determined based on the weld configuration and location in

the piping system

• dose considerations, as determined based on area dose rates at the physical location of 

each weld

• limiting locations of the total population of ASME Code Class 1 small-bore piping 

locations

The staff reviewed the applicant’s response and finds it acceptable because it indicates that the 

inspection locations under the One-Time Inspection – Small-Bore Piping Program will be based 

on the factors outlined in GALL Report AMP XI.M35. Specifically, in selecting the inspection 

locations, the applicant will consider which locations are more susceptible to cracking and which 

are limiting or practical for inspection based on inspectability and dose. The staff also finds 

acceptable the applicant’s use of the guidance in BWRVIP-155 because this report addresses 

industry operating experience concerning susceptibility to thermal fatigue for typical BWR plant 

piping configurations. Thermal fatigue is an aging mechanism that can lead to cracking, the 

primary aging effect managed by GALL Report AMP XI.M35. Selection of inspection locations 

based on operating experience is also recommended by GALL Report AMP XI.M35. LRA 

Section B.0.4 describes the applicant’s process for review of future plant-specific and industry 

operating experience to ensure that the AMPs, including One-Time Inspection – Small-Bore 

Piping Program, be effective in managing the effects of aging for which they are credited. The 

staff’s review of this process is discussed in SER Section 3.0.5.

In its response dated May 18, 2012, the applicant also addressed the staff’s request in

RAI B.1.34-3 to describe the sampling basis for the destructive examinations. The applicant 

stated that, if removed from service, multiple welds may be destructively examined based on the 
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sample selection criteria of GALL Report AMP XI.M35. The sample selection will be based on 

susceptibility, inspectability, dose considerations, operating experience, and the limiting 

locations of the total population of ASME Code Class 1 small-bore piping locations. The 

applicant further stated that the opportunistic destructive examinations will be performed when a 

weld is removed from service or for other considerations, such as plant modifications, and in the 

event that more than one weld is removed, the weld or welds considered most susceptible to 

cracking will be destructively examined. In addition, the applicant stated that the sampling 

requirements will be 10 percent of the total population, up to a maximum of 25 of both butt and 

socket welds. The staff finds the applicant’s response acceptable because the welds 

considered most susceptible to cracking will be selected for destructive examination, and 

susceptibility to cracking will be determined based on the factors for selecting the inspection 

locations, both of which are consistent with the criteria in GALL Report AMP XI.M35. The staff’s 

concern described in RAI B.1.34-3 is resolved.

Based on its audit and review of the LRA and the applicant’s responses to RAIs B.1.34-1, 

B.1.34-2, B.1.34-2a, B.1.34-2b, B.1.34-2c, and B.1.34-3, the staff finds that the program 

elements for which the applicant claimed consistency with the GALL Report are consistent with 

the corresponding program elements of GALL Report AMP XI.M35.

Operating Experience. LRA Section B.1.34 summarizes operating experience related to the 

One-Time Inspection – Small-Bore Piping Program. The LRA states that the program is new 

and industry operating experience will be considered when it is implemented. The LRA also 

states that plant-specific operating experience will be gained as the program is implemented,

and this operating experience will be factored into the program through the “confirmation 

process” and “corrective actions” program elements. In addition, the LRA states that the 

program applies to the potential aging effect of cracking in ASME Code Class 1 piping less than 

4 inches NPS, for which there is no operating experience at GGNS. The LRA further states that 

the program will use volumetric or destructive inspection techniques with demonstrated 

capability and a proven industry record to detect cracking in piping weld and base material.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

The “operating experience” program element in GALL Report AMP XI.M35 recommends 

volumetric inspection techniques that have a demonstrated capability and proven industry 

record to detect cracking in piping weld and base metal material. During its audit, the staff 

found that the applicant’s One-Time Inspection – Small-Bore Piping Program includes 

volumetric examinations of full penetration welds using “demonstrated techniques”; however, 

there was insufficient information available on what constitutes a “demonstrated technique” or 

whether such techniques are capable of detecting cracking. By letter dated April 18, 2012, the 

staff issued RAI B.1.34-4 requesting that the applicant describe how the volumetric techniques 

used to examine full penetration welds are capable of detecting cracking.

In its response dated May 18, 2012, the applicant stated that a qualified ASME Code Section Xl

volumetric examination method, such as UT or radiography, is considered a “demonstrated 

technique.” The applicant indicated that both of these methods have demonstrated the ability to 

detect cracking in the area of interest in full penetration small-bore welds when performed by 
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ASME-qualified personnel. In addition, the applicant stated that when performing ASME Code 

Section Xl examinations at GGNS, ultrasonic examination techniques, equipment, and 

personnel performing the examinations comply with the standards of ASME Code Section Xl as 

described in site procedures.

The staff finds the applicant’s response acceptable because both ultrasonic and radiographic 

tests are volumetric and, when performed by qualified personnel, these examinations are 

capable of detecting discontinuities, such as cracks, that initiate from the inside diameter of 

piping. The inside diameter of ASME Code Class 1 small-bore piping is susceptible to cracking 

when exposed to reactor coolant, and this aging effect and environment is covered by GALL 

Report AMP XI.M35. The staff’s concern described in RAI B.1.34-4 is resolved.

The LRA also states that the One-Time Inspection – Small-Bore Piping Program is new, and 

there is no operating experience at GGNS concerning cracking in ASME Code Class 1 

small-bore piping. As discussed in SRP-LR Section A.1.2.3.10, for new programs, there may be 

other relevant plant-specific operating experience or generic industry operating experience that 

is relevant to the program elements, even though this operating experience was not identified 

through implementation of the new AMP. The SRP-LR further states that, for new programs, an 

applicant may need to consider the impact of relevant operating experience from 

implementation of its existing AMPs. The “detection of aging effects” program element in 

GALL Report AMP XI.M35 also addresses operating experience. It states that the generic 

program does not apply to plants that have experienced cracking in ASME Code Class 1 

small-bore piping due to aging mechanisms. The staff’s evaluation of the applicant’s 

consideration of plant-specific operating experience for this program is addressed under the 

evaluation of the “detection of aging effects” program element, which is discussed above under 

the “Staff Evaluation” heading above.

UFSAR Supplement. LRA Section A.1.34 provides the UFSAR supplement for the One-Time 

Inspection – Small-Bore Piping Program. The staff reviewed this UFSAR supplement 

description of the program against the recommended description for this type of program as 

described in SRP-LR Table 3.0-1 and found that the applicant’s UFSAR supplement did not 

provide sufficient information for the administrative and regulatory control of the program 

because it did not describe certain characteristics of the program important for managing the 

effects of aging. The staff determined that the inspection sample size is important because it is 

used to establish whether cracking is occurring in ASME Code Class 1 small-bore piping; 

however, the applicant’s UFSAR supplement did not specifically state the sample size. Also, 

during its audit, the staff found that the One-Time Inspection – Small-Bore Piping Program

includes opportunistic destructive tests as a method for detecting aging effects. The 

examination techniques used under the program are important because they are used to detect 

the effects of aging; however, the applicant’s UFSAR supplement did not state that the program 

detects aging through destructive examinations. By letter dated April 18, 2012, the staff issued

RAI B.1.34-5 requesting that the applicant revise the summary description in LRA 

Section A.1.34 to specify the inspection sample size and that the program relies on destructive 

examinations, in addition to volumetric examinations, to detect aging effects. Alternatively, the 

staff requested the applicant to justify the adequacy of the program’s administrative and 

regulatory controls.

In its response dated May 18, 2012, the applicant revised LRA Section A.1.34. The revision 

incorporates the provision to volumetrically examine 10 percent, with a maximum of 25, of the 

socket welds and 10 percent, with a maximum of 25, of the butt welds within the total population 

of ASME Code Class 1 small-bore piping welds. In addition, the revision incorporates the option
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to perform either volumetric or opportunistic destructive examination of socket welds. The 

revision also specifies that, for inspections of full penetration welds, volumetric examinations will 

be performed and, for socket welds, credit for two volumetric examinations will be taken in the 

event that a destructive examination is performed. The staff reviewed the revised UFSAR 

supplement and determined that it accurately reflects the inspection sample size and methods 

for detecting aging effects. These changes make the UFSAR supplement for the One-Time 

Inspection – Small-Bore Piping Program consistent with the corresponding program description 

in SRP-LR Table 3.0-1. The staff’s concern described in RAI B.1.34-5 is resolved.

Subsequently, by letter dated November 29, 2012, the applicant revised the UFSAR supplement 

to state that, prior to the period of extended operation, it will search the GGNS condition 

reporting system for all potential instances of cracking in ASME Code Class 1 small-bore piping 

for the period beginning at the start of licensed plant operation. This revision was consistent 

with the applicant’s response to RAI B.1.34-2b, which the staff determined was incomplete, as 

discussed above under the “Staff Evaluation” heading. However, by letter dated April 15, 2013, 

the applicant provided the results for the completed condition report search and review. In this 

letter, the applicant also removed the statement from the UFSAR indicating that it would 

complete the search and review prior to the period of extended operation. The staff finds that 

the information in the UFSAR supplement, as amended by letter dated April 15, 2013, is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s One-Time Inspection –

Small-Bore Piping program, the staff concludes 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).

3.0.3.1.34 Protective Coating Monitoring and Maintenance

Summary of Technical Information in the Application. LRA Section B.1.36 describes the 

existing Protective Coating Monitoring and Maintenance Program as consistent, with 

enhancements, with GALL Report AMP XI.S8, “Protective Coating Monitoring and Maintenance 

Program.” The LRA states that the AMP addressed service level 1 coatings inside containment 

and assesses coating condition through visual inspection.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S8.

The staff also reviewed the portions of the “parameters monitored or inspected,” “detection of 

aging effects,” and “acceptance criteria” program elements associated with enhancements to 

determine whether the program will be adequate to manage the aging effects for which it is 

credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.36 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that “[t]he Protective 

Coating Monitoring and Maintenance Program will be enhanced to include parameters 

monitored or inspected per guidance in ASTM D5163-08.” The staff reviewed this enhancement 
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against the corresponding program elements in GALL Report AMP XI.S8. The staff finds it 

acceptable since the staff has confirmed that ASTM D5163-08 is acceptable for the parameters 

to be monitored and inspected since it is endorsed by the NRC in RG 1.54, “Service Level I, II, 

and III Protective Coatings Applied to Nuclear Power Plants,” Revision 2.

Enhancement 2. LRA Section B.1.36 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that “[t]he Protective Coating 

Monitoring and Maintenance Program will be enhanced to provide for inspection of coating near 

sumps or screens associated with the ECCS. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.S8, and it is consistent with GALL 

Report AMP XI.S8 wording of “inspection shall also be carried out on all coatings near sumps or 

screens.” Therefore, the staff finds that adding the coatings near sumps or screens is

acceptable.

Enhancement 3. LRA Section B.1.36 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that “[t]he Protective Coating 

Monitoring and Maintenance Program will be enhanced to include acceptance criteria per 

ASTM D5163-08.” The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S8. The staff finds it acceptable since the staff has confirmed 

that ASTM D5163-08 is acceptable for the acceptance criteria since the NRC endorsed it in 

RG 1.54, Revision 2.

Operating Experience. LRA Section B.1.36 summarizes operating experience related to the 

Protective Coating Monitoring and Maintenance Program. The LRA states that visual 

inspections were completed in 2000, 2002, 2005, 2007, 2008, and 2010 with no conditions 

found that required immediate repair. In addition, some conditions were noted for future 

inspections.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.36 provides the UFSAR supplement for the Protective 

Coating Monitoring and Maintenance Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description in 

SRP-LR Table 3.0-1. The staff finds that the information in the UFSAR supplement is an 

adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Protective Coating Monitoring 

and Maintenance Program, the staff determines that those program elements for which the 
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applicant claimed consistency with the GALL Report are consistent. Also, the staff reviewed the 

enhancements and confirmed that they will make the AMP adequate to manage the applicable 

aging effects. The staff concludes that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also 

reviewed the 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).

3.0.3.1.35 Reactor Head Closure Studs

Summary of Technical Information in the Application. LRA Section B.1.37 describes the 

existing Reactor Head Closure Studs Program as consistent, with an exception, with 

GALL Report AMP XI.M3, “Reactor Head Closure Stud Bolting.” The LRA states that the 

Reactor Head Closure Stud Bolting program is an existing program that manages cracking and 

loss of material for reactor head closure stud bolting using ISI and preventive measures. The 

LRA also states that the examination and inspection requirements specified in the ASME Code 

Section XI, Subsection IWB, Table IWB-2500-1, are used. The LRA further states that the 

program relies on recommendations listed in NUREG-1339 and NRC RG 1.65, “Materials and 

Inspections for Reactor Vessel Closure Studs,” to address reactor head closure stud bolting 

degradation.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M3. For the applicant’s 

“detection of aging effects” program element, the staff determined the need for additional 

information, which resulted in the issuance of RAIs, as discussed below.

The program description of LRA Section B.1.37 states that ASME Section XI examination and 

inspection requirements specified in Table IWB 2500-1 are used. The LRA AMP also states 

that surface examination of reactor pressure vessel studs, nuts, and washers from 2001 through 

2010 identified no relevant indications. However, the applicant’s Appendix A of its Inservice 

Inspection Program dated June 26, 2000, indicates that VT-1 visual examinations, rather than 

surface examinations, were planned to be performed on closure nuts and washers, consistent 

with ASME Code Section XI, Table IWB-2500-1.

By letter dated April 18, 2012, the staff issued RAI B.1.37-2, requesting that the applicant:

(a) Clarify which methods of examinations are used to inspect the studs, nuts, washers, and 

flange threads. If the examination method is not consistent with those specified in 

ASME Code Section XI, as referenced in the GALL Report, justify why the examination 

method is acceptable to detect and manage the aging effects.

(b) Summarize the inspection results for the following ASME Code inspection items, for the 

period (2001-2010) discussed in the LRA, to confirm the effectiveness of the program: 

(1) volumetric examinations of the closure studs and RV flange threads, and (2) visual 

examination of the nuts and washers.

In its response dated May 18, 2012, the applicant stated that inspections are performed to 

ASME Section 2001 Edition through 2003 Addenda, Table IWB 2500-1, Examination 

Category B-G-1. The applicant also stated that the nuts and washers were examined by visual, 

VT-1, and studs and flange threads were examined by volumetric examination using UT. In 

addition, the applicant stated that volumetric examinations were performed on all 76 RV studs 
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and flange threads during the period from 2001 to 2010, and no indications were noted. The 

applicant also stated that during the same inspection period, visual examinations were 

performed on all nuts and washers, and again no indications were identified.

The staff finds the applicant’s response acceptable because the applicant’s reactor head 

closure stud bolting components are examined in accordance with Examination Category B-G-1 

of ASME Code, Section XI, Table IWB-2500-1, as recommended in GALL Report AMP XI.M3. 

Furthermore, the examinations performed on all of the applicant’s closure studs, flange threads, 

nuts, and washers during the period from 2001 to 2010, did not identify any indication. 

Therefore, the staff’s concern described in RAI B.1.37-2 is resolved.

The staff also reviewed the portions of the “preventive actions” program element associated with 

the exception to determine whether the program will be adequate to manage the aging effects 

for which it is credited. During the course of this review, the staff found the need to also review 

portions of the “corrective actions” program element, as discussed below. The staff’s evaluation 

of this exception follows.

Exception. LRA Section B.1.37 states an exception to the “preventive actions” program element 

of GALL Report AMP XI.M3. NUREG-1801 recommends use of bolting material for closure 

studs that have an actual measured yield strength less than 150 ksi. The applicant stated that it 

does not have actual measured yield strength data. During its audit, the staff noted that the 

“corrective actions” program element of GALL Report AMP XI.M3 also has a similar 

recommendation for replacement bolting. However, onsite program documentation did not 

clearly indicate whether the applicant’s “corrective actions” program element is consistent with 

the GALL Report in using replacement bolting materials that have a measured yield strength of 

less than 150 ksi.

By letter dated April 18, 2012, the staff issued RAI B.1.37-1 requesting the applicant to clarify if 

the “corrective actions” program element is consistent with the GALL Report in terms of using 

replacement bolting materials with a measured yield strength less than 150 ksi. In addition, the 

staff requested that if the “corrective actions” program element is not consistent with the 

GALL Report, the applicant identify this as a program exception, and provide justification for 

why the Reactor Head Closure Studs Program, with the cited exception, is adequate in 

managing the aging effects of replacement bolting. Finally, the staff also asked that the 

applicant revise the LRA as necessary, consistent with its response to RAI B.1.37-1.

In its response dated May 18, 2012, the applicant stated that the cited exception to the 

“preventive actions” program element also applies to the “corrective actions” program element. 

As part of its response to RAI B.2.37-1, the applicant revised LRA Section B1.37, to cite the 

additional exception of its “corrective actions” program element to the corresponding program 

element of GALL Report AMP XI.M3. In addition, the applicant stated that its justification, which 

is stated in the LRA for the “preventive actions” program element, also applies to the “corrective 

actions” program element for replacement bolting.

In its review, the staff finds that the applicant’s response to RAI B.1.37-1 includes an 

appropriate revision to the LRA to identify the exception to the “corrective actions” program 

element of the Reactor Head Closure Studs Program in addition to the exception to the 

“preventive actions” program element.

In its review, the staff also noted that the recommendation to use closure bolting with measured 

yield strength of less than 150 ksi is related to a threshold susceptibility of higher strength 
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materials to SCC. A review of the applicant’s UFSAR Section 5.3.1.7 indicated that the 

applicant’s reactor head closure studs, nuts, and washers are fabricated from SA-540 

Grade B23 or B24 material with a specified minimum yield strength of 130 ksi, and a maximum 

reported ultimate tensile strength less than 170 ksi. Since the applicant stated that it does not 

have data regarding actual measured yield strength for its current or replacement closure 

bolting, it has appropriately and conservatively assumed that the closure bolting material is 

susceptible to SCC.

To manage cracking due to SCC, the applicant’s program includes ultrasonic examination of 

each closure stud during each inspection period. The staff finds that the ultrasonic examination 

provides reasonable assurance that SCC in closure studs, should it occur, will be detected and 

managed before loss of intended function. In addition, the previous volumetric examinations of 

the closure studs have not indicated any evidence of SCC. Therefore, the staff finds the 

applicant’s exceptions to the “preventive actions” and “corrective actions” program elements 

concerning use of material with yield strength equal or greater than 150 ksi acceptable. The 

staff’s concerns described in RAI B.1.37-1 are resolved.

Summary. Based on its audit, and review of the applicant’s Reactor Head Closure Studs 

Program, the staff finds that the program elements one, three, four, five, and six, for which the 

applicant claimed consistency with the GALL Report, are consistent with the corresponding 

program elements of GALL Report AMP XI.M3. The staff also reviewed the exceptions 

associated with the “preventive actions” and “corrective actions” program elements and the 

applicant’s response to RAIs B.1.37-1 and B.1.37-2. Based on its review, the staff finds the 

applicant’s proposed AMP, with exceptions, is adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.3.7 summarizes operating experience related to the 

Reactor Head Closure Studs Program. The applicant stated that examinations performed on 

the closure studs, nuts, and washers from 2001 to 2010 identified no relevant indications. The 

applicant also indicated that these examinations in accordance with the ASME Code 

requirements are widely used and have been demonstrated effective at detecting aging effects 

during the ISIs. The applicant further stated that the application of these proven methods 

provides assurance that the effects of aging will be managed such that the reactor head closure 

studs will continue to perform their intended functions consistent with the CLB through the 

period of extended operation.

The staff reviewed operating experience information in the LRA and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its audit and review, the staff identified operating experience for which it determined the 

need for additional clarification and resulted in the issuance of an RAI, as discussed below.

During the audit and review of the applicant’s database, the staff noted that in 1986 the 

applicant discovered that two of the closure studs were undersized. The condition report did not 

provide any additional information regarding the applicant’s finding. During the audit, the staff 

requested additional information from the applicant on the referenced undersized studs, such as 

which portions of the studs were undersized, and, if corrected, how the condition was corrected. 

However, the information was not available to the staff during the audit.
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By letter dated April 18, 2012, the staff issued RAI B.1.37-3 requesting that the applicant clarify 

if the “undersized” studs are in service and will continue to be in service during the period of 

extended operation. In addition, if the studs are in service the staff requested the applicant to 

provide the following additional information: (a) location of the studs in the RV head flange, 

(b) inspection results for the studs, (c) information to justify the adequacy of the undersized 

studs for continued use, including engineering evaluations such as stress and fatigue analyses, 

and (d) justification of the adequacy of the program to manage the aging effects of the 

undersized studs. If the undersized studs were replaced, the staff requested that the applicant 

provide information on the material properties and surface coatings for the replaced studs.

In its response dated May 18, 2012, the applicant stated that the “undersize” condition noted in 

the 1986 documentation was a slight oversize condition of the bottom plug hole for two reactor 

head closure studs. The applicant also stated that the condition had been identified before

initial startup. The applicant further stated that the condition was determined acceptable and,

therefore, the studs are still in service. Finally, the applicant stated that there was no condition 

involving the outside diameter of the studs.

Based on its review, the staff finds the applicant’s response to RAI B.1.37-3 acceptable because 

the applicant clarified that the “undersized” condition reported in 1986, involved a slight oversize 

condition of stud bottom plug holes for two reactor head closure studs. The staff finds that the 

slight oversize condition of stud bottom plug holes is not critical to maintain the intended 

function of the closure studs. Furthermore, the applicant had identified the condition before

startup and determined it was acceptable. In addition, the outside diameter of the studs is not 

affected and the 2001 through 2010 volumetric examinations of the subject studs did not note 

any indication of stud degradation. Therefore, the staff’s concern described in RAI B.1.37-3 

is resolved.

Based on its audit and review of the application, and review of the applicant’s responses to

RAIs B.1.37-1, B.1.37-2, and B.1.37-3, the staff finds that the applicant has appropriately 

evaluated plant-specific and industry operating experience and implementation of the program 

has resulted in the applicant taking corrective actions. In addition, the staff finds that the 

conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.37 provides the UFSAR supplement for the Reactor 

Head Closure Studs Program. The staff reviewed this UFSAR supplement description of the 

program and noted that it conforms to the recommended description for this type of program as 

described in SRP-LR Table 3.0-1. The staff finds that the information in the UFSAR supplement 

is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Reactor Head Closure Studs 

Program, the staff determines that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the exception 

and its justification and determines that the AMP, with the exception, is adequate to manage the 

applicable aging effects. 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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3.0.3.1.36 Reactor Vessel Surveillance

Summary of Technical Information in the Application. LRA Section B.1.38 describes the 

existing Reactor Vessel Surveillance Program as consistent, with exception and enhancement, 

with GALL Report AMP XI.M31, “Reactor Vessel Surveillance.” The Reactor Vessel 

Surveillance Program manages reduction of fracture toughness for reactor vessel beltline 

materials using material data and dosimetry. The program includes all reactor vessel beltline 

materials as defined by 10 CFR Part 50, Appendix G, Section II.F, and complies with 

10 CFR Part 50, Appendix H, for vessel material surveillance. The applicant participates in an 

ISP, which is based on the BWRVIP documents, as approved by the NRC staff.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M31. For the “scope of 

program” and “detection of aging effects” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.M31 recommends monitoring 

all of the beltline materials as defined by 10 CFR Part 50, Appendix F. The GALL Report also 

states that materials originally monitored within the scope of the licensee’s existing 

10 CFR Part 50, Appendix H, materials surveillance program will continue to serve as the basis 

for the reactor vessel surveillance aging management program unless safety considerations for 

the term of the renewed license would require the monitoring of additional or alternative 

materials.

LRA Table 4.2-2 for the applicant's upper-shelf energy analysis includes analysis results for 

“Shell Plate 1” material. The LRA also indicates that the 1/4T fluence of this plate is 3.94x1017

n/cm2 (E > 1 MeV) for 54 effective full-power years (EFPYs) in consideration of the planned 

EPU. The projected operation period of 54 EFPY corresponds to the end of the period of 

extended operation. The projected fluence of Shell Plate 1 exceeds 1.0x1017 n/cm2

, which is a 

fluence threshold for the consideration in a Reactor Vessel Surveillance Program in accordance 

with 10 CFR Part 50, Appendix H. During the audit, the staff also noted that Shell Plate 1 has 

the highest adjusted reference temperature (ART) for 54 EFPY among all the plates of the 

applicant's reactor vessel.

In its review of the LRA, the staff further noted that the LRA information does not permit the staff 

to independently confirm the neutron irradiation embrittlement of all relevant beltline materials, 

including the shell plate material and other extended beltline materials, for the period of 

extended operation. In addition, the LRA does not clearly address how the applicant's program 

will monitor and use actual test data related to the new limiting material (i.e., Shell Plate 1), 

including the data of the ISP, in order to achieve the program objective specified in the GALL 

Report (i.e., to provide sufficient material data and dosimetry to monitor irradiation embrittlement

and to determine the need for operating restrictions). The staff also noted that the general 

description of the program in LRA Section B.1.38 includes references to BWRVIP-102 and 

BWRVIP-135 that have never been submitted to the NRC for approval.

By letter dated June 27, 2012, the staff issued RAI B.1.38-1 requesting that the applicant 

provide a new table to reflect all the relevant material properties for the beltline and extended 

beltline materials. The staff also requested that the new table include the heat numbers, 

material compositions (copper and nickel contents), unirradiated reference temperature (RTNDT) 

data, projected neutron fluences, and calculated ART values of the reactor vessel materials for 
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the period of extended operation (54 EFPY). The staff further requested the applicant to clarify 

how the applicant’s program will interact with the BWRVIP ISP and will use the data generated 

by the ISP for the period of extended operation. In addition, the staff requested the applicant 

remove references to the BWRVIP documents that have not been submitted for approval.

In its response dated July 26, 2012, the applicant revised LRA Section 4.2.1 to add a new table 

that provides the requested information for the beltline and extended beltline materials. The 

new table is LRA Table 4.2-5, GGNS Beltline Adjusted Reference Temperature (ART) Values 

(54 EFPY),” which lists the beltline materials, including the extended beltline materials, and their 

heat numbers, copper and nickel contents, chemistry factors, fluence levels, and data regarding 

RTNDT and ART for the period of extended operation (54 EFPY).

The applicant also indicated that as a member of the BWRVIP ISP, monitoring and use of actual 

test data related to the new limiting material of Shell Plate 1 is conducted in accordance with 

BWRVIP-86, Revision 1, and BWRVIP-135, Revision 2. The applicant further indicated that as 

required by BWRVIP-135, Revision 2, Section 3, plants are required to notify the BWRVIP of 

changes in fluence projections for the reactor pressure vessel (at inner diameter and 1/4T 

locations) and the latest ART tables.

In addition, the applicant stated that it will ensure that new fluence projections throughout the 

period of extended operation and latest beltline ART values are provided to the BWRVIP prior to 

the period of extended operation. The applicant also revised LRA Sections A.1.38 (UFSAR 

supplement) and B.1.38 (program description) accordingly to identify this item as an 

enhancement to the “monitoring and trending” program element. The staff’s evaluation of this 

enhancement is described below. The following evaluation is also addressed in the evaluation 

section for Enhancement 2.

The applicant further stated that LRA Sections A.1.38 and B.1.38 are revised to remove 

references to BWRVIP-102 and BWRVIP-135, and the correct statement for these sections is, 

“The NRC staff has approved an integrated surveillance program for the period of extended 

operation based on BWRVIP-86, Revision 1.”

In its review, the staff found that the applicant’s new table (LRA Table 4.2-5) is appropriate 

because the LRA table provides the information that the staff requested for its independent 

confirmation. The staff also confirmed that the applicant adequately determined the ARTs of the 

reactor vessel beltline and extended beltline materials, using the data described in the table. In 

addition, the staff found that the removal of the references to BWRVIP-102 and BWRVIP-135 

from the LRA is adequate because these BWRVIP documents have not been submitted to the 

NRC for approval. The staff’s concern described in RAI B.1.38-1 is resolved.

The “detection of aging effects” program element in GALL Report AMP XI.M31 recommends the 

integrated surveillance program shall have at least one capsule with a projected neutron fluence 

equal to or exceeding the 60-year peak reactor vessel wall neutron fluence prior to the end of 

the period of extended operation.

In comparison, LRA Section B.1.38 indicates the applicant's program relies on the BWRVIP ISP 

based on staff-approved BWRVIP documents to meet the 10 CFR Part 50, Appendix H,

requirements. The LRA also refers to BWRVIP-86, Revision 1, “BWR Vessel and Internals 

Project Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” as 

described in a program enhancement (Enhancement 1). The ISP is an approved method for the 

commercial BWR reactors to manage the neutron embrittlement of the reactor vessel materials.
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Table 4-7 of BWRVIP-86, Revision 1, indicates that the maximum fluence values (E > 1 MeV) of 

the tested surveillance plate and weld materials for the applicant‘s reactor vessel are 

2.66x1018 n/cm2 and 2.75x1018 n/cm2

, respectively. BWRVIP-86, Revision 1, also indicates that 

only two additional weld materials will be withdrawn additionally in 2013 and 2039 for the 

applicant’s program, which correspond to estimated fluence values of 1.35x1018 n/cm2 and 

2.67x1018 n/cm2

, respectively.

In addition, LRA Sections 4.2 and 4.2.1 indicate that 54 EFPY corresponds to the end of the 

period of extended operation and the peak 1/4T fluence for 54 EFPY with the planned EPU is 

3.02x1018 n/cm2 as projected for the lower-intermediate shell and axial welds. The peak ID 

fluence of the reactor vessel for 54 EFPY is 4.44x1018 n/cm2

. These fluence values (E > 1 MeV) 

are compared as follows, indicating that the LRA fluence projection for the reactor vessel in 

consideration of the planned EPU exceeds the fluence values of tested and to-be-tested 

surveillance materials in the BWRVIP ISP:

• Maximum fluence of the tested surveillance plate materials (ISP): 2.66x1018 n/cm2

• Maximum fluence of the tested surveillance weld materials (ISP): 2.75x1018 n/cm2

• Fluence of the surveillance weld to be withdrawn in 2039 (ISP): 2.67x1018 n/cm2

• Peak ID fluence of the reactor vessel (LRA with EPU): 4.44x1018 n/cm2

• Peak 1/4T fluence of the reactor vessel (LRA with EPU): 3.02x1018 n/cm2

In its review, the staff further noted that the LRA does not clearly address whether the peak ID 

fluence of the reactor vessel for 54 EFPY with the planned EPU is projected to exceed the 

maximum fluence of the ISP surveillance materials (for either weld or plate).

By letter dated June 27, 2012, the staff issued RAI B.1.38-2 requesting that the applicant clarify 

whether the peak ID fluence of the reactor vessel for 54 EFPY in consideration of the planned 

EPU is projected to exceed the maximum fluence of the surveillance materials (for either weld 

or plate). The staff also requested that if the peak ID fluence of the reactor vessel for 54 EFPY 

is projected to exceed the maximum fluence of the ISP surveillance materials, the applicant 

modify the LRA to include an exception, or explain how its Reactor Vessel Surveillance Program 

is consistent with the GALL Report.

In its response dated July 26, 2012, the applicant stated that the peak reactor vessel ID fluence 

for weld and plate material is expected to exceed the [surveillance] fluence values for GGNS 

listed in BWRVIP-86, Revision 1, Table 4-7, before reaching 54 EFPY. The applicant also 

indicated that this is not consistent with the GALL Report and should be considered an 

exception to the “detection of aging effects” program element of GALL Report AMP XI.M31. In 

addition, the applicant provided a revision to LRA Section B.1.38 to identify this item as a 

program exception.

The applicant further stated that in a letter dated November 4, 2003, GGNS was issued License 

Amendment No. 160 approving participation in the BWRVIP ISP; and in an SER dated 

October 20, 2011, the staff approved BWRVIP-86, Revision 1, which is an updated BWRVIP 

ISP for the period of extended operation. The applicant also stated that BWRVIP-86, 

Revision 1, Section 5, includes provisions to apply the embrittlement evaluation described in 

RG 1.99, Revision 2, for evaluating materials and calculating an ART. The applicant indicated 

that the use of RG 1.99, Revision 2, to project the embrittlement evaluation is also described in 

the “monitoring and trending” program element of GALL Report AMP XI.M31.
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In its review, the staff found that the applicant appropriately identified a program exception 

related to the program not being expected to have a capsule with a projected neutron fluence 

level equal to or exceeding the 60-year peak reactor vessel wall neutron fluence prior to the end 

of the extended period. The staff also confirmed the applicant revised LRA Section B.1.38, 

consistent with the program exception. In addition, the staff found the applicant’s response 

acceptable because (a) the applicant participates in the staff-approved BWRVIP ISP, which 

generates and evaluates the embrittlement trend data of the BWR fleet reactor vessels, 

including the data for the surveillance materials of the applicant’s reactor vessel, (b) the 

BWRVIP ISP and GALL Report include the provisions to use the guidance in RG 1.99, 

Revision 2, in determining the embrittlement levels of reactor vessel materials, and (c) the 

projected peak 1/4T fluence of the applicant’s reactor vessel (3.02x1018 n/cm2

) with EPU is not 

significantly higher than the maximum surveillance fluence levels of the surveillance plate and 

weld materials that represent the applicant’s vessel materials (2.66x1018 n/cm2 and 

2.75x1018 n/cm2 for plate and weld, respectively). The staff’s concern described in RAI B.1.38-2 

is resolved.

The applicant’s program enhancement and exception, which the applicant identified in its 

amended LRA, are also described in the evaluation sections for program enhancement and 

exception as follows. The staff reviewed the portions of the “monitoring and trending” program 

element associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of the program 

exception also follows.

Exception. As discussed above, the applicant amended the LRA in response to RAI B.1.38-2, 

by letter dated July 26, 2012. The amended LRA identifies a program exception to the 

“detection of aging effects” program element. In this exception, the applicant stated that the 

applicant’s program is not expected to have a capsule with a projected neutron fluence level 

equal to or exceeding the 60-year peak reactor vessel wall neutron fluence prior to the end of 

the extended period.

As described above in the staff’s evaluation regarding RAI B.1.38-2, the staff reviewed this 

exception against the corresponding program element in GALL Report AMP XI.M31 and finds it 

acceptable because (a) the applicant participates in the staff-approved BWRVIP ISP, which 

generates and evaluates the embrittlement trend data of the BWR fleet reactor vessels, 

including the data for the surveillance materials of the applicant’s reactor vessel, (b) the 

BWRVIP ISP and GALL Report include the provisions to use the guidance in RG 1.99, 

Revision 2, in determining the embrittlement levels of reactor vessel materials, and (c) the 

projected peak 1/4T fluence of the applicant’s reactor vessel with EPU is not significantly higher 

than the maximum fluence of the surveillance plate and weld materials that represent the 

applicant’s vessel materials.

Enhancement. LRA Section B1.38 states an enhancement to the “monitoring and trending” 

program element. The applicant stated that the enhancement would ensure that any additional 

requirements specified in the final NRC SE for BWRVIP-86, Revision 1, will be addressed 

before the period of extended operation. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M31, and the staff determined the 

need for additional information, which resulted in the issuance of an RAI as discussed below.

The conclusion section of the staff's SE for BWRVIP-86, Revision 1, dated October 20, 2011, 

states that BWRVIP-86, Revision 1, is acceptable subject to the conditions discussed in 

previous SEs (e.g., staff’s evaluation regarding BWRVIP-116), where such conditions have not 
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been superseded by the SE regarding BWRVIP-86, Revision 1. Therefore, during its review of 

the program enhancement, the staff found that there are no “additional requirements” in the 

NRC SE of BWRVIP-86, Revision 1, other than those already identified for BWRVIP-116 and 

BWRVIP-86. By letter dated June 27, 2012, the staff issued RAI B.1.38-4 requesting that the 

applicant clarify what will be included in the “additional requirements.”

In its response dated July 26, 2012, the applicant indicated that BWRVIP-86, Revision 1, has 

combined BWRVIP-86-A, BWRVIP-116, and associated implementation activities into a single 

implementation plan for the BWRVIP ISP, covering plant operation to 60 years. The applicant 

also indicated that BWRVIP-86, Revision 1, incorporated the staff’s final SE for BWRVIP-116. 

The applicant further indicated that the applicant’s enhancement will ensure that (a) the 

requirements of the ISP specified in BWRVIP-86, Revision 1, including the conditions of the 

staff’s SE for BWRVIP-116, will be addressed before the period of extended operation, and 

(b) the new fluence projections throughout the extended operation and latest beltline ART 

values are provided to the BWRVIP prior to the period of extended operation. In addition, the 

applicant provided revisions to LRA Section A.1.38 (UFSAR supplement) and LRA 

Section B.1.38 (program description), consistent with the applicant’s response.

In its review, the staff finds the applicant’s response acceptable because the applicant’s 

revisions to LRA Sections A.1.38 and B.1.38 clarify that the program enhancement ensures that 

the requirements of the BWRVIP ISP, specified in BWRVIP-86, Revision 1, will be adequately 

addressed before the period of extended operation. The staff’s concern described in 

RAI B.1.38-4 is resolved.

Summary. Based on its audit, and review of the applicant’s responses to RAIs B.1.38-1, 

B.1.38-2, and B.1.38-4, the staff finds that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M31. The staff also reviewed the exception associated with the “detection 

of aging effects” program element, and its justification, and finds that the AMP, with the 

exception, is adequate to manage the applicable aging effects. In addition, the staff reviewed 

the enhancement associated with the “monitoring and trending” program element and finds that,

when implemented, it will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.38 summarizes operating experience related to the 

applicant’s Reactor Vessel Surveillance Program. The LRA indicates that the applicant 

committed to using the BWRVIP ISP, and as part of the ISP, the applicant is not required to 

withdraw any capsules from the applicant’s reactor vessel. The LRA also indicates that material 

property data for the plant’s limiting materials can be projected into the future with data from 

other plants. In addition, the applicant stated that updated values for its vessel fluence and 

applicable ISP data were used to evaluate the impact of neutron embrittlement on the P-T limits 

and the analysis in this evaluation confirmed that the reduction of fracture toughness due to 

neutron embrittlement is adequately managed.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects, and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program, with the exception of the following item. During its review, the staff identified 

operating experience for which it determined the need for additional clarification and resulted in 

the issuance of an RAI, as discussed below.
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LRA Sections 4.2 and 4.2.1 and Table 4.2-1 indicate that the peak 1/4T fluence value of the 

reactor vessel for 54 EFPY is 3.02x1018 n/cm2 (E > 1MeV) as projected for lower-intermediate 

shell and axial welds in consideration of the EPU. In comparison, the applicant's previous 

fluence projections without the consideration of EPU are described as follows.

The applicant's program credits the ISP specified in BWRVIP-86, Revision 1. Tables 7-2 and 

7-3 and Section 7.2 in BWRVIP-86, Revision 1, indicate that the 1/4T fluence of the applicant’s 

reactor vessel materials estimated for 48 EFPY is 1.8x1018 n/cm2 (E > 1 MeV). This 1/4T 

fluence for 48 EFPY is equivalent to 2.03x1018 n/cm2 for 54 EFPY based on linear extrapolation 

from 48 to 54 EFPY. This 54-EFPY neutron fluence (2.03x1018 n/cm2

) based on the fluence 

data in BWRVIP-86, Revision 1, is equivalent to the fluence in UFSAR Section 5.3.1.6.2, 

“Neutron Fluence.” The UFSAR section indicates that the 1/4T fluence of the reactor vessel 

beltline region for 32 EFPY is 1.21x1018 n/cm2

, and this fluence value for 32 EFPY is converted 

to 2.04x1018 n/cm2 for 54 EFPY using linear extrapolation.

In addition, UFSAR Sections 4.3.2.8, 5.3.1.6.1, and 5.3.1.6.2 indicate that the updated lead 

factor for this fluence projection for 32 EFPY is based on 3-degree surveillance capsule 

dosimetry data. However, the applicant's letter dated May 5, 1994, in response to GL 92-01 

indicates that the 1/4T fluence at the end of original 40-year license (32 EFPY) is 2.11x1018

n/cm2 as determined from flux wire dosimetry measurements at the applicant's reactor vessel 

(without consideration of planned EPU). This fluence value is converted to 3.56 x1018 n/cm2 for 

54 EFPY using linear extrapolation.

With the aforementioned assumption that linear extrapolation of the fluence is applicable, these

1/4T fluence values (E > 1 MeV) projected for 54 EFPY are compared as follows:

• Projection based on the data in the 1994 letter: 3.56x1018 n/cm2 (without EPU)

• Projection based on the data in BWRVIP-86, Revision 1: 2.03x1018 n/cm2 (without EPU)

• Projection based on the data in the UFSAR: 2.04x1018 n/cm2 (without EPU)

• LRA Section 4.2.1: 3.02x1018 n/cm2 (with EPU)

In its review, the staff noted that the “operating experience” program element of the AMP does 

not provide sufficient information to demonstrate the adequacy of the applicant's dosimetry 

monitoring activities which are part of the Reactor Vessel Surveillance Program. For example, 

the LRA does not clearly address why the 1/4T fluence projected for 54 EFPY based on the 

fluence information in the applicant's 1994 letter is significantly greater than the other fluence 

values described above.

By letter dated June 27, 2012, the staff issued RAI B.1.38-3 requesting that the applicant 

provide the following information regarding the neutron dosimetry data obtained and to be 

obtained in the program: (a) the withdrawal schedule of the dosimetry capsules/wires (including 

the dosimetry data addressed in UFSAR Section 5.3.1.6.1 and applicant's letter dated 

May 5, 1994), and (b) the results of the benchmark of the flux calculations with the dosimetry 

data. The staff also requested that the applicant clarify why the 1/4T fluence for 54 EFPY 

projected from the fluence information in the 1994 response significantly exceeds the other 

fluence values addressed above. The staff further requested that as part of the response, the 

applicant justify why the 54-EFPY fluence in the LRA that considers EPU is less than the 

54-EFPY fluence projected using the dosimetry-based 32-EFPY fluence in the 1994 letter with 

no consideration of EPU. In addition, the staff requested that the applicant justify why the 

dosimetry monitoring activities are adequate to provide sufficient dosimetry for the Reactor 

Vessel Surveillance Program, consistent with the GALL Report.
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In its response dated July 26, 2012, the applicant stated that flux wire was pulled at the end of 

the first operating cycle, and the results from the flux wire had been used in the fluence 

evaluations performed through operating cycle 13. The applicant also indicated that since it has 

been approved to use the ISP to meet the Appendix H requirements (November 4, 2003), there 

is no plan for future withdrawals of dosimetry wires or capsules from the applicant’s reactor 

vessel. The applicant further indicated that with input from the BWRVIP, the first cycle flux wire 

dosimetry results have been shown to be over-conservative and unreliable for reasonable endof-license fluence projections.

In addition, the applicant indicated that BWRVIP-86, Revision 1, Section 5, includes provisions 

for ongoing vessel dosimetry for plants that do not have dosimetry capsules tested. The 

applicant stated that the dosimetry activities for the applicant’s Reactor Vessel Surveillance 

Program are adequate and, therefore, consistent with the GALL Report.

In comparison with the applicant’s response, the staff noted that BWRVIP-86, Revision 1, 

Section 5.4, “Plan for Ongoing Vessel Dosimetry,” states that if a plant has not previously tested 

a capsule, but has tested a first-cycle dosimeter, the first-cycle dosimetry is generally the basis 

for its current fluence projection. The staff also noted that the applicant’s response does not 

provide a technical basis for why the fluence, which is based on the first-cycle dosimetry data, is 

overly-conservative and unreliable for the 54-EFPY fluence projections. Therefore, the staff 

needed additional information to determine the adequacy of the operating experience program 

element. By letter dated October 17, 2012, the staff issued RAI B.1.38-3a, requesting the 

applicant to explain why the first-cycle flux wire dosimetry results are considered to be 

unreliable for reasonable end-of-license fluence projections.

In the November 15, 2012, response, the applicant stated:

First cycle dosimetry data are unreliable because initial core configurations are 

atypical of other cycles. General Electric Hitachi (GEH) flux wire measurement 

data indicate that first cycle flux measurements are often overly conservative in 

comparison to flux measurements taken after later cycles. However, in some 

cases, first cycle measurements are not conservative. Therefore, first cycle 

dosimetry data are considered unreliable for reasonable end-of-license fluence 

projections.

The staff’s concern described in RAIs B.1.38-3 and B.1.38-3a are related to the adequacy of the 

fluence measurements as part of the Reactor Vessel Surveillance Program. The staff agrees 

that the first cycle flux measurements are unreliable, and therefore, the Reactor Vessel 

Surveillance Program will rely on the calculated fluence values. However, the applicant’s 

methodologies for fluence calculations, documented in SER Section 4.2.1, are still under review 

as part of Open Item 4.2.1 1 where the staff noted that the applicant’s fluence calculation 

uncertainty analysis was not consistent with RG 1.190, and the errors associated with the two 

different fluence calculation methods are expected to propagate when the two methods are 

combined. The staff’s concern described in RAIs B.1.38-3 and B.1.38-3a can be resolved with

acceptable resolution of the Open Item. This issue therefore is part of Open Item 4.2.1-1. As 

documented in Section 4.2.1, Open Item 4.2.1-1 is closed. The staff confirmed that the 

applicant incorporated an NRC-approved single fluence method (MPM method) into its current 

licensing basis with appropriate fluence projections for 60 years of operation. The staff also 

noted that the qualification of the fluence method included an adequate evaluation of GGNS 

Cycle 1 dosimetry data. In its letter dated July 29, 2015 (response to RAI 4.2.1-2c(5)(b)), the 

applicant provided the updated reactor vessel fluence values based on the staff-approved MPM 
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fluence methodology. The staff finds that the updated fluence values are acceptable to use in 

the applicant’s program. In addition, the staff’s evaluation regarding neutron embrittlement 

TLAAs are documented in Sections 4.2.2 – 4.2.6 of this SER. The staff’s concern described in 

RAIs B.1.38-3 and B.1.28-3a is resolved.

Based on its audit and review of the application, and review of the applicant’s response to RAIs,

the staff finds that the applicant has appropriately evaluated plant-specific and industry 

operating experience. In addition, the staff finds that the conditions and operating experience at 

the plant are bounded by those for which the corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.38 provides the UFSAR supplement for the applicant’s 

Reactor Vessel Surveillance Program. The staff reviewed this UFSAR supplement description 

of the program against the recommended description for this type of program as described in 

SRP-LR Table 3.0-1 and noted that LRA Section A.1.38 does not address some of the 

important program attributes included in the UFSAR supplement described in SRP-LR, 

Table 3.0-1. By letter dated June 27, 2012, the staff issued RAI B.1.38-5 requesting that the 

applicant justify why some of important program attributes are not included in the supplement.

In its response dated July 26, 2012, the applicant stated that most of the important program 

attributes are incorporated by referencing BWRVIP-86, Revision 1. The one significant attribute 

of the program that is not explicitly controlled by the ISP would be the control of standby 

capsules in the applicant’s reactor vessel. The applicant stated that to address this issue, LRA 

Section A.1.38 is revised to clearly state that the standby capsules at GGNS may be required 

for contingencies of the ISP, and as a result, any change to the status of the standby capsules, 

must be approved by the NRC prior to implementation, and untested capsules, which are placed 

in storage, must be maintained for future insertion. In its response, the applicant also provided 

a revision to the LRA Section A.1.38, consistent with the response.

The staff finds the applicant’s response acceptable because the revised UFSAR supplement, 

which includes the reference to BWRVIP-86, Revision 1, and the provisions regarding the 

stand-by and untested capsules, is adequate to summarize the applicant’s aging management 

program. Therefore, the UFSAR supplement for the applicant’s Reactor Vessel Surveillance 

Program is consistent with the corresponding program description in SRP-LR Table 3.0-1. The 

staff’s concern described in RAI B.1.38-5 is resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

July 26, 2012, is an adequate summary description of the program.

Applicant’s July 29, 2015, response to RAI 4.2.1-2c(5)(b) provided slightly different fluence 

values due to the implementation of the single MPM fluence calculation methodology, but the 

conclusions regarding program acceptability remain the same.

Conclusion. On the basis of its audit and review of the applicant’s Reactor Vessel Surveillance 

Program, the staff determines that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M31. In addition, the staff reviewed the exception and its justification and 

determines that the AMP, with the exception, is adequate to manage the applicable aging 

effects. Also, the staff reviewed Enhancement 1 and confirmed that its implementation through 

Commitment No. 27 prior to the period of extended operation will make the AMP adequate to 

manage the applicable aging effects. The staff reviewed the UFSAR supplement for this AMP 
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and finds that the information in the UFSAR supplement, as amended by letter dated 

July 26, 2012, is an adequate summary description of the program.

3.0.3.1.37 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants

Summary of Technical Information in the Application. LRA Section B.1.39 describes the 

existing “Regulatory Guide (RG) 1.127, “Inspection of Water-Control Structures Associated with 

Nuclear Power Plants,” as consistent, with enhancements, with GALL Report AMP XI.S7, 

“RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants.” The 

LRA states that this is an existing program that requires periodic monitoring of water-control 

structures so that the consequences of age-related deterioration and degradation can be 

prevented or mitigated in a timely manner. The LRA also states that the program contains 

guidance on engineering data compilation, inspection activities, technical evaluation, inspection 

frequency, and content of inspection reports.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S7.

The staff also reviewed the portions of the “detection of aging effects” and “acceptance criteria”

program elements associated with enhancements to determine whether the program will be 

adequate to manage the aging effects for which it is credited. The staff’s evaluation of these 

enhancements follows.

Enhancement 1. LRA Section B.1.39 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be clarified to 

specify that detection of aging effects will monitor accessible surfaces on a frequency not to 

exceed 5 years. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S7 and finds it acceptable because when it is implemented, 

the inspection frequency will be consistent with the recommendation identified in the GALL

Report AMP.

Enhancement 2. LRA Section B.1.39 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that periodic sampling, testing, and 

analysis of groundwater chemistry for pH, chlorides, and sulfates will be conducted at a 

frequency of at least every 5 years. The enhancement also states that the program owner will 

review the results and evaluate anomalies and perform trending of the results to provide 

reasonable assurance that degradation of inaccessible structures will be detected before loss of

an intended function. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.S7 and finds it acceptable because when it is implemented, 

the inspection frequency and parameters monitored and analyzed will be consistent with the 

recommendations identified in the GALL Report AMP.

Enhancement 3. LRA Section B.1.39 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that quantitative acceptance 

criteria for evaluation and acceptance will be based on guidance provided in ACI 349.3R.

The staff reviewed this enhancement against the corresponding program element in GALL

Report AMP XI.S7 and finds it acceptable because, the “Evaluation Criteria” provided in 

Chapter 5 of ACI 349.3R provides a three-tier acceptance criteria (including quantitative criteria) 
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for determining the adequacy of observed aging effects and specifies criteria for further 

evaluation. When this enhancement is implemented, it will make the acceptance criteria 

consistent with the recommendations identified in the GALL Report.

Summary. Based on its audit of the applicant’s RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants, the staff finds that program elements one 

through six for which the applicant claimed consistency with the GALL Report are consistent 

with the corresponding program elements of GALL Report AMP XI.S7. In addition, the staff 

reviewed the enhancements associated with the “detection of aging effects” and “acceptance 

criteria” program elements and finds that when implemented, they will make the AMP adequate 

to manage the applicable aging effects.

Operating Experience. LRA Section B.1.39 summarizes operating experience related to the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants. 

Program basis documentation indicated that during a walkdown in 1997 of the “A” and “B” SSW

basins, discolored efflorescence was noted on the north face of both pump houses. Pictures 

were taken of the two affected areas, and a chemical composition analysis of the discolored 

efflorescence was performed. A subsequent walkdown of this area conducted in 2007, under 

the “Maintenance Rule,” noted that no observable concrete damage such as concrete spalling 

was observed, and the condition was determined to be similar to that when first observed 

in 1997. The applicant determined that there was no immediate structural integrity concern for 

the next two plant operating cycles.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.39 provides the UFSAR supplement for the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program. The 

staff reviewed this UFSAR supplement description of the program and noted that it is consistent 

with the recommended description in SRP-LR Table 3.0-1. The staff also noted that the 

applicant committed (Commitment No. 28) to enhance the RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants Program before the period of 

extended operation as follows:

• monitor accessible structures on a frequency not to exceed 5 years, consistent with the 

frequency for implementing the requirements of RG 1.127

• perform periodic sampling, testing, and analysis of groundwater chemistry for pH, 

chlorides, and sulfates on a frequency of at least every 5 years
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• include quantitative acceptance criteria for evaluation and acceptance based on the 

guidance provided in ACI 349.3R

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s RG 1.127, Inspection of 

Water-Control Structures Associated with Nuclear Power Plants, the staff determines that those 

program elements for which the applicant claimed consistency with the GALL Report are 

consistent. Also, the staff reviewed the enhancements and confirmed that their implementation 

prior to the period of extended operation will make the AMP adequate to manage the applicable 

aging effects. 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).

3.0.3.1.38 Selective Leaching

Summary of Technical Information in the Application. LRA Section B.1.40 describes the new

Selective Leaching Program as consistent with GALL Report AMP XI.M33, “Selective Leaching 

of Materials.” The LRA states that the program will include a one-time visual inspection of 

selected components coupled with hardness measurement or other mechanical examination 

techniques to determine whether or not loss of material is occurring due to selective leaching.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M33. For the “detection of 

aging effects” and “corrective actions” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.M33 recommends 

that one-time inspections using visual and hardness measurement techniques should be 

conducted to detect selective leaching. However, during its audit, the staff found that the 

applicant’s Selective Leaching Program basis document states that the program will include 

visual inspection and hardness measurements; however, the plant-specific implementing 

procedure states that hardness testing or verification is conducted “where possible.”

By letter dated April 25, 2012, the staff issued RAI B.1.40-1 requesting that the applicant state 

what methods will be used to confirm the absence of selective leaching when hardness 

measurements are not possible.

In its response dated May 25, 2012, the applicant stated that its Selective Leaching Program will 

be consistent with GALL Report AMP XI.M33, without exception. The applicant also clarified 

that its program will include other mechanical examination techniques such as destructive 

testing, chipping, or scraping when the hardness measurements are not possible.

The staff finds the applicant’s response acceptable because the applicant clarified the types of 

examination techniques that may be used when the hardness measurements are not possible. 

The other mechanical examination techniques cited by the applicant are consistent with the 
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recommendations in the GALL Report; therefore, the staff’s concern described in RAI B.1.40-1 

is resolved.

The “corrective actions” program element in GALL Report AMP XI.M33 recommends that 

unacceptable inspection findings will result in additional inspections being performed. However, 

during its audit, the staff found that the applicant’s Selective Leaching Program basis document 

states that corrective actions of unacceptable inspection findings will be carried out in 

accordance with the CAP and that corrective actions will be consistent with the GALL Report; 

however, the implementing procedure states that the cause evaluation and corrective actions for 

indications of selective leaching should include consideration of scope expansion.

By letter dated April 25, 2012, the staff issued RAI B.1.40-2 requesting that the applicant 

confirm that, if selective leaching is detected in the one-time inspection proposed in the 

program, further inspections will be conducted to ensure that the extent of degradation is 

understood.

In its response dated May 25, 2012, the applicant stated that the Selective Leaching Program at 

GGNS is a new AMP that will be consistent with GALL Report AMP XI.M33. The applicant also 

cited the recommendations in the GALL Report for unacceptable inspection findings, which 

include a possible expansion of the inspection sample size and location and additional 

inspections, and stated that it will develop or revise procedures as necessary to ensure the 

program is consistent with GALL Report AMP XI.M33.

The staff finds the applicant’s response acceptable because the applicant stated that it will 

develop or revise procedures to be consistent with GALL Report AMP XI.M33, including the 

recommendations for unacceptable inspection findings. The staff’s concern described in

RAI B.1.40-2 is resolved.

Based on its audit and review of the applicant’s responses to RAIs B.1.40-1 and B.1.40-2, of the 

applicant’s Selective Leaching Program, the staff finds that program elements one through six 

for which the applicant claimed consistency with the GALL Report are consistent with the 

corresponding program elements of GALL Report AMP XI.M33.

Operating Experience. LRA Section B.1.40 does not provide any plant-specific operating 

experience. Instead, it states that industry operating experience will be considered when 

implementing the program. It also states that plant operating experience will be gained as the 

program is implemented during the period of extended operation and will be factored into the 

program via its 10 CFR Part 50, Appendix B, quality assurance program.

As discussed in the AMP Audit Report, the staff conducted an independent review of the 

applicant’s corrective action database and confirmed that there were no plant-specific operating 

experience results identifying selective leaching as an aging effect. During its review, the staff 

found no operating experience to indicate that the applicant’s program would not be effective in 

adequately managing aging effects during the period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated industry operating experience. In addition, the staff finds that the 

conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.
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UFSAR Supplement. LRA Section A.1.40 provides the UFSAR supplement for the Selective 

Leaching Program. The staff reviewed this UFSAR supplement description of the program and 

noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The staff 

also noted that the applicant committed (Commitment No. 29) to implement the new Selective 

Leaching Program prior to entering the period of extended operation for managing aging of 

applicable components.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Selective Leaching Program, 

the staff concludes 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).

3.0.3.1.39 Service Water Integrity

Summary of Information in the Application. LRA Section B.1.41 describes the existing Service 

Water Integrity Program as consistent with GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System.” The LRA states that the program manages loss of material and fouling in 

open-cycle cooling water systems as described in the GGNS response to GL 89-13, “Service 

Water System Problems Affecting Safety-Related Equipment,” issued July 1989.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M20. For the “scope of 

program,” “parameters monitored or inspected,” and “detection of aging effects” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “detection of aging effects” program element of GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” states, in part, that the inspection frequencies are in accordance with 

the applicant’s docketed response to GL 89-13. SRP-LR Section A.1.2.3.4 states that, for 

condition monitoring programs, the frequency of inspections may be linked to plant-specific 

operating experience and the discussion should provide justification that the frequency is 

adequate to detect the aging effects before the loss of intended function. LRA Section B.1.41 

states that the Service Water Integrity Program manages loss of material and fouling as 

described in the GGNS response to GL 89-13. The GGNS GL 89-13 response, dated 

January 29, 1990, states that “accessible external piping surface coatings are maintained by 

routine plant painting efforts.” However, the GGNS GL 89-13 response does not discuss 

management of submerged piping. During the audit, the staff reviewed GGNS 

procedure 07-S-07-211, “Service Level I Coatings Condition Assessment,” Section 6.0, 

“Frequency of Inspection,” which states that the time between inspections of the pipe coating in 

the SSW basin will not exceed 36 months. During its review of related operating experience, 

the staff noted that condition reports CR-GGN-2010-05825 and CR-GNN-2010-03814 

documented loss of material from submerged piping in the SSW basin ranging from 0.134 inch 

to 0.200 inch in 12 months. Based on the amount of material lost in 12 months, the staff 
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questioned the adequacy of the inspection frequency of 36 months specified in the controlling 

procedure. By letter dated April 26, 2012, the staff issued RAI B.1.41-1 requesting the applicant 

to justify the 36-month inspection frequency specified in Procedure 07-S-07-211.

In its response dated May 25, 2012, the applicant stated that procedure 07-S-07-211 applies to 

underwater coatings in the SSW basin, including coatings on concrete structures and that the 

36-month inspection frequency is appropriate for these concrete structures. The applicant also 

stated that in addition to the SSW basin inspections specified in procedure 07-S-07-211, it 

performs SSW basin piping coating inspections annually. However, the applicant did not 

describe where these additional inspections are specified and how the inspection frequencies 

are adjusted based on plant-specific operating experience. In order to address this concern, the 

staff issued RAI B.1.41-1a, by letter dated September 5, 2012, requesting that the applicant 

clarify which GGNS procedure controls the coating inspections and how the frequencies of 

these inspections are adjusted. The RAI also requested the applicant to update the description 

of the Service Water Integrity Program, since the GGNS response to GL 89-13 did not reflect 

the current aging management activities associated with the inspections of submerged piping in 

the SSW basin.

In its response dated October 2, 2012, the applicant stated that the coatings inspections are 

performed in accordance with GGNS 07-S-07-211 and that the inspection frequency is based 

on a study performed by the GGNS equipment reliability team and is specified as at least once 

per 12 months through the GGNS maintenance management system. The applicant also stated 

that the frequency is adjusted, based on documented inspection results, and would be 

increased for indications of accelerated corrosion to ensure unacceptable degradation does not 

occur prior to the next scheduled inspection. In addition, the applicant revised LRA 

Sections A.1.41 and B.1.41 by stating that the program includes inspections of coatings for 

submerged piping in the SSW basin and that the frequency of these inspections is based on 

previous inspection results. The staff finds the applicant’s response acceptable because it 

clarified which procedure controls the coatings inspections, how the inspection frequency was 

developed, how the inspection frequency will be adjusted, and which process specifies the 

coating inspection frequency. The staff considers the current 12-month frequency with 

adjustments for indications of accelerated corrosion to provide reasonable assurance that the 

effects of aging will be adequately managed. The staff’s concerns described in RAIs B.1.41-1 

and B.1.41-1a are resolved.

For the “parameters monitored or inspected” program element, GALL Report AMP XI.M20 

states that the program uses condition monitoring to manage corrosion. During the audit, the 

staff reviewed the GGNS “Strategic Plan for Open Loops,” dated 2004, which states that 

corrosion coupon testing and trending is performed quarterly with a target value of less than 

0.005 inch per year for mild steel. The staff also reviewed GGNS procedure 08-S-03-10, 

“Chemistry Sampling Program,” Attachment VII, “Standby Service Water A & B,” which includes 

a corrosion coupon test every 6 months; however, it does not specify any control limit value. 

The staff noted that the corrosion coupon testing was not discussed in the LRA and was not 

included in the GGNS response to GL 89-13. The staff also noted that UFSAR Section 9.2.1.2 

states long-term corrosion of the service water piping is compensated for by an appropriate 

corrosion allowance. Although corrosion coupon testing for the SSW system is being performed 

by the controlling procedure, it was not clear whether it is being credited as part of this program 

and how the target value given in the Strategic Plan for Open Loops factors into the program. 

By letter dated April 26, 2012, the staff issued RAI B.1.41-2 requesting the applicant to provide 

the bases for managing long-term corrosion of the SSW system and to clarify whether corrosion 

coupon testing will be included in the program.
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In its response dated May 25, 2012, the applicant stated that, although a corrosion allowance 

was provided during the system design, the ongoing periodic visual inspections and other NDEs 

performed by the Service Water Integrity Program provide reasonable assurance that the SSW 

system pipe wall thicknesses remain acceptable. The applicant stated that GGNS performs 

coupon testing for information only and that it is not relied upon in the Service Water Integrity 

Program to manage the effects of aging. The applicant also stated that corrosion coupon 

testing was not an activity proposed in its response to GL 89-13. The staff finds the applicant’s 

response acceptable because the Service Water Integrity Program performs visual and other 

nondestructive examinations, consistent with the GALL Report AMP, which ensures that the 

pipe wall thicknesses remain acceptable. The staff’s concern described in RAI B.1.41-2 is 

resolved.

For the “detection of aging effects” program element, GALL Report AMP XI.M20 states that 

visual inspections are typically performed to determine whether erosion is occurring in the 

system. The staff noted that, although GL 89-13, Action III, recommended a routine inspection 

program to ensure that erosion and other problems cannot degrade the performance of the 

service water system, the GGNS response to GL 89-13, Action III, Item 7 “Erosion Monitoring 

and Control,” concludes that the SSW system does not require monitoring for erosion. 

However, relatively recent plant-specific operating experience in condition report 

CR-GGN-2010-01344 discusses loss of material due to minor erosion or corrosion at the 

flanged connection to a discharge valve in the SSW system and proposes the inclusion of this 

valve in an “appropriate piping program (i.e., MS-46, Moderate Energy Piping).” The applicant 

provided a copy of GGNS MS-46, “Project Plan for Monitoring Internal Erosion/Corrosion in 

Moderate Energy Piping Components,” during the audit to help clarify this issue. Although the 

program plan identified the SSW system as a susceptible system in the moderate energy 

program, it was not clear to the staff whether components in the SSW system were being 

managed for loss of material due to erosion/corrosion, because it is not described in the LRA 

nor discussed in the onsite program evaluation documentation. By letter dated April 26, 2012, 

the staff issued RAI B.1.41-3, requesting that the applicant clarify if the components that are 

being managed for loss of material by the Service Water Integrity Program are also being 

managed for loss of material due to erosion/corrosion through GGNS MS-46.

In its response dated May 25, 2012, the applicant stated that the “GGNS-MS-46 procedure for 

moderate energy piping is not an aging management program that is necessary or credited to 

manage the effects of aging for components that are included in the Service Water Integrity 

program.” The response also stated that, while the cited condition report did propose inclusion 

of this component in inspections performed under GGNS MS-46, the associated engineering 

evaluation concluded that continued monitoring was not needed because the wall thickness 

would remain acceptable beyond the end of the period of extended operation. However, the 

staff noted that, in its response to RAI B.1.22-3, the applicant stated that, although the 

inspections described in GGNS MS-46 are not credited as part of the Flow-Accelerated 

Corrosion Program, the “inspections specified in GGNS MS-46 are credited as part of the AMPs 

for loss of material described in [the] Fire Water System and Service Water Integrity programs.” 

In order to resolve the apparent conflicting information and to determine if SSW piping is being 

monitored for wall thinning due to erosion/corrosion, the staff issued RAI B.1.41-3a, by letter 

dated September 5, 2012, requesting that the applicant reconcile the apparent disparity 

between its responses to RAI B.1.22-3 and RAI B.1.41-3 and to provide information regarding 

all components that are being monitored for erosion/corrosion through GGNS MS-46.

In its response dated October 2, 2012, the applicant stated that site procedure GGNS MS-46 is 

not an AMP; however, the inspections performed by that procedure may be used as 
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opportunistic or periodic inspections for AMPs in the LRA. The response also states that the 

inspections prescribed by GGNS MS-46 “are ongoing monitoring activities that are credited by 

aging management programs described in the GGNS LRA, such as the Fire Water System 

Program, the Water Chemistry Control – Closed Treated Water Systems Program, and the 

Service Water Integrity Program.” The staff noted an inconsistency because the LRA states 

that all three of the cited AMPs were consistent with the corresponding AMP in the GALL 

Report, and none of the three GALL Report AMPs manage loss of material due to 

erosion/corrosion. In addition, LRA Section A.1.41 states that the Service Water Integrity 

Program manages loss of material as described in the GGNS response to GL 89-13, except the 

GGNS GL 89-13 response states that the SSW system does not meet the criteria for 

erosion/corrosion monitoring. In addition, GGNS-EP-08-LRD06, “Aging Management Program 

Evaluation Report Non-Class 1 Mechanical” (which was provided to the staff during the staff’s 

onsite AMP audit), did not cite GGNS MS-46 as an implementing procedure for the three AMPs 

cited in the RAI response.

In order to resolve these concerns, by letter dated November 20, 2012, the staff issued 

RAI B.1.41-3b requesting that the applicant provide additional detail in the LRA tables such that 

the AMR items associated with the erosion aging mechanism are identified and to confirm that 

the onsite AMP evaluation documentation will be updated to include GGNS MS-46 and to 

update the appropriate sections of the LRA to reflect the current aging management activities 

that are performed by the Service Water Integrity Program. In the “Safety Evaluation Report 

with Open Items Related to the License Renewal of Grand Gulf Nuclear Station Unit 1,” the staff 

had identified the resolution of the issues documented in RAI B.1.41-3b as Open 

Item 3.0.3.1.39-1.

In its response dated December 18, 2012, the applicant stated that it had revised the 

appropriate sections of GGNS EP-08-LRD06 to identify GGNS MS-46 as an implementing 

procedure for monitoring microbiologically-influenced corrosion in the Fire Water System 

Program, the Water Chemistry Control – Closed Treated Water Systems Program, and the 

Service Water Integrity Program. In addition, the applicant stated that (a) GGNS MS-46 is not 

credited for managing loss of material due to erosion and it does not describe components that 

are subject to loss of material due to erosion, (b) GGNS MS-46 requires revision to update its 

purpose and scope because it does not reflect the systems and components that it addresses, 

and (c) no recent monitoring activities have been performed through GGNS MS-46.

In its review of the applicant’s response, the staff noted that the applicant’s GL 89-13 response 

states that the SSW does not meet the criteria for erosion monitoring; however, GGNS 

EP-08-LRD02, “Operating Experience Review Report (AERM),” finds that loss of material due to 

erosion is an aging effect requiring management for the SSW and other in-scope systems. 

Consequently, it was not clear to the staff how the applicant manages loss of material due to 

erosion, since the description of the Service Water Integrity Program only states that the 

program manages aging as described in the GGNS response to GL 89-13, and corresponding 

AMR items were not included in the LRA. In addition, it was not clear to the staff what aging 

management activities were being performed through GGNS MS-46, because no recent 

activities had been performed through GGNS MS-46 and, according to the applicant, the 

procedure did not reflect the systems and components that it addresses. By letter dated 

March 12, 2013, as modified by letter dated November 21, 2013, the staff issued RAI B.1.41-3c 

asking the applicant to clarify these issues.

The staff noted, in correspondence dated August 8, 2013, which was associated with a 

Predecisional Enforcement Conference, the applicant stated that its above response to 
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RAI B.1.41-3b had incorrectly stated that GGNS does not credit GGNS MS-46 for managing 

loss of material due to erosion. The applicant’s corrective actions for the related enforcement 

are documented in its reply dated October 17, 2013, to the Notice of Violation.

In its response to RAI B.1.41-3c dated December 20, 2013, the applicant revised LRA 

Sections A.1.41 and B.1.41 to state that the Service Water Integrity Program also includes 

inspections for loss of material due to erosion and included a new enhancement to revise 

program documents to include inspections for this aging mechanism. In addition, the applicant 

stated that the loss of material due to erosion, which was identified in EP-08-LRD02, is being 

managed through a combination of AMPs, including the Service Water Integrity Program, the 

Periodic Surveillance and Preventive Maintenance Program, and the Flow-Accelerated 

Corrosion Program. As a result, the applicant added new AMR items to Tables 3.3.2-16, 

3.3.2-19-1, and 3.4.2-2-9 with plant-specific notes stating that the aging effect of loss of material 

for the associated components is related to erosion. In addition, the applicant revised LRA 

Sections A.1.22 and B.1.22 for the Flow-Accelerated Corrosion Program and LRA 

Sections A.1.35 and B.1.35 for the Periodic Surveillance and Preventive Maintenance Program 

to reflect their use for managing loss of material due to erosion.

As part of its above response to RAI B.1.41-3c, the applicant provided a table with the most 

recent inspection results for components in the MS-46 database that are being monitored for 

erosion. The applicant stated that it had identified discrepancies in the MS-46 database during 

the development of its response to the RAI, which prevented the determination of appropriate 

dates for the next inspection of some components, and that this condition had been entered into 

the GGNS CAP. The staff noted that, although some inspections were performed in 2008, only 

one inspection was performed in 2012, but the majority of the inspections were conducted since 

August 2013.

The staff finds the applicant’s response to RAI B.1.41-3c acceptable because the applicant 

clarified that it manages loss of material due to erosion through three different AMPs and 

provided additional enhancements to these programs and new AMR items that address this 

aging mechanism. The staff’s evaluation of the enhancement to the Service Water Integrity 

Program is documented later in this section of the SER. The staff’s evaluations of the 

enhancements described above to the Flow-Accelerated Corrosion Program and the Periodic 

Surveillance and Preventive Maintenance Program are documented in SER Sections 3.0.3.1.21 

and 3.0.3.2.2, respectively. In addition, the applicant’s CAP will address the discrepancies that 

it identified in the MS-46 database. The staff’s concerns described in RAIs B.1.41-3, B.1.41-3a, 

B.1.41-3b, and B.1.41-3c are resolved, and Open Item 3.0.3.1.39-1 is closed.

For the “scope of program” program element, GALL Report AMP XI.M20 states that the 

program addresses the aging effect of material loss as described in the applicant’s response to 

GL 89-13. The GGNS response to GL 89-13 states that, as a result of microbiological activity in 

the SSW system, it had implemented a Small Bore and Deadleg Pipe Inspection Program. 

However, the program basis documents reviewed during the audit did not discuss this program, 

and it was not clear whether all aspects of the program cited in the GL 89-13 response had 

been incorporated into the Service Water Integrity Program. By letter dated April 26, 2012, the 

staff issued RAI B.1.41-4 requesting that the applicant confirm that all aspects of the Small Bore 

and Deadleg Pipe Inspection Program have been incorporated into the Service Water Integrity 

Program.

In its response dated May 25, 2012, the applicant stated that the site activities referred to in its 

response to GL 89-13 as the “Small Bore and Deadleg Pipe Inspection Program” have been 
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incorporated into the Service Water Integrity Program. The applicant also stated that procedure 

EN-DC-340, “Microbiologically Influenced Corrosion Monitoring Program,” does not supplement 

any AMP other than the Service Water Integrity Program. The staff finds the applicant’s 

response acceptable because the program includes the inspection activities referenced in the 

GGNS response to GL 89-13, which is consistent with the guidance in the GALL Report for this 

AMP. The staff’s concern described in RAI B.1.41-4 is resolved.

The staff also reviewed the portions of the “detection of aging effects” program element 

associated with an enhancement to determine whether the program will be adequate to manage 

the aging effects for which it is credited. The staff’s evaluation of this enhancement follows.

Enhancement. In its response dated December 20, 2013, to RAI B.1.41-3c, the applicant 

provided an enhancement to the “detection of aging effects” program element for revising the 

Service Water Integrity Program documents to include inspections for loss of material due to 

erosion. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M20 and finds it acceptable because, when it is implemented, it will 

manage the components within the program for the appropriate aging mechanisms that the 

applicant identified during its operating experience reviews conducted for the LRA.

Based on reviews of LRAs and industry operating experience conducted by the staff, the staff 

identified an issue concerning loss of coating integrity of internal coatings of piping, piping 

components, heat exchangers, and tanks. By letter dated January 2, 2014, the staff issued 

RAI 3.0.3-2 requesting that the applicant address several questions associated with managing 

loss of coating integrity. As a result of this RAI and follow-on RAIs, the applicant provided 

several enhancements to the Service Water Integrity Program in order to manage loss of 

coating integrity. The staff’s evaluations of the changes described in these enhancements are

documented in SER Section 3.0.3.3.

Based on its audit of the applicant’s Service Water Integrity Program and review of the 

applicant’s responses to RAIs B.1.41-1, B.1.41-1a, B.1.41-2, B.1.41-3, B.1.41-3a, B.1.41-3b, 

B.1.41-3c, and B.1.41-4, the staff finds that program elements one through six for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

elements of GALL Report AMP XI.M20. The staff also reviewed the enhancement associated 

with the “detection of aging effects” program element, and its justification, and finds that, when 

implemented, it will make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.41 summarizes operating experience related to the 

Service Water Integrity Program. The LRA discusses a 2009 program assessment that 

evaluated the health of the system and the program and concluded that the performance and 

regulatory margin of the SSW system will be restored, once appropriate corrective actions are 

implemented for the longstanding structural and operational issues. The LRA also discusses a 

visual inspection in 2010, which detected excessive pitting and corrosion on an SSW valve body 

and discharge flange. The LRA states subsequent ultrasonic inspections concluded that the 

minimum wall thickness requirements were met. The LRA concludes by stating that the 

identification and evaluation of aging effects prior to loss of intended function provides evidence 

that the program remains effective.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 
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whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of an RAI, as 

discussed below.

For the “operating experience” program element, SRP-LR Section A.1.2.3.10, “Operating 

Experience,” states that operating experience should consider past corrective actions. Plant 

operating experience identified in condition report CR-GGN-2003-00919 describes an issue with 

the SSW basin siphon line, in which numerous nodules and areas of corrosion were visible on 

the internal surfaces of this piping and that the internal surfaces are inaccessible with respect to 

applying protective coatings. The condition report also states that this piping does not benefit 

from the water treatment program for the SSW system. The staff noted that this line is 

discussed in UFSAR Section 9.2.1.3, which states that the interconnecting line between the two 

SSW basins is required to ensure the availability of a 30-day water supply, and depending on 

the water level, the line either equalizes or siphons water from one basin to the other. Since the 

siphon function may be affected by a pin-hole leak in the upper portion of interconnecting line 

and given the lack of protective coatings and the lack of benefit from the water treatment 

program, it was not clear to the staff whether the inspections of this line would be sufficient to 

ensure that the effects of aging will be adequately managed such that the intended function of 

the siphon line will be maintained. By letter dated April 26, 2012, the staff issued RAI B.1.41-5 

asking the applicant to justify the adequacy of the current inspection program for the 

interconnecting line between the two SSW basins for the effect that pin-hole leaks may have on 

the siphon function of the line and for the effect that internal nodules will have on the equalizing 

flow rate.

In its response dated May 25, 2012, the applicant stated that the siphon line was replaced 

during the spring 2012 refueling outage with super-austenitic stainless steel piping, which is not 

susceptible to microbiologically-influenced corrosion, and that visual inspections conducted 

through the Service Water Integrity Program will continue. The staff agrees that the new piping 

material is far more resistant to corrosion and does not require protective coatings on the 

submerged portions of the piping. In addition, the applicant will continue to perform the visual 

inspections as part of this AMP to detect loss of material that will provide reasonable assurance 

that the siphon line will continue to perform its intended functions. The staff’s concern described 

in RAI B.1.41-5 is resolved.

Based on its audit and review of the application, and review of the applicant’s response to 

RAI B.1.41-5, the staff finds that the applicant has appropriately evaluated plant-specific and 

industry operating experience and implementation of the program has resulted in the applicant 

taking corrective actions. In addition, the staff finds that the conditions and operating 

experience at the plant are bounded by those for which the corresponding GALL Report AMP 

was evaluated.

UFSAR Supplement. LRA Section A.1.41, as amended in response to RAI B.1.41-1a dated 

October 2, 2012, and RAI B.1.41-3c dated December 20, 2013, provides the UFSAR 

supplement for the Service Water Integrity Program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 35) to enhancing the program by revising Service Water Integrity Program 

documents to include inspections for loss of material due to erosion. The staff finds that the 

information in the UFSAR supplement, as amended by letters dated October 2, 2012, and 

December 20, 2013, is an adequate summary description of the program. In addition, the staff’s 
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evaluation of the UFSAR changes to address loss of coating integrity is documented in SER 

Section 3.0.3.3.

Conclusion. On the basis of its audit and review of the applicant’s Service Water Integrity 

Program, the staff concludes that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. In addition, the staff reviewed the 

enhancement and confirmed that its implementation through Commitment No. 35 prior to the 

period of extended operation will make the AMP adequate to manage the applicable aging 

effects. 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).

3.0.3.1.40 Structures Monitoring Program

Summary of Technical Information in the Application. LRA Section B.1.42 describes the 

existing Structures Monitoring Program as consistent, with enhancements, with GALL Report

AMP XI.S6, “Structures Monitoring.” The Structures Monitoring Program is an existing program 

that provides for aging management of structures and structural components, including 

structural bolting, within the scope of license renewal. The program was developed based on 

guidance in RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,”

Revision 2, and NUMARC 93-01, “Industry Guidelines for Monitoring the Effectiveness of 

Maintenance at Nuclear Power Plants,” Revision 2, to satisfy the requirement of 10 CFR 50.65, 

“Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.”

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.S6. For the “detection of aging 

effects,” and “acceptance criteria” program elements, the staff determined the need for 

additional information, which resulted in the issuance of RAIs, as discussed below.

The “detection of aging effects” program element in GALL Report AMP XI.S6 recommends that 

in general all structures be monitored at a frequency not to exceed 5 years (e.g., structures 

exposed to natural environments, structures inside primary containment, continuous 

fluid-exposed structures, and structures retaining fluid or pressure). The GALL Report also 

notes that some structures of lower safety significance and subjected to benign environmental 

conditions may be monitored at an interval exceeding 5 years; however, they should be 

identified and listed together with their operating experience. The GALL Report recommends 

that for plants with non-aggressive groundwater or soil, the acceptability of inaccessible areas 

should be evaluated when conditions exist in accessible areas that could indicate the presence 

of, or result in, degradation to such inaccessible areas. During its audit, the staff found that the 

applicant’s Structures Monitoring Program notes that inspection frequency is every 5 years for 

high-risk significant structures and 10 years for low-risk significant structures, with provisions for 

more frequent inspections to ensure that observed conditions that have the potential to affect

the intended functions are evaluated or corrected in accordance with the corrective action 

process. The LRA AMP basis document also states that for high radiation areas, operationally 

sensitive areas inaccessible due to congestion, portions of structures that are underground or 

underwater, concealed by the presence of other permanent structures, or that cannot be safely 

inspected without an extraordinary expenditure of plant resources do not need to be inspected. 

Furthermore, the reason for not inspecting these structures is to be recorded. The LRA AMP 
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further notes that inspections of inaccessible areas will be performed in environments where 

observed conditions in accessible areas exposed to the same environment indicate significant 

degradation is occurring. The staff is uncertain that the inspection frequency for all structures is 

in compliance with industry standards on inspection frequency (e.g., as noted in ACI 349.3R-96) 

or what conditions in accessible areas will result in inspections of inaccessible areas. By letter 

dated May 3, 2012, the staff issued RAI B.1.42-1 requesting that the applicant: (1) provide 

information to confirm that the inspection frequency criteria identified in the Structures 

Monitoring Program and criteria identified in industry standards (e.g., as noted in 

ACI 349.3R-96) are aligned, or provide justification for not meeting the industry-recommended 

inspection frequency; and (2) provide information to confirm that criteria in the Structures 

Monitoring Program relative to inspection requirements for inaccessible areas and criteria in 

GALL Report AMP XI.S6 are aligned.

In its response dated May 30, 2012, the applicant responded to part (1) of RAI B.1.42-1 by 

stating that ACI 349.3R-96, Chapter 6 states in part that “the frequency at which periodic 

inspections are conducted within the evaluation procedure should be defined by the plant 

owner. Frequencies should be based on the aggressiveness of environmental and physical 

conditions of the plant structures.” The applicant also stated that an enhancement identified in 

LRA Section B.1.42 will require inspections every 5 years for structures and structural 

components within the scope of license renewal unless technical justification is provided to 

extend the inspection interval to 10 years. The applicant further stated that this enhancement 

will ensure that in-scope structures are inspected at least once every 10 years during the period 

of extended operation.

Based on its review, the staff finds additional information is needed to ensure that structures 

and structural components, within the scope of the Structures Monitoring Program, are 

inspected at an inspection frequency consistent with the GALL Report recommendations. It is 

not clear to the staff which structures and structural components are inspected at a frequency of 

10 years and what technical justification (e.g., safety significance, environmental conditions, and 

operating experience) has been used to identify these structures and structural components.

By letter dated July 27, 2012, the staff issued RAI B.1.42-1a asking the applicant to clarify if all 

structures and structural components, within the scope of license renewal, will be inspected 

every 5 years, and if there are structures and structural components that will be inspected at a 

frequency greater than the 5-year interval, to identify and list the structures and structural 

components, and provide technical justification for the inspection frequency.

In its response dated August 23, 2012, the applicant stated that, consistent with 

recommendations in the GALL Report, GGNS structures and structural components within the 

scope of license renewal will be inspected every 5 years during the period of extended 

operation. The applicant further stated that GGNS has not identified any structures or structural 

components within the scope of license renewal that will be inspected at a frequency of less 

than once every 5 years during the period of extended operation.

Based on its review, the staff finds the applicant’s response acceptable because the applicant 

has clarified that inspections will be performed every 5 years for structures and structural 

components within the scope of license renewal. Additionally, the applicant has revised the 

UFSAR supplement and the Structures Monitoring Program enhancement to clarify that the 

inspection frequency is consistent with recommendations in GALL Report AMP XI.S6. The 

staff’s concern described in RAI B2.1.42-1a is resolved.
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In its response dated May 30, 2012, the applicant responded to part (2) of RAI B.1.42-1 by 

stating that the groundwater is non-aggressive (chloride less than 500 ppm, sulfates less than

1,500 ppm, and pH greater than 5.5) and periodic sampling, testing, and analyzing of the 

groundwater will be done at least once every 5 years. The applicant also stated that if normally 

inaccessible areas become accessible due to required plant activities, an inspection of these 

areas will be conducted. The applicant further stated that inspections will be performed of 

inaccessible areas in environments where observed conditions in accessible areas exposed to 

the same environment indicate that significant degradation is occurring that could lead to loss of 

structural integrity.

Based on its review, the staff finds the applicant’s response acceptable because the 

groundwater will be monitored at a frequency not to exceed 5 years, the acceptability of 

inaccessible areas will be evaluated when conditions exist in accessible areas that could 

indicate the presence of, or result in, degradation to such inaccessible areas, and representative 

samples of exposed portions of below-grade concrete will be examined when excavated for any 

reason. These inspection criteria for inaccessible areas, therefore, are consistent with the 

criteria in GALL Report AMP XI.S6. The staff’s concern described in RAI B.1.42-1, part (2), is 

resolved.

The “acceptance criteria” program element in GALL Report AMP XI.S6 recommends 

ACI 349.3R-96 as providing an acceptable basis for developing acceptance criteria for concrete 

structural elements, steel liners, joints, coatings, and waterproofing membranes. It also notes 

that the plant-specific structures monitoring programs are to contain sufficient detail or 

acceptance criteria to conclude that this program attribute is satisfied. However, during its audit, 

the staff found that the applicant’s Structures Monitoring Program noted that it will be enhanced 

to prescribe acceptance criteria considering information provided in industry codes, standards, 

and guidelines, including NEI 93-03, ACI 201.1R-92, ANSI/ASCE 11-99, and ACI 349.3R-96. 

A review of Program Basis Documentation indicated that a yes-no check list is used to provide 

Tier One acceptance criteria corresponding to Section 5.1 of ACI 349.3R-96; however, this 

acceptance criteria does not correspond to the quantitative surface condition criteria for 

cracking, popouts and voids, and spalling provided in ACI 349.3R-96. By letter dated 

May 3, 2012, the staff issued RAI B.1.42-2 requesting the applicant to provide quantitative 

acceptance criteria to demonstrate that acceptance criteria in the Structures Monitoring 

Program meet the Tier One, Tier Two, and Tier Three Criteria recommended by the 

GALL Report AMP, or if not committing to ACI 349.3R-96 and electing to use plant-specific 

criteria, provide a technical basis for deviations from criteria specified in ACI 349.3R-96.

In its response dated May 30, 2012, the applicant stated that the acceptance criteria of the 

Structures Monitoring Program, with enhancements, align with the criteria provided in GALL

Report AMP XI.S6 criteria. The applicant also stated that the Structures Monitoring Program 

recording criteria, identified on specific inspection forms as Yes-No response, align with 

“first-tier” criteria from Section 5.1 of ACI 349.3R-96 with a positive response indicating that the 

findings are within first-tier criteria of ACI 349.3R-96 and thus are “acceptable,” and no further 

action is warranted; however, a no response invokes “second-tier” criteria that use criteria 

provided in Section 5.2 of ACI 349.3R-96. The applicant further stated that if the responsible 

engineer determines that the “second-tier” criteria are exceeded, further technical evaluations 

result, which is consistent with “tier-three” criteria in ACI 349.3R-96.

The staff finds the applicant’s response acceptable because acceptance criteria of the 

Structures Monitoring Program use a three-tier approach that is consistent with that provided in 
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ACI 349.3R-96, and, therefore, is consistent with GALL Report AMP XI.S6 acceptance criteria. 

The staff’s concern described in RAI B.1.42-2 is resolved.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with enhancements to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of these enhancements follows.

Enhancement 1. LRA Section B.1.42 states an enhancement to the “scope of program”

program element. In this enhancement, the applicant stated that: (1) the following in-scope 

structures and structural components will be included in the AMP: GGNS containment building, 

control house-switchyard, culvert No. 1 and drainage channel, manholes and duct banks, and 

radioactive waste building pipe tunnel, as well as a number of other in-scope structural 

components specifically identified in the LRA AMP; (2) “significant degradation” is clarified to 

include the following: “that could lead to loss of structural integrity”; and (3) guidance will be 

included to perform periodic sampling, testing, and analysis of groundwater chemistry for pH, 

chlorides, and sulfates on a frequency of at least every 5 years. The staff reviewed this 

enhancement against the corresponding program element in GALL Report AMP XI.S6 and finds 

it acceptable because when it is implemented, the “scope of program” program element will 

clearly identify all structures, structural components, component supports, and structural 

commodities in the scope of the program; it will clarify the meaning of “significant degradation”; 

and it will include guidance to perform periodic sampling and analysis of groundwater, 

consistent with recommendations in the GALL Report AMP.

Enhancement 2. LRA Section B.1.42 states an enhancement to the “parameters monitored or 

inspected,” program element. In this enhancement, the applicant stated that: (1) inspections 

will be conducted for missing nuts for the structural connections; (2) sliding and bearing 

surfaces such as lubrite plates will be monitored for loss of material due to wear or corrosion, 

debris, or dirt; and (3) elastomeric vibration isolators and structural sealants will be monitored 

for cracking, loss of material, and hardening. The staff reviewed this enhancement against the 

corresponding program element in GALL Report AMP XI.S6 and finds it acceptable because 

when it is implemented, the parameters monitored for these components will be consistent with 

those identified in the GALL Report AMP.

Enhancement 3. LRA Section B.1.42 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that: (1) inspection requirements 

for vibration isolators will include augmented inspections by feel or touch to detect hardening, if 

the vibration isolation function is suspect; and as amended by letter dated August 23, 2012, and 

(2) inspections will be required every 5 years for structures and structural components within the 

scope of license renewal. The staff reviewed this revised enhancement against the 

corresponding program element in GALL Report AMP XI.S6 and finds it acceptable because 

when it is implemented, the “detection of aging effects” program element will be consistent with 

GALL Report AMP XI.S6.

Enhancement 4. LRA Section B.1.42 states an enhancement to the “acceptance criteria”

program element. In this enhancement, the applicant stated that program acceptance criteria 

will be prescribed based on information provided in industry codes, standards, and guidelines,

including NEI 96-03, ACI 201.1R-92, ANSI/ASCE 11-99, and ACI 349.3R-96, and that industry 

and plant-specific operating experience also will be considered in the development of the 

acceptance criteria. The staff reviewed this enhancement against the corresponding program 
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elements in GALL Report AMP XI.S6 and finds it acceptable because when it is implemented 

the acceptance criteria will be consistent with those identified in the GALL Report AMP.

Summary. Based on its audit, and review of the applicant’s responses to RAIs B.1.42-1, 

B.1.42-1a, and B.1.42-2 of the applicant’s Structures Monitoring Program, the staff finds that 

program elements one through six for which the applicant claimed consistency with the GALL 

Report are consistent with the corresponding program elements of GALL Report AMP XI.S6. In 

addition, the staff reviewed the enhancements associated with the “scope of program,” 

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria”

program elements and finds that when implemented, they will make the AMP adequate to 

manage the applicable aging effects.

Operating Experience. LRA Section B.1.42 summarizes operating experience related to the 

Structures Monitoring Program. During a 2007 inspection, Door 1M112 at the SSW valve room 

would not completely open due to vertical settlement in the area. A review of the applicable 

design calculation indicated that vertical settlement was not an issue for the shield wall, 

although it could interfere with the ability to use the door; therefore, an engineering change was 

prepared to allow removal of concrete in the area that the door was rubbing. The applicant also 

described an instance when there was water leaking in the reactor water cleanup (RWCU) heat 

exchanger room from a crack in the ceiling identified in 2007, which previously had been 

identified in 1987. Samples were taken and results indicated that no corrosion was occurring. 

The RWCU heat exchanger room was found to be structurally adequate. The applicant stated 

that these examples illustrating identification of degradation and corrective action before loss of 

intended function provide evidence that the program is effective for managing aging effects for 

structural components.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff identified operating experience for which it 

determined the need for additional clarification and resulted in the issuance of RAIs, as 

discussed below.

During a walkdown of the auxiliary building, a crack was observed in the south stairwell exterior 

concrete wall that was noted to run from about 228 feet elevation to about 166 feet elevation. 

The crack width was on the order of 0.01 inch with some locations along the crack length 

exhibiting chipping. Plant personnel were uncertain whether the crack extended completely 

through the exterior concrete wall and stated that exterior monitoring of the concrete surface 

was done from lower elevations using binoculars. The staff was concerned that the applicant’s 

visual resolution capability used during visual inspections may not be consistent with that 

recommended in Section 3.5, “Evaluation Techniques,” of ACI 349.3R-96, “Evaluation of 

Existing Nuclear Safety-Related Concrete Structures,” which describes that the scope of the 

visual examinations of structures should include all exposed surfaces of the structure; joints and 

joint material; interfacing structures and materials, such as abutting soil; embedments; and 

attached components, such as base plates and anchor bolts; and that these components should 

be directly viewed (maximum 600 mm focal distance), and photographs or video images taken 

of all discontinuities, defects, and significant findings, if possible. Section 3.5 of ACI 349.3R-96 

also notes that direct viewing can require the installation of temporary ladders, platforms, or 

scaffolding and use of binoculars, fiberscopes, and other optical aids is recommended if 
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necessary to gain better access, augment the inspection, or further examine discontinuities. 

Furthermore, such equipment should have suitable resolution capabilities under ambient or 

enhanced lighting. Also, Table IWA-2211-1, “Visual Examinations,” of Section XI of the ASME 

Boiler and Pressure Vessel Code identifies a maximum direct examination distance of 2 feet for 

VT-1 examinations. The staff is uncertain that visual resolution capability is being used during 

visual examinations of structures.

By letter dated May 3, 2012, the staff issued RAI B.1.42-3 requesting that the applicant provide 

information to verify that sufficient visual resolution capability is being used during visual 

examinations of structures to detect and quantify forms of degradation that can potentially affect 

intended functions of the structures.

In its response dated May 30, 2012, the applicant stated that the Structures Monitoring Program 

uses visual inspections to detect and quantify the extent of degradation and requires use of 

appropriate tools such as feeler gages, tape measures, flashlights, cameras, and binoculars 

during the inspections. The applicant also stated that the Structures Monitoring Program will be 

enhanced to: (1) require direct visual examination when observations can be made within 

24 inches of the surface to be examined and at an angle not less than 30 degrees to the 

surface, and may incorporate mirrors to improve the angle of vision and accessibility in 

constricted areas; and (2) specify use of remote visual examination (e.g., optical aids such as 

telescopes, borescopes, fiber optics, cameras, and other suitable instruments) to substitute for 

direct examination, provided such systems have a resolution capability as least equivalent to 

that attainable by direct visual examination.

Based on its review, the staff finds the applicant’s response acceptable because the Structures 

Monitoring Program, after enhancements related to direct and remote visual inspections, will be 

consistent with recommendations provided in industry codes, standards, and guidelines such as 

provided in Section 3.5.1 of ACI 349.3R-96. The staff also confirmed that the applicant through 

Commitment No. 30 will enhance the “detection of aging effects” program element of the 

Structures Monitoring Program to implement these enhancements before November 1, 2024. 

The staff’s concern described in RAI B.1.42-3 is resolved.

During a walkdown of the auxiliary building, water leakage was observed near stair 1T02 

(elevation 93 feet), apparently resulting from groundwater infiltration from ineffective or 

degraded expansion or isolation joints between the turbine building and the auxiliary building. 

It was also noted on several surfaces in this area that rust colored stains were present. Since 

Plant Basis Documentation has identified this as a continuing problem, it is unclear to the staff 

how the Structures Monitoring Program, or other plant-specific aging program, will address the 

leakage to ensure that aging effects, especially in inaccessible areas and plant internal steel 

components exposed to groundwater leakage, will be effectively managed to ensure that there 

is no loss of intended function. By letter dated May 3, 2012, the staff issued RAI B.1.42-4 

requesting that the applicant provide information on how the in-leakage of groundwater will be 

addressed under the CAP.

In its response dated May, 30, 2012, the applicant stated that the in-leakage of groundwater has 

been addressed through the site corrective action process that resulted in implementation of 

corrective actions. Corrective action includes guidance on sealing the locations where 

in-leakage is identified, either in the construction joints or cracks of the structures. As an 

additional protective measure, ground floor slabs have been coated, including attachments, to 

minimize the effects of in-leakage of groundwater on concrete and steel structures. The 

applicant also stated the in-building leakage source, in the stairwell of the turbine building and 
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auxiliary building, was determined to be construction joints where water stop seals may have 

degraded. A condition report was initiated and an evaluation was performed determining that 

the liquid was clear without indication of iron oxides that would be present if corrosion of the 

concrete steel reinforcement was occurring, the cracks were not sufficient to impact the building 

structural integrity, and the area has been sealed against further in-leakage. The applicant 

further stated that monitoring of external SC surfaces during walkdowns to identify degraded 

conditions, such as the water in-leakage noted and the corrective action process will be 

effective in managing aging during the period of extended operations.

The staff finds the applicant’s response acceptable because it was demonstrated that conditions 

such as in-leakage of groundwater, which can lead to SC degradation, will be identified during 

walkdowns (e.g., presence of rust staining on internal plant steel components and presence of 

iron oxides in groundwater indicating degradation of steel reinforcement of inaccessible 

concrete areas) and corrective actions were initiated to seal the area against further in-leakage, 

before loss of intended function(s). The staff’s concern described in RAI B.1.42-4 is resolved.

During the breakout session for the Structures Monitoring Program, the staff asked: (1) if 

historical data on leakage of the spent fuel pool are available; (2) if leakage is present, is the 

leakage confined to the leak-chase system; and (3) if leakage is not present, is the leak-chase 

system routinely inspected to verify that it is clear. This information was not available during the 

breakout session, so the staff is uncertain if leakage of the spent fuel pool is occurring, and if 

leakage is present, that it is being confined to the leak-chase system.

By letter dated May 3, 2012, the staff issued RAI B.1.42-5 requesting that the applicant provide: 

(1) historical data on spent fuel pool leakage obtained by monitoring the leak-chase system and 

note whether or not the leakage is confined to the leak-chase system; (2) if the leakage is not 

confined to the leak-chase system, identify any structures or structural components potentially 

affected and any plans to address the leakage; and (3) if no leakage has been reported, provide 

inspection results, or plans for inspection of the leak-chase system, to demonstrate that the 

leak-chase system is not blocked.

In its response dated May 30, 2012, the applicant stated that leakage from the upper 

containment pool is monitored daily and from the spent fuel pool weekly, with two incidences of 

leakage from the upper containment pool noted that have been contained in the leak chase 

system and therefore have not affected structures. The applicant also noted that leakage from 

the pools will be monitored periodically during the period of extended operation with trending 

and leakage through the tell-tale drains used as an indicator that drainage through the leak 

chase is occurring and that the tell-tale drains are not blocked and are performing as designed. 

The applicant further noted in order to confirm that no significant blockage of the tell-tale drains 

has occurred, the Structures Monitoring Program will be enhanced to periodically inspect the 

leak chase system associated with the upper containment pool and spent fuel pool, and 

concrete surfaces will be inspected for degradation where leakage has been observed.

The staff finds the applicant’s response acceptable because the leakage from the upper 

containment pool has been identified and noted to be confined to the leak-chase system and 

there is no evidence that it has affected other structures or components, upper containment pool 

and spent fuel pool leakage is periodically monitored, and the Structures Monitoring Program 

will be enhanced to periodically inspect the leak-chase system associated with the upper 

containment pool and spent fuel pool to ensure the tell-tale drains are free of significant 

blockage. The staff also confirmed that the applicant, through Commitment No. 30, will 

enhance the “parameters monitored or inspected” program element of the Structures Monitoring 
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Program to implement the enhancement before November 1, 2024. The staff’s concern 

described in RAI B.1.42-5 is resolved.

Based on its audit and review of the application, and review of the applicant’s responses to 

RAIs B.1.42-3, B.1.42-4, and B.1.42-5, the staff finds that the applicant has appropriately 

evaluated plant-specific and industry operating experience and implementation of the program 

has resulted in the applicant taking corrective actions. In addition, the staff finds that the 

conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.42 provides the UFSAR supplement for the Structures 

Monitoring Program. The staff reviewed this UFSAR supplement description of the program 

and noted that it is consistent with the recommended description in SRP-LR Table 3.0-1. The 

staff also noted that the applicant committed (Commitment No. 30) to enhance the Structures 

Monitoring Program prior to May 1, 2024, to:

• clarify the in-scope structures and structural components

• clarify the term “significant degradation” to include the following: “that could lead to loss 

of structural integrity”

• include guidance to perform periodic sampling and analysis of groundwater chemistry for 

pH, chlorides, and sulfates on a frequency of at least once every 5 years

• include an inspection for missing nuts for the structural connections

• include monitoring of sliding and bearing surfaces, such as lubrite plates, for loss of 

material due to wear or corrosion, debris, or dirt. The program will be enhanced to 

include monitoring elastomeric vibration isolators and structural sealants for cracking, 

loss of material, and hardening

• include periodically inspecting the leak-chase system associated with the upper 

containment pool and spent fuel pool to ensure the tell-tale drains are free of significant 

blockage. The inspection will also inspect concrete surfaces for degradation where 

leakage has been observed in accordance with this program

• inspection requirements for vibration isolators will be enhanced to include augmented 

inspections by feel or touch to detect hardening, if the vibration isolation function is 

suspect

• require inspections every 5 years for structures and structural components within the 

scope of license renewal

• require direct visual examinations when access is sufficient for the eye to be within 

24 inches of the surface to be examined and at an angle of not less than 30 degrees to 

the surface. Mirrors may be used to improve the angle of vision and accessibility in 

constricted areas.

• specify that remote visual examination may be substituted for direct examination. For all 

remote visual examinations, optical aids such as telescopes, borescopes, fiber optics, 

cameras, or other suitable instruments may be used provided such systems have a 

resolution capability at least equivalent to that attainable by direct visual examination

• prescribe acceptance criteria based on information provided in industry codes, 

standards, and guidelines, including NEI 96-03, ACI 201.1R-92, ANSI/ASCE 11-99, and 

ACI 349.3R-96. Industry and plant-specific operating experience will also be considered 

in the development of the acceptance criteria
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The staff finds that the information in the UFSAR supplement, as amended by letters dated 

July 3, 2012, and August 23, 2012, and is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Structures Monitoring 

Program, the staff determines that those program elements for which the applicant claimed 

consistency with the GALL Report are consistent. Also, the staff reviewed the enhancements 

and confirmed that their implementation prior to the period of extended operation will make the 

AMP adequate to manage the applicable aging effects. 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).

3.0.3.1.41 Water Chemistry Control – BWR

Summary of Technical Information in the Application. LRA Section B.1.43 describes the 

existing Water Chemistry Control – BWR Program as consistent with GALL Report AMP XI.M2, 

“Water Chemistry.” The LRA states that this program uses the EPRI water chemistry guidelines 

to manage loss of material, cracking, and fouling by monitoring and controlling water chemistry. 

The LRA also states that the One-Time Inspection Program verifies the effectiveness of the 

Water Chemistry Control – BWR Program through inspections or non-destructive evaluations of 

representative samples.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP Xl.M2. For the “parameters 

monitored or inspected” program element, the staff determined the need for additional 

information, which resulted in the issuance of an RAI, as discussed below.

The “parameters monitored or inspected” program element in GALL Report AMP XI.M2 

recommends maintaining water quality in accordance with the EPRI water chemistry guidelines, 

which for BWRs is EPRI 1016579, BWRVIP-190. However, during the audit, the staff noted that 

the applicant’s controlling procedure 01-S-08-29, “EPRI Water Chemistry Guidelines,” does not 

specify the parameter for electrochemical corrosion potential (ECP) as contained in 

BWRVIP-190, Table 6-5, for reactor water power operation with hydrogen water chemistry 

(HWC). In addition, the applicant’s procedure 08-S-03-10, “Chemistry Sampling Program,”

specifies a control limit for zinc, which is consistent with BWRVIP-190 for noble metal chemical 

application (NMCA), but the LRA did not indicate that GGNS was using NMCA. The staff also 

noted that BWRVIP-190 states that the basis for inspection relief for BWR internals based 

strictly on environmental considerations is documented in BWRVIP-62, “Technical Basis for 

Inspection Relief for BWR Internal Components with Hydrogen Injection.” However, the staff 

could not confirm whether the applicant has met all of the conditions in the staff’s SE of 

BWRVIP-62. By letter dated April 26, 2012, the staff issued RAI B.1.43-1, requesting the 

applicant to confirm the method of controlling HWC in the RV, and to confirm whether NMCA 

plus hydrogen is being used. The staff also requested that the applicant confirm whether all of 

the conditions in the staff’s SE for BWRVIP-62 are met and to provide the method of 

determining the effectiveness of HWC at the site.

In its response dated May 25, 2012, the applicant stated that HWC is controlled using FW 

hydrogen injection in conjunction with online NMCA. The applicant also stated that continuous 
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ECP monitoring will be installed during the spring 2012 outage, which will meet the 

recommendations of BWRVIP-62, Revision 1. The applicant further stated that the 

effectiveness of HWC is determined through: (a) monitoring ECP, (b) monitoring FW hydrogen 

flow, (c) maintaining the hydrogen-to-oxygen molar ratio greater than or equal to 2 in 

non-monitored locations when determined by the BWR Vessel and Internals Application 

radiolysis model, and (d) removing an artifact from the reactor core to measure platinum 

loading. The applicant also stated that BWRVIP-62, Revision 1, does not require platinum 

deposition measurements on coupons for plants using online noble metals chemistry to 

demonstrate mitigation.

The staff finds the applicant’s response partially acceptable because the applicant clarified that 

it uses online NMCA and FW hydrogen injection to control HWC, and that, pending confirmation 

that the ECP probes were installed and except as noted below, it confirms the effectiveness of 

HWC consistent with the EPRI water chemistry guidelines and meets the recommendations in 

BWRVIP-62. However, the staff noted that BWRVIP-62, Revision 1, has not been reviewed by 

the NRC, and that there are differences between this revision and the previous revision 

regarding verification of noble metal loading. Specifically, the revision that the staff accepted 

states that noble metal (platinum) loading shall be monitored by periodic removal of durability 

monitors or by removal and analysis of deposits from artifacts within the vessel. In addition, 

BWRVIP-190, Table 2-5, states that the catalyst loading (platinum deposition) is one of the two 

primary parameters to be monitored to demonstrate HWC effectiveness. In its response to

RAI B.1.43-1, the applicant stated that it had removed an artifact to measure platinum loading; 

however, the applicant also stated that BWRVIP-62, Revision 1, does not require deposition 

measurements. It is not clear to the staff whether the applicant will continue to monitor noble 

metal loading during the period of extended operation or whether continuous ECP monitoring 

has been installed. By letter dated August 15, 2012, the staff issued RAI B.1.43-1a requesting 

the applicant to confirm that it will continue to monitor catalyst loading as specified by 

BWRVIP-190 or to provide justification otherwise. The staff also requested that the applicant 

confirm that continuous ECP monitoring had been installed.

In its response dated September 13, 2012, the applicant stated that it completed the installation 

of the equipment for continuous ECP monitoring during the spring 2012 refueling outage. The 

applicant also stated that noble metal loading will be monitored using periodic removal of 

durability monitor coupons, during the period of extended operation. The staff finds the 

response acceptable because the applicant has installed continuous ECP monitoring and will 

monitor catalyst loading as specified by BWRVIP-190, which ensures that water chemistry 

parameters are being maintained to mitigate applicable aging effects consistent with the EPRI 

water chemistry guidelines recommended in GALL Report AMP XI.M2. The staff’s concerns 

described in RAI B.1.43-1a are resolved.

Based on its audit of the applicant’s Water Chemistry Control – BWR Program and review of the 

applicant’s response to RAI B.1 43-1, the staff finds that program elements for which the 

applicant claimed consistency with the GALL Report are consistent with the corresponding 

program elements of GALL Report AMP XI.M2.

Operating Experience. LRA Section B.1.43 summarizes operating experience related to the 

Water Chemistry Control – BWR Program. The LRA discusses an evaluation required by 

SOER 03-02, which upgraded and confirmed the effectiveness of the water chemistry program. 

The LRA also described the condition reports that were initiated due to adverse trends in water 

chemistry parameters and the corrective actions taken to prevent the parameters from reaching 

unacceptable values. In addition, the LRA discusses the addition of an advanced resin cleaning 
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system for the condensate resins and the management of condensate temperatures in cold 

weather to improve iron removal. The LRA states that the identification of program 

enhancements and corrective actions provides assurance that the program will remain effective 

for managing aging effects.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program. During its review, the staff found no operating experience to indicate that the 

applicant’s program would not be effective in adequately managing aging effects during the 

period of extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.43 provides the UFSAR supplement for the Water 

Chemistry Control – BWR Program. The staff reviewed this UFSAR supplement description of 

the program against the recommended description for this type of program as described in 

SRP-LR Table 3.0-1 and noted that, although the supplement stated that the program is based 

on EPRI water chemistry guidelines, it did not state that the program is based on BWRVIP-190. 

The staff determined that the licensing basis for this program may not be adequate if the 

applicant does not incorporate this information into its UFSAR supplement. By letter dated 

April 26, 2012, the staff issued RAI B.1.43-2 requesting the applicant to provide information 

showing that a reference to the specific EPRI water chemistry guideline was not required or to 

revise Section A.1.43 to refer to a specific version of the EPRI water chemistry guideline.

In its response dated May 25, 2012, the applicant revised LRA Section A.1.43 to include 

reference to BWRVIP-190. The staff finds the applicant’s response acceptable because the 

applicant has revised the UFSAR supplement to include the specific EPRI guideline upon which 

the program is based. Therefore, the UFSAR supplement for the Water Chemistry Program is 

consistent with the corresponding program description in SRP-LR Table 3.0-1. The staff’s 

concern described in RAI B.1.43-2 is resolved.

The staff finds that the information in the UFSAR supplement, as amended by letter dated 

May 25, 2012, is an adequate summary description of the program.

Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Control –

BWR Program, the staff determines that the program elements for which the applicant claimed 

consistency with the GALL Report are consistent with the corresponding program elements of 

GALL Report AMP XI.M2. The staff also 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 reviewed the UFSAR supplement for this AMP and further 

concludes that it provides an adequate summary description of the program, as required by 

10 CFR 54.21(d).
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3.0.3.1.42 Water Chemistry Control – Closed Treated Water Systems

Summary of Technical Information in the Application. LRA Section B.1.44 describes the 

existing Water Chemistry Control – Closed Treated Water Systems Program as consistent, with 

enhancements, with GALL Report AMP XI.M21A, “Closed Treated Water Systems.” The LRA 

states that the AMP manages loss of material, cracking, and fouling in components exposed to 

a treated water environment. The LRA also states that the AMP proposes to manage these 

aging effects through monitoring and control of water chemistry as well as visual inspections.

Staff Evaluation. During its audit, the staff reviewed the applicant’s claim of consistency with the 

GALL Report. The staff compared program elements one through six of the applicant’s program 

to the corresponding program elements of GALL Report AMP XI.M21A. For the “scope of 

program,” “parameters monitored or inspected,” and “detection of aging effects” program 

elements, the staff determined the need for additional information, which resulted in the 

issuance of RAIs, as discussed below.

The “scope of program” program element in GALL Report AMP XI.M21A recommends that this 

program manages aging effects of components fabricated from any material and exposed to 

treated water, but the program does not include systems managed by another AMP. During its 

audit, the staff found that the applicant’s documentation for its GL 89-13 Service Water Integrity 

Program stated that the GL 89-13 program is also applied to closed cooling loops, due to the 

potential for in-leakage, inadequate chemistry controls, or aging that may have occurred before 

current chemistry controls became active. The staff noted that GL 89-13 program activities 

were not included in documentation of the applicant’s Water Chemistry Control – Closed 

Treated Water Systems Program. By letter dated April 26, 2012, the staff issued RAI B.1.44-3 

requesting that the applicant state what aging management activities associated with the 

applicant’s GL 89-13 Service Water Integrity Program are applied to systems managed by the 

Water Chemistry – Closed Treated Water Systems Program and what, if any, operating 

experience prompted the use of the GL 89-13 program activities for closed cooling loops.

In its response dated May 25, 2012, the applicant stated that there are no systems at GGNS 

that are part of the service water system that meet the GL 89-13 definition of a closed-cycle 

system, and thus no activities associated with the Service Water Integrity Program are applied 

to any closed-cycle treated water cooling systems. The applicant also stated that the reference 

to closed-loop cooling systems is included in the Entergy fleet GL 89-13 Service Water Program 

document since they may be present at other Entergy facilities.

The staff finds the applicant’s response acceptable because the applicant clarified that the 

scope of the Water Chemistry Control – Closed Treated Water Systems Program is fully defined 

in the LRA and the applicant’s onsite documentation of this program, and there are no 

applicable activities associated with the applicant’s GL 89-13 Service Water Program. The 

staff’s concern described in RAI B.1.44-3 is resolved.

The “parameters monitored or inspected” program element in GALL Report AMP XI.M21A 

recommends that the acceptable range of water chemistry parameters be in accordance with 

industry standard guidance, such as those described in EPRI Technical Report 1007820. 

However, during its audit, the staff was not able to confirm that the applicant’s Water Chemistry 

Control – Closed Treated Water Systems Program maintains water chemistry in closed treated 

water systems in accordance with EPRI guidelines. The staff noted that deviations in the 

applicant’s program from EPRI guidelines included missing control limits and control limits with 

undefined action levels. By letter dated April 26, 2012, the staff issued RAI B.1.44-1 requesting 
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that the applicant provide an enhancement to the Water Chemistry Control – Closed Treated 

Water Systems Program to align the plant’s water chemistry controls with the EPRI guidance or 

justify that the deviations will not adversely affect corrosion mitigation.

In its response dated May 25, 2012, the applicant revised LRA Sections A.1.44 and B.1.44 to 

include an enhancement to align the water chemistry control parameter limits for closed treated 

water systems with those of EPRI 1007820.

The staff finds the applicant’s response acceptable because the applicant’s enhancement to the 

Water Chemistry Control – Closed Treated Water Systems Program will maintain water 

chemistry consistent with the industry standard guidance in EPRI Technical Report 1007820, 

which is consistent with GALL Report guidance and provides assurance that corrosion will be 

effectively mitigated during the period of extended operation. The staff’s concern described in

RAI B.1.44-1 is resolved.

The staff also reviewed the portions of the “scope of program,” “preventive actions,” “parameters 

monitored or inspected,” “detection of aging effects,” and “acceptance criteria” program 

elements associated with enhancements to determine whether the program will be adequate to 

manage the aging effects for which it is credited. The staff’s evaluation of these enhancements 

follows.

Enhancement 1. LRA Section B.1.44 states an enhancement to the “scope of program” and 

“preventive actions” program elements. In this enhancement, the applicant stated that the 

program will be enhanced to provide a corrosion inhibitor for the engine jacket water on the 

engine-driven fire water pump diesels in accordance with industry guidelines and vendor 

recommendations. The staff reviewed this enhancement against the corresponding program 

elements in GALL Report AMP XI.M21A and finds it acceptable because the addition of 

corrosion inhibitors is consistent with the “preventive actions” program element of GALL Report

AMP XI.M21A and, when the enhancement is implemented, the corrosion inhibitor will be 

capable of mitigating loss of material due to corrosion such that the function of the jacket water 

system is maintained.

Enhancement 2. LRA Section B.1.44 states an enhancement to the “parameters monitored or 

inspected” program element. In this enhancement, the applicant stated that the program will be 

enhanced to provide periodic flushing of the engine jacket water and cleaning of the heat

exchanger tubes for the engine-driven fire water pump diesels in accordance with industry 

guidelines and vendor recommendations. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M21A and finds it acceptable 

because, although GALL Report AMP XI.M21A does not specify flushing and cleaning of closed 

cooling systems, these activities, in addition to water chemistry monitoring, are capable of 

ensuring that the jacket water chemistry remains within specifications for cooling and corrosion 

control and heat transfer properties are maintained.

Enhancement 3. LRA Section B.1.44 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to provide testing of the engine jacket water for the engine-driven fire water pump diesels at 

least once per refueling cycle. However, the staff noted that GALL Report AMP XI.M21A 

recommends that water testing intervals should be in accordance with the selected industry 

standard, but in no case should the testing interval be greater than quarterly, unless justified. 

The staff also noted that the guidelines in EPRI Technical Report 1007820 state that water 

chemistry monitoring of intermittently used closed cooling systems be performed monthly or as 
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operated. EPRI Report 1007820 has an exception for glycol-based systems, in which case the 

recommended testing interval is quarterly (Tier 1 systems) or annually (Tier 2 systems). By 

letter dated April 26, 2012, the staff issued RAI B.1.44-2 requesting that the applicant justify why 

testing of the jacket water once per refueling cycle is adequate to ensure that the ability of the 

water chemistry to mitigate corrosion will be maintained or to revise the testing frequency to be 

consistent with the EPRI guidelines.

In its response dated May 25, 2012, the applicant revised LRA Sections A.1.44 and B.1.44 to 

state that the fire water pump diesel jacket water will be tested annually, consistent with 

EPRI 1007820 guidelines.

The staff finds the applicant’s response acceptable because the annual testing of the engine 

jacket water for the fire water pump diesels is consistent with the GALL Report and EPRI 

guidelines for intermittently used glycol-based Tier 2 closed cooling water systems, which 

provides assurance that corrosion will be effectively mitigated during the period of extended 

operation. The staff noted that the glycol chemistry of the engine jacket water was confirmed 

during the staff’s audit of the Water Chemistry Control – Closed Treated Water Systems 

Program. The staff’s concern described in RAI B.1.44-2 is resolved.

Enhancement 4. LRA Section B.1.44, as revised by the applicant’s response to RAI B.1.44-1 

dated May 25, 2012, states an enhancement to the “parameters monitored or inspected” and 

“acceptance criteria” program elements. In this enhancement, the applicant stated that the 

program will be enhanced to revise the water chemistry procedure for closed treated water 

systems to align the water chemistry control parameter limits with those of EPRI 1007820. The 

staff reviewed this enhancement against the corresponding program elements in GALL Report

AMP XI.M21A and finds it acceptable because, when it is implemented, it will ensure that the 

specific water chemistry parameters monitored and the acceptance range of values for these 

parameters will be in accordance with EPRI Technical Report 1007820, which is consistent with 

the GALL Report guidance for effective mitigation of loss of material, cracking, and fouling.

Enhancement 5. LRA Section B.1.44 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to conduct inspections whenever a boundary is opened for the systems managed by the Water 

Chemistry Control – Closed Treated Water Systems Program. The applicant also stated that 

the inspections will be conducted in accordance with applicable ASME codes, industry 

standards, and plant-specific inspection procedures that are capable of detecting corrosion or 

cracking. The staff reviewed this enhancement against the corresponding program elements in 

GALL Report AMP XI.M21A and finds it acceptable because, when it is implemented, the 

opportunistic inspections, along with the 10-year inspection periodicity documented below in 

Enhancement 6, will be capable of detecting degradation prior to loss of intended function, 

consistent with the “detection of aging effects” program element of GALL Report AMP XI.M21A.

Enhancement 6. LRA Section B.1.44 states an enhancement to the “detection of aging effects”

program element. In this enhancement, the applicant stated that the program will be enhanced 

to conduct inspections on a representative sample of piping and components at a frequency of 

once every 10 years for the systems managed by the Water Chemistry Control – Closed 

Treated Water Systems Program. The applicant also stated that the inspection sample will be 

20 percent of each material/environment/aging effect combination (with a maximum of 

25 components) and will focus on locations with the highest likelihood of corrosion or cracking. 

The applicant further stated that the inspections will be conducted in accordance with applicable 

ASME Codes, industry standards, and plant-specific inspection procedures that are capable of 
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detecting corrosion or cracking. The staff reviewed this enhancement against the 

corresponding program elements in GALL Report AMP XI.M21A and finds it acceptable 

because the inspections described here, in addition to the opportunistic inspections described 

above in Enhancement 5, will be capable of detecting degradation prior to loss of intended 

function, consistent with the “detection of aging effects” program element of GALL Report

AMP XI.M21A.

Summary. Based on its audit, and review of the applicant’s responses to RAIs B.1.44-1, 

B.1.44-2, and B.1.44-3 of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program, the staff finds that program elements one through six for which the applicant 

claimed consistency with the GALL Report are consistent with the corresponding program 

elements of GALL Report AMP XI.M21A. In addition, the staff reviewed the enhancements 

associated with “scope of program,” “preventive actions,” “parameters monitored or inspected,”

and “detection of aging effects” program elements and finds that when implemented, they will 

make the AMP adequate to manage the applicable aging effects.

Operating Experience. LRA Section B.1.44 summarizes operating experience related to the 

Water Chemistry Control – Closed Treated Water Systems Program. The applicant stated that, 

from 2008 to 2010, several condition reports were initiated due to adverse trends in parameters 

monitored by the program and that timely corrective actions were taken to preclude reaching 

unacceptable values. As discussed in the AMP Audit Report, the staff reviewed several of 

these condition reports related to the maintenance of water chemistry to confirm this information 

in the LRA.

The staff reviewed operating experience information in the application and during the audit to 

determine whether the applicable aging effects and industry and plant-specific operating 

experience were reviewed by the applicant. As discussed in the AMP Audit Report, the staff 

conducted an independent search of the plant operating experience information to determine 

whether the applicant had adequately evaluated and incorporated operating experience related 

to this program.

During its review, the staff found no operating experience to indicate that the applicant’s 

program would not be effective in adequately managing aging effects during the period of 

extended operation.

Based on its audit and review of the application, the staff finds that the applicant has 

appropriately evaluated plant-specific and industry operating experience and implementation of 

the program has resulted in the applicant taking corrective actions. In addition, the staff finds 

that the conditions and operating experience at the plant are bounded by those for which the 

corresponding GALL Report AMP was evaluated.

UFSAR Supplement. LRA Section A.1.44 provides the UFSAR supplement for the Water 

Chemistry Control – Closed Treated Water Systems Program. The staff reviewed this UFSAR 

supplement description of the program and noted that it is consistent with the recommended 

description in SRP-LR Table 3.0-1. The staff also noted that the applicant committed 

(Commitment No. 31) to implement the enhancements to the program prior to the period of 

extended operation.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.
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Conclusion. On the basis of its audit and review of the applicant’s Water Chemistry Control –

Closed Treated Water Systems Program, the staff determines that those program elements for 

which the applicant claimed consistency with the GALL Report are consistent. Also, the staff 

reviewed the enhancements and confirmed that their implementation through Commitment 

No. 31 prior to the period of extended operation will make the AMP adequate to manage the 

applicable aging effects. 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 AMPs Not Consistent with or Not Addressed in the GALL Report

In LRA Appendix B, the applicant identified the following AMPs as plant-specific:

• 115 kV Inaccessible Transmission Cable

• Periodic Surveillance and Preventive Maintenance

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.

3.0.3.2.1 115 kV Inaccessible Transmission Cable

Summary of Technical Information in the Application. LRA Section B.1.1 describes the new 

115 kV Inaccessible Transmission Cable Program as plant specific. The applicant stated that 

the 115 kV Inaccessible Transmission Cable Program is a new condition monitoring program 

that will manage the effects of aging on the 115 kV inaccessible transmission cables. In this 

program, inaccessible transmission cables will be tested to provide an indication of the condition 

of the cable insulation properties. The specific type of test will be a proven test for detecting 

deterioration of the cable insulation. The applicant also stated that this program will be 

implemented before the period of extended operation, and the first cable tests and manhole 

inspections are to be completed prior to the period of extended operation.

Staff Evaluation. The staff reviewed program elements one through six of the applicant’s 

program against the acceptance criteria for the corresponding elements as stated in SRP-LR 

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 

each of these elements follows. The staff’s review of the “corrective actions,” “confirmation 

process,” and “administrative controls” program elements are documented in SER 

Section 3.0.4.

Scope of Program. LRA Section B.1.1 states that this program applies to inaccessible 

underground (e.g., in conduit, duct banks, or direct buried) transmission cables (115 kV) within 

the scope of license renewal that are exposed to significant moisture. The LRA defines 

significant moisture as periodic exposure to moisture that lasts more than a few days 

(e.g., cable wetting or submergence in water). The following cables are included in the scope of 

this program:
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• ESF 12 Feeder - 115 kV Switchyard to Overhead Power Pole: Phases A, B, & C 

(2 cables per phase)

The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which states that the scope of program should include the specific 

SCs, the aging of which the program manages. The staff noted that the specific commodity 

groups for which the program manages aging effects are identified (ESF 12 feeder – 115 kV

switchyard to overhead power poles: phases A, B, and C), which satisfies the criterion defined 

in SRP-LR Appendix A.1.2.3.1.

The staff finds the applicant’s “scope of program” program element to be adequate because the 

specific SCs for which the program manages aging effects are identified.

Based on its review of the application, the staff confirmed that the “scope of program” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.1 and, therefore, the staff finds 

it acceptable.

Preventive Actions. LRA Section B.1.1 states that this program will take periodic actions to 

prevent cables from being exposed to significant moisture by inspecting for water collection in 

cable manholes and removing water, as needed. The inspection frequency for manholes will be 

established and performed based on plant-specific operating experience with cable wetting or 

submergence in manholes. Condition-based inspections of manholes not automatically 

dewatered by a sump pump will be performed based on (a) the potential for high water table 

conditions and (b) the occurrence of periods of heavy rain. In addition, operation of dewatering 

devices, if applicable, will be inspected and operation confirmed before any known or predicted 

heavy rain or flooding events. The applicant also stated that the periodic inspection will occur at 

least annually. The manhole inspections will include direct observation that cables are not 

wetted or submerged, that cables/splices and cable support structures are intact, and 

verification that dewatering/drainage systems (i.e., sump pumps) and associated alarms, if 

applicable, operate properly. If water is found during inspection (i.e., cable exposed to 

significant moisture), corrective actions are taken to keep the cable dry and to assess cable 

degradation. The first inspection for license renewal is completed before the period of extended 

operation.

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 the activities for preventing and mitigating should 

be described. These actions should mitigate or prevent aging degradation. The staff noted that 

inspecting for water collection in cable manholes and removing water will prevent cables from 

being exposed to wetting or submergence. These actions are necessary to minimize the 

potential for cable insulation degradation. The staff finds the applicant’s “preventive actions”

program element to be adequate because specific prevention activities are stated in this new 

condition monitoring program.

Based on its review of the application, the staff confirmed that the “preventive actions” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds 

it acceptable.

Parameters Monitored or Inspected. LRA Section B.1.1 states that inspection for water 

collection in manholes will be performed based on plant-specific operating experience with 

water accumulation in the manhole, with the inspections to occur at least annually. In-scope 

transmission cables (115 kV) exposed to significant moisture will be tested to provide an 
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indication of the condition of the conductor insulation. The specific type of test performed will be 

determined before the initial test. The test will be proven tests for detecting deterioration of the 

insulation system because of wetting or submergence, such as dielectric loss (dissipation 

factor/power factor), AC voltage withstand partial discharge, step voltage, time domain 

reflectometry, insulation resistance and polarization index, line resonance analysis, or other 

testing that is state-of-the-art at the time the test is performed.

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 this program element should 

identify the aging effects that the program manages and should provide a link between the 

parameter or parameters that will be monitored and how the monitoring of these parameters will 

ensure adequate aging management. For a condition monitoring program, the parameter 

monitored or inspected should be capable of detecting the presence and extent of aging effects.

The staff noted that long-term wetting of inaccessible transmission cables can cause 

water-related degradation of cable insulation. The staff noted that performing inspection for 

water collection in manholes is acceptable to prevent cables from being exposed to significant 

moisture, defined as periodic exposures to moisture that lasts more than few days (e.g., cable 

wetting or submergence in water). The staff also noted that the frequency of manhole 

inspection based on plant-specific operating experience with water accumulation in the 

manholes, or at least annually, is acceptable because due to the relatively slow rate of 

propagation for water to permeate the insulation material, the effect of exposure to moisture 

may take several years to manifest itself.

The staff also noted that inspection for water accumulation in the manholes is taken to prevent 

cables from being exposed to significant moisture. However, this action is not sufficient to 

ensure that water is not trapped elsewhere in the raceways. The inspection for water 

accumulation in manholes is necessary to minimize the potential for insulation degradation. In 

addition to the inspection, in-scope cables exposed to significant moisture are tested to indicate 

the condition of the conductor insulation.

The staff finds the applicant’s “parameters monitored or inspected” program element to be 

adequate because the tests proposed by the applicant are acceptable to assess the condition of 

conductor insulation because those tests are industry standard tests and will ensure the 

component’s intended function during the period of extended operation.

Based on its review of the application, the staff confirmed that the “parameters monitored or 

inspected” program element satisfies the criterion defined in SRP-LR Section A.1.2.3.3 and, 

therefore, the staff finds it acceptable.

Detection of Aging Effects. LRA Section B.1.1 states that testing will be performed at least once 

every 6 years, with the first tests for license renewal occurring before the period of extended 

operation. For transmission cables exposed to significant moisture, test frequencies may be 

adjusted based on test results (including trending of degradation where applicable) and 

operating experience. The applicant also stated that the condition of the cable insulation will be 

assessed with reasonable confidence using tests such as dielectric loss (dissipation 

factor/power factor), AC voltage withstand, partial discharge, step voltage, time domain 

reflectometry, insulation resistance and polarization index, line resonance analysis, or other 

testing that is state-of-the-art at the time the tests are performed. The applicant also stated that 

the test used to determine the condition of the cable insulation will ensure that the cables 

continue to meet their intended function during the period of extended operation.
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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 the parameters to be monitored or 

inspected should be appropriate to ensure that the intended function(s) of the SCs will be 

adequately maintained for license renewal under all CLB design conditions. This includes 

aspects such as method or technique (e.g., visual, volumetric, surface inspection), frequency 

and timing of inspection to ensure timely detection of aging effects. In addition, it states that the 

method or technique and frequency may be linked to plant-specific or industry-wide operating 

experience.

The staff noted that testing frequency based on the test results and operating experience or at 

least once every 6 years is acceptable for assessing the condition of cable insulation materials 

because the proposed test frequency is consistent with GALL Report AMP XI.E3, “Inaccessible 

Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification 

Requirements.” Furthermore, SAND 96-0344, Aging Management Guideline for Commercial 

Nuclear Plants – Electrical Cable and Terminations (September 1996), reiterates that due to the 

relatively slow rate of propagation for water to ingest into cable material, the effect of exposure 

to moisture may take several years. The staff finds the applicant’s “detection of aging effects”

program element to be adequate because the tests proposed by the applicant are acceptable to 

assess the condition of conductor insulation because those tests are industry standard tests and 

will ensure the component’s intended function during the period of extended operation.

Based on its review of the application, the staff confirmed that the “detection of aging effects”

program element satisfies the criterion defined in SRP-LR Section A.1.2.3.4 and, therefore, the 

staff finds it acceptable.

Monitoring and Trending. LRA Section B.1.1 states that trending will be used as part of this 

program based on the ability of trending the test results for the specific test chosen. Since the 

ability to trend test results will depend on the specific type of test chosen, only results that can 

be trended will be used to provide additional information on the rate of cable insulation 

degradation.

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 affect 

timely corrective or mitigative actions. This program element describes how the data collected 

are evaluated and may also include trending for a forward look. The parameter or indicator 

trended should be described.

The staff finds the applicant’s “monitoring and trending” program element to be adequate 

because trending based on the ability of trending the test results for the specific test chosen is 

acceptable. Since the ability to trend test results will depend on the specific type of test chosen, 

only results that can be trended will be used to provide additional information on the rate of 

cable insulation degradation. The results will be trended from testing to testing and will provide 

a basis for timely corrective actions before a loss of intended functions.

Based on its review of the application, the staff confirmed that the “monitoring and trending”

program element satisfies the criterion defined in SRP-LR Section A.1.2.3.5 and, therefore, the 

staff finds it acceptable.

Acceptance Criteria. LRA Section B.1.1 states that the acceptance criteria for each test will be 

defined by the type of test performed and the specific cable tested. Acceptance criteria for 
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inspections of manholes are defined by the observation that the cables and support structures 

are not submerged or immersed in standing water at the time of the inspection.

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 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.

The staff finds the applicant’s “acceptance criteria” program element to be adequate because 

the applicant described acceptance criteria for inspection of manholes (e.g., observation that 

cables and support structures are not submerged or immersed in standing water at the time of 

inspection). The staff also finds that it is acceptable to define the acceptance criteria for each 

test by the type of test performed and the specific cable tested because the acceptance criteria 

will be evaluated depending on the specific cable tested, to ensure that high-voltage

transmission cable-intended function(s) are maintained during under all CLB design conditions 

during the period of extended operation.

Based on its review of the application, the staff confirmed that the “acceptance criteria” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.6 and, therefore, the staff finds 

it acceptable.

Corrective Actions. LRA Section B.1.1 states that an engineering evaluation will be performed 

when the test acceptance criteria are not met to be sure that the intended functions of the 

electrical cables can be maintained consistent with the CLB. When an acceptable condition or 

situation is identified, a determination is made as to whether the same condition or situation is 

applicable to other in-scope transmission cables. Corrective actions may include, but are not 

limited to, installation of permanent drainage systems, installation of sump pumps and alarms, 

more frequent cable testing or manhole inspections, or replacement of the affected cable. 

When an acceptable condition or situation is identified, the requirements of 10 CFR Part 50, 

Appendix B, will be used to address corrective actions.

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 the actions to be taken when the acceptance 

criteria are not met should be described in appropriate detail or referenced to source 

documents. Corrective actions, including root cause determination and prevention of 

recurrence, should be timely.

The applicant requires corrective actions when the test acceptance criteria are not met. 

However, the applicant did not specifically require corrective actions when inspection 

acceptance criteria are not met to ensure that the intended functions of the electrical cables can 

be maintained consistent with the CLB. When the inspection acceptance criteria are not met, 

the applicant is not required to perform an engineering evaluation to ensure that the electrical 

cables are not submerged again. In a letter dated June 22, 2012, the staff issued RAI B1.1-2, 

requesting the applicant revise the corrective actions as appropriate to include the corrective 

actions when inspection acceptance criteria are not met or provide a technical justification of 

how the proposed corrective actions are consistent with SRP-LR Section A.1.2.3.7, which states 

that the actions to be taken when the acceptance criteria are not met should be described in 

appropriate detail or referenced to source documents. In its response dated July 23, 2012, the 

applicant stated that it will revise the LRA as indicated below (underlined portions) to clarify the 

corrective actions of the 115 kV Inaccessible Transmission Cable Program:
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7. Corrective Actions

Corrective actions are taken and an engineering evaluation will be performed 

when the test or inspection acceptance criteria are not met to ensure that the 

intended functions of the electrical cables can be maintained consistent with the 

current licensing basis. When an unacceptable condition or situation is identified, 

a determination is made as to whether the same condition or situation is 

applicable to other in-scope transmission cables. Corrective actions may 

include, but are not limited to, installation of permanent drainage systems, 

installation of sump pumps and alarms, more frequent cable testing or manhole 

inspections, or replacement of the affected cable. When an unacceptable 

condition or situation is identified, the requirements of 10 CFR Part 50, 

Appendix B, will be used to address corrective actions.

A.1.1 115 kV Inaccessible Transmission Cable Program

The 115 kV Inaccessible Transmission Cable Program manages the effects of 

aging on the 115 kV inaccessible transmission cable systems. The program 

includes periodic actions to prevent inaccessible transmission cables from being 

exposed to significant moisture. In this program, inaccessible 115 kV

transmission cables exposed to significant moisture will be tested at least once 

every six years to provide an indication of the condition of the cable insulation 

properties. Test frequencies may be adjusted based on test results and 

operating experience. The specific type of test will be a proven test for detecting 

deterioration of the cable insulation. The program includes periodic inspections 

for water accumulation in manholes at least once every year (annually). In 

addition to the periodic manhole inspections, manhole inspection for water after 

events, such as heavy rain or flooding will be performed. Inspection frequency 

will be increased as necessary based on evaluation of inspection results. The 

corrective action program will be entered and an engineering evaluation will be 

performed when the test or inspection acceptance criteria are not met.

This program will be implemented prior to the period of extended operation. The 

first cable tests and manhole inspections are to be completed prior to the period 

of extended operation.

The staff found the applicant’s response acceptable because the applicant revised its LRA to 

specifically require that the CAP will be entered and an engineering evaluation will be performed 

when the testing or inspection criteria are not met. The staff’s concern in RAI B1.1-2 is 

resolved.

Based on its review of the application and review of the applicant’s response to RAI B1.2-1, the 

staff confirmed that the “corrective actions” program element satisfies the criterion defined in 

SRP-LR Section A.1.2.3.7 and, therefore, the staff finds it acceptable.

Operating Experience. LRA Section B.1.1 summarizes operating experience related to the 

115 kV Inaccessible Transmission Cables Program. The applicant stated that the 115 kV

Inaccessible Transmission Cable Program is a new program. Industry operating experience 

was considered in the development of this program. Plant operating experience will be gained 

as the program is implemented and will be factored into the program through the confirmation 

and corrective action elements of the 10 CFR Part 50, Appendix B, quality assurance program. 
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The applicant also stated this inspection program applies to a potential aging effect for which 

there is no operating experience at GGNS indicating the need for an AMP. A search of GGNS 

operating experience with the 115 kV inaccessible transmission cables and connections in this 

program identified no age-related failures and no aging mechanisms not considered in SRP-LR. 

The GGNS program is similar to the program description in the GALL Report AMP XI.E3, which 

in turn is based on industry operating experience that demonstrates that this program is 

effective for managing the aging effects described herein. As such, operating experience 

assures that implementation of the 115 kV Inaccessible Transmission Cable Program will 

manage the effects of aging such that applicable components will continue to perform their 

intended functions consistent with the CLB for the period of extended operation.

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which states that for new AMPs that have yet to be implemented at an 

applicant’s facility, the programs have not yet generated any operating experience. However, 

there may be other relevant plant-specific operating experience at the plant or generic operating 

experience in the industry that is relevant to the AMP’s program elements, even though the 

operating experience was not identified as a result of the implementation of the new program. 

Thus, for a new program, an applicant may need to consider the impact of relevant operating 

experience that results from the past implementation of its existing AMPs that are existing 

programs and the impact of relevant generic operating experience on developing the program 

elements. Therefore, operating experience applicable to a new program should be discussed.

The applicant stated that a search of GGNS operating experience with the 115 kV inaccessible 

transmission cables and connections in this program identified no age-related failures, and no 

aging mechanisms not considered in the GALL Report have been identified. During the 

switchyard walkdown, the staff noted that Manhole 15 (MH-15) contains the 115 kV in-service 

transmission cables and the 115 kV transmission spare cables. These cables have the same 

manhole, but different vaults. The spare cables have a manhole cover and appeared to have 

the new sump pump installed. However, the vault containing in-service cables appears to have 

never been inspected for water and does not have a sump pump. This vault is covered by a 

thick concrete slab with no manhole cover. When a power cable is exposed to wet, submerged, 

or other adverse environmental conditions for which it was not designed, an aging effect of 

reduced insulation resistance may result, causing a decrease in the dielectric strength of the 

conductor insulation. This can potentially lead to failure of the cable’s insulation system. In a 

letter dated June 22, 2012, the staff issued RAI B1.1-1, requesting the applicant confirm that 

MH-15 containing in-service cables has been inspected. The staff also requested the applicant 

to describe recent operating experience with water accumulation in MH-15. If water is found

submerging cables, the staff requested the applicant to describe corrective actions to prevent 

future cable submergence conditions. In response to the staff’s request, in a letter dated 

July 23, 2012, the applicant stated that it inspected the 115 kV cables and the associated 

manhole MH-15 in 2009 and 2010. In 2009, a condition report was written for MH-15 stating 

that this cable manhole contained water, but there was no indication that the water level in the 

manhole was above the cables. In 2010, a condition report was written for MH-15 stating that 

water was discovered during the manhole inspection, but the water was not covering the cables. 

The applicant further stated that Entergy has a design modification prepared to install a 

solar-powered sump pump in manhole MH-15. The purpose of this modification is to provide a 

method to remove water from the MH-15 vault that contains in-service cables. The staff found 

the applicant response acceptable because the applicant has inspected 115 kV service cables 

and found that there was water in MH-15, but no submerged cables were found. The applicant 

plans to install a sump pump to remove water from the MH-15 vault that contains in-service 

cables. The staff concern in RAI B1.1-1 is resolved.
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Based on its review of the application and review of the applicant’s response to RAIs B1.1-1 and 

B1.1-2, the staff finds that the applicant has appropriately evaluated plant-specific and industry 

operating experience, operating experience related to the applicant’s program demonstrates 

that it will adequately manage the effects of aging on SSCs within the scope of the program and 

that implementation of the program has resulted in the applicant taking appropriate corrective 

actions. The staff confirmed that the “operating experience” program element satisfies the 

criterion in SRP-LR Section A.1.2.3.10 and, therefore, the staff finds it acceptable.

UFSAR Supplement. LRA Section A.1.1 provides the UFSAR supplement for the 115 kV

Inaccessible Transmission Cable Program. The staff reviewed this UFSAR supplement 

description of the program and noted that it is consistent with the recommended description for 

this type of program as described in SRP-LR Table 3.0.1.

The staff also noted that the applicant committed (Commitment No. 1) to implement the new 

115 kV Transmission Cable Program before entering the period of extended operation for 

managing aging of applicable components.

The staff finds that the information in the UFSAR supplement is an adequate summary 

description of the program.

Conclusion. On the basis of its technical review of the applicant’s 115 kV Transmission Cable 

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).

3.0.3.2.2 Periodic Surveillance and Preventive Maintenance

Summary of Technical Information in the Application. LRA Section B.1.35, as modified by 

letters dated December 20, 2013, May 13, 2014, and November 6, 2014, describes the existing 

Periodic Surveillance and Preventive Maintenance Program as plant specific, with an 

enhancement. The LRA states that the AMP manages aging effects not managed by other 

AMPs, including loss of material, loss of coating integrity, cracking, and change in material 

properties. The LRA also states that the AMP addresses piping and piping components in the 

LPCS system, HPCS system, RHR system, pressure relief system, RCIC system, nonsafetyrelated systems affecting safety-related systems (CRD system, circulating water (CW) system, 

and floor and equipment drain system), and the floor and equipment drain system. The AMP 

also addresses recurring internal corrosion issues in the CW, SSW, plant service water, and fire 

protection systems. The LRA further states that the AMP addresses the rubber gasket/seal for 

upper containment pool gates in the containment system. The staff notes that the applicant 

addressed those portions of LR-ISG-2012-02 pertaining to recurring internal corrosion and loss 

of coating integrity by modifying this program. The staff’s evaluation of the program changes to 

address recurring internal corrosion is documented in SER Section 3.3.2.2.7. Additionally, the 

staff’s evaluation of the program changes to address loss of coating integrity is documented in 

SER Section 3.0.3.3.

Staff Evaluation. The staff reviewed program elements one through six of the applicant’s 

program against the acceptance criteria for the corresponding elements as stated in SRP-LR 

Section A.1.2.3. The staff’s review focused on how the applicant’s program manages aging 

effects through the effective incorporation of these program elements. The staff’s evaluation of 
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each of these program elements follows. The staff’s review of the “corrective actions,”

“confirmation process” and “administrative controls” programs elements are documented in SER 

Section 3.0.4.

Scope of Program. LRA Section B.1.35, as modified in response to RAI B.1.41-3c, by letter 

dated December 20, 2013, states that the program includes piping and piping components in 

the LPCS system, HPCS system, RHR system, pressure relief system, RCIC system, 

nonsafety-related systems affecting safety-related systems (CRD system, CW system, moisture 

separator-reheater system, and floor and equipment drain system), and the floor and equipment 

drain system. Section B.1.35 also states that the AMP addresses the rubber gasket/seal for 

upper containment pool gates in the containment system.

The staff reviewed the applicant’s “scope of program” program element against the criteria in 

SRP-LR Section A.1.2.3.1, which states that this element includes the specific SCs managed by 

the program.

The staff noted that, in the portion of its letter dated May 13, 2014, relating to recurring internal 

corrosion, the applicant stated that this program monitors for loss of material due to 

microbiologically-influenced corrosion in the CW, SSW, plant service water, and fire protection 

systems. However, the corresponding change made to the table in the Periodic Surveillance 

and Preventive Maintenance Program also included the component cooling water system. By 

letter dated September 11, 2014, the staff issued RAI 3.0.3-1-RIC-1, part 1, requesting that the 

applicant clarify this apparent discrepancy. By letter dated November 6, 2014, the applicant 

stated that microbiologically-influenced corrosion has not occurred in the component cooling 

water system, and amended the table for the Periodic Surveillance and Preventive Maintenance 

Program and the corresponding UFSAR supplement by removing the component cooling water 

system from the systems listed. The staff finds the applicant’s response acceptable because 

microbiologically-influenced corrosion is not a recurring internal corrosion mechanism that is 

applicable to the component cooling water system. The staff’s concern described in 

RAI 3.0.3 1-RIC-1, part 1 is resolved.

Based on its review of the application, the staff confirmed that the “scope of program” program 

element satisfies the criterion defined in SRP-LR Section A.1.2.3.1 and, therefore, the staff finds 

it acceptable.

Preventive Actions. LRA Section B.1.35 states that the program is a condition monitoring 

program and does not include preventive actions.

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 if the program does not rely on preventive actions, 

the information need not be provided.

The staff noted that the Periodic Surveillance and Preventive Maintenance Program does not 

prevent loss of material, cracking, or change in material properties, but instead provides a 

means for detecting the degradation before a loss of intended function.

The staff finds the applicant’s “preventive actions” program element to be adequate because the 

applicant has provided information that clearly identifies the program as being a conditioning 

monitoring program only, with no preventive actions needing description.
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Based on its review of the application, the staff confirmed that the “preventive actions” program 

element satisfies the criteria defined in SRP-LR Section A.1.2.3.2 and, therefore, the staff finds 

it acceptable.

Parameters Monitored or Inspected. LRA Section B.1.35 states that the program monitors and 

inspects parameters linked to the degradation of the particular structure or component intended 

function(s).

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 the program element should 

identify the aging effects that the program manages and should provide a link to the parameters 

that will be monitored. SRP-LR Section A.1.2.3.3 also states that the parameters monitored 

should be capable of detecting the presence and extent of aging effects.

The staff did not find the applicant’s “parameters monitored or inspected” program element to be 

adequate because the application did not have sufficient detail for the staff to conclude that the 

parameters monitored are appropriate or are capable of detecting the presence and extent of 

aging effects. By letter dated April 11, 2012, the staff issued RAI B.1.35-1 requesting that the 

applicant revise Section B.1.35 to include the specific parameters monitored and their related 

aging effects for the SC groupings managed by the program.

In its response dated May 9, 2012, the applicant revised the “parameters monitored or 

inspected” program element of LRA Section B.1.35 to state that the program monitors cracking 

and change in material properties for elastomer components and the surface condition of the 

internal and external surfaces of the remaining (metallic) components to manage loss of 

material.

The staff finds the applicant’s response to be acceptable and the “parameters monitored or 

inspected” program element to be adequate because monitoring for the presence of cracking 

and change in material properties is capable of detecting elastomer degradation, consistent with 

the GALL Report guidance that identifies hardening and loss of strength as the applicable 

elastomer aging effects in air environments (e.g., GALL Report item VII.F2.AP-102). Also, 

monitoring the surface condition is capable of detecting loss of material of metallic components, 

which is the identified aging effect in the GALL Report for steel and stainless steel piping 

components exposed to water environments (e.g., GALL Report item V.D2.EP-60). The staff 

noted that this program is used to manage loss of material of gray cast iron valve bodies, which 

are subject to selective leaching and would thus require physical manipulation to detect loss of 

material due to this aging mechanism. However, the applicant is using the Selective Leaching 

Program to manage loss of material due to selective leaching for gray cast iron. The staff’s 

concern described in RAI B.1.35-1 is resolved.

The staff noted that, by letter dated May 13, 2014, the applicant amended the “parameters 

monitored or inspected” program element to state that the program will monitor the wall 

thickness to manage loss of material due to recurring internal corrosion, and it will monitor the 

condition of internal coated surfaces of components to manage loss of coating integrity. The 

staff finds these amendments of the AMP to be acceptable because the program element 

appropriately reflects the additional monitored parameters. The staff’s evaluations of the 

applicant’s activities to address recurring internal corrosion and loss of coating integrity are 

documented in SER Sections 3.3.2.2.7 and 3.0.3.3 respectively.
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Based on its review of the application, the staff confirmed that the “parameters monitored or 

inspected” program element satisfies the criteria defined in SRP-LR Section A.1.2.3.3 and, 

therefore, the staff finds it acceptable.

Detection of Aging Effects. LRA Section B.1.35 states that preventive maintenance activities 

and periodic surveillances provide for periodic component inspections to detect aging effects. 

The LRA also states that established techniques such as visual inspections are used, and each 

inspection occurs at least once every 5 years. The LRA further states that, for each activity that 

refers to a representative sample, a representative sample is 20 percent of the population with a 

maximum of 25 components.

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 the program element should address 

how age-related degradation will be detected prior to a loss of component function and should 

describe all aspects of data collection activities (e.g., inspection technique, frequency, and 

timing). The SRP-LR Section A.1.2.3.4 also states that inspection samples should be biased 

toward locations most susceptible to the specific aging effect of concern.

The staff did not initially find the applicant’s “detection of aging effects” program element to be 

adequate because (1) LRA Section B.1.35 did not specify that inspection samples should be 

biased toward locations most susceptible to aging and (2) the staff did not consider the LRA to 

have the necessary detail regarding how data are collected. By letter dated April 11, 2012, the 

staff issued RAI B.1.35-2, requesting that the applicant revise the “detection of aging effects”

program element of LRA Section B.1.35 to include the selection of inspection locations most 

susceptible to aging. The staff also issued RAI B.1.35-3, requesting that the applicant revise 

the “detection of aging effects” program element to include specific inspection techniques that 

will be used to detect the aging effects. In this RAI, staff also requested that the applicant revise 

the LRA to state the qualification requirements of personnel who will be performing the 

inspections, or justify their exclusion.

In its response dated May 9, 2012, the applicant revised the “detection of aging effects” program 

element of LRA Section B.1.35 to state that the selection of components to be inspected will 

focus on locations that are most susceptible to aging, where practical. The applicant also 

revised the LRA to state that visual inspections and manual flexing will be used to detect the 

aging of elastomers and visual or NDE techniques will be used to detect the aging of the 

metallic components. The applicant further revised the LRA to state that inspections will be 

performed by qualified personnel.

The staff finds the applicant’s response acceptable and the “detection of aging effects” program 

element to be adequate because visual inspections and manual flexing are capable of detecting 

cracking and change in material properties of elastomers. Also, visual inspections and NDE 

techniques are capable of detecting loss of material of metallic components. Further, the 

performance of these elastomer and metallic component inspections by qualified personnel at 

least once every 5 years on a representative sample of components, focusing on locations most 

prone to aging, is capable of detecting aging before loss of component function. The staff’s 

concerns described in RAI B.1.35-2 and RAI B.1.35-3 are resolved.

Based on its review of the application and review of the applicant’s responses to RAI B.1.35-2 

and RAI B.1.35-3, the staff confirmed that the “detection of aging effects” program element 

satisfies the criteria defined in SRP-LR Section A.1.2.3.4 and, therefore, the staff finds it 

acceptable.
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Monitoring and Trending. LRA Section B.1.35 states that preventive maintenance activities 

provide for monitoring and trending of aging degradation. The LRA also states that inspection 

intervals are established such that they provide for timely detection of component degradation. 

The LRA further states that inspection intervals take into consideration industry and 

plant-specific operating experience and manufacturers’ recommendations.

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 the results should be evaluated against the acceptance criteria to effect timely 

corrective or mitigative actions.

The staff finds the applicant’s “monitoring and trending” program element to be adequate 

because the program’s preventive maintenance activities include inspection intervals that are 

informed by operating experience, such that aging degradation can be detected prior to loss of 

intended function.

Based on its review of the application, the staff confirmed that the “monitoring and trending”

program element satisfies the criteria defined in SRP-LR Section A.1.2.3.5 and, therefore, the 

staff finds it acceptable.

Acceptance Criteria. LRA Section B.1.35 states that acceptance criteria are defined in specific 

inspection procedures, which confirm that the structure or component intended function(s) are 

maintained by verifying the absence of aging effects or by comparing applicable parameters to 

limits established by the plant design basis.

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 the acceptance criteria of the program and its basis 

should be described and the acceptance criteria should ensure that the component’s intended 

function(s) are maintained consistent with the CLB.

The staff did not find the applicant’s “acceptance criteria” program element to be adequate 

because the application did not have sufficient detail on the inspection procedures for the staff

to conclude that the acceptance criteria will be capable of confirming that component intended 

functions will be maintained. By letter dated April 11, 2012, the staff issued RAI B.1.35-4, 

requesting that the applicant revise the “acceptance criteria” program element of LRA 

Section B.1.35 to include specific acceptance criteria (e.g., any indication of relevant 

degradation, pipe wall remaining above minimum design wall thickness, absence of cracking) 

for each of the SC groupings managed by the program.

In its response dated May 9, 2012, the applicant revised the “acceptance criteria” program 

element of LRA Section B.1.35 to state that the acceptance criteria for elastomers includes no 

significant change in material properties or cracking while visually observing and flexing 

components. The applicant also stated that the acceptance criteria for metallic components 

include no unacceptable loss of material, such that component wall thickness remains above 

the required minimum.

The staff finds the applicant’s response to be acceptable and the “acceptance criteria” program 

element to be adequate because maintaining no significant change in material properties or 

cracking of elastomers and maintaining metallic component wall thicknesses above required 

minimums ensure that component intended functions will be maintained consistent with the 

CLB. The staff’s concern described in RAI B.1.35-4 is resolved.
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Based on its review of the application and review of the applicant’s response to RAI B.1.35-4, 

the staff confirmed that the “acceptance criteria” program element satisfies the criteria defined in 

SRP-LR Section A.1.2.3.6 and, therefore, the staff finds it acceptable.

The staff also reviewed the portions of the “scope of program,” “parameters monitored or 

inspected,” “detection of aging effects,” and “acceptance criteria” program elements associated 

with an enhancement to determine whether the program will be adequate to manage the aging 

effects for which it is credited. The staff’s evaluation of this enhancement follows.

Enhancement 1. LRA Section B.1.35 states an enhancement to the “scope of program,”

“parameters monitored or inspected,” “detection of aging effects,” and “acceptance criteria”

program elements. In this enhancement, the applicant stated that the program will be enhanced 

to revise program guidance documents as necessary to include all inspection activities provided 

in the program description of LRA Section B.1.35, which is summarized in the staff’s evaluation 

of the “scope of program” program element above. The staff reviewed this enhancement and 

finds it acceptable, because this enhancement to the program, as revised by the responses to 

RAIs B.1.35-1, B.1.35-2, B.1.35-3, B.1.35-4, and B.1.41-3c, establishes appropriate inspection 

activities capable of ensuring that degradation will be detected before the loss of intended 

function.

By letter dated November 6, 2014, the applicant amended the enhancement to the program 

given in LRA Sections A.1.35, A.4 (Commitment No. 25), and B.1.35 to be more consistently 

worded for the three sections. The amended enhancement added the “monitoring and trending” 

and “corrective actions” program elements to the list of affected elements. In addition, the 

enhancement clarified that the enhanced activities included, not just the activities described in 

the table provided in the program description for LRA Section B.1.35, but all the activities 

described in LRA Section B.1.35. The staff finds the amended enhancement acceptable 

because it captures all of the recent changes made to the program to ensure that degradation

will be detected before the loss of intended function.

Based on reviews of LRAs and industry operating experience conducted by the staff, the staff 

identified an issue concerning loss of coating integrity of internal coatings of piping, piping 

components, heat exchangers, and tanks. By letter dated January 2, 2014, the staff issued 

RAI 3.0.3-2 requesting that the applicant address several questions associated with managing 

loss of coating integrity. As a result of this RAI and follow-on RAIs, the applicant made several 

changes to the Periodic Surveillance and Preventive Maintenance Program in order to manage 

loss of coating integrity. The staff’s evaluation of the changes described in these enhancements 

is documented in SER Section 3.0.3.3.

Operating Experience. LRA Section B.1.35 summarizes operating experience related to the 

Periodic Surveillance and Preventive Maintenance Program. The applicant stated that 

operating experience includes NDE wall-thickness measurements performed on diesel 

generator exhaust piping in 2005, which showed acceptable results and confirmed that there 

was no indication of aging. The applicant also stated that, in 2006, a visual inspection of the 

internal surfaces of a check valve in the component cooling water system found significant 

wear. The applicant stated that, after the valve was replaced, there was no other indication of 

aging such as erosion or corrosion. The applicant cited these examples of operating experience 

as evidence that the program is effective for managing aging effects for components.

The staff reviewed this information against the acceptance criteria in SRP-LR 

Section A.1.2.3.10, which states that operating experience should be discussed. SRP-LR 
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Section A.1.2.3.10 also states that this information 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. During its review, the 

staff found no operating experience to indicate that the applicant’s program would not be 

effective in adequately managing aging effects during the period of extended operation.

Based on its review of the application, the staff finds that (1) the applicant has appropriately 

evaluated plant-specific and industry operating experience, (2) operating experience related to 

the applicant’s program demonstrates that it will adequately manage the effects of aging on 

SSCs within the scope of the program, and (3) implementation of the program has resulted in 

the applicant taking corrective actions. The staff confirmed that the “operating experience”

program element satisfies the criteria in SRP-LR Section A.1.2.3.10 and, therefore, the staff 

finds it acceptable.

UFSAR Supplement. LRA Section A.1.35 provides the UFSAR supplement for the Periodic 

Surveillance and Preventive Maintenance Program. The UFSAR supplement includes 

Commitment No. 25 in LRA Table A.4, in which the applicant committed to updating the 

program guidance documents as necessary to include all inspection activities provided in the 

program description of LRA Section B.1.35, which the staff evaluated in the “scope of program” 

program element and enhancement in this AMP. The staff reviewed this UFSAR supplement 

description of the program against the recommended description for this type of program as 

described in SRP-LR Table 3.0-1 and noted that LRA Section A.1.35 does not include the 

minimum 5-year inspection frequency. The staff noted that the licensing basis for this program 

for the period of extended operation may not be adequate if the applicant does not incorporate 

this information into its UFSAR supplement. By letter dated April 11, 2012, the staff issued

RAI B.1.35-5 requesting that the applicant revise LRA Section A.1.35 to include the frequency of 

inspections to be conducted during the period of extended operation.

In its response dated May 9, 2012, the applicant revised the UFSAR supplement in LRA 

Section A.1.35 to state that inspections will be conducted at least once every 5 years during the 

period of extended operation. The applicant also revised the UFSAR supplement to describe 

the inspections in greater detail, including the specific components and systems inspected.

The staff finds the applicant’s response acceptable because the applicant included the 5-year 

inspection frequency in the UFSAR supplement, which provides an important detail on the basis 

for how this program will manage aging during the period of extended operation. Therefore, the 

UFSAR supplement for the Periodic Surveillance and Preventive Maintenance Program is 

consistent with the corresponding program description in SRP-LR Table 3.0-1. The staff’s 

concern described in RAI B.1.35-5 is resolved.

By letters dated May 13, 2014, and September 11, 2014, the applicant amended the UFSAR 

supplement description in LRA Section A.1.35, to add “recurring internal corrosion” and “loss of 

coating integrity” as additional, applicable aging effects that will be managed by the program. 

The applicant also clarified that the frequencies of inspections for coating integrity and recurring 

internal corrosion due to microbiologically-influenced corrosion are based on inspection results 

instead of at least once every 5 years. In addition, the applicant added extensive details related 

to the coating integrity inspections and the microbiologically-influenced corrosion inspections.

The staff finds that the information in the UFSAR supplement, as amended, is an adequate 

summary description of the program. In addition, the staff’s evaluation of the UFSAR changes 

to address loss of coating integrity is documented in SER Section 3.0.3.3.
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Conclusion. On the basis of its technical review of the applicant’s Periodic Surveillance and 

Preventive Maintenance 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). Also, the staff reviewed the enhancement and confirmed that its 

implementation through Commitment No. 25 prior to the period of extended operation will make 

the AMP adequate to manage the applicable aging effects. 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 Aging Management Related to Loss of Coating Integrity for Internal Coatings 

on In-Scope Mechanical SSCs

3.0.3.3.1 Technical Information in the Application

Based on reviews of LRAs and industry operating experience conducted by the staff, the staff 

identified an issue concerning loss of coating integrity of internal coatings of piping, piping 

components, heat exchangers, and tanks. By letter dated January 2, 2014, the staff issued 

RAI 3.0.3-2 requesting that the applicant address several questions associated with managing 

loss of coating integrity. In its response dated May 13, 2014, the applicant revised the Periodic 

Surveillance and Preventive Maintenance, Fire Water System, and Service Water Integrity 

Programs to address loss of coating integrity of internal coatings of piping, piping components, 

heat exchangers, and tanks. By letter dated September 11, 2014, the staff issued follow-up

requests for additional information. The applicant responded on November 6, 2014. On 

November 14, 2014, the staff issued LR-ISG-2013-01, which contains the current 

staff-recommended actions to manage loss of coating integrity. The staff’s evaluation of this 

issue and the applicant’s responses are presented here.

3.0.3.3.2 Staff Evaluation

By letter dated January 2, 2014, the staff issued RAI 3.0.3-2 requesting that, if coatings have 

been installed on the internal surfaces of in-scope components (i.e., piping, piping components, 

heat exchangers, and tanks), the applicant state the inspection method, when inspections will 

commence and the frequency of subsequent inspections, the extent of inspections, the training 

and qualification of individuals involved in coating inspections, how trending of coating 

degradation will be conducted, acceptance criteria, and corrective actions for coatings that do 

not meet acceptance criteria.

The staff noted that the applicant included 10 enhancements to the Service Water Integrity 

Program and enhanced the Periodic Surveillance and Preventive Maintenance Program in order 

to incorporate the inspections, testing, and actions below to address loss of coating integrity. 

The staff’s evaluation of enhancements to the Fire Water System to address loss of coating 

integrity is documented in SER Section 3.0.3.1.20.

In its response dated May 13, 2014, the applicant provided the following:

Visual Inspections. The applicant stated that visual inspections will be conducted on the internal 

surfaces of coated components.

The staff finds this portion of the RAI response acceptable because it is consistent with 

LR-ISG-2013-01 and visual inspections are an effective means to detect coating degradation.
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Baseline and Subsequent Frequency of Inspections. The applicant stated that baseline 

inspections will begin during the 10-year period prior to the period of extended operation and be 

completed no later than the last scheduled refueling outage prior to the period of extended 

operation. Subsequent inspections will be based on the initial inspection results as follows: 

(a) if no peeling, delamination, blisters, or rusting are detected and any cracking and flaking has 

been found acceptable, subsequent inspections will be performed at least once every 6 years,

(b) if no indications are found during the inspection of one train, the redundant train will not be 

inspected and the subsequent inspection will be on the redundant train, and (c) if the inspection 

results do not meet the above (however, a coating specialist has determined that no 

remediation is required), subsequent inspections will be conducted on an every other refueling 

outage interval. The applicant also stated that, “[i]nspections of coatings that are repaired, 

replaced or newly installed are not periodic activities performed to manage the effects of aging. 

Such inspections confirm adequacy of application of protective coatings which is not an activity 

necessary to manage the effects of aging in accordance with the license renewal rule.”

The staff noted that, if no indications are found during the inspection of one train, the redundant 

train would not need to be inspected as long as: (a) an identical coating/lining material was 

installed with the same installation requirements in the redundant train (e.g., piping segments, 

tanks) with the same operating conditions, and (b) the components within the redundant trains 

are not subject to turbulent conditions. By letter dated September 11, 2014, the staff issued 

RAI 3.0.3-2a Request (1) requesting that the applicant state the basis for why inspection results 

on one train are sufficiently representative of the coating condition in a redundant train.

In its response dated November 6, 2014, the applicant enhanced the Periodic Surveillance and 

Preventive Maintenance Program and Service Water Integrity Program to state that, when the 

inspections of coatings on one train do not detect any indications, the redundant train’s coatings 

will not have to be inspected in that inspection interval as long as the coatings in the redundant 

train have the same coating and the redundant train does not have turbulent flow. The applicant 

stated that, “[u]nder these conditions, inspection results on one train are representative of the 

coating condition on redundant train(s) such that it is acceptable to extend the inspection 

interval for redundant train(s) when no indications are found during the inspection of the 

initial train.”

The staff finds the applicant’s response and proposal for beginning inspections and the 

frequency of subsequent inspections acceptable because they are consistent with 

LR-ISG-2013-01 and: (a) baseline inspections will be conducted prior to entering the period of 

extended operation in order to provide insight into the condition of coatings after many years of 

service, (b) subsequent inspection intervals will be based on the results of prior inspections 

such that, where degraded coatings are noted, more frequent inspections will occur, (c) the 

maximum inspection intervals are consistent with the staff’s recommended actions to manage 

loss of coating integrity, and (d) conducting alternating inspections of redundant trains with the 

same coatings when no indications are detected in prior inspections and turbulent flow 

conditions do not exist is consistent with the staff’s recommended actions to manage loss of 

coating integrity. The staff’s concern described in RAI 3.0.3-2a Request (1) is resolved.

The applicant revised its Periodic Surveillance and Preventive Maintenance Program and 

Service Water Integrity Program to conduct one or more inspections or tests whenever coating 

conditions such as cracking, peeling, blistering, delamination, rust, or flaking are identified 

during inspections. The tests include lightly tapping the coating to detect degraded conditions, 

wet-sponge testing, adhesion testing, and ultrasonic examinations. The staff finds this change 
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acceptable because they are effective means to determine the degree of degradation 

in coatings.

Extent of Inspections. The applicant stated that all accessible internal surfaces of tanks and 

heat exchangers are inspected; and a representative sample of the internal surfaces of piping is 

inspected, consisting of 73 1-foot axial length circumferential segments of piping or 50 percent 

of the pipe length for each coating material and environment combination.

The staff finds the applicant’s response and proposal acceptable because it is consistent with 

LR-ISG-2013-01, which ensures that a minimum number of inspections are conducted.

Training and Qualification of Personnel. The applicant stated that coating inspections will be 

performed by individuals qualified to ANSI N45.2.6, “Qualification of Inspections, Examinations, 

and Testing Personnel for Nuclear Power Plants.” The applicant also stated that the evaluation 

of inspection findings will be conducted by a nuclear coatings subject matter expert qualified in 

accordance with ASTM D7108-5, “Standard Guide for Establishing Qualifications for a Nuclear 

Coating Specialist.”

The staff noted that qualifications meeting the recommendations in RG 1.54 are consistent with 

the staff’s recommended actions to manage loss of coating integrity. The staff finds the training 

and qualification requirements acceptable because ANSI N45.2.6 certification is an acceptable 

basis for qualifying coatings inspectors based on RG 1.54, June 1973, Section C.1, which 

endorses conformance to the ANSI N45.2 quality assurance standards, and because the use of 

D7108-05 is endorsed by RG 1.54.

Monitoring and Trending of Results. The applicant stated that monitoring and trending is 

accomplished by preventive maintenance activities. In a letter dated November 6, 2014, the 

applicant revised LRA Sections B.1.35 and B.1.41, Periodic Surveillance and Preventive 

Maintenance and Service Water Integrity Programs, respectively, to state that: (a) “[a]n 

individual knowledgeable and experienced in nuclear coatings work will prepare a coating 

report; and (b) the coating inspection report will include a list of locations identified with coating 

degradation, a prioritization of the repair areas into areas that must be repaired before returning 

the system to service and areas where repair can be postponed to the next refueling outage, 

and where possible, photographic documentation indexed to inspection locations.”

The staff noted that LRA Section B.1.35 was revised to state that the results of previous 

inspections are reviewed prior to conducting a coating inspection; however, LRA Section B.1.41 

does not include this requirement. The staff also noted that LRA Section B.1.21, Fire Water 

System Program, does not include any of the above-described requirements. In addition, the 

staff has concluded that a coatings specialist should prepare the coating report and the term “an 

individual knowledgeable and experienced in nuclear coatings work” lacks sufficient specificity 

for the staff to conclude that the individual will be appropriately qualified to perform the task. By 

letter dated September 11, 2014, the staff issued RAI 3.0.3-2a Request (2), requesting that the 

applicant state: (a) the specific qualifications for the individual that prepares the coating report 

for the Periodic Surveillance and Preventive Maintenance, Fire Water System, and Service 

Water Integrity Programs, (b) how the results of coatings inspections will be monitored and 

trended for the Service Water Integrity Program, and (c) how the results of coatings inspections 

will be monitored, trended, and reported for the Fire Water System Program.

In its response dated November 6, 2014, the applicant revised LRA Sections A.1.21, A.1.35, 

A.1.41, A.4, B.1.21, B.1.35, and B.1.41, as necessary, to state: (a) post-inspection reports will 
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be prepared by a nuclear coating specialist, (b) results of previous inspections will be reviewed 

prior to conducting a coating inspection, and (c) the qualifications of individuals conducting 

coating inspections. In addition, the Fire Water System Program and the UFSAR supplement 

description of the program were revised to include both the level of detail to be included in 

coating inspection reports, similar to that contained in the Periodic Surveillance and Preventive 

Maintenance and Service Water Integrity Programs, and the qualifications for personnel 

conducting coating inspection activities.

The staff finds the applicant’s response and proposal to monitor and trend coating degradation 

acceptable because they are consistent with LR-ISG-2013-01, which ensures that individuals 

that prepare inspection reports are appropriately qualified and the results of prior inspections 

are used to inform the inspectors of potential coating degradation prior to conducting 

subsequent inspections. The staff’s concerns described in RAI 3.0.3-2a Request (2) are 

resolved.

Acceptance Criteria. The applicant stated that peeling and delamination are not acceptable; 

cracking is not acceptable if there is also evidence of delamination or loss of adhesion. By 

letters dated August 19, 2015, and November 23, 2015, the applicant stated that blisters are 

limited to a few small intact blisters completely surrounded by sound coating bonded to the 

surface. When peeling, delamination, cracking, or loss of adhesion is detected, follow-up

evaluations such as an adhesion test will be performed. If base metal is exposed and 

accompanied by corrosion, a volumetric examination will be performed to ensure there is 

sufficient wall thickness so that the component can perform its CLB intended function until the 

next inspection.

The staff noted that the applicant stated that a volumetric examination will be performed if there 

is evidence of “accelerated corrosion;” however, the staff has concluded that, if coatings are 

credited for corrosion prevention (e.g., corrosion allowance in design calculations is zero, the 

“preventive actions” program element credited the coating) and the base metal has been 

exposed or it is beneath a blister, the component’s base material in the vicinity of the degraded 

coating is examined to determine if the minimum wall thickness is met and will be met until the 

next inspection. The staff also noted that the Fire Water System Program does not include 

acceptance criteria for loss of coating integrity. By letter dated September 11, 2014, the staff 

issued RAI 3.0.3-2a Request (3), requesting that the applicant state: (a) the basis for why 

conducting volumetric wall thickness examinations of components only when the extent of loss 

of material is characterized as “accelerated corrosion” is sufficient to provide reasonable 

assurance that the CLB intended function(s) of components with exposed base metal or base 

metal in the vicinity of a blister will be met, and (b) the acceptance criteria that will be used to 

assess degraded coatings in the fire water system.

In its response dated November 6, 2014, the applicant stated that the term “accelerated 

corrosion” was revised to “corrosion;” and the Fire Water System Program was revised to state 

the same acceptance criteria as for the Periodic Surveillance and Preventive Maintenance and 

Service Water Integrity Programs.

The staff finds the applicant’s response and proposed acceptance criteria acceptable because 

they are consistent with LR-ISG-2013-01, which states that peeling and delamination are not 

acceptable, cracking can be evaluated by a coatings specialist, and a few intact small blisters 

that are completely surrounded by sound coating/lining bonded to the substrate meet 

acceptance criteria. The staff’s concern described in RAI 3.0.3-2a Request (3) is resolved.
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Corrective Actions for Coatings That Do Not Meet Acceptance Criteria. The applicant stated 

that “[c]orrective actions for unacceptable inspection findings will be determined in accordance 

with the GGNS 10 CFR Part 50 Appendix B Corrective Action Program (CAP).”

The staff has concluded that coatings that do not meet acceptance criteria should be repaired, 

replaced, or removed, and testing or examination should be conducted to ensure that the extent 

of repaired, replaced, or removed coatings encompasses sound coating material. Although the 

applicant’s acceptance criteria state the aging mechanisms that are not acceptable, the 

“corrective actions” program element does not state that the coatings will be repaired, replaced, 

or removed, and that testing or examination will be conducted to ensure that the extent of 

repaired, replaced, or removed coatings encompasses sound coating material. The “corrective 

actions” program element lacks sufficient specificity for the staff to complete its evaluation. By 

letter dated September 11, 2014, the staff issued RAI 3.0.3-2a Request (4), requesting that the 

applicant state the specific corrective actions that will be taken when loss of coating integrity is 

detected that does not meet acceptance criteria.

In its response dated November 6, 2014, and as amended by letter dated August 19, 2015, the 

applicant stated that: (a) if peeling, delamination, cracking, or loss of adhesion is identified, the 

degraded condition will be evaluated by techniques such as adhesion testing, (b) “[c]oatings that 

do not meet acceptance criteria will be repaired or replaced,” and (c) in the event that base 

metal is exposed, “[i]f repair or replacement of the coating is postponed, the evaluation will 

consider the minimum wall thickness requirements and the rate of corrosion and confirm the 

component remains acceptable for continued service until the next inspection or repair 

opportunity.” In addition, the applicant revised the Fire Water System Program to state that dry 

film thickness readings, spot wet sponge tests, and ultrasonic thickness readings will be 

conducted where pitting or corrosion is detected in the fire water storage tank walls or floor.

The staff finds the applicant’s response and proposed “corrective actions” program elements 

acceptable, in part, because repairing or replacing coatings that do not meet acceptance criteria 

is consistent with LR-ISG-2013-01. However, the applicant did not state: (a) what alternatives 

to adhesion testing would be conducted in order to evaluate degraded coatings, (b) how 

downstream flow blockage will be addressed when degraded coatings that do not meet 

acceptance criteria are returned to service, and (c) what actions would be taken if degraded 

coatings exhibiting peeling or delamination are returned to service without correction. In 

addition, in regard to fire water storage tanks, NFPA 25, Section 9.2.7 states that adhesion 

testing should be conducted in addition to those tests that the applicant stated it will conduct 

when coating defects are detected. The staff addressed the fire water storage tank adhesion 

testing question in RAI 3.0.3.1-FWS-2a, as documented in SER Section 3.0.3.1.20. The staff 

required additional information to resolve the above concerns in RAI 3.0.3-2a Request (4).

By letter dated April 6, 2015, the staff issued RAI 3.0.3-2b requesting that the applicant state 

(a) what alternatives to adhesion testing will be conducted in order to evaluate degraded 

coatings, (b) how potential downstream flow blockage due to degraded coatings that do not 

meet acceptance criteria will be evaluated prior to returning a degraded coating to service, and 

(c) what actions would be taken if degraded coatings exhibiting peeling or delamination are 

returned to service without correction.

The applicant originally responded to this RAI on May 20, 2015; however, it revised its response 

as stated in an August 19, 2015, letter. The applicant revised LRA Section B.1.41 to state that if 

a coatings specialist determines that coating remediation is required, the coated component can 

be returned to service if the following actions, testing, and examination occur: (a) removal of 
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blisters in excess of a few small intact blisters or blisters not completely surrounded by coating 

bonded to the substrate, (b) removal of delaminated or peeled coatings, (c) adhesion testing is 

conducted in three locations in accordance with standards cited in RG 1.54, (d) feathering of the 

outermost coating and adhesion testing of the surface surrounding the feathering, (e) ultrasonic 

testing to ensure minimum wall thickness requirements are met, (f) an evaluation to ensure that 

downstream flow blockage is not an issue, and (g) follow-up inspections within 2 years and 

every 2 years until the coating is repaired, replaced, or removed.

The staff noted that the applicant had not included the changes to its Periodic Surveillance and 

Preventive Maintenance Program in the August 19, 2015, letter. By letter dated 

October 29, 2015, the staff issued RAI 3.0.3-3 requesting that the applicant provide the changes 

to its Periodic Surveillance and Preventive Maintenance Program. In its response dated 

November 23, 2015, the applicant provided the changes to the Periodic Surveillance and 

Preventive Maintenance Program. The staff finds the applicant’s response acceptable because 

the changes to the Periodic Surveillance and Preventive Maintenance Program are consistent 

with the changes described in this section in this SER. The staff’s concern described in 

RAI 3.0.3-3 is resolved.

The staff finds the applicant’s response acceptable because the applicant’s proposal in relation 

to alternative adhesion testing methods and to potential downstream flow blockage due to 

degraded coatings, and the actions, testing, and examinations that will be conducted prior to 

returning a component to service with degraded coatings are consistent with the “acceptance 

criteria” and “corrective actions” program elements of AMP XI.M42. The staff’s concerns 

described in RAI 3.0.3-2a Request (4) and RAI 3.0.3-2b are resolved.

The staff noted that LRA Section B.1.35 lists the program elements that are required to be 

enhanced for the Periodic Surveillance and Preventive Maintenance Program. The staff also 

noted that the “monitoring and trending” program element includes new requirements necessary 

to effectively manage loss of coating integrity; however, this program element is not included in 

the list of elements affected. In addition, the changes to the program submitted in response to 

RAI 3.0.3-2a resulted in changes to the “corrective actions” program element. In response to 

RAI 3.0.3-2a Request (5) the applicant included the “monitoring and trending” and “corrective 

actions” program elements in the list of program elements requiring enhancement. The staff 

finds this change acceptable because the program now accurately reflects all program elements 

that must change. The staff’s concern described in RAI 3.0.3-2a Request (5) is resolved.

3.0.3.3.3 UFSAR Supplement

The staff noted that, in its response dated August 19, 2015, the applicant revised LRA 

Sections A.1.21, A.1.35, and A.1.41, to address loss of coating integrity for the Fire Water 

System, Periodic Surveillance and Preventive Maintenance, and Service Water Integrity 

Programs, respectively. In addition, the applicant revised the UFSAR supplement for the 

Periodic Surveillance and Preventive Maintenance Program in its response dated 

November 23, 2015. The staff’s evaluation of changes to the UFSAR supplement for the Fire 

Water System Program is documented in SER Section 3.0.3.1.20.

LR-ISG-2013-01, Table 3.0-1, AMP XI.M42 states that the UFSAR supplement for programs 

that will manage loss of coating integrity should state key aspects of the program associated 

with coating degradation, including periodic visual inspections to detect potential loss of coating 

integrity; follow-up testing that will be conducted when degradation does not meet acceptance 

criteria; and the basis for the training and qualification of individuals involved in coating 
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inspections. The staff noted that LRA Sections A.1.35 and A.1.41 address these aspects of 

managing loss of coating integrity. The staff also noted that the applicant committed 

(Commitment No. 35) to enhance the program by revising Service Water Integrity Program 

documents to include inspections for loss of material due to erosion.

The staff finds that the information in the UFSAR supplements, as amended by letter dated 

August 19, 2015, and November 23, 2015, are adequate summary descriptions of the 

associated programs.

3.0.3.3.4 Conclusion

On the basis of its technical review of the applicant’s changes to the Fire Water System, 

Periodic Surveillance and Preventive Maintenance and Service Water Integrity Programs to 

address loss of coating integrity, 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 these AMPs and 

concludes that they provide an adequate summary description of the program, as required by 

10 CFR 54.21(d).

3.0.4 QA Program Attributes Integral to Aging Management Programs

Pursuant to 10 CFR 54.21(a)(3), the applicant is required to demonstrate that the effects of 

aging on SCs subject to an AMR will be adequately managed so that their intended function(s) 

will be maintained consistent with the CLB for the period of extended operation. SRP-LR, 

Branch Technical Position (BTP) RLSB-1, “Aging Management Review – Generic,” describes 

10 elements of an acceptable AMP. Elements (7), (8), and (9) are associated with the QA 

activities of “corrective actions,” “confirmation process,” and “administrative controls.”

BTP RLSB-1 Table A.1-1, “Elements of an Aging Management Program for License Renewal,”

provides the following description of these program elements:

(7) Corrective Actions – Corrective actions, including root cause determination and 

prevention of recurrence, should be timely.

(8) Confirmation Process – The confirmation process should ensure that preventive actions 

are adequate and that appropriate corrective actions are completed and effective.

(9) Administrative Controls – Administrative controls should provide for a formal review and 

approval process.

BTP IQMB-1, “Quality Assurance for Aging Management Programs,” notes that AMP aspects 

that affect the quality of safety-related SSCs are subject to the QA requirements of 

10 CFR Part 50, Appendix B. Additionally, for nonsafety-related SCs subject to an AMR, the 

applicant may use the existing 10 CFR Part 50, Appendix B, QA program to address the 

elements of “corrective actions,” “confirmation process,” and “administrative controls.”

BTP IQMB-1 provides the following guidance on the QA attributes of AMPs:

• Safety-related SCs are subject to 10 CFR Part 50, Appendix B, requirements which are 

adequate to address all quality-related aspects of an AMP consistent with the CLB of the 

facility for the period of extended operation.

• For nonsafety-related SCs that are subject to an AMR, an applicant has an option to 

expand the scope of its 10 CFR Part 50, Appendix B, program to include these SCs to 
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address “corrective action,” “confirmation process,” and “administrative control” for aging 

management during the period of extended operation. In this case, the applicant should 

document such commitment in the UFSAR supplement in accordance with 

10 CFR 54.21(d).

3.0.4.1 Summary of Technical Information in the Application

In LRA Appendix A, “Updated Final Safety Analysis Report Supplement,” Section A.1, “Aging 

Management Programs,” and LRA Appendix B, “Aging Management Programs and Activities,”

Section B.0.3, “Corrective Actions, Confirmation Process and Administrative Controls,” the 

applicant described the elements of corrective action, confirmation process, and administrative 

controls that are applied to the AMPs for both safety-related and nonsafety-related components.

LRA Appendix A, Section A.1 states:

GGNS QA procedures, review and approval processes, and administrative 

controls are implemented in accordance with the requirements of 10 CFR 50, 

Appendix B. The GGNS Quality Assurance Program applies to safety-related 

structures and components. The appendix also states that corrective actions and 

administrative (document) control for both safety-related and nonsafety-related 

structures and components are accomplished in accordance with the established 

GGNS corrective action and document control programs and are applicable to all 

aging management programs.

LRA Appendix B, Section B.0.3 states:

Corrective Actions:

The corrective action controls of the GGNS (10 CFR Part 50, Appendix B) 

Quality Assurance Program are applicable to all aging management programs 

and activities during the period of extended operation.

Confirmation Process:

Corrective actions and administrative (document) control for both safety-related 

and nonsafety-related structures and components are accomplished in 

accordance with the established GGNS Corrective Action Program (CAP) and 

Document Control Program. The confirmation process is part of the CAP and 

includes the following:

• Reviews to assure that corrective actions are adequate

• Tracking and reporting of open corrective actions

• Review of corrective action effectiveness

Any follow-up inspection required by the confirmation process is documented in 

accordance with the CAP. The CAP constitutes the confirmation process for 

aging management programs and activities.
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Administrative Controls:

Administrative (document) control for both safety-related and nonsafety-related 

structures and components is accomplished per the existing document control 

program. The GGNS administrative controls are consistent with NUREG-1801.

3.0.4.2 Staff Evaluation

The staff reviewed LRA Sections Appendix A, Section A.1 and Appendix B, and LRA 

Section B.0.3, which describe how the existing GGNS quality assurance program includes the 

QA-related elements (corrective action, confirmation process, and administrative controls) for 

AMPs consistent with the staff’s guidance described in BTP IQMB-1. The staff also reviewed a 

sample of AMP program basis documents and confirmed that the AMPs implement the CAP, 

confirmation processes, and administrative controls as described in the LRA. Based on its 

review, the staff determined that the quality attributes presented in the AMP program basis 

documents and the associated AMPs are consistent with the staff’s position regarding QA for 

aging management.

3.0.4.3 Conclusion

On the basis of the staff’s evaluation, the descriptions and applicability of the plant-specific 

AMPs and their associated quality attributes provided in LRA Sections Appendix A, Section A.1, 

and Appendix B, Section B.0.3, were determined to be consistent with the staff’s position 

regarding QA for aging management. The staff concludes that the QA attributes (corrective 

action, confirmation process, and administrative control) of the applicant’s AMPs are consistent 

with 10 CFR 54.21(a)(3).

3.0.5 Operating Experience for Aging Management Programs

3.0.5.1 Summary of Technical Information in Application

LRA Section B.0.4 describes how the applicant considered operating experience in the 

preparation of the application. The LRA states that the applicant reviewed operating experience 

for the programs and activities credited with managing the effects of aging, and this review 

included corrective actions resulting in program enhancements. For inspection programs, the 

LRA states that reports of recent inspections, examinations, or tests were reviewed to determine 

if aging effects had been identified for applicable components. For monitoring programs, the 

LRA states that reports of sample results were reviewed to determine if parameters were being 

maintained as required by the program. The LRA also states that program owners contributed 

evidence of program success or weakness and identified applicable self-assessments, quality 

assurance audits, peer evaluations, and NRC reviews.

LRA Section B.0.4 also describes the process for review of future plant-specific and industry 

operating experience, which is applicable to the AMPs described in LRA Sections B.1.1 

through B.1.44. The LRA states that external industry operating experience is screened, 

evaluated, and acted on to prevent or mitigate the consequences of similar age-related 

degradation. The sources of this external operating experience include NRC generic 

communications and other documents, such as reports made in accordance with 

10 CFR Part 21, “Reporting of Defects and Noncompliance,” LERs, and nonconformance 

reports. The LRA also states that internal operating experience may include items such as 

event investigations, trending reports, lessons learned from in-house events, self-assessments, 
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and the 10 CFR Part 50, Appendix B, corrective action process. In addition, the LRA states that 

the procedures for the evaluation of these sources of operating experience will remain in-place 

as GGNS continues operation through the license renewal period. These procedures 

implement two existing programs, the Operating Experience Program (OEP) and the CAP, 

which monitor, on an ongoing basis, industry and plant-specific operating experience, including, 

but not limited to, future operating experience related to the effects of aging on in-scope SCs. 

The LRA further states that the evaluations completed under the OEP and CAP ensure that the 

AMPs will continue to be effective in managing the aging effects for which they are credited.

3.0.5.2 Staff Evaluation

3.0.5.2.1 Overview

In accordance with requirements of 10 CFR 54.21(a)(3), an applicant is required to demonstrate 

that the effects of aging on SCs subject to an AMR will be adequately managed so that their 

intended functions will be maintained consistent with the CLB for the period of extended 

operation. SRP-LR, Appendix A, describes 10 elements of an acceptable AMP, and 

Element 10, “operating experience,” is described in SRP-LR Section A.1.2.3.10. Subsequent to 

receipt of the LRA, on March 16, 2012, the staff issued Final License Renewal Interim Staff 

Guidance (LR-ISG), LR-ISG-2011-05, “Ongoing Review of Operating Experience.” This LR-ISG 

provides interim revisions to the SRP-LR to clarify the staff’s acceptance criteria and review 

procedures with respect to the ongoing review of operating experience and also provides 

revisions to the GALL Report to make the AMP descriptions therein consistent with the SRP-LR 

guidance for acceptable AMPs. LR-ISG-2011-05, Appendix A, identifies changes to the 

SRP-LR and GALL Report. Specifically, LR-ISG-2011-05, Appendix A, revises the three 

operating experience criteria in SRP-LR Section A.1.2.3.10 to:

(1) Consideration of future plant-specific and industry operating experience relating to AMPs 

should be discussed. The ongoing review of operating experience may identify areas 

where AMPs should be enhanced or new AMPs developed. As such, an applicant 

should ensure that it has adequate processes to monitor and evaluate plant-specific and 

industry operating experience related to aging management to ensure that the AMPs are 

effective in managing the aging effects for which they are credited. The AMPs are 

informed by this review of operating experience on an ongoing basis, regardless of the 

AMP’s implementation schedule. The ongoing review of operating experience 

information should provide objective evidence to support the conclusion that the effects 

of aging are managed adequately so that the structure- and component- intended 

function(s) will be maintained during the period of extended operation.

(2) Currently available operating experience with existing programs should be discussed. 

The operating experience of existing programs, including past corrective actions 

resulting in program enhancements or additional programs, should be considered. A 

past failure would not necessarily invalidate an AMP 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 not been fully effective 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.
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(3) Currently available operating experience applicable to new programs should also be 

discussed. For new AMPs that have yet to be implemented at an applicant’s facility, the 

programs have not yet generated any operating experience. However, there may be 

other relevant plant-specific or generic industry operating experience that is relevant to 

the program elements, even though the operating experience was not identified through 

implementation of the new program. Thus, when developing the elements for new 

programs, an applicant should consider the impact of relevant operating experience from 

implementation of its existing AMPs and from generic industry operating experience.

SER Section 3.0.3 discusses the staff’s review of the second and third attributes, which concern 

currently available operating experience associated with existing and new programs, 

respectively. The below evaluation discusses the staff’s review of the first attribute, which 

concerns the consideration of future operating experience and applies to both existing and new 

programs.

3.0.5.2.2 Consideration of Future Operating Experience

Itemized Change No. 7 in LR-ISG-2011-05 Appendix A establishes a new SRP-LR Section A.4. 

This section provides a framework of ongoing activities to address operating experience 

concerning age-related degradation and aging management during the term of the renewed 

operating license to ensure that the effects of aging are adequately managed. The staff 

evaluated the details of the applicant’s ongoing operating experience review activities, as 

described in LRA Section B.0.4, against the staff position described in SRP-LR Section A.4.2.

Based on its review, the staff determined that LRA Section B.0.4 provides a general description 

of how the applicant gathered and considered operating experience in preparing the LRA, and 

LRA Sections B.1.1 through B.1.44 summarize the specific operating experience considered for 

each AMP. The LRA also states that the CAP and OEP will be used to evaluate operating 

experience to ensure that the AMPs will continue to be effective in managing the aging effects 

for which they are credited. However, the staff determined that the LRA does not provide 

specific details as to how the CAP and OEP will be used to monitor operating experience 

related to aging on an ongoing basis. The staff also determined that the LRA does not state 

whether new AMPs will be developed, if necessary.

By letter dated July 27, 2012, the staff issued RAI 3.0.5-1 requesting that the applicant describe 

the programmatic activities that will be used to continually identify aging issues, evaluate them, 

and, as necessary, enhance the AMPs or develop new AMPs for license renewal. The staff 

also asked the applicant to indicate whether these activities are consistent with the guidance in 

LR-ISG-2011-05, and if they are not, the staff requested the applicant to provide the basis for its 

conclusion that the programmatic activities will ensure that operating experience will be 

reviewed on an ongoing basis to address age-related degradation and aging management 

during the term of the renewed license.

The applicant responded to RAI 3.0.5-1 by letter dated August 23, 2012. The applicant 

provided further information to describe how it processes relevant site and industry operating 

experience on an ongoing basis under its CAP and OEP. The applicant stated that it uses the 

OEP to monitor industry operating experience and listed some typical industry operating 

experience sources. The applicant described the process for screening incoming operating 

experience items and initiating written reviews for issues that could have a potential impact on

the plant. The applicant also described the CAP, which is used to monitor plant-specific 

operating experience and evaluate industry operating experience relevant to the plant. A list of 
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typical plant-specific operating experience sources monitored under the CAP was also provided. 

In addition, the applicant described how age-related conditions are coded and trended. 

Evaluations of age-related conditions and extent-of-condition reviews were described, along 

with corrective actions for enhancement of AMPs or development of new AMPs. The applicant 

explained that training requirements for personnel responsible for processing operating 

experience are based on the complexity of the job performance requirements and assigned 

responsibilities. In summary, the applicant stated that it considers these activities to be 

consistent with the framework in LR-ISG-2011-05.

The staff reviewed the applicant’s response to RAI 3.0.5-1. Although the response indicates 

that the applicant’s programmatic activities for the ongoing review of operating experience are 

consistent with LR-ISG-2011-05, the staff found that the response does not fully address or is 

not clear on the extent to which these activities are consistent with each of the further review 

areas described in LR-ISG-2011-05, Appendix A, Itemized Change No. 7. Therefore, the staff 

could not confirm that the operating experience review activities are actually consistent with the 

guidance in the LR-ISG. By letter dated November 5, 2012, the staff issued RAI 3.0.5-1a 

requesting that the applicant further describe its operating experience review activities to 

demonstrate how they align with several of the further review areas in LR-ISG-2011-05. The 

specific areas on which the staff requested further information concerned the review of certain 

types of industry guidance documents, identification and trending of age-related issues in the

CAP, information considered in the operating experience evaluations, evaluation of AMP 

implementation results, training of personnel, and guidelines for reporting plant-specific 

operating experience to the industry.

By letter dated November 29, 2012, the applicant provided further information in response to 

RAI 3.0.5-1a. The staff evaluated the information provided in this response, together with the 

information provided in the applicant’s response to RAI 3.0.5-1, in accordance with the guidance 

in SRP-LR Section A.4.2 on “Acceptable Use of Existing Programs” and “Areas of Further 

Review.” The staff’s evaluations with respect to these two sections of guidance follow in SER 

Sections 3.0.5.2.3 and 3.0.5.2.4, respectively. As a result of its review of the applicant’s 

responses to RAIs 3.0.5-1 and RAI 3.0.5-1a, the staff could not determine whether the 

programmatic activities associated with the identification of age-related operating experience, 

evaluation of AMP implementation results, content of personnel training, and operating 

experience reporting were fully consistent with the guidelines in SRP-LR Section A.4.2, as 

claimed by the applicant. The staff identified these areas as the subject of Open Item 3.0.5-1. 

SER Section 3.0.5.2.4 discusses their closure.

3.0.5.2.3 Acceptable Use of Existing Programs

SRP-LR Section A.4.2 describes existing programs generally acceptable to the staff for the 

capture, processing, and evaluation of operating experience concerning age-related 

degradation and aging management during the term of a renewed operating license. The 

acceptable programs are those relied upon to meet the requirements of 10 CFR Part 50, 

Appendix B, and Item I.C.5, “Procedures for Feedback of Operating Experience to Plant Staff,” 

of NUREG-0737, “Clarification of TMI Action Plan Requirements,” dated November 1980. 

SRP-LR Section A.4.2 additionally states that, as part of meeting the requirements of 

NUREG-0737, Item I.C.5, the applicant’s operating experience program should rely on active 

participation in the Institute of Nuclear Power Operations (INPO) operating experience program 

(formerly the INPO Significant Event Evaluation and Information Network (SEE-IN) program 

endorsed in GL 82-04, “Use of INPO SEE-IN Program”).
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The response to RAI 3.0.5-1 states that the applicant uses its OEP to monitor industry operating 

experience, and the OEP implements the requirements NUREG-0737 Item I.C.5 and is 

consistent with INPO 10-006, Revision 1, “Operating Experience (OE) Program and 

Construction Experience (CE) Program Descriptions,” and INPO 97-011, “Guidelines for the 

Use of Operating Experience.” The response also states that the applicant uses its CAP to 

monitor plant-specific operating experience and evaluate industry operating experience relevant 

to the plant, and the CAP implements the requirements of 10 CFR Part 50, Appendix B, 

Criterion XVI, “Corrective Action.” Based on this information, the staff determined that the 

applicant’s existing CAP and OEP are consistent with the programs described in SRP-LR 

Section A.4.2 and therefore are generally acceptable for capturing, processing, and evaluating 

age-related operating experience.

3.0.5.2.4 Areas of Further Review

Notwithstanding the general acceptability of the applicant’s CAP and OEP, certain areas of the 

applicant’s operating experience review activities are also subject to further staff review as 

described in SRP-LR Section A.4.2. The staff’s reviews of these areas follow.

Application of Existing Programs and Procedures to the Processing of Operating Experience 

Related to Aging. SRP-LR Section A.4.2 states that the programs and procedures relied upon 

to meet the requirements of 10 CFR Part 50, Appendix B, and NUREG-0737, Item I.C.5, should 

not preclude the consideration of operating experience on age-related degradation and aging 

management. In response to RAI 3.0.5-1, the applicant stated that the CAP is used to address 

a broad range of problems and areas for improvement, such as conditions adverse to quality 

and minor problems that could be precursors to more significant events. The applicant also 

specifically stated that the CAP is used to address equipment degradation due to the effects of 

aging, including when the degradation is identified from an initial evaluation of industry operating 

experience under the OEP. Additionally, in response to RAI 3.0.5-1a, the applicant stated that 

the written definition of operating experience in the OEP does not restrict the sources of 

operating experience, and information from various internal and industry sources is identified 

and processed to obtain lessons learned applicable to managing the effects of aging.

The staff reviewed the information provided in these responses and determined that the 

applicant’s CAP and OEP would not preclude the capture and evaluation of operating 

experience related to aging because (a) the scope of the OEP covers all potential sources of 

industry operating experience, and (b) the CAP is specifically used to address age-related 

degradation and aging management issues, whether identified from a plant-specific source or 

from the review of an industry source. The applicant’s use of these programs for processing 

operating experience is therefore consistent with the guidance in SRP-LR Section A.4.2. 

SRP-LR Section A.4.2 also states that the applicant should use the option described in SRP-LR 

Appendix A.2 to expand the scope of the 10 CFR Part 50, Appendix B, program to include 

nonsafety-related structures and components. As discussed in SER Section 3.0.4, the staff 

determined that the applicant’s inclusion of nonsafety-related structures and components within 

the scope of its 10 CFR Part 50, Appendix B, program is consistent with the guidance in 

SRP-LR Appendix A.2 and therefore also consistent with the guidance in SRP-LR 

Section A.4.2.

Consideration of Industry Guidance Documents as Operating Experience. SRP-LR 

Section A.4.2 states that revisions to the GALL Report should be considered as a source of 

industry operating experience and evaluated accordingly. In response to RAI 3.0.5-1a, the 

applicant confirmed that it reviews revisions of the GALL Report as a source of industry 
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operating experience. SRP-LR Section A.4.2 also states that NRC and industry guidance 

documents and standards applicable to aging management should be considered as sources of 

operating experience. In response to RAI 3.0.5-1a, the applicant stated that the OEP does not 

restrict the review of industry operating experience to sources only from a predetermined list. In 

addition to specifically listed sources of industry operating experience, the applicant stated that 

its policies and procedures contain written plans and expectations for identifying and processing 

other sources of information, when they concern industry guidance or standards applicable to 

aging management. The staff reviewed the information provided in this response and 

determined that the applicant will consider the impacts of industry guidance documents on its 

aging management activities because the applicant’s operating experience reviews will cover 

appropriate NRC and industry guidance documents and standards applicable to aging 

management, including revisions to the GALL Report. The applicant’s consideration of industry 

guidance documents as operating experience is therefore consistent with the guidance in 

SRP-LR Section A.4.2.

Screening of Incoming Operating Experience. SRP-LR Section A.4.2 states that all incoming 

plant-specific and industry operating experience should be screened to determine whether it 

may involve age-related degradation or impacts to aging management activities. The 

applicant’s response to RAI 3.0.5-1 outlines its operating experience screening and evaluation 

process. For industry operating experience, the applicant explained that a team of operating 

experience coordinators screens incoming items for impact on the applicant’s fleet of plants. If 

the initial evaluation identifies certain conditions involving age-related issues, then further 

documentation is required as part of the CAP. The applicant stated that the CAP is used to 

evaluate both plant-specific and industry operating experience relevant to the plant, and 

extent-of-condition reviews are used to determine the scope of corrective actions, which include 

enhancement of AMPs or development of new AMPs as appropriate. The staff reviewed the

information provided in this response and determined that the applicant’s operating experience 

review processes are acceptable because they will include screening of all new operating 

experience items to identify and evaluate items that have the potential to affect the aging 

management activities. The applicant’s screening of plant-specific and industry operating 

experience is, therefore, consistent with the guidance in SRP-LR Section A.4.2.

Identification of Operating Experience Related to Aging. SRP-LR Section A.4.2 states that an 

identification code should be used in the CAP to identify operating experience concerning 

age-related degradation applicable to the plant. The SRP-LR also states that the associated 

entries should be periodically reviewed and any adverse trends should receive further 

evaluation. The applicant’s identification of age-related operating experience was one of the 

subject areas of Open Item 3.0.5-1.

In response to RAI 3.0.5-1a, the applicant stated that it periodically reviews information in its 

CAP to identify and evaluate adverse trends. The applicant also stated that aging is a 

contributing factor in SSC degradation and, therefore, issues specific only to aging are rare. As 

such, the applicant stated that it does not have trend codes specifically for identifying aging 

issues; however, the applicant indicated that it does use several trend codes to track issues in 

which aging is a factor. The applicant specifically described three such codes: (1) code “CA,” 

which is used to identify deviations from the licensing or design basis caused by the effects of 

aging or other issues, (2) code “EO,” which is used to identify equipment or system problems 

due to aging or other issues not attributed to inadequate maintenance, and (3) code “EV,” which 

is used to identify aging issues for plant buildings and structures.
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The staff reviewed the information provided in response to RAI 3.0.5-1a and determined that the 

applicant’s process for evaluating adverse trends is consistent with the guidance in SRP-LR 

Section A.4.2 because the applicant will identify such trends through periodic reviews of 

information in its CAP. However, the staff determined that the trend codes described by 

applicant are not consistent with the guidance in SRP-LR Section A.4.2 because they only cover 

general operational issues and do not provide for the comprehensive identification and 

categorization of aging specific issues for all in-scope SSCs. As such, the staff determined that 

the applicant did not have the means, at a programmatic level, to identify, track, and trend plant 

issues that are specific to aging. By letter dated March 12, 2013, the staff issued RAI 3.0.5-1b 

requesting that the applicant provide further information as to why the operating experience 

review activities provide for the adequate identification of operating experience involving agerelated degradation and aging management.

By letter dated April 15, 2013, the applicant responded to RAI 3.0.5-1b. In its response, the 

applicant reiterated its position that the trend codes and periodic review process previously 

described in its response to RAI 3.0.5-1a demonstrate consistency with the guidance in 

LR-ISG-2011-05 for identification of age-related operating experience.

The staff reviewed the applicant’s response to RAI 3.0.5-1b. The staff noted that the intent of 

LR-ISG-2011-05, which establishes SRP-LR Section A.4.2, is to use a single code or set of 

codes to specifically identify age-related issues so that an applicant can evaluate the potential 

impact that these issues may have on the effectiveness of its AMPs. Per the definitions 

provided in the applicant’s response to RAI 3.0.5-1a, code “EV” partially meets this intent 

because it specifically captures age-related issues for plant buildings and structures. However, 

the applicant did not describe similar codes that would categorically capture age-related issues 

for other in-scope SCs, such as those in mechanical or electrical systems. The applicant’s 

codes “CA” and “EO” cover these other categories of in-scope SSCs; however, the staff 

determined that the intended application of these codes is unclear because they may be used to 

identify items that are not age related, along with age-related items. By letter dated 

September 12, 2013, the staff issued RAI 3.0.5-1c. If the applicant intended to demonstrate 

consistency with the guidance in LR-ISG-2011-05, the staff requested that the applicant 

describe codes that will be used to specifically identify age-related issues. Alternatively, the 

staff asked the applicant to describe how the operating experience review activities provide for 

the adequate consideration of operating experience involving age-related degradation and aging 

management to maintain the effectiveness of the AMPs.

By letter dated October 11, 2013, the applicant responded to RAI 3.0.5-1c. The applicant stated 

that it established a new code, “FE25,” for the identification of all aging management issues at 

the plant. The staff reviewed the intended application of this code and determined that it is 

consistent with the guidance in LR-ISG-2011-05, because it provides for the specific capture of 

aging issues and categorically covers all in-scope SSCs. As such, the staff determined that the 

applicant’s activities for identifying age-related operating experience are consistent with the 

guidance in SRP-LR Section A.4.2. The staff’s concerns regarding the applicant’s identification 

of age-related operating experience, as in described in RAIs 3.0.5-1b and 3.0.5-1c, are resolved 

and the related area of Open Item 3.0.5-1 is closed.

Information Considered in Operating Experience Evaluations. SRP-LR Section A.4.2 states that 

operating experience identified as involving aging should receive further evaluation based on 

the consideration of information such as the affected SSCs, materials, environments, aging 

effects, aging mechanisms, and AMPs. The SRP-LR also states that actions should be initiated 

within the CAP to either enhance the AMPs or develop and implement new AMPs if it is found,
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through an operating experience evaluation, that the effects of aging may not be adequately 

managed. In response to RAI 3.0.5-1a, the applicant confirmed that its evaluations of agerelated operating experience include the consideration of information such as the affected 

SSCs, materials, environments, aging effects, aging mechanisms, and AMPs. Also, in response 

to RAI 3.0.5-1, the applicant stated that the CAP, which implements the requirements of 

10 CFR Part 50, Appendix B, is used to evaluate both plant-specific and industry operating 

experience relevant to the plant. The applicant further stated that, under the CAP, corrective 

actions resulting from an operating experience evaluation include the enhancement of AMPs or 

the development of new AMPs, as appropriate. The staff reviewed the information provided in 

these responses and determined that the applicant’s evaluations of age-related operating 

experience will include the assessment of appropriate information to determine potential 

impacts on the aging management activities. The staff also determined that the applicant will 

use its CAP to implement any changes necessary to manage the effects of aging, as 

determined through its operating experience evaluations. Therefore, the staff finds that the 

information considered in the applicant’s operating experience evaluations and use of its CAP to 

ensure that the effects of aging are adequately managed is consistent with the guidance in 

SRP-LR Section A.4.2.

Evaluation of AMP Implementation Results. SRP-LR Section A.4.2 states that the results of 

implementing the AMPs, such as data from inspections, tests, and analyses, should be 

evaluated regardless of whether the acceptance criteria of the particular AMP have been met. 

SRP-LR Section A.4.2 also states that actions should be initiated within the plant CAP to either 

enhance the AMPs or develop and implement new AMPs, if these evaluations indicate that the 

effects of aging may not be adequately managed. The applicant’s evaluation of AMP 

implementation results was one of the subject areas of Open Item 3.0.5-1.

In response to RAI 3.0.5-1, the applicant stated that it considers the results of inspections 

performed under the AMPs to be a source of operating experience under the CAP. The 

applicant stated that its evaluations of these results include consideration of the need to adjust 

the frequency of future inspections, whether new or different inspections are needed, and 

whether the inspections include an adequate depth and breadth of component, material, and 

environment combinations. The applicant further stated that, under the CAP, it uses 

extent-of-condition reviews to determine the scope of corrective actions, which include the 

enhancement of AMPs or the development of new AMPs, as appropriate. Additionally, in 

response to RAI 3.0.5-1a, the applicant stated that it has conservatively established the 

acceptance criteria for its AMPs to identify the thresholds for taking additional action. The 

applicant further stated that acceptable implementation results confirm the effectiveness of the 

program. In these instances, the applicant stated that an evaluation is not needed to determine 

whether changes to the AMPs are needed.

The staff reviewed the information provided in response to RAIs 3.0.5-1 and 3.0.5-1a and 

determined that, although the applicant will consider the AMP implementation results as a 

source of plant-specific operating experience, its evaluation activities are not fully consistent 

with the guidance in SRP-LR Section A.4.2 because the applicant only plans to evaluate the 

implementation results when they do not meet the applicable acceptance criteria. As such, the 

staff determined that the applicant did not have a process to assess the overall performance 

and effectiveness of the AMPs. The staff noted that not all implementation results would 

necessitate a change to an AMP, but an evaluation of acceptable implementation results could 

be used, for example, to determine the continued appropriateness of the program’s acceptance 

criteria. As part of RAI 3.0.5-1b, the staff requested that the applicant provide further 
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information as to how its assessments of AMP implementation are performed to determine if the 

effects of aging are adequately managed.

In response to RAI 3.0.5-1b, the applicant provided additional information about its approach to 

evaluating AMP implementation results. The applicant stated that it will perform periodic 

assessments of AMP implementation to evaluate the effectiveness of the AMPs. The applicant 

explained that these assessments will include focused self-assessments, independent 

assessments, external assessments, ongoing assessments, or snapshot assessments. In 

addition, the applicant stated that program health reports will be prepared to periodically monitor 

how effective the AMPs are at maintaining the material condition of components. According to 

the applicant, these assessments and reports will include evaluations of parameter trends, 

which will support decisions on whether the frequency of future inspections should be adjusted, 

whether new inspections should be established, or whether the inspection scope or acceptance 

criteria should be adjusted or expanded. The applicant stated that, if these assessments 

indicate that the effects of aging may not be adequately managed, it will initiate an action in its 

CAP to either enhance the AMPs or develop and implement new AMPs.

The staff reviewed the additional information provided in response to RAI 3.0.5-1b and 

determined that the applicant’s treatment of AMP implementation results as operating 

experience is acceptable because the applicant will evaluate these results and use the 

information to determine whether to adjust its aging management activities. The staff also 

determined the applicant’s periodic assessment activities will appropriately cover the evaluation 

of AMP implementation results, even when these results have met the applicable acceptance 

criteria of the AMPs. As such, the staff determined that the applicant’s activities for evaluating 

the AMP implementation results are consistent with the guidance in SRP-LR Section A.4.2. The 

staff’s concern regarding the applicant’s evaluation of AMP implementation results, as described 

in RAI 3.0.5-1b, is resolved and the related area of Open Item 3.0.5-1 is closed.

Training. SRP-LR Section A.4.2 states that training on age-related degradation and aging 

management should be provided to those personnel responsible for implementing the AMPs 

and those personnel that may submit, screen, assign, evaluate, or otherwise process plantspecific and industry operating experience. SRP-LR Section A.4.2 also states that the training 

should occur on a periodic basis and include provisions to accommodate the turnover of plant 

personnel. The content of the applicant’s personnel training program was one of the subject 

areas of Open Item 3.0.5-1.

In response to RAI 3.0.5-1a, the applicant described the training activities that will be associated 

with processing and evaluating operating experience. The applicant stated that it will provide 

training to those personnel who are responsible for implementing the AMPs or who submit 

operating experience to the CAP and OEP. The applicant also stated that it will provide training 

to those personnel who screen operating experience items, evaluate them, and assign or

otherwise process them for evaluation. According to the applicant, the training activities will 

include instruction on applicable references and databases; discussion of relevant codes, 

standards, inspection methods, and evaluation techniques; review of applicable operating 

experience; and demonstration of the ability to develop an inspection plan and evaluate the 

results. The applicant also stated that it will schedule this training on a recurring basis to 

accommodate the turnover of plant personnel and the need for new training content.

The staff reviewed the information provided in response to RAI 3.0.5-1a and determined that the 

scope of key personnel covered by the applicant’s training activities is consistent with the 

guidelines in SRP-LR Section A.4.2. The staff also determined that the applicant’s plans to 
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provide recurring training and training when personnel turn over are also consistent with these 

guidelines. However, the applicant did not describe how the content of the training includes 

topics on age-related degradation and aging management; therefore, it was not clear to the staff 

whether the applicant’s training activities were fully consistent with guidance in SRP-LR 

Section A.4.2. As part of RAI 3.0.5-1b, the staff requested that the applicant provide further 

information on the content of its personnel training program.

In response to RAI 3.0.5-1b, the applicant provided an outline to illustrate how its training 

activities cover topics on aging management and age-related degradation. Per this outline, the 

applicant’s training activities include a combination of classroom training, required reading, and 

mentored skills demonstrations. The response indicates that the training covers areas such as 

understanding and identifying various aging effects, knowledge of relevant industry operating 

experience documents, and knowledge of site-specific AMPs and procedures.

The staff reviewed the response to RAI 3.0.5-1b and determined that the additional information 

provided by the applicant acceptably demonstrates that its training program covers topics on 

age-related degradation and aging management. As such, the staff determined that the 

applicant’s training activities are consistent with the guidance in SRP-LR Section A.4.2. The 

staff’s concern regarding the applicant’s training activities, as in described in RAI 3.0.5-1b, is 

resolved and the related area of Open Item 3.0.5-1 is closed.

Reporting Operating Experience to the Industry. SRP-LR Section A.4.2 states that guidelines 

should be established for reporting plant-specific operating experience on age-related 

degradation and aging management to the industry. The applicant’s reporting of age-related 

operating experience was one of the subject areas of Open Item 3.0.5-1.

In response to RAI 3.0.5-1a, the applicant stated that it reports its plant-specific operating 

experience to the industry per the guidelines in INPO 12-009, “INPO Consolidated Event 

System.” The applicant stated that this reporting includes findings of root cause investigation 

reports, LERs submitted under 10 CFR 50.73, and plant event notices submitted under 

10 CFR 50.72. The applicant also stated that it submits reports after the discovery of other 

issues, including the failure of equipment and components to meet intended functions.

The staff reviewed the information provided in response to RAI 3.0.5-1a and determined that the 

applicant’s reporting of plant-specific operating experience was not consistent with the guidance 

in SRP-LR Section A.4.2 because the applicant only described general reporting criteria that are 

not specific to circumstances involving age-related degradation and aging management. As 

such, the staff determined that the applicant did not have a process to consistently identify and 

communicate this kind of operating experience. As part of RAI 3.0.5-1b, the staff requested that 

the applicant provide further information as to how its OEP includes guidelines for reporting 

age-related operating experience.

In response to RAI 3.0.5-1b, the applicant provided additional information about its process for 

reporting plant-specific operating experience. The applicant stated that its OEP includes 

specific guidelines for reporting operating experience involving age-related degradation or 

aspects of programs that manage the effects of aging. The applicant also stated that the 

reporting is accomplished in accordance with the guidelines from INPO 12-009. For example, 

the applicant stated that it reports findings from root cause investigations involving age-related 

degradation and leaks or adverse inspection findings for buried or underground piping. In 

addition, the applicant stated that INPO 12-009 includes several cause categories that cover 
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aging issues, such as “erosion/corrosion process,” “equipment aging - nonmetallic,” and 

“equipment aging - metallic.”

The staff reviewed the additional information provided in the applicant’s response to 

RAI 3.0.5-1b. The staff noted that the intent of SRP-LR Section A.4.2 is to establish reporting 

guidelines for communicating noteworthy plant-specific operating experience that specifically 

involves age-related degradation or aging management issues. However, the current reporting 

criteria in INPO 12-009 do not specifically address aging issues or only cover limited situations 

involving aging. As such, the staff determined that these criteria do not provide for the 

comprehensive identification and subsequent reporting of age-related operating experience. In 

RAI 3.0.5-1c, if the applicant intended to demonstrate consistency with the guidance in SRP-LR 

Section A.4.2, the staff requested that the applicant describe guidelines specifically for 

identifying circumstances in which plant-specific operating experience involving age-related 

degradation and aging management would be reported to the industry. Alternatively, the staff 

requested that the applicant describe how the operating experience review activities would 

provide for the adequate consideration of operating experience involving age-related 

degradation and aging management to maintain the effectiveness of the AMPs.

In response to RAI 3.0.5-1c, the applicant reiterated its position that its current procedures 

provide for the reporting of plant-specific operating experience involving age-related degradation 

and aging management, consistent with the guidance in SRP-LR Section A.4.2, because the 

procedures are in accordance with INPO 12-009. As additional support for its position, the 

applicant stated that the effectiveness of the INPO operating experience program is 

demonstrated by the numerous examples of industry operating experience involving age-related 

degradation that have been identified and reported.

The staff reviewed the applicant’s response to RAI 3.0.5-1c and determined that the additional 

information provided by the applicant does not demonstrate consistency with the guidance in 

SRP-LR Section A.4.2 regarding operating experience reporting. In particular, the applicant did 

not describe any reporting criteria beyond those specified in INPO 12-009, and the staff 

determined that this document does not currently include criteria that would categorically cover 

the reporting of noteworthy issues involving age-related degradation and aging management. In 

addition, although the INPO 12-009 cause codes identified by the applicant would cover a broad 

range of age-related issues, under the INPO process they do not constitute a set of reporting 

criteria, because they are only applied after it been determined that a given issue is reportable. 

Notwithstanding, the staff determined that it is not necessary for the applicant to establish 

operating experience reporting criteria per the guidelines of SRP-LR Section A.4.2, because the 

reporting of age-related operating experience to other licensees would not directly facilitate the 

applicant’s ability to maintain the effectiveness of its own AMPs. Therefore, such reporting is 

not needed to demonstrate that the effects of aging will be adequately managed so that the 

intended functions will remain consistent with the CLB for the period of extended operation, as 

required by 10 CFR 54.21(a)(3). As such, the staff determined that it is acceptable for the 

applicant to not be consistent with this particular area of SRP-LR Section A.4.2.

However, the staff continues to believe that it is prudent to establish specific reporting guidelines 

for noteworthy issues that are age related. Although the current reporting criteria in INPO 

12-009 do not necessarily exclude these issues, they also do not specifically cover them, either. 

Therefore, some potentially noteworthy aging issues may not be communicated, because they 

that do not fall under the current reporting guidelines. The staff notes that the industry has 

recognized this issue as a potential area for improvement in the INPO operating experience 

program, and the industry has begun an initiative to revise INPO 12-009 accordingly. A draft of 
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the revised reporting guidelines was discussed with the staff during a public meeting held on 

July 29, 2014. The staff supports this industry initiative and notes that, if the proposed changes 

are adopted, they would fulfill the intent the operating experience reporting criterion in 

LR-ISG-2011-05.

The staff finds that establishing operating experience reporting guidelines specific to age-related 

issues is a best practice and is not necessary to fulfill the requirements of 10 CFR 54.21(a)(3). 

Accordingly, the staff’s concerns regarding the applicant’s reporting of age-related operating 

experience, as in described in RAIs 3.0.5-1b and 3.0.5-1c, are resolved and the related area of 

Open Item 3.0.5-1 is closed.

Schedule for Implementing the Operating Experience Review Activities. SRP-LR Section A.4.2 

states that any enhancements to the existing operating experience review activities should be 

put in place no later than the date when the renewed operating license is issued. In 

RAI 3.0.5-1a, the staff requested that the applicant identify any such enhancements and provide 

a schedule for their implementation, including a justification if the implementation date is later

than the date when the renewed operating license is scheduled to be issued, if approved. In 

response, the applicant stated that there are no enhancements to its existing activities. The 

staff reviewed the applicant’s response and determined that the guidance in SRP-LR 

Section A.4.2 does not apply, because the applicant is currently implementing all of the 

operating experience review activities described in its LRA. Accordingly, there are 

no enhancements.

SRP-LR Section A.4.2 also states that the operating experience review activities should be 

implemented on an ongoing basis throughout the term of the renewed license. By letter dated 

August 23, 2012, as revised by letter dated October 11, 2013, the applicant amended the 

UFSAR supplement in the LRA to include a summary description of the ongoing operating 

experience review activities. As discussed in SER Section 3.0.5.3, the staff determined that this 

summary description is sufficiently comprehensive to describe the applicant’s programmatic 

activities for the ongoing review of operating experience. On issuance of a renewed license in 

accordance with 10 CFR 54.31(c), the summary description will be incorporated into the plant’s 

CLB and, at that time, the applicant will need to conduct its operating experience review 

activities accordingly. The staff finds this implementation schedule acceptable, because the 

applicant will implement the operating experience review activities on an ongoing basis 

throughout the term of the renewed operating license. This ongoing implementation is, 

therefore, consistent with the guidance in SRP-LR Section A.4.2.

3.0.5.2.5 Summary

Based on its review of the applicant’s responses to RAIs 3.0.5-1, 3.0.5-1a, 3.0.5-1b, 

and 3.0.5-1c, the staff determined that the applicant’s programmatic activities for the ongoing 

review of operating experience are consistent with the guidance in SRP-LR Section A.4.2, with 

the exception of the applicant’s operating experience reporting activities, which are an 

acceptable departure from the guidance. Therefore, the staff determined that these activities 

are acceptable for: (a) the systematic review of plant-specific and industry operating experience 

to ensure that the license renewal AMPs are and will continue to be effective in managing the 

aging effects for which they are credited, and (b) the enhancement of AMPs or development of 

new AMPs when it is determined, through the evaluation of operating experience, that the 

effects of aging may not be adequately managed. Based on completion of the staff’s review 

and the general consistency of the applicant’s operating experience review activities with the 

guidance in SRP-LR Section A.4.2, as established in LR-ISG-2011-05, the staff’s concerns 
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described in RAIs 3.0.5-1, 3.0.5-1a, 3.0.5-1b, and 3.0.5-1c are resolved. Open Item 3.0.5-1 

is closed.

3.0.5.3 UFSAR Supplement

LRA Section A.1 provides the UFSAR supplement summary description of the applicant’s 

operating experience review activities. It states that the OEP and the CAP help to ensure the 

continued effectiveness of the AMPs through evaluations of operating experience. The 

summary description states that the OEP implements the requirements of NUREG-0737, 

Item l.C.5, and that it is used to evaluate site, fleet, and industry operating experience. The 

summary description also states that the CAP implements the requirements of 10 CFR Part 50, 

Appendix B, and that it is used to evaluate and effect appropriate actions in response to 

operating experience that indicates a condition adverse to quality or a nonconformance.

SRP-LR Section A.4.2, as established in LR-ISG-2011-05, states that the programmatic 

activities for the ongoing review of plant-specific and industry operating experience concerning 

age-related degradation and aging management should be described in the UFSAR

supplement. LR-ISG-2011-05 also revises SRP-LR Table 3.0-1 to include sample summary 

description language for the UFSAR supplement. The staff reviewed the content of the 

applicant’s summary description against the content from the example in the SRP-LR. Based 

on its review, the staff determined that the LRA did not specifically describe how the CAP and 

OEP address aging, so in RAI 3.0.5-1, the staff requested that the applicant further describe 

how the activities conducted under these programs capture aging issues, evaluate them, and, 

as necessary, initiate actions to enhance the AMPs or develop new AMPs. The staff also 

requested that the applicant describe in the UFSAR supplement how operating experience will 

be reviewed on an ongoing basis to address age-related degradation and aging management 

during the period of extended operation.

In response to RAI 3.0.5-1, the applicant amended the UFSAR supplement to include a new 

LRA Section A.0.1 to describe the details of its programmatic activities for the ongoing review of 

operating experience. Based on its responses to RAIs 3.0.5-1a and 3.0.5-1b, the applicant 

subsequently amended LRA Section A.0.1 by letters dated November 29, 2012, and 

April 15, 2013, respectively. The staff reviewed the revised summary description in conjunction 

with its review of the applicant’s responses to RAIs 3.0.5-1a and 3.0.5-1b. Based on its review, 

the staff determined that the applicant’s RAI responses describe certain key operating 

experience review activities; however, these activities were not addressed in LRA Section A.0.1. 

Specifically, the staff noted that the summary description did not address: (a) the applicant’s 

plans to review future revisions of the GALL Report as a source of industry operating 

experience, and (b) that the operating experience evaluations determine potential impacts on

the aging management activities, based on consideration of the affected plant SSCs, materials, 

environments, aging effects, aging mechanisms, and AMPs. By letter dated 

September 12, 2013, the staff issued RAI 3.0.5-1d requesting that the applicant either revise 

LRA Section A.0.1 to summarize these activities or provide a justification for not including such 

a summary description in the UFSAR supplement.

By letter dated October 11, 2013, the applicant responded to RAI 3.0.5-1d by further amending 

LRA Section A.0.1 to capture its plans for reviewing future revisions of the GALL Report and the 

specific information that it will consider when evaluating operating experience items with the

potential to involve age-related degradation. The staff reviewed the content of the revised LRA

Section A.0.1 against the sample language in SRP-LR Table 3.0-1. Based on its review, the 

staff determined that the content of the applicant’s summary description, as amended by letter 
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dated October 11, 2013, is consistent with the example and also sufficiently comprehensive to 

describe the applicant’s programmatic activities for evaluating operating experience to maintain 

the effectiveness of the AMPs. Therefore, the staff finds the applicant’s UFSAR supplement 

summary description acceptable. The staff’s concern described in RAI 3.0.5-1d is resolved.

3.0.5.4 Conclusion

Based on its review of the applicant’s programmatic activities for the ongoing review of 

operating experience, the staff concludes that the applicant has demonstrated that operating 

experience will be reviewed to ensure that the effects of aging will be adequately managed so 

that the intended functions will remain 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 these activities and concludes that it provides an adequate summary description, as required 

by 10 CFR 54.21(d).

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:

• reactor vessel

• reactor vessel internals

• reactor coolant pressure boundary

• miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2)

3.1.1 Summary of Technical Information in the Application

LRA Section 3.1 provides AMR results for the reactor vessel, reactor vessel internals, and 

reactor coolant system components and component groups. LRA Table 3.1.1, “Summary of 

Aging Management Programs for the Reactor Coolant System Evaluated in Chapter IV of 

NUREG-1801,” is a summary comparison of the applicant’s AMRs with those evaluated in the 

GALL Report for the reactor vessel, reactor vessel internals, and reactor coolant system 

components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.1.2 Staff Evaluation

The staff reviewed LRA Section 3.1 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the reactor vessel, 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).

The staff conducted a review of AMRs to ensure the applicant’s claim that certain AMRs are 

consistent with the GALL Report. The staff did not repeat its review of the matters described in 
3-249

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’s 

evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s evaluation 

are documented in SER Section 3.1.2.1.

During its review, 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 

are consistent with the SRP-LR Section 3.1.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 3.1.2.2.

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 are appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.1.2.3.

For SSCs which the applicant claimed are not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

Table 3.1-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.1 and addressed in the GALL Report.

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

Coolant System Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High strength, 

low-alloy steel top 

head closure stud 

assembly exposed 

to air with potential 

for reactor coolant 

leakage (3.1.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)

Nickel alloy tubes 

and sleeves 

exposed to reactor 

coolant and 

secondary 

feedwater/steam 

(3.1.1-2)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Stainless steel or 

nickel alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-3)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)
3-250

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel pressure 

vessel support skirt 

and attachment 

welds (3.1.1-4)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)

Steel, stainless 

steel, or steel (with 

stainless steel or 

nickel alloy cladding) 

steam generator 

components, 

pressurizer relief 

tank components or 

piping components 

or bolting (3.1.1-5)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation (See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

coolant pressure 

boundary 

components: piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-6)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(See SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy reactor 

vessel components: 

flanges; nozzles; 

penetrations; safe 

ends; thermal 

sleeves; vessel

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-7)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.1)
3-251

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), or 

stainless steel; or 

nickel alloy steam 

generator 

components 

exposed to reactor 

coolant (3.1.1-8)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

RCPB piping; 

flanges; nozzles & 

safe ends; 

pressurizer shell 

heads & welds; 

heater sheaths & 

sleeves; 

penetrations; 

thermal sleeves 

exposed to reactor 

coolant (3.1.1-9)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)

Steel (with or without 

nickel-alloy or 

stainless steel 

cladding), stainless 

steel; nickel alloy 

reactor vessel 

flanges; nozzles; 

penetrations; 

pressure housings; 

safe ends; thermal 

sleeves; vessel 

shells, heads and 

welds exposed to 

reactor coolant 

(3.1.1-10)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation, and for 

Class 1 components 

environmental 

effects on fatigue are 

to be addressed 

(see SRP, 

Section 4.3 “Metal 

Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.1)
3-252

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel or stainless 

steel pump and 

valve closure bolting 

exposed to high 

temperatures and 

thermal cycles 

(3.1.1-11)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA 

evaluated for the 

period of extended 

operation; check 

ASME Code limits 

for allowable cycles 

(less than 7,000 

cycles) of thermal 

stress range (see 

SRP Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

to comply with 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.1.2.2.2)

Steel steam 

generator 

components: upper 

and lower shells, 

transition cone; new 

transition cone 

closure weld 

exposed to 

secondary feedwater 

or steam (3.1.1-12)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and, for 

Westinghouse Model 

44 and 51 S/G, if 

corrosion of the shell 

is found, additional 

inspection 

procedures are 

developed

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.2)

Steel (with or without 

stainless steel 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds 

exposed to reactor 

coolant and neutron 

flux (3.1.1-13)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement

TLAA is to be 

evaluated in 

accordance with 

Appendix G of 

10 CFR Part 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 Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.2.3(1))

Steel (with or without 

cladding) reactor 

vessel beltline shell, 

nozzles, and welds; 

safety injection 

nozzles (3.1.1-14)

Loss of fracture 

toughness due 

to neutron 

irradiation

embrittlement

Chapter XI.M31, 

“Reactor Vessel 

Surveillance”

Yes Reactor Vessel 

Surveillance

Consistent with the 

GALL Report (see 

SER 

Section 3.1.2.2.3(2))
3-253

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-15)

Reduction in 

ductility and 

fracture 

toughness due 

to neutron 

irradiation

Ductility - Reduction 

in Fracture 

Toughness is a 

TLAA to be 

evaluated for the 

period of extended 

operation (see SRP, 

Section 4.7, “Other 

Plant-Specific 

TLAAs,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.3(3))

Stainless steel and 

nickel alloy top head 

enclosure vessel 

flange leak detection 

line (3.1.1-16)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

A plant-specific AMP

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 Water Chemistry 

Control – BWR 

Program and 

One-Time 

Inspection

See SER 

Section 3.1.2.2.4(1))

Stainless steel 

isolation condenser 

components 

exposed to reactor 

coolant (3.1.1-17)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

for BWR water, and 

a plant-specific 

verification program

Yes Not applicable Not applicable to 

GGNS (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-heat-input 

welding process 

exposed to reactor 

coolant (3.1.1-18)

Crack growth 

due to cyclic 

loading

Growth of 

intergranular 

separations is a 

TLAA evaluated for 

the period of 

extended operation. 

The Standard 

Review Plan, 

Section 4.7, “Other 

Plant-Specific 

Time-Limited Aging 

Analysis,” provides 

guidance for meeting 

the requirements of 

10 CFR 54.21(c))

Yes Not applicable See SER 

Section 3.1.2.2.5)
3-254

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

reactor vessel 

closure head flange 

leak-detection line 

and bottom-mounted 

instrument guide 

tubes (external to 

reactor vessel) 

(3.1.1-19)

Cracking due to 

stress corrosion 

cracking

A plant-specific AMP

is to be evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.6(1))

Cast austenitic 

stainless steel 

Class 1 piping, 

piping components, 

and piping elements 

exposed to reactor 

coolant (3.1.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

and, for CASS 

components that do 

not meet the 

NUREG-0313 

guidelines, a plantspecific AMP

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.6(2))

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-21)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components. 

The ISI program is to 

be augmented by a 

plant-specific 

verification program

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.2.7)

Steel steam 

generator feedwater 

impingement plate 

and support exposed 

to secondary 

feedwater (3.1.1-22)

Loss of material 

due to erosion

A plant-specific AMP

is to be evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.8)

Stainless steel or 

nickel alloy PWR 

reactor vessel 

internal components 

(inaccessible 

locations) exposed 

to reactor coolant 

and neutron flux 

(3.1.1-23)

Cracking due to 

stress corrosion 

cracking and 

irradiation--assis

ted stress 

corrosion 

cracking

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.9)
3-255

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel alloy PWR 

reactor vessel 

internal components 

(inaccessible 

locations) exposed 

to reactor coolant 

and neutron flux 

(3.1.1-24)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement; 

or changes in 

dimension due 

to void swelling; 

or loss of 

preload due to 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.10)

Steel (with 

nickel-alloy cladding) 

or nickel alloy steam 

generator primary 

side components: 

divider plate and 

tube-to-tube sheet 

welds exposed to 

reactor coolant 

(3.1.1-25)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

Yes Not applicable Not applicable to 

BWRs (see SER 

Sections

3.1.2.2.11(1) and 

3.1.2.2.11(2))

Stainless steel 

Combustion 

Engineering core 

support barrel 

assembly: lower 

flange weld exposed 

to reactor coolant 

and neutron flux. 

Upper internals 

assembly: fuel 

alignment plate 

(applicable to plants 

with core shrouds 

assembled with full 

height shroud plates) 

exposed to reactor 

coolant and neutron 

flux. Lower support 

structure: core 

support plate 

(applicable to plants 

with a core support 

plate) exposed to 

reactor coolant and 

neutron flux 

(3.1.1-26)

Cracking due to 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry,” if 

fatigue life cannot be 

confirmed by TLAA

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.12)
3-256

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins exposed to 

reactor coolant and 

neutron flux 

(3.1.1-27)

Cracking due to 

stress corrosion 

cracking and 

fatigue

A plant-specific AMP

is to be evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.13)

Nickel alloy 

Westinghouse 

control rod guide 

tube assemblies, 

guide tube support 

pins, and Zircaloy-4 

Combustion 

Engineering in-core

instrumentation 

thimble tubes 

exposed to reactor 

coolant and neutron 

flux (3.1.1-28)

Loss of material 

due to wear

A plant-specific AMP

is to be evaluated

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.2.14)

Nickel alloy core 

shroud and core 

plate access hole 

cover (welded 

covers) exposed to 

reactor coolant 

(3.1.1-29)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation--assis

ted stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry,”

and for BWRs with a 

crevice in the access 

hole covers, 

augmented 

inspection using UT 

or other acceptable 

techniques

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel alloy 

penetration: drain 

line exposed to 

reactor coolant 

(3.1.1-30)

Cracking due to 

stress corrosion 

cracking, 

intergranular

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)

Steel and stainless 

steel isolation 

condenser 

components 

exposed to reactor 

coolant (3.1.1-31)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD,” and 

Chapter XI.M2,

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)
3-257

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel alloy, or CASS 

reactor vessel 

internals, core 

support structure, 

exposed to reactor 

coolant and neutron 

flux (3.1.1-32)

Cracking, or 

loss of material 

due to wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding Class 1 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-33)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding pressurizer 

relief tank (tank shell 

and heads, flanges, 

nozzles) exposed to 

treated borated 

water >60 °C 

(>140 °F) (3.1.1-34)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

ASME components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

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 (3.1.1-35)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No, Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel, stainless steel 

pressurizer integral 

support exposed to 

air with metal 

temperature up to 

288 °C (550 °F) 

(3.1.1-36)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel reactor vessel 

flange (3.1.1-37)

Loss of material 

due to wear

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-258

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Cast austenitic 

stainless steel 

Class 1 pump 

casings, and valve 

bodies and bonnets 

exposed to reactor 

coolant >250 °C 

(>482 °F) 

(3.1.1-38)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components.

For pump casings 

and valve bodies, 

screening for 

susceptibility to 

thermal aging is not 

necessary.

No Inservice 

Inspection

Consistent with the 

GALL Report

Steel, stainless 

steel, or steel with 

stainless steel 

cladding Class 1 

piping, fittings and 

branch connections 

< NPS 4 exposed to 

reactor coolant 

(3.1.1-39)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking (for 

stainless steel 

only), and 

thermal, 

mechanical, and 

vibratory loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

Chapter XI.M2, 

“Water Chemistry,”

and XI.M35, 

“One-Time 

Inspection of ASME 

Code Class 1 

Small-bore Piping”

No Inservice 

Inspection, Water 

Chemistry 

Control – BWR, 

and One-Time 

Inspection –

Small-Bore 

Piping

Consistent with the 

GALL Report

Steel with stainless 

steel or nickel alloy 

cladding; or stainless 

steel pressurizer 

components 

exposed to reactor 

coolant (3.1.1-40)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection,

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy core 

support pads; core 

guide lugs exposed 

to reactor coolant 

(3.1.1-40x)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy core 

shroud and core 

plate access hole 

cover (mechanical 

covers) exposed to 

reactor coolant 

(3.1.1-41)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiation--assis

ted stress 

corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)
3-259

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel with stainless 

steel or nickel alloy 

cladding or stainless 

steel primary side 

components; steam 

generator upper and 

lower heads, and 

tube sheet weld; or 

pressurizer 

components 

exposed to reactor 

coolant (3.1.1-42)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion

cracking

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel-alloy reactor 

vessel internals 

exposed to reactor 

coolant (3.1.1-43)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 1 components, 

and Chapter XI.M2, 

“Water Chemistry”

No Inservice 

Inspection, Water 

Chemistry 

Control – BWR, 

and One-Time 

Inspection –

Small-Bore 

Piping

Consistent with the 

GALL Report

Steel steam 

generator secondary 

manways and 

handholds (cover 

only) exposed to air 

with leaking 

secondary-side 

water and/or steam 

(3.1.1-44)

Loss of material 

due to erosion

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD” for 

Class 2 components

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy and

steel with 

nickel-alloy cladding 

reactor coolant 

pressure boundary 

components 

exposed to reactor 

coolant (3.1.1-45)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material Due 

to Boric 

Acid-induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-260

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel, 

nickel-alloy, 

nickel-alloy welds 

and/or buttering 

control rod drive 

head penetration 

pressure housing or 

nozzles safe ends 

and welds (inlet, 

outlet, safety 

injection) exposed to 

reactor coolant 

(3.1.1-46)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry,” and, for 

nickel-alloy, Chapter 

XI.M11B, “Cracking 

of Nickel-Alloy 

Components and 

Loss of Material Due 

to Boric 

Acid-induced 

corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel, 

nickel-alloy control 

rod drive head 

penetration pressure 

housing exposed to 

reactor coolant 

(3.1.1-47)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M1, 

“ASME Section XI 

ISI, IWB, IWC & 

IWD,” and Chapter 

XI.M2, “Water 

Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel external 

surfaces: reactor 

vessel top head, 

reactor vessel 

bottom head, reactor 

coolant pressure 

boundary piping or 

components 

adjacent to dissimilar 

metal (Alloy 82/182) 

welds exposed to air 

with borated water 

leakage (3.1.1-48)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion,” and 

Chapter XI.M11B, 

“Cracking of 

Nickel-Alloy 

Components and 

Loss of Material Due 

to Boric 

Acid-Induced 

Corrosion in RCPB 

Components (PWRs 

Only)”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel reactor coolant 

pressure boundary 

external surfaces or 

closure bolting 

exposed to air with 

borated water 

leakage (3.1.1-49)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (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) (3.1.1-50)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not applicable See SER 

Section 3.1.2.1.1
3-261

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel-alloy B&W

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-51)

Cracking due to 

stress corrosion 

cracking, 

irradiation--assis

ted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-52)

Cracking due to 

stress corrosion 

cracking, 

irradiation--assis

ted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Westinghouse 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-53)

Cracking due to 

stress corrosion 

cracking, 

irradiation--assis

ted stress 

corrosion 

cracking, or 

fatigue

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

bottom mounted 

instrument system 

flux thimble tubes 

(with or without 

chrome plating) 

exposed to reactor 

coolant and neutron 

flux (3.1.1-54)

Loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals,” and 

Chapter XI.M37, 

“Flux Thimble Tube 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

thermal shield 

assembly, thermal 

shield flexures 

exposed to reactor 

coolant and neutron 

flux (3.1.1-55)

Cracking due to 

fatigue; Loss of 

material due to 

wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Combustion 

Engineering reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-56)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement; 

or changes in 

dimension due 

to void swelling; 

or loss of 

preload due to 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-262

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel or 

nickel-alloy B&W

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-58)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement; 

or changes in 

dimension due 

to void swelling; 

or loss of 

preload due to 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy 

Westinghouse 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-59)

Loss of fracture 

toughness due 

to neutron 

irradiation 

embrittlement; 

or changes in 

dimension due 

to void swelling; 

or loss of 

preload due to 

thermal and 

irradiation 

enhanced stress 

relaxation; or 

loss of material 

due to wear

Chapter XI.M16A, 

“PWR Vessel 

Internals”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to reactor 

coolant (3.1.1-60)

Wall thinning 

due to 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Flow-Accelerated 

Corrosion

Consistent with the 

GALL Report

Steel steam 

generator steam 

nozzle and safe end, 

feedwater nozzle 

and safe end, AFW 

nozzles and safe 

ends exposed to 

secondary 

feedwater/steam 

(3.1.1-61)

Wall thinning 

due to 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-263

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-62)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel or stainless 

steel closure bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-63)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion or 

wear

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air –

indoor uncontrolled 

(3.1.1-64)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-65)

Loss of material 

due to wear

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength, low 

alloy steel, or 

stainless steel 

closure bolting; 

stainless steel 

control rod drive 

head penetration 

flange bolting 

exposed to air with 

reactor coolant 

leakage (3.1.1-66)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel or stainless 

steel closure bolting 

exposed to air –

indoor with potential 

for reactor coolant 

leakage (3.1.1-67)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Nickel alloy steam 

generator tubes 

exposed to 

secondary feedwater 

or steam (3.1.1-68)

Changes in 

dimension 

(“denting”) due 

to corrosion of 

carbon steel 

tube support 

plate

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-264

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater

or steam (3.1.1-69)

Cracking due to 

outer diameter 

stress corrosion 

cracking and 

intergranular 

attack

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes, 

repair sleeves, and 

tube plugs exposed 

to reactor coolant 

(3.1.1-70)

Cracking due to 

primary water 

stress corrosion 

cracking

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-71)

Cracking due to 

stress corrosion 

cracking or 

other 

mechanism(s); 

loss of material 

due general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator tube 

support plate, tube 

bundle wrapper, 

supports, and 

mounting hardware 

exposed to 

secondary feedwater 

or steam (3.1.1-72)

Loss of material 

due to erosion, 

general, pitting, 

and crevice 

corrosion, 

ligament 

cracking due to 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

phosphate chemistry 

in secondary 

feedwater or steam 

(3.1.1-73)

Loss of material 

due to wastage 

and pitting 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator upper 

assembly and 

separators including 

feedwater inlet ring 

and support exposed 

to secondary 

feedwater or steam 

(3.1.1-74)

Wall thinning 

due to 

flow-accelerated 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator tube 

support lattice bars 

exposed to 

secondary feedwater 

or steam (3.1.1-75)

Wall thinning 

due to 

flow-accelerated 

corrosion and 

general 

corrosion

Chapter XI.M19, 

“Steam Generators,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-265

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel, chrome plated 

steel, stainless steel, 

nickel alloy steam 

generator U-bend 

supports including 

anti-vibration bars 

exposed to 

secondary feedwater 

or steam (3.1.1-76)

Loss of material 

due to fretting

Chapter XI.M19, 

“Steam Generators”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator tubes and 

sleeves exposed to 

secondary feedwater

or steam (3.1.1-77)

Loss of material 

due to wear and 

fretting

Chapter XI.M19, 

“Steam Generators”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Nickel alloy steam 

generator 

components such as 

secondary side 

nozzles (vent, drain, 

and instrumentation) 

exposed to 

secondary feedwater 

or steam (3.1.1-78)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection,” or 

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD.”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and 

nickel-alloy reactor 

coolant pressure 

boundary 

components 

exposed to reactor 

coolant (3.1.1-79)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection

See SER 

Section 3.2.1.1

Stainless steel or 

steel with stainless 

steel cladding 

pressurizer relief 

tank: tank shell and 

heads, flanges, 

nozzles 

(none-ASME 

Section XI 

components) 

exposed to treated 

borated water 

>60 °C (>140 °F) 

(3.1.1-80)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-81)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-266

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy 

pressurizer spray 

head exposed to 

reactor coolant 

(3.1.1-82)

Cracking due to 

stress corrosion 

cracking, 

primary water 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel steam 

generator shell 

assembly exposed 

to secondary 

feedwater or steam 

(3.1.1-83)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Steel top head 

enclosure (without 

cladding) top head 

nozzles (vent, top 

head spray or RCIC, 

and spare) exposed 

to reactor coolant 

(3.1.1-84)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

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 

exposed to reactor 

coolant (3.1.1-85)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

steam generator 

primary side divider 

plate exposed to 

reactor coolant 

(3.1.1-86)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel or 

nickel-alloy PWR 

reactor internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-87)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel; steel 

with nickel-alloy or 

stainless steel 

cladding; and 

nickel-alloy reactor 

coolant pressure 

boundary 

components 

exposed to reactor 

coolant (3.1.1-88)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)
3-267

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-89)

Loss of material 

due to general,

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Copper-alloy piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-90)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-91)

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (BWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Reactor Head 

Closure Studs

Consistent with the 

GALL Report

High-strength low 

alloy steel closure 

head stud assembly 

exposed to air with 

potential for reactor 

coolant leakage 

(3.1.1-92)

Cracking due to 

stress corrosion 

cracking; loss of 

material due to 

general, pitting, 

and crevice 

corrosion, or 

wear (PWR)

Chapter XI.M3, 

“Reactor Head 

Closure Stud 

Bolting”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Copper alloy >15% 

Zn or > 8% Al piping, 

piping components, 

and piping elements 

exposed to closed 

cycle cooling water 

(3.1.1-93)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching “

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.1.2.1.1)

Stainless steel and 

nickel alloy vessel 

shell attachment 

welds exposed to 

reactor coolant 

(3.1.1-94)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M4, 

“BWR Vessel ID 

Attachment Welds,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel ID 

Attachment 

Welds and Water 

Chemistry

Control – BWR 

Consistent with the 

GALL Report

Steel (with or without 

stainless steel 

cladding) feedwater 

nozzles exposed to 

reactor coolant 

(3.1.1-95)

Cracking due to 

cyclic loading

Chapter XI.M5, 

“BWR Feedwater 

Nozzle”

No BWR Feedwater 

Nozzle

Consistent with the 

GALL Report

Steel (with or without 

stainless steel 

cladding) control rod 

drive return line 

nozzles exposed to 

reactor coolant 

(3.1.1-96)

Cracking due to 

cyclic loading

Chapter XI.M6, 

“BWR Control Rod 

Drive Return Line 

Nozzle”

No Not applicable Not applicable to

GGNS (see SER 

Section 3.2.1.1)
3-268

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy piping, 

piping components, 

and piping elements 

greater than or equal 

to 4 NPS; nozzle 

safe ends and 

associated welds 

(3.1.1-97)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR Stress 

Corrosion 

Cracking, Water 

Chemistry 

Control – BWR, 

Inservice 

Inspection, and 

BWR CRD 

Return Line 

Nozzle

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.2)

Stainless steel or 

nickel alloy 

penetrations: 

instrumentation and 

standby liquid 

control exposed to 

reactor coolant 

(3.1.1-98)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, cyclic 

loading

Chapter XI.M8, 

“BWR Penetrations,”

and Chapter XI.M2, 

“Water Chemistry”

No BWR 

Penetrations and 

Water Chemistry

Control – BWR, 

and BWR Vessel 

Internals

Consistent with the 

GALL Report

(see SER 

Section 3.1.2.1.3)

Cast austenitic 

stainless steel; PH 

martensitic stainless 

steel; martensitic 

stainless steel; 

X-750 alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-99)

Loss of fracture 

toughness due 

to thermal aging 

and neutron 

irradiation 

embrittlement

Chapter XI.M9, 

“BWR Vessel 

Internals”

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel 

reactor vessel 

internals 

components (jet 

pump wedge 

surface) exposed to 

reactor coolant 

(3.1.1-100)

Loss of material 

due to wear

Chapter XI.M9, 

“BWR Vessel 

Internals”

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel 

steam dryers 

exposed to reactor 

coolant (3.1.1-101)

Cracking due to 

flow-induced 

vibration

Chapter XI.M9, 

“BWR Vessel 

Internals” for steam 

dryer

No BWR Vessel 

Internals

Consistent with the 

GALL Report

Stainless steel fuel 

supports and control 

rod drive assemblies 

control rod drive 

housing exposed to 

reactor coolant 

(3.1.1-102)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry

Control – BWR

Consistent with the 

GALL Report
3-269

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism

Recommended 

AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel and 

nickel alloy reactor 

internal components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-103)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking, 

irradiationassisted stress 

corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals,” and 

Chapter XI.M2, 

“Water Chemistry”

No BWR Vessel 

Internals and 

Water Chemistry 

Control – BWR

Consistent with the 

GALL Report

X-750 alloy reactor 

vessel internal 

components 

exposed to reactor 

coolant and neutron 

flux (3.1.1-104)

Cracking due to 

intergranular 

stress corrosion 

cracking

Chapter XI.M9, 

“BWR Vessel 

Internals” for core 

plate, and Chapter 

XI.M2, “Water 

Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)

Steel piping, piping 

components, and 

piping element 

exposed to concrete 

(3.1.1-105)

None None, provided 

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and 2) plant

operating experience 

indicates no 

degradation of the 

concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

GGNS (see SER 

Section 3.1.2.1.1)

Nickel alloy piping, 

piping components, 

and piping element 

exposed to air –

indoor, uncontrolled, 

or air with borated 

water leakage 

(3.1.1-106)

None None NA None Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping element 

exposed to gas, 

concrete, air with 

borated water 

leakage, air –

indoors, uncontrolled 

(3.1.1-107)

None None NA None Consistent with the 

GALL Report

The staff’s review of the reactor vessel, reactor vessel internals, and reactor coolant system 

component groups followed any one of several approaches. One approach, documented in 

SER Section 3.1.2.1, reviewed AMR results for components that the applicant indicated are 

consistent with the GALL Report and require no further evaluation. Another approach, 
3-270

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, reactor 

vessel internals, 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 RV, RVI, and RCS components:

• Bolting Integrity

• BWR CRD Return Line Nozzle

• BWR Feedwater Nozzle

• BWR Penetrations

• BWR Stress Corrosion Cracking

• BWR Vessel ID Attachment Welds

• BWR Vessel Internals

• External Surfaces Monitoring

• Flow-Accelerated Corrosion

• Inservice Inspection

• Internal Surfaces in Miscellaneous Piping and Ducting Components

• Oil Analysis

• One-Time Inspection

• One-Time Inspection – Small-Bore Piping

• Reactor Head Closure Studs

• Reactor Vessel Surveillance

• Selective Leaching

• Water Chemistry Control – BWR

• Water Chemistry Control – Closed Treated Water Systems

LRA Tables 3.1.2-1 through 3.1.2-4 summarize AMRs for the reactor vessel, internals and 

reactor coolant system components and indicate AMRs claimed to be consistent with the 

GALL Report.

The staff reviewed the information in the LRA. The staff did not repeat its review of the matters 

described in the GALL Report; however, the staff did verify that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluation follows.

3.1.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.1.1, items 3.1.1-32 through 3.1.1-37, 3.1.1-40, 3.1.1-42, 3.1.1-44 through

3.1.1-49, 3.1.1-51 through 3.1.1-59, 3.1.1-61, 3.1.1-64 through 3.1.1-66, 3.1.1-68 through 

3.1.1-78, 31.1.-80 through 3.1.1-83, 3.1.1-86 through 3.1.1-90, 3.1.1-92, and 3.1.1-93, the 

applicant claimed that the corresponding AMR items in the GALL Report are not applicable 

because the associated items are only applicable to PWRs. The staff reviewed the SRP-LR, 

confirmed these items only apply to PWRs, and finds that these items are not applicable to 

GGNS, which is a BWR.
3-271

For LRA Table 3.1.1, items 3.1.1-29, 3.1.1-31, 3.1.1-35, 3.1.1-36, 3.1.1-41, 3.1.1-96, 3.1.1-104, 

3.1.1-105, the applicant claimed that the corresponding items in the GALL Report are not 

applicable. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA 

does not have any AMR results applicable for these items.

For LRA Table 3.1.1, item 3.1.1-30, the applicant stated this item is not applicable because the 

applicant’s reactor pressure vessel does not have a stainless steel or nickel alloy drain 

penetration. The staff reviewed the LRA and UFSAR and confirmed that the applicant’s LRA 

does not have any AMR results that are applicable for this item.

LRA Table 3.1.1, item 3.1.1-50 addresses cast austenitic stainless steel (CASS) Class 1 piping,

piping component, and piping elements and CRD pressure housings exposed to a reactor 

coolant greater than 250 oC (greater than 482 oF) environment. The GALL Report recommends 

GALL Report AMP Chapter XI.M12, “Thermal Aging Embrittlement of Cast Austenitic Stainless 

Steel (CASS),” to manage loss of fracture toughness due to thermal aging embrittlement for this 

component group.

The applicant stated that this item was not used for the LRA. The applicant stated that the only 

CASS components in the GGNS RCS are: (a) CASS pump casing; (b) CASS valve bodies 

greater than or equal to 4-inches NPS; and (c) the CASS main steam line flow elements 

(referred as flow restrictors in the UFSAR). The applicant stated that it manages loss of fracture 

toughness due to thermal aging embrittlement in the applicable CASS pump casings and valve 

bodies using LRA AMR item 3.1.1-38 and the applicant’s Inservice Inspection Program (LRA 

AMP B.1.23). The staff evaluated the applicant’s claim for this basis and finds it to be 

acceptable because it is consistent with the NRC recommended criteria for CASS pump casings 

and valve bodies in AMR item 38 of SRP-LR Table 3.1-1 and in GALL AMR item IV.C1.R-08.

The applicant also stated that AMR item 50 of SRP-LR Table 3.1-1 was not used for the 

evaluation of the CASS main steam line flow elements. The applicant stated that these CASS 

flow elements were made from CF8 CASS materials. However, the applicant clarified that loss 

of fracture toughness due to thermal aging is not an applicable aging effect requiring 

management (AERM) for these flow elements because the components were fabricated using a 

centrifugally cast fabrication process. The NRC’s recommended basis for the program element 

criteria in GALL Report AMP XI.M12 and for determining when thermal aging embrittlement 

needs to be age-managed in CASS components is given in the NRC’s evaluation on License 

Renewal Issue No. 98-0030, “Thermal Aging Embrittlement of Cast Austenitic Stainless Steel 

Components.” In this document, the NRC identifies that centrifugally CASS materials with a 

maximum molybdenum (Mo) contents of 0.5 Wt. percent are not susceptible to the phenomenon 

of thermal aging embrittlement. The staff noted that in GALL Report AMP XI.M12, the staff 

identifies that CF8 materials are low-Mo CASS materials that conform to this criteria basis. The 

staff also confirmed, with review of the UFSAR, that the main steam line flow elements are 

made from CASS CF8 materials (i.e., cast 304 stainless steel materials meeting ASTM A351 

alloying requirements). Thus, based on this review, the staff evaluated the applicant’s claim and 

finds it to be acceptable because the staff has confirmed that: (a) the main steam flow elements 

(restrictors) are made from centrifugally cast CF8 materials with a maximum Mo content of 

0.5 Wt percent; and (b) consistent with the criteria in GALL Report AMP XI.M12 and the 

evaluation in License Renewal Issue No. 98-0030, loss of fracture toughness due to thermal 

aging embrittlement is not an AERM for centrifugally cast CF8 materials.

LRA Table 3.1.1, item 3.1.1-62, addresses high-strength, low alloy steel, or stainless steel 

closure bolting and stainless steel CRD head penetration flange bolting exposed to air with 
3-272

reactor coolant leakage. The GALL Report recommends GALL Report AMP XI.M18 “Bolting 

Integrity” program to manage cracking due to SCC for this component group. The applicant 

stated that this item is not applicable because it is only applicable to PWR plants. The staff 

lacked sufficient information to evaluate the applicant’s claim because although the SRP-LR 

states that item 3.1.1-62 is applicable to PWRs, the applicant has in-scope carbon and low alloy 

steel bolting exposed to air with reactor coolant leakage that may be susceptible to cracking due 

to SCC. The staff noted that the applicant is managing these items for loss of material and loss 

of preload, but not cracking due to SCC. By letter dated May 24, 2012, the staff issued

RAI 3.1.1.62-1 requesting that the applicant state the basis for why cracking due to SCC is not 

applicable to in-scope carbon and low alloy steel closure bolting exposed to air with reactor

coolant leakage (external) in the RCS.

In its response dated June 22, 2012, the applicant stated that since the GALL Report does not 

include any listings for high-strength steel bolting in the BWR RCS tables, the ESF Table V.E, 

External Surfaces of Components and Miscellaneous Bolting, was used for comparison. As a 

result, high-strength, low-alloy steel closure bolting is evaluated with the RV and is listed in LRA

Table 3.1.2-1 and managed for cracking using the Bolting Integrity Program.

The staff finds the applicant’s response acceptable because the applicant has credited the 

Bolting Integrity Program with managing cracking for high-strength, low-alloy steel closure 

bolting, the material, environment, aging effect (MEA) combination described by item 3.1.1-62 is 

managed through another AMR item, and there are no other in-scope stainless steel or highstrength carbon or low-alloy steel bolts exposed to air with reactor coolant leakage in the RCS

susceptible to SCC, other than reactor head closure studs managed separately for aging effects 

by the Reactor Head Closure Studs Program. The staff’s concern described in RAI 3.1.1.62-1 

is resolved.

LRA Table 3.1.1, item 3.1.1-79 also addresses CASS Class 1 piping, piping component, and 

piping elements and CRD pressure housings exposed to a reactor coolant greater than 250 °C 

(greater than 482 °F) environment. The GALL Report recommends GALL Report AMP 

Chapter XI.M2, “Water Chemistry,” and Chapter XI.M32, “One-Time Inspection” to manage loss 

of material for this component group, but this is only applicable to loss of material initiated solely 

by a corrosive or chemically related aging mechanism, such as general corrosion, pitting 

corrosion, or crevice corrosion. In contrast to this, UFSAR Section 5.4.4.3 identifies that the 

applicant selected the CF8 CASS materials for the main steam line flow elements based on 

their inherent resistance to loss of material by erosion-corrosion mechanism. The staff noted 

that in LRA Section 4.7.1, the applicant included its TLAA for managing 

erosion-corrosion-induced loss of material in the main steam line flow elements; however, the 

applicant did not include an AMR item in LRA Table 3.1.2-3 for these flow elements that 

credited the applicable TLAA on erosion-corrosion for managing loss of material in the main 

steam line flow elements by an erosion-corrosion mechanism.

By letter dated September 7, 2012, the staff issued RAI 4.7.1-2, requesting justification on why 

LRA Table 3.1.2-3 did not have an AMR item for these flow elements that credited the TLAA on 

erosion-corrosion of the main steam line flow elements for managing loss of material in the 

components by an erosion-corrosion mechanism.

In its response dated October 2, 2012, the applicant revised LRA Table 3.1.2-3 by adding an 

AMR item for loss of material due to erosion of the flow element to indicate that it is being 

managed through a TLAA. The staff finds this response acceptable because the LRA now 

provides the aging management method used by GGNS to demonstrate that the effects of aging 
3-273

(i.e., loss of material due to erosion) will be adequately managed for the main steam line flow 

elements (flow restrictors). The staff’s concern described in RAI 4.7.1-2 is resolved.

3.1.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.1.1, item 3.1.1-43 addresses nickel-alloy and stainless steel RVI components 

exposed to reactor coolant which are being managed for loss of material due to pitting and 

crevice corrosion. The LRA credits the Water Chemistry Program and the One-Time Inspection 

Program to manage the aging effect. The GALL Report recommends GALL Report AMP XI.M1, 

“ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD,” and GALL Report 

AMP XI.M2, “Water Chemistry,” to ensure that these aging effects are adequately managed. 

The associated AMR items cite generic note E, indicating that the LRA AMR is consistent with 

the GALL Report item for material, environment, and aging effect, but a different AMP is 

credited.

For those items associated with generic note E, GALL Report AMP XI.M1 recommends using 

periodic visual, surface, and/or volumetric examination and leakage testing along with GALL 

Report AMP XI.M2, which recommends monitoring and controlling known detrimental 

contaminants in accordance with the recommendations of BWRVIP-130 to manage the aging of 

this item. In its review of components associated with LRA Table 3.1.1, item 43, for which the 

applicant cited generic note E, the staff noted that the One-Time Inspection Program, consistent 

with GALL Report AMP XI.M32, is substituted for the ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program because it proposes to manage the aging of nickelalloy and stainless steel RVI components through a one-time verification that pitting and crevice

corrosion is not occurring or that it is occurring, but at such a slow rate that it does not affect the 

component’s or structure’s intended function during the period of expended operation. The 

staff’s evaluation of the applicant’s Water Chemistry and One-Time Inspection Programs are 

documented in SER Sections 3.0.3.1.41 and 3.0.3.1.32, respectively. The staff noted that the 

Water Chemistry Program includes controls of chemistry parameters which create an 

environment that is not conducive for loss of material to occur.

In its review of components associated with item 3.1.1-43, the staff finds the applicant’s 

proposal to manage aging using the Water Chemistry Program and the One-Time Inspection 

Program acceptable because: (1) the applicant’s use of the Water Chemistry Program creates 

an environment that is not conducive for loss of material to occur and is consistent with the 

recommendations of the GALL Report, and (2) the One-Time Inspection Program will provide 

augmented inspections for components that are not already covered by the ISI and BWRVIP 

programs, but are isolated from the flow stream for extended periods and would be susceptible 

to the gradual accumulation or concentration of agents that promote pitting and crevice 

corrosion, verifying that unacceptable degradation is not occurring. The One-Time Inspection 

Program may also trigger additional actions that ensure the intended functions of affected 

components are maintained during the period of extended operation.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that 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).
3-274

3.1.2.1.3 Cracking Due to Stress Corrosion Cracking and Intergranular Stress Corrosion 

Cracking

LRA Table 3.1.1, item 3.1.1-97 addresses stainless steel and nickel alloy piping, piping 

components, and piping elements greater than or equal to 4 NPS and nozzle safe ends and 

associated welds exposed to reactor coolant. The GALL Report recommends GALL Report

AMP XI.M7, “BWR Stress Corrosion Cracking,” and AMP XI.M2, “Water Chemistry,” to ensure 

that cracking due to SCC and intergranular stress corrosion cracking (IGSCC) is adequately 

managed for this component group.

In LRA Table 3.1.2-3, the applicant cited generic note A for the AMR items that address piping, 

valve bodies, pump casings, and thermowells. For these AMR items, the applicant credited the 

BWR Stress Corrosion Cracking Program, Water Chemistry Control – BWR Program, and 

Inservice Inspection Program to manage cracking due to SCC and IGSCC.

In LRA Table 3.1.2-1, the applicant also cited generic note A for the AMR items that address RV

nozzle safe ends and extensions, and RV nozzle thermal sleeves and thermal sleeve 

extensions. For these AMR items, the applicant credited the BWR Stress Corrosion Cracking 

Program and Water Chemistry Control – BWR Program to manage cracking due to SCC and 

IGSCC.

In its review, the staff noted that the inspections described in GALL Report AMP XI.M7, are 

mainly based on the guidance in GL 88-01, “NRC Position on Intergranular Stress Corrosion 

Cracking (IGSCC) In BWR Austenitic Stainless Steel Piping,” issued January 1988, which 

addresses inspections of piping and piping welds. Therefore, it was not clear to the staff what 

inspections are performed on valve bodies, pump casings, thermowells, and RV nozzle thermal

sleeves and thermal sleeve extensions as part of the applicant’s BWR Stress Corrosion 

Cracking Program.

By letter dated April 3, 2012, the staff issued RAI B.1.9-2 requesting that the applicant identify 

the types of inspections performed on the following components in accordance with the 

applicant’s BWR Stress Corrosion Cracking Program: (1) stainless steel sleeves and nickel 

alloy thermal sleeve extensions of RV nozzles (recirculation inlet, CS inlet, RHR/LPCI nozzles), 

and (2) stainless steel pump casings, valve bodies, and thermowells. The staff also requested 

that the applicant identify the inspection methods, sample sizes, and inspection frequencies that 

will be applied to the inspections of these components during the period of extended operation 

and justify why inspection methods, sample sizes, and inspection frequencies selected are 

considered to be capable of detecting and managing cracking in the components during the 

period of extended operation.

In its response dated May 1, 2012, the applicant stated that the applicant selects components 

and piping for examination based on the staff-approved inspection schedule and methods 

described in BWRVIP-75-A. The applicant also stated that welds adjacent to specific 

components are inspected because welds are the susceptible areas. In addition, the applicant 

stated that the BWR Stress Corrosion Cracking Program specifies that these welds shall be 

volumetrically examined using a UT method. In its review of the applicant’s response to

RAI B.1.9-2, the staff finds that this portion of the applicant’s response is adequate to manage 

cracking due to SCC and IGSCC of the pump casings, valve bodies, and thermowells and their 

adjacent welds, consistent with the GALL Report.
3-275

However, the staff noted that GALL Report item IV.B1.R-99 recommends the BWR Vessel 

Internals Program and Water Chemistry Program to manage cracking of the CS nozzle thermal 

sleeves. In comparison, the LRA does not include an AMR item for aging management of CS

nozzle thermal sleeves based on GALL Report item IV.B1.R-99. Therefore, the staff needed 

further clarification as to whether the BWR Vessel Internals Program (including BWRVIP-18-A) 

is used to manage cracking of the CS nozzle thermal sleeves as recommended in the GALL 

Report. By letter dated July 23, 2012, the staff issued RAI B.1.9-2a requesting that the 

applicant clarify whether the BWR Vessel Internals Program is used to manage cracking of the 

CS nozzle thermal sleeves.

In its response dated August 15, 2012, the applicant clarified that the thermal sleeves 

addressed in LRA Table 3.1.2-1 are within the scope of the BWR Vessel Internals Program, 

consistent with the GALL Report. In its response, the applicant also revised LRA Table 3.1.2-1 

to indicate that the BWR Vessel Internals Program and Water Chemistry Control - BWR 

Program are used to manage cracking of the thermal sleeves and thermal sleeve extensions.

In its review, the staff finds that the applicant’s proposal of using the BWR Vessel Internals 

Program and Water Chemistry Control - BWR Program to manage cracking in these thermal 

sleeve components is consistent with the GALL Report and therefore, is acceptable. SER 

Section 3.0.3.1.10 documents the staff’s evaluation regarding the applicant’s aging 

management for the thermal sleeve components using the BWR Vessel Internals Program. The 

staff’s concern described in RAIs B.1.9-2 and B.1.9-2a is resolved.

The staff concludes that for LRA item 3.1.1-97, 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).

In its review of components associated with item 3.1.1-97, the staff noted that the applicant 

addressed piping, valve body, pump casing, and thermowell, and cited generic note A for these 

components. For the AMR items associated with these components, the staff found the 

applicant’s proposal to manage cracking due to SCC and IGSCC using the BWR Stress 

Corrosion Cracking Program, Water Chemistry Control – BWR Program, and Inservice 

Inspection Program acceptable because (1) the BWR Stress Corrosion Cracking Program 

includes volumetric examinations of the associated welds of these components, consistent with 

the GALL Report, which is adequate to manage cracking due to SCC and IGSCC, (2) the Water 

Chemistry Control – BWR Program includes monitoring and control of the reactor coolant water 

chemistry, which can mitigate environmental effects on SCC and IGSCC, and (3) the Inservice 

Inspection Program includes visual and volumetric examinations in accordance with the 

requirements of ASME Code Section XI, which are also adequate to manage cracking due to 

SCC and IGSCC.

In its review of components associated with LRA item 3.1.1-97, the staff noted that the applicant 

addressed RV nozzle thermal sleeves and thermal sleeve extensions, and cited generic note A 

for these components. For these AMR items associated with these components, the staff found 

the applicant’s proposal to manage cracking due to SCC and IGSCC using the BWR Stress 

Corrosion Cracking Program and Water Chemistry Control – BWR Program acceptable 

because (1) the BWR Stress Corrosion Cracking Program includes volumetric examinations of 

the associated welds of these components, which is adequate to manage cracking due to SCC 

and IGSCC, and (2) the Water Chemistry Control – BWR Program includes monitoring and 
3-276

control of the reactor coolant water chemistry that can mitigate environmental effect on SCC 

and IGSCC.

In LRA Table 3.1.2-1, the applicant cited generic note E for the AMR item that addresses nickel 

alloy CRD return line cap and weld (N10). For this AMR item, the LRA credits the BWR CRD 

Return Line Nozzle Program and Water Chemistry Control – BWR Program to manage cracking 

due to SCC and IGSCC of these components.

In its review, the staff found that the applicant credited adequate AMPs to manage cracking due 

to SCC and IGSCC of the CRD return line cap and welds, consistent with the scopes of the 

BWR CRD Return Line Nozzle Program and Water Chemistry Control – BWR Program. The 

applicant’s AMR result is consistent with GALL Report, AMP XI.M6, “BWR Control Rod Drive 

Return Line Nozzle,” which states that the scope of the program also includes a CRD return line 

nozzle cap and nozzle-to-cap welds if an applicant has cut the piping to the CRD retune line 

nozzle, and capped the nozzle to mitigate cracking.

The staff’s evaluations of the Water Chemistry Control – BWR Program and BWR CRD Return 

Line Nozzle Program are documented in SER Sections 3.0.3.1.41 and 3.0.3.1.5, respectively. 

In its review of components associated with LRA item 3.1.1-97, the staff noted that the applicant 

addressed nickel alloy CRD return line cap and weld (N10), and cited generic note E for these 

components. For this AMR item associated with these components, the staff found the 

applicant’s proposal to manage cracking due to SCC and IGSCC using the BWR CRD Return 

Line Nozzle Program and Water Chemistry Control – BWR Program acceptable because (1) the 

BWR CRD Return Line Nozzle Program examines the return line cap-to-safe-end weld 

periodically and (2) the Water Chemistry Control – BWR Program includes monitoring and 

control of the reactor coolant water chemistry that can mitigate environmental effect on SCC 

and IGSCC.

In LRA Table 3.1.2-1, the applicant also cited generic note E for the AMR items that address low 

alloy steel clad with stainless steel RV components (bottom head, shell closure flange, beltline 

shell rings and connecting welds, non-beltline shell rings, and upper head closure flange), 

stainless steel CRD, and stainless steel and nickel alloy heat exchanger assembly. For these 

AMR items, the LRA credits the Inservice Inspection Program and Water Chemistry Control –

BWR Program to manage cracking of these components.

In its review, the staff noted that the Inservice Inspection Program in accordance with ASME 

Code, Section XI includes visual and volumetric examinations of these components, which are 

adequate to manage cracking due to SCC and IGSCC. Since these components are included 

in the scope of the Inservice Inspection Program that performs appropriate visual and volumetric 

examinations in accordance with ASME Code Section XI, the staff finds that the Inservice 

Inspection Program is adequate to manage cracking due to SCC and IGSCC of these 

components.

The staff’s evaluations of the Water Chemistry Control – BWR Program, and Inservice 

Inspection Program are documented in SER Sections 3.0.3.1.41, and 3.0.3.1.22, respectively. 

In its review of components associated with LRA item 3.1.1-97, the staff noted that the applicant 

addressed low alloy steel clad with stainless steel RV components, stainless steel CRD, and 

stainless steel and nickel alloy heat exchanger assembly. For the AMR items associated with 

these components, the staff found the applicant’s proposal to manage cracking due to SCC and 

IGSCC using the Water Chemistry Control – BWR Program and Inservice Inspection Program 

acceptable because (1) the Water Chemistry Control – BWR Program includes monitoring and 
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control of the reactor coolant water chemistry, which can mitigate environmental effect on SCC 

and IGACC and (2) the Inservice Inspection Program includes visual, surface, and volumetric 

examinations of these components in accordance with the requirements of ASME Code 

Section XI, which are adequate to manage cracking due to SCC and IGSCC.

The staff concludes that for LRA item 3.1.1-97, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.1.2.1.4 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion 

Cracking, and Cyclic Loading

LRA Table 3.1.1, item 3.1.1-98 addresses stainless steel or nickel alloy penetrations of the RV, 

which will be managed for cracking due to SCC, IGSCC, and cyclic loading. For the AMR items 

that cite generic note E, the LRA credits the Water Chemistry Control – BWR Program and 

BWR Vessel Internals Program to manage the aging effect for the RV penetrations. The 

GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” and AMP XI.M8, 

“BWR Penetrations,” to ensure that these aging effects are adequately managed. GALL Report

AMP XI.M2 recommends monitoring and controlling of the concentrations of corrosive impurities 

listed in the EPRI water chemistry guidelines to mitigate the environmental effects on cracking. 

GALL Report AMP XI.M8 recommends the inspections in accordance with BWRVIP-49-A, 

BWRVIP-47-A, BWRVIP-27-A, and ASME Code Section XI, Table IWB-2500-1.

In its review, the staff noted that LRA Table 3.1.2-1 addresses applicant’s AMR results for the 

RV, including RV nozzles and penetrations. LRA Table 3.1.2-1 indicates that the BWR Vessel 

Internals Program and Water Chemistry Control – BWR Program manage cracking due to SCC, 

IGSCC, and cyclic loading of the CRD housing penetrations and incore housing penetrations in 

LRA items 3.1.1-102 and 3.1.1-98, respectively.

In contrast, GALL Report item IV.A1.RP-369 and the program scope of the BWR Penetrations 

Program recommend that the BWR Penetrations Program and Water Chemistry Program be 

used to manage cracking of these RV penetrations. Therefore, the applicant’s AMR results for 

cracking of the CRD housing and in-core housing penetrations (which are part of the RCPB) are 

not consistent with GALL Report item IV.A1.RP-369 and the scope of the BWR Penetrations 

Program.

By letter dated April 1, 2012, the staff issued RAI B.1.8-4 requesting that the applicant justify 

why cracking due to SCC, IGSCC and cyclic loading of the CRD housing penetrations and 

incore housing penetrations is managed by the BWR Vessel Internals Program and Water 

Chemistry Control – BWR Program, inconsistent with GALL Report item IV.A1.RP-369 and the 

scope of GALL Report AMP XI.M8, “BWR Penetrations.”

In its response dated August 15, 2012, the applicant stated inspection guidance for the CRD 

housings and in-core housings is provided in BWRVIP-47-A, “BWR Lower Plenum Inspection 

and Flaw Evaluation Guidelines,” and for the purposes of comparisons to the GALL Report, the 

BWR Penetrations Program described in GALL Report AMP XI.M8, which references 

BWRVIP-47-A, better represents the AMP requirements. In its response, the applicant also 

provided revisions to LRA Table 3.1.2-1 and LRA Table 3.1.1, item 3.1.1-98, in order to identify 

that the BWR Penetrations and Water Chemistry Control – BWR Programs manage cracking of 
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the CRD housing penetrations and incore housing penetrations, consistent with the 

GALL Report.

The staff finds the applicant’s response acceptable because the applicant’s revisions to the LRA 

are consistent with the GALL Report that recommends the BWR Penetration Program in 

conjunction with the Water Chemistry Program to manage cracking of the CRD and incore 

housing penetrations that are part of the RCPB. The staff also finds that the BWR Penetrations 

Program includes the examinations specified in BWRVIP-47-A and ASME Code Section XI, 

which are adequate to detect and manage cracking of these RV penetrations. The staff’s 

concern described in RAI B.1.8-4 is resolved.

The staff’s evaluations of the applicant’s Water Chemistry Control – BWR Program and BWR 

Penetrations Program are documented in SER Sections 3.0.3.1.41 and 3.0.3.1.7, respectively. 

In its review of the components associated with item 3.1.1-98, for which the applicant cited 

generic note E, the staff finds the applicant’s proposal to manage aging using the Water 

Chemistry Control – BWR Program and BWR Penetrations Program acceptable because the 

applicant’s Water Chemistry Control – BWR Program manages the aging of the components 

through monitoring and control of water chemistry in accordance with the EPRI water chemistry 

guidelines, and the applicant’s BWR Penetrations Program manages the aging of the 

components through the examinations in accordance with applicable industry standards and 

staff-approved BWRVIP documents, consistent with the GALL Report, which are adequate to 

manage the effects of aging for these components.

The staff concludes that for LRA item 3.1.1-98, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.1.2.1.5 Cracking Due to Stress Corrosion Cracking, Intergranular Stress Corrosion 

Cracking, and Irradiation Assisted Stress Corrosion Cracking

LRA Table 3.1.1, item 3.1.1-103, addresses stainless steel in-core dry tubes exposed to reactor 

coolant and neutron flux which are being managed for cracking due to SCC, IGSCC, and 

IASCC. The LRA credits the Water Chemistry Program and the Inservice Inspection Program to 

manage the aging effect. The GALL Report recommends GALL Report AMP XI.M9, “BWR 

Vessel Internals,” and GALL Report AMP XI.M2, “Water Chemistry,” to ensure that these aging 

effects are adequately managed. The associated AMR items cite generic note E, indicating that 

the LRA AMR is consistent with the GALL Report item for material, environment, and aging 

effect, but a different AMP is credited.

For those items associated with generic note E, GALL Report AMP XI.M9 recommends using 

periodic visual, surface, and/or volumetric examination and leakage testing along with GALL 

Report AMP XI.M2, which recommends monitoring and controlling known detrimental 

contaminants in accordance with the recommendations of BWRVIP-130 to manage the aging of 

this item. In its review of components associated with LRA Table 3.1.1, item 103, for which the 

applicant cited generic note E, the staff noted that the applicant’s Inservice Inspection Program, 

consistent with the GALL Report AMP XI.M1, “ASME Section XI Inservice Inspection, 

Subsections IWB, IWC, and IWD Program,” is substituted for the BWR Vessels Internals 

Program. The staff’s evaluation of the applicant’s Water Chemistry and Inservice Inspection 

Programs are documented in SER Sections 3.0.3.1.41 and 3.0.3.1.32, respectively.
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In its review of components associated with LRA Table 3.1.1, item 103, the staff finds the 

applicant’s proposal to manage aging using the Water Chemistry Program and the Inservice 

Inspection Program acceptable because (a) the applicant’s use of the Water Chemistry Program 

creates an environment that is not conducive for cracking to occur and is consistent with the 

recommendations of the GALL Report, and (b) the visual inspections associated with the 

Inservice Inspection Program is capable of detecting cracking during the period of extended 

operation.

The staff concludes that the applicant has demonstrated that the effects of aging for these 

components will be adequately managed so that 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).

3.1.2.1.6 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.1.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

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).

3.1.2.2 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 RV, internals, and RCS 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 stress corrosion cracking (SCC) and intergranular stress corrosion 

cracking (IGSCC)

• crack growth due to cyclic loading

• cracking due to SCC

• cracking due to cyclic loading

• loss of material due to erosion

• cracking due to SCC and irradiation-assisted SCC (IASCC)
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• loss of fracture toughness due to neutron irradiation embrittlement; change in dimension 

due to void swelling; loss of preload due to stress relaxation; or loss of material due to 

wear

• cracking due to primary water SCC (PWSCC)

• cracking due to fatigue

• cracking due to SCC and fatigue

• loss of material due to wear

• 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 3.1.2.2. The staff’s review of the applicant’s further 

evaluation follows.

3.1.2.2.1 Cumulative Fatigue Damage

LRA Section 3.1.2.2.1 addresses the applicant’s AMR basis for managing cumulative fatigue 

damage for RPV, RVI, RCPB, and CRD system. The applicant stated that fatigue is a TLAA as 

defined in 10 CFR 54.3 and these TLAAs are required to be evaluated in accordance with 

10 CFR 54.21(c). Additional information for these TLAAs is discussed in LRA Section 4.3.

The applicant identified the following items in LRA Table 3.1.1 that are applicable:

Item 3.1.1-1 - The applicant stated that metal fatigue of steel top head closure 

stud is a TLAA addressed in LRA Section 4.3

Item 3.1.1-3 - The applicant stated that metal fatigue of steel, stainless steel, and 

steel with nickel-alloy reactor internal components is a TLAA addressed in LRA 

Section 4.3

Item 3.1.1-4 - The applicant stated that metal fatigue of steel pressure vessel 

support skirt and attachment welds is a TLAA addressed in LRA Section 4.3

Item 3.1.1-6 - The applicant stated that metal fatigue of stainless steel, steel with 

nickel-alloy or stainless steel cladding, and nickel-alloy RCPB piping, piping 

components, and piping elements is a TLAA addressed in LRA Section 4.3

Item 3.1.1-7 - The applicant stated that metal fatigue of steel or stainless steel 

and nickel-alloy RV components is a TLAA in LRA Section 4.3

Item 3.1.1-11 - The applicant stated that metal fatigue of the stainless steel or 

steel pump and valve closure bolting is a TLAA addressed in LRA Section 4.3

The staff noted that LRA Table 3.1.1, items 3.1.1-2, 3.1.1-5, 3.1.1-8, 3.1.1-9, and 3.1.1-10 are 

specifically related to components in a pressurized water reactor design; therefore, the staff 

finds it appropriate that the applicant did not address these items in the LRA.
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The staff reviewed LRA Section 3.1.2.2.1 against the further evaluation criteria in SRP-LR 

Section 3.1.2.2.1, which states that fatigue is a TLAA as defined in 10 CFR 54.3, and that these 

TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) and consistent with SRP-LR 

Section 4.3. The staff also reviewed the AMR items associated with LRA Section 3.1.2.2.1, and 

found that the AMR results are consistent with the GALL Report and SRP-LR.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.1.2.2.1 criteria. For those items that apply to LRA Section 3.1.2.2.1, the staff 

determined 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). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components.

3.1.2.2.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

The staff reviewed LRA Section 3.1.2.2.2 against the following criteria in SRP-LR 

Section 3.1.2.2.2:

(1) LRA Section 3.1.2.2.2, item 1, which is associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material due to general, pitting, and crevice corrosion in steel PWR 

steam generator components exposed to secondary feedwater and steam. The 

applicant stated that this SRP-LR item is not applicable to GGNS because it is 

applicable to PWRs only. The staff confirmed that the item is applicable only to PWRs 

and; therefore, the staff finds the applicant’s claim acceptable.

(2) LRA Section 3.1.2.2.2, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-12, 

addresses loss of material due to general, pitting, and crevice corrosion in steel PWR 

steam generator components exposed to secondary feedwater and steam. The 

applicant stated that this SRP-LR item is not applicable to GGNS because it is 

applicable to PWRs only. The staff confirmed that the item is applicable only to PWRs 

and; therefore, the staff finds the applicant’s claim acceptable.

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, which is associated with LRA Table 3.1.1, item 3.1.1-13, 

states that neutron irradiation embrittlement is a TLAA evaluated in accordance with 

10 CFR 54.21(c)(1) and that the evaluations are addressed in LRA Section 4.2. This is 

consistent with SRP-LR Section 3.1.2.2.3 item 1 and is, therefore, acceptable. The 

staff’s evaluation of the TLAAs is documented in SER Section 4.2.

(2) LRA Section 3.1.2.2.3 refers to LRA Table 3.1.1, item 14 and addresses RPV steel (with 

or without cladding) RV beltline shell, nozzles, and welds exposed to reactor coolant and 

neutron flux, which are being managed for loss of fracture toughness due to neutron 

irradiation embrittlement by the applicant’s Reactor Vessel Surveillance Program.

The SRP-LR states that the applicant must implement a reactor surveillance program 

that follows the requirements of 10 CFR Part 50, Appendix H, by incorporating 

plant-specific factors such as the composition of limiting materials, availability of 

surveillance capsules, and projected fluence levels. In addition, the plant-specific 
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program must provide for untested capsules to be maintained in a manner such that they 

could be re-inserted into the vessel in the future if the need arises. This program 

monitors changes in the fracture toughness properties of ferritic materials in the reactor 

pressure vessel (RPV) beltline region. As described in Appendix B, the Reactor Vessel 

Surveillance Program is consistent with the program described in NUREG-1801, 

Section XI.M31, Reactor Vessel Surveillance, including recommendations for 

maintaining untested capsules in storage for future reinsertion.

The staff’s evaluation of the applicant’s Reactor Vessel Surveillance Program noted the 

applicant’s program consists of periodic testing of metallurgical surveillance samples to 

monitor the progress of neutron embrittlement of the RPV as a function of neutron 

fluence that is capable of identifying, evaluating, and managing the effects of loss of 

fracture toughness due to neutron irradiation embrittlement of the steel with stainless 

steel cladding of the RV.

The applicant addressed the further evaluation requirement by stating that the Reactor 

Vessel Surveillance Program manages reduction in fracture toughness due to neutron 

embrittlement of RV beltline materials, and relies on the BWRVIP ISP, of which GGNS is 

a participant, and satisfies the requirements of 10 CFR Part 50, Appendix H.

The Reactor Vessel Surveillance Program will adequately identify, evaluate, and 

manage the effects of loss of fracture toughness due to neutron irradiation embrittlement 

of the steel with stainless steel cladding of the RV to ensure there is no loss of intended 

function during the period of extended operation.

Based on the program identified, the staff concludes that the applicant’s program meets 

SRP-LR Section 3.1.2.2.3, item 14 criteria. For the item that applies to LRA 

Section 3.1.2.2.3, Table 3.1.1, item 14, the staff determines that the LRA is consistent 

with the GALL Report and that the applicant has demonstrated that the effects of aging 

will be adequately managed so that the intended function(s) will be maintained 

consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

(3) LRA Section 3.1.2.2.3 item 3, associated with LRA Table 3.1.1, item 3.1.1-15, states that 

Ductility – Reduction in Fracture Toughness is a plant-specific TLAA for Babcock and 

Wilcox (B&W) reactor internals and is not applicable to GGNS. The staff confirmed that 

this item is associated only with B&W designed PWRs and, therefore, finds the 

applicant’s claim acceptable.

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 associated with LRA Table 3.1.1 item 3.1.1-16 addresses the 

nickel alloy vessel flange leak detection (VFLD) nozzle which will be managed for 

cracking due to SCC and IGSCC by the Water Chemistry Control – BWR Program and 

ISI Program. The applicant further states that the One-Time Inspection Program will 

verify the effectiveness of the Water Chemistry Control – BWR Program. The criteria in 

SRP-LR Section 3.1.2.2.4 item 1 state that cracking due to SCC and IGSCC could occur 

in stainless steel and nickel alloy BWR top head enclosure vessel flange leak detection 

lines. The GALL Report recommends that a plant-specific AMP be evaluated because 
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existing programs may not be capable of mitigating or detecting cracking due to SCC 

and IGSCC.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that the 

VFLD nozzle is nickel alloy, and has the potential for cracking due to SCC and IGSCC. 

The applicant further states the leak detection line downstream of the nozzle is ASME 

Class 2, and the portion of this line that is wetted during refueling is carbon steel. The 

applicant cites LRA Table 3.1.1, item 3.1.1-16, which credits the Water Chemistry 

Control – BWR Program and ISI Programs. The applicant also describes, in LRA 

Appendix C, the GGNS response to BWRVIP applicant action items. BWRVIP-74-A, 

“BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” states 

concerns of leakage around the RV seal rings that could accumulate in the VFLD lines 

that could cause cracking in the line. The applicant stated in its response to the action 

item that the VFLD line is managed by the Water Chemistry Control – BWR Program, 

which will be confirmed by the One-Time Inspection Program.

The staff’s evaluation of the applicant’s Water Chemistry Control – BWR Program is 

documented in SER Section 3.0.3.1.41. The staff noted that the applicant’s program 

manages loss of material, cracking, and fouling in components exposed to a treated 

water environment through monitoring and control of water chemistry, using EPRI water 

chemistry guidelines. The staff further noted that enhancements based on industry 

experience and guidelines, BWR cycle design, and BWR metallurgy were implemented 

to optimize corrosion control for the RV, primary system components, and balance of 

plant components and reduce IGSCC. The staff noted that these enhancements 

included the addition of an advanced resin cleaning system and management of 

condensate temperatures in cold weather months.

The staff’s evaluation of the applicant’s ISI Program is documented in SER 

Section 3.0.3.1.22. The staff noted that the applicant’s program includes the 

requirements of ASME Code Section XI, Subsections IWB, IWC, and IWD, which 

manages aging effects for ASME Class 1, 2, and 3 pressure-retaining components,

including welds, pump casings, valve bodies, integral attachments and 

pressure-retaining bolting using volumetric, surface, or visual examination.

In its review of components associated with item 3.1.1-16, the staff finds that the 

applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Water Chemistry Control – BWR Program and ISI Program is acceptable 

because the applicant’s use of programs capable of mitigating and detecting SCC and 

IGSCC, the aging effect, and mechanism is consistent with the recommendations of the 

GALL Report and SRP-LR Section 3.1.2.2.4, item 1.

The staff determines that the applicant’s programs meet SRP-LR Section 3.1.2.2.4, 

item 1 criteria. For those AMR items associated with LRA Section 3.1.2.2.4, item 1, the 

staff concludes that the LRA is consistent with the GALL Report and that the applicant 

has demonstrated that the effects of aging will be adequately managed so that the 

intended 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 3.1.2.2.4.2, which is associated with LRA Table 3.1.1, item 3.1.1-17, 

addresses SCC and IGSCC for stainless steel BWR isolation condenser components 

exposed to reactor coolant. The applicant stated that this item is not used because its 

design does not use an isolation condenser. The staff reviewed the applicant’s UFSAR 

and confirmed that the design of the applicant’s unit does not include an isolation 

condenser; therefore, the staff finds the applicant’s review result acceptable.
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3.1.2.2.5 Crack Growth Due to Cyclic Loading

LRA Section 3.1.2.2.5, associated with LRA Table 3.1.1, item 3.1.1-18, addresses intergranular 

separations (underclad cracks) in welds used to join cladding to RPV shell or nozzle forgings 

made from SA-508 Class 2 alloy steel materials and are exposed to the reactor coolant 

environment. The LRA states that this item is not applicable to the LRA because the issue is 

only applicable to SA-508 Class 2 RPV forging components in PWR designs.

SRP-LR Section 3.1.2.2.5 identifies that crack growth due to cyclic loading could occur in RPV 

low alloy steel forging components that have a coarse-grained material structure and that were 

clad with austenitic stainless steel using a high-heat-input welding process. The SRP-LR states 

that growth of intergranular separations (underclad cracks) in the heat-affected zone of RPV 

clad-to-forging welds may need to be identified as a TLAA for the period of extended operation.

The staff sought additional information from the applicant to confirm that the LRA would not 

need to include an RPV underclad cracking TLAA. By letter dated June 5, 2012, the staff 

issued RAI 4.1-1, requesting in part (a) of the RAI, that the applicant identify the RPV forging 

components that were ordered and fabricated to SA-5O8, Class 2 specifications and whose 

design included an associated welded cladding. In RAI 4.1-1, part (b), the staff asked the 

applicant to clarify the regulatory process used in the CLB to address underclad cracking in the 

RPV cladding-to-forging welds. In RAI 4.1-1, part (c), the staff also asked the applicant to justify 

why the assessment of RPV underclad cracking would not need to be identified as a TLAA in 

accordance with 10 CFR 54.21(c)(1).

The applicant responded to RAI 4.1-1 by letter dated July 3, 2012. In its response to RAI 4.1-1, 

part (a), the applicant stated the only RPV components that were made from SA-508, Class 2 

low alloy steel forging materials are the RPV lower flange component that is welded to the RPV 

shell and the RPV upper flange component that is welded to the RPV upper head. In its 

response to RAI 4.1-1, part (b), the applicant stated that the UFSAR Section 5.3.1.6.4 identifies 

that its RPV design specifications required all low alloy steel components in the RPV to be 

fabricated from materials and welding methods that resulted in fine-grain microstructures and 

that based on this, the phenomenon of underclad cracking is not a concern for RPV flange 

components that were fabricated from SA-508 Class 2 forging materials. The applicant also 

stated that this is the only reference to RPV underclad cracking that is incorporated into the 

CLB. In its response to RAI 4.1-1, part (c), the applicant stated that the CLB does not include 

any time-dependent RPV underclad cracking analysis and that based on this fact, that there is 

not any RPV underclad cracking analysis to identify for the LRA.

The staff finds the applicant’s response acceptable because the UFSAR Section 5.3.1.6.4 

indicates that all low alloy steel components in the RPV were fabricated from materials and 

welding methods that resulted in fine-grain microstructures; RPV components were made from 

SA-508, Class 2 low alloy steel forging materials; and its CLB does not include any 

time-dependent RPV underclad cracking analysis. The staff’s concern described in RAI 4.1-1 

is resolved.

The staff also confirmed that the UFSAR verifies that the RPV upper and lower flange 

component forgings were fabricated using fine-grain material fabrication processes. Therefore, 

based on this review, the staff finds that the applicant presented a valid basis for concluding that 

the management of underclad is not applicable to the applicant and that the LRA does not need 

to include a RPV underclad cracking TLAA because the staff has confirmed that: (a) the 

operating experience with underclad cracking is relevant to SA-508, Class 2 RPV forging 
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components in PWR designed facilities; (b) that the RPV upper and lower flange forging 

components were fabricated to fine-grain material fabrication processes; and (c) the CLB does 

not include a RPV underclad cracking analysis for these RPV flange components.

3.1.2.2.6 Cracking Due to Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.6 against the criteria in SRP-LR Section 3.1.2.2.6.

(1) LRA Section 3.1.2.2.6, item 1, which is associated with LRA Table 3.1.1, item 3.1.1-19, 

addresses cracking due to SCC in PWR stainless steel RV flange leak detection lines 

and bottom-mounted instrument guide tubes exposed to reactor coolant. The applicant 

stated that this SRP-LR item is not applicable to GGNS because it is applicable to PWRs 

only. The staff confirmed that the item is applicable only to PWRs and; therefore, the 

staff finds the applicant’s claim acceptable.

(2) LRA Section 3.1.2.2.6, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-20, 

addresses cracking due to SCC in Class 1 PWR CASS RCS piping, piping components, 

and piping elements. The applicant stated that this SRP-LR item is not applicable to 

GGNS because it is applicable to PWRs only. The staff confirmed that the item is 

applicable only to PWRs and; therefore, the staff finds the applicant’s claim acceptable.

3.1.2.2.7 Cracking Due to Cyclic Loading

LRA Section 3.1.2.2.7, which is associated with LRA Table 3.1.1, item 3.1.1-21, addresses 

cracking due to cyclic loading for steel and stainless steel BWR isolation condenser 

components exposed to reactor coolant. The applicant stated that this item is not used because 

its design does not use an isolation condenser. The staff reviewed the applicant’s UFSAR and 

confirmed that the design of the applicant’s units does not include an isolation condenser; 

therefore, the staff finds the applicant’s review result acceptable.

3.1.2.2.8 Loss of Material Due to Erosion

LRA Section 3.1.2.2.8, which is associated with LRA Table 3.1.1, item 3.1.1-22, addresses loss 

of material due to erosion in PWR steam generator FW impingement plates and supports 

exposed to secondary FW. The applicant stated that this SRP-LR item is not applicable to 

GGNS because it is applicable to PWRs only. The staff confirmed that the item is applicable 

only to PWRs and; therefore, the staff finds the applicant’s claim acceptable.

3.1.2.2.9 Cracking Due to Stress Corrosion Cracking and Irradiation-Assisted Stress 

Corrosion Cracking

LRA Section 3.1.2.2.9, which is associated with LRA Table 3.1.1, item 3.1.1-23, addresses 

cracking due to SCC and IASCC could occur in inaccessible locations for stainless steel and 

nickel-alloy primary and expansion PWR RVI components. The applicant stated that this 

SRP-LR item is not applicable to GGNS because it is applicable to PWRs only. The staff 

confirmed that the item is applicable only to PWRs and; therefore, the staff finds the applicant’s 

claim acceptable.
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3.1.2.2.10 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement, Change in 

Dimension Due to Void Swelling, Loss of Preload Due to Stress Relaxation, or Loss 

of Material Due to Wear

LRA Section 3.1.2.2.10, which is associated with LRA Table 3.1.1, item 3.1.1-24, addresses 

loss of fracture toughness due to neutron irradiation embrittlement, change in dimension due to 

void swelling, loss of preload due to stress relaxation, or loss of material due to wear that could 

occur in inaccessible locations for stainless steel and nickel-alloy primary and expansion PWR 

RVI components. The applicant stated that this SRP-LR item is not applicable to GGNS 

because it is applicable to PWRs only. The staff confirmed that the item is applicable only to 

PWRs and; therefore, the staff finds the applicant’s claim acceptable.

3.1.2.2.11 Cracking Due to Primary Water Stress Corrosion Cracking

The staff reviewed LRA Section 3.1.2.2.11 against the criteria in SRP-LR Section 3.1.2.2.11.

(1) LRA Section 3.1.2.2.11, item 1, which is associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses foreign operating experience in steam generators with a similar design to that 

of Westinghouse Model 51, which has identified extensive cracking due to PWSCC in 

steam generator divider plate assemblies fabricated of Alloy 600 and/or the associated 

Alloy 600 weld materials, even with proper primary water chemistry (EPRI TR-1014982). 

The applicant stated that this SRP-LR item is not applicable to GGNS because it is 

applicable to PWRs only. The staff confirmed that the item is applicable only to PWRs 

and; therefore, the staff finds the applicant’s claim acceptable.

(2) LRA Section 3.1.2.2.11, item 2, which is associated with LRA Table 3.1.1, item 3.1.1-25, 

addresses cracking due to PWSCC that could occur in steam generator nickel alloy 

tube-to-tube sheet welds exposed to reactor coolant. The applicant stated that this 

SRP-LR item is not applicable to GGNS because it is applicable to PWRs only. The 

staff confirmed that the item is applicable only to PWRs and; therefore, the staff finds the 

applicant’s claim acceptable.

3.1.2.2.12 Cracking Due to Fatigue

LRA Section 3.1.2.2.12, which is associated with LRA Table 3.1.1, item 3.1.1-26, addresses 

cracking due to fatigue as an aging effect that can occur for the lower flange weld in the core 

support barrel assembly, fuel alignment plate in the upper internals assembly, and core support 

plate lower support structure in PWR internals designed by Combustion Engineering. The 

applicant stated that this SRP-LR item is not applicable to GGNS because it is applicable to 

PWRs only. The staff confirmed that the item is applicable only to PWRs and; therefore, the 

staff finds the applicant’s claim acceptable.

3.1.2.2.13 Cracking Due to Stress Corrosion Cracking and Fatigue

LRA Section 3.1.2.2.13, which is associated with LRA Table 3.1.1, item 3.1.1-27, addresses 

cracking due to SCC and fatigue that could occur in nickel alloy control rod guide tube 

assemblies, guide tube support pins exposed to reactor coolant, and neutron flux. The 

applicant stated that this SRP-LR item is not applicable to GGNS because it is applicable to 

PWRs only. The staff confirmed that the item is applicable only to PWRs and; therefore, the 

staff finds the applicant’s claim acceptable.
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3.1.2.2.14 Loss of Material Due to Wear

LRA Section 3.1.2.2.14, associated with LRA Table 3.1.1, item 3.1.1-28, addresses loss of 

material due to wear in nickel alloy control rod guide tube assemblies, guide tube support pins, 

and Zircaloy-4 incore instrumentation lower thimble tubes exposed to reactor coolant and 

neutron flux. The applicant stated that this item is not applicable because it is associated with 

PWRs only. The staff confirmed that this item is associated only with PWRs and, therefore, 

finds the applicant’s claim acceptable.

3.1.2.2.15 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.

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

In LRA Tables 3.1.2-1 through 3.1.2-4, 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 3.1.2-4, the applicant indicated, via notes F through J that the 

combination of component type, material, environment, and AERM does not correspond to an 

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.1.2.3.1 Reactor Vessel - 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 

RV component groups.

In LRA Section 3.1.2.1.1, which is associated with LRA Table 3.1.2-1, the applicant stated that 

carbon and low-alloy steel RV external attachments, support skirt, and stabilizer attachment 

brackets exposed to indoor air will be managed for loss of material by the applicant’s ISI 

program. The AMR item cites 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 

associated items in the LRA and considered whether the aging effects proposed by the 

applicant constitute all of the credible aging effects for this component, material, and 

environment description. Based on its review, the staff finds that the applicant has identified all 

credible aging effects for these component, material, and environment combinations.
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The staff’s evaluation of the ISI program is documented in SER Section 3.0.3.1.22. The staff 

noted that the ISI program manages loss of material for the RV external attachments, support 

skirt, and stabilizer attachment brackets using visual and volumetric inspections in accordance 

with ASME Code Section XI, Subsection IWA. The staff finds that the applicant’s proposed 

program to manage loss of material for carbon steel and low-alloy steel exposed to indoor air 

acceptable because the applicant will use inspection techniques that are in accordance with 

ASME Code Section XI, Subsection IWA, which are acceptable for detection of loss of material.

In LRA Table 3.1.2-1, the applicant stated that the carbon steel and low alloy steel components 

including nozzles, nozzle safe ends and extensions, nozzle flanges, RV head, and flange 

exposed to indoor air does not have any aging effects that require management. The related 

AMR items cite generic note G, indicating this environment is not in the GALL Report for the 

aging effects of this component and material combination. In addition, the associated 

plant-specific note 102 states that high component surface temperature precludes moisture 

accumulation that could result in corrosion.

In its review, the staff found that essentially identical material and environment combinations 

were found in the GALL Report, albeit not in the RCS. The staff noted that the applicant’s basis 

for stating that no aging management is necessary was that the temperature of the components 

under consideration was above the dew point. However, the staff also noted that, during 

refueling outages, the components could be at ambient temperatures for prolonged periods of 

time, negating the plant-specific note. By letter dated June 20, 2012, the staff issued

RAI 3.1.2.1-1 requesting that the applicant provide technical basis to justify why aging 

management is not necessary given that, during normal plant events such as refueling outages, 

these components will be at or near ambient temperatures. In its response dated July 19, 2012, 

the applicant stated that the subject components are typically at or near ambient temperatures 

and are rarely below ambient temperatures during shutdown conditions, such as refueling 

outages. It stated that “these conditions are comparatively brief,” and that “any minor moisture 

accumulated during shutdown is quickly evaporated during startup.” The applicant also 

indicated that its “operating experience has shown that these components are not subject to 

loss of material due to corrosion.”

Based on its review, the staff finds the applicant’s response to RAI 3.1.2.1-1 acceptable, 

because the applicant provided information indicating that water condensation seldom occurs 

on the exterior surfaces of the referenced components. In addition, the applicant’s plant-specific 

operating experience demonstrated that these components are not subject to loss of materials 

due to corrosion. Therefore, the staff’s concerns described in RAI 3.1.2.1-1 are resolved.

Based on its review, the staff finds the applicant has appropriately identified that the 

above-mentioned components are not subject to AERM because component temperatures are 

above the dew point and water condensation seldom occurs on the exterior surfaces of the 

components. Loss of material due to corrosion is not expected with these conditions.

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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3.1.2.3.2 Reactor Vessel Internals - Summary of Aging Management Review – LRA

Table 3.1.2-2

The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for the 

RVI component groups. The staff’s review did not identify any items with notes F through J, 

indicating that the combinations of component type, material, environment, and AERM for this 

system are consistent with the GALL Report.

3.1.2.3.3 Reactor Coolant Pressure Boundary - 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 

RCPB component groups.

Carbon Steel Piping and Piping Components Exposed to Air-Indoor (External). In LRA

Table 3.1.2-3, the applicant stated that carbon steel piping, flow elements, thermal sleeves, and 

valve bodies exposed to air-indoor (external) have no aging effects and no AMP is proposed. 

The AMR items cite generic note G and plant-specific note 102, which states that the high 

component surface temperature precludes moisture accumulation that could result in corrosion. 

The staff’s concern with the basis for this conclusion for outages, where component surfaces 

temperatures are lower, is documented in SER Section 3.1.2.3.3.

The staff reviewed the associated items in the LRA to confirm that there are no credible aging 

effects for this component, material and environmental combination. The staff noted that the 

ASM Handbook, Volume 13A, 2003, chapter on “Atmospheric Corrosion,” states that the 

atmospheric corrosion reaction will not occur without the presence of an electrolyte. The staff 

also noted that moisture accumulation is not expected to occur on components with 

temperatures above the atmospheric dew point. The staff further noted that GALL Report

item VII.J.AP-4 states that steel piping, piping components, and piping elements exposed to dry 

air have no aging effects. The staff finds the applicant’s proposal acceptable because high 

component surface temperatures prevent the accumulation of the moisture (i.e., electrolyte) 

necessary for aging to occur.

Carbon Steel Piping and Valve Bodies Less Than 4-inch NPS Exposed to Air–Indoor (External). 

In LRA Table 3.1.2-3, the applicant stated that for carbon steel piping less than 4 inches NPS 

exposed to indoor air on their external surfaces, there is no aging effect and no AMP is 

proposed. The AMR items cite generic note G, which states that the environment for this 

component and material is not found in the GALL Report. The AMR items also cite a 

plant-specific note that states that high component surface temperature precludes moisture 

accumulation that could result in corrosion.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description.

In its review, the staff noted that the applicant’s basis for stating that no aging effect was present 

was that the external surface temperature of the components was above the dew point. The 

staff also noted that the GALL Report defines indoor air as an environment in which 

condensation is only expected on rare occasions. The staff further noted that this combination 

of environment and material is present in the GALL Report, albeit not in the RCS, and that the 

management of the aging effect, loss of material, is recommended.
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By letter dated June 20, 2012, the staff issued RAI 3.1.2.1-1, requesting that the applicant justify 

why aging management is not required for these components given that during normal plant 

events (e.g., refueling), the components under consideration will be at or near ambient 

temperature and may be subject to condensation.

By letter dated July 19, 2012, the applicant responded to RAI 3.1.2.1-1, which stated that these 

components are at or near (but seldom, if ever, below) ambient temperatures during shutdown 

conditions, such as refueling outages. The applicant stated that these conditions are 

comparatively brief. The applicant stated that the dew point inside containment during outages 

is typically below the ambient temperature. The applicant stated that actual condensation on 

RCS piping is not a concern because of these conditions. The applicant further stated that any 

minor moisture that accumulated during shutdown is quickly evaporated during startup; these 

components operate at high temperatures (greater than 212 °F) during normal operation. The 

applicant also stated that operating experience has shown that these components are not 

subject to loss of material due to corrosion.

Based on its review, the staff finds the applicant has appropriately identified that the abovementioned components are not subject to AERM because component temperatures are above 

the dewpoint and the duration of time when the component temperature is near the dewpoint is 

too short to allow significant corrosion to occur even if condensation does occur. Loss of 

material due to corrosion is not expected with these conditions.

Loss of Material Due to Erosion in Main Steam Line Flow Elements. By letter dated 

October 2, 2012, the applicant amended LRA Table 3.1.2-3 to include a new AMR item on loss 

of material due to erosion in the plant’s main steam line flow elements (flow restrictors) that are 

made from cast austenitic stainless steel (CASS). In this AMR item, the applicant stated that 

loss of material due to erosion in main steam flow elements that are exposed to reactor steam 

environment will be managed for loss of material due to erosion by the time-limited aging 

analysis for this aging. The AMR item cites generic note H.

The staff reviewed the associated item in the response letter that amended the LRA and 

considered whether the aging effects proposed by the applicant constitute all of the credible 

aging effects for this component, material, and environment description. The staff noted that 

loss of material due to erosion is a specific aging effect and mechanism that is applicable to this 

component, material and environment combination. The staff verified that the applicant 

included the applicable TLAA for managing loss of material due to erosion in the main steam 

line flow elements in LRA Section 4.7.1 and that this serves as an acceptable basis for 

complying with the aging management requirement in 10 CFR 54.21(a)(3). Based on this 

review, the staff finds that the applicant has included an applicable AMR item for managing loss 

of material due to erosion in the CASS main steam line flow elements. The staff’s evaluation of 

the applicant’s TLAA for the main steam line flow elements is documented in SER Section 4.7.1.

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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3.1.2.3.4 Miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2) - 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 

miscellaneous RCS systems in scope for 10 CFR 54.4(a)(2) component groups. The staff’s 

review did not identify any items with notes F through J, indicating that the combinations of 

component type, material, environment, and AERM for this system are consistent with the GALL

Report.

3.1.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the RV, RVI, and RCS components within the scope of license renewal 

and subject to an AMR will be adequately managed so that the intended functions will remain 

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 Systems

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

engineered safety features systems components and component groups of:

• RHR

• low pressure core spray

• high pressure core spray (HPCS)

• RCIC

• pressure relief

• standby gas treatment

• containment penetrations

• miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2)

3.2.1 Summary of Technical Information in the Application

LRA Section 3.2 provides AMR results for the engineered safety features (ESF) systems 

components and component groups. LRA Table 3.2.1, “Summary of Aging Management 

Programs for Engineered Safety Features Evaluated in Chapter V of NUREG-1801,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

ESF systems components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.2.2 Staff Evaluation

The staff reviewed LRA Section 3.2 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the ESF systems components within the 

scope of license renewal and subject to an AMR, 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 conducted a review of AMRs to ensure the applicant’s claim that certain AMRs are 

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 evaluation 

are documented in SER Section 3.2.2.1.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.2.2.2 acceptance criteria. The staff’s 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 items and the plant’s operating experience to verify the 

applicant’s claims.

Table 3.2-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.2 and addressed in the GALL Report.

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

GALL Report

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel, steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

(3.2.1-1)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a 

time-limited aging 

analysis (TLAA) to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1)).

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.2.2.2.1)
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Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with stainless 

steel cladding) pump 

casings exposed to 

treated water 

(borated) (3.2.1-2)

Loss of material 

due to cladding 

breach

A plant-specific AMP

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 

BWRs (see SER 

Section 3.2.2.2.2) 

Stainless steel 

partially-encased 

tanks with breached 

moisture barrier 

exposed to raw 

water (3.2.1-3)

Loss of material 

due to pitting 

and crevice 

corrosion

A plant-specific AMP

is to be evaluated for 

pitting and crevice 

corrosion of tank 

bottom because 

moisture and water 

can egress under 

the tank due to 

cracking of the 

perimeter seal from 

weathering.

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.2.3(1))

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.2.1-4)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

GGNS (see 

SER Section 3.2.2.2.

3(2))

Stainless steel 

orifice (miniflow 

recirculation) 

exposed to treated 

water (borated) 

(3.2.1-5)

Loss of material 

due to erosion

A plant-specific AMP

is to be evaluated for 

erosion of the orifice 

due to extended use 

of the centrifugal 

HPSI pump for 

normal charging. 

See LER 

50-275/94-023 for 

evidence of erosion.

Yes Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.2.4)

Steel drywell and 

suppression 

chamber spray 

system (internal 

surfaces): flow 

orifice; spray nozzles 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-6)

Loss of material 

due to general 

corrosion; 

fouling that 

leads to 

corrosion

A plant-specific AMP

is to be evaluated

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.2.5)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.2.1-7)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.2.6)
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Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum, copperalloy (>15% Zn or 

>8% Al) piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-8)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.2.1-9)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.1.1)

Cast austenitic 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water (borated) 

>250 °C (>482 °F); 

treated water 

>250 °C (>482 °F) 

(3.2.1-10)

Loss of fracture 

toughness due 

to thermal aging 

embrittlement

Chapter XI.M12, 

“Thermal Aging 

Embrittlement of 

Cast Austenitic 

Stainless Steel 

(CASS)”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.2.1-11)

Wall thinning 

due to 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No FlowAccelerated 

Corrosion

Consistent with the 

GALL Report

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.2.1-12)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel; stainless steel 

volting, closure 

bolting exposed to 

air – outdoor 

(external); air –

indoor, uncontrolled 

(external) (3.2.1-13)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.2.1-14)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable See SER 

Section 3.2.2.1.1
3-295

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy, nickel 

alloy, steel; stainless 

steel, stainless steel, 

steel; stainless steel 

bolting, closure 

bolting exposed to 

any environment, 

air – outdoor 

(external), raw 

water, treated 

borated water, fuel 

oil, treated water, air 

– indoor, 

uncontrolled 

(external) (3.2.1-15)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel containment 

isolation piping and 

components (internal 

surfaces), piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.2.1-16)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry

Control – BWR, 

One-Time 

Inspection, and 

Bolting Integrity, 

Periodic 

Surveillance 

and Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.2)

Aluminum, stainless 

steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.2.1-17)

Loss of material 

due to pitting

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR, 

One-Time 

Inspection, and 

Bolting Integrity, 

Periodic 

Surveillance 

and Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.3)

Stainless steel 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

treated water 

(3.2.1-18)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection 

Consistent with the 

GALL Report

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.2.1-19)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) >60 °C 

(>140 °F) (3.2.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)
3-296

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with stainless 

steel or nickel-alloy 

cladding) safety 

injection tank 

(accumulator) 

exposed to treated 

water (borated) 

>60 °C (>140 °F) 

(3.2.1-21)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

treated water 

(borated) (3.2.1-22)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-23)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

- influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.2.1-24)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger 

components, 

containment 

isolation piping and 

components (internal 

surfaces) exposed to 

raw water (3.2.1-25)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Stainless steel heat 

exchanger tubes 

exposed to raw 

water (3.2.1-26)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Stainless steel, steel 

heat exchanger 

tubes exposed to 

raw water (3.2.1-27)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (See SER 

Section 3.2.2.1.1)
3-297

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.2.1-28)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control – BWR 

and Inservice 

Inspection

Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.4)

Steel piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-29)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed Treated 

Water Systems

Consistent with the 

GALL Report

Steel heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water (3.2.1-30)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Stainless steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-31)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed Treated 

Water System

Not applicable to 

GGNS (see SER 

Section 3.2.2.1.5)

Copper-alloy Heat 

exchanger 

components, Piping, 

piping components, 

and piping elements 

exposed to 

Closed-cycle cooling 

water (3.2.1-32)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed Treated 

Water System

Consistent with the 

GALL Report

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water (3.2.1-33)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to 

closed-cycle cooling 

water (3.2.1-34)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)
3-298

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Gray cast iron motor 

cooler exposed to 

treated water 

(3.2.1-35)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.2.1-36)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil 

(3.2.1-37)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Elastomers 

elastomer seals and 

components 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-38)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

Steel containment 

isolation piping and 

components 

(external surfaces) 

exposed to 

condensation 

(external) (3.2.1-39)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

Steel ducting, piping, 

and components 

(external surfaces), 

ducting, closure 

bolting, containment 

isolation piping and 

components 

(external surfaces) 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-40)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

Steel external 

surfaces exposed to 

air – outdoor 

(external) (3.2.1-41)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.2.1-42)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)
3-299

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Elastomers 

elastomer seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-43)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel piping and 

components (internal 

surfaces), ducting 

and components 

(internal surfaces) 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-44)

Loss of material 

due to general 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel encapsulation 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.2.1-45)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Steel piping and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.2.1-46)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Steel encapsulation 

components 

exposed to air with 

borated water 

leakage (internal) 

(3.2.1-47)

Loss of material 

due to general, 

pitting, crevice, 

and boric acid 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

(internal surfaces); 

tanks exposed to 

condensation 

(internal) (3.2.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-49)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy, 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.2.1-50)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report
3-300

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel, copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.2.1-51)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.2.1-52)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.2.1-53)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Steel; stainless steel 

underground piping, 

piping components, 

and piping elements 

exposed to 

air-indoor 

uncontrolled or 

condensation 

(external) (3.2.1-53x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.2.1-54)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,”

and Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.2.1-55)

None None, provided

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and

2) plant operating 

experience indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)
3-301

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external) 

(3.2.1-56)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external), gas 

(3.2.1-57)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.2.1-58)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

BWRs (see SER 

Section 3.2.2.1.1)

Galvanized steel 

ducting, piping, and 

components 

exposed to air –

indoor, controlled 

(external) (3.2.1-59)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Glass piping 

elements exposed to 

air – indoor, 

uncontrolled 

(external), lubricating 

oil, raw water, 

treated water, 

treated water 

(borated), air with 

borated water 

leakage, 

condensation 

(internal/external), 

gas, closed-cycle 

cooling water, air –

outdoor (3.2.1-60)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.1)

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.2.1-61)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)
3-302

Component Group 

(SRP-LR Item No.)

Aging Effect/ 

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air with 

borated water 

leakage (3.2.1-62)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.2.1-63)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

(see SER 

Section 3.2.2.1.6)

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor, controlled 

(external), gas 

(3.2.1-64)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.2.2.1.1)

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 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:

• Bolting Integrity

• Compressed Air Monitoring

• External Surfaces Monitoring

• Flow-Accelerated Corrosion

• Internal Surfaces in Miscellaneous Piping and Ducting Components

• Oil Analysis

• One-Time Inspection

• Periodic Surveillance and Preventive Maintenance

• Selective Leaching
3-303

• Service Water Integrity

• Water Chemistry Control – BWR

• Water Chemistry Control – Closed Treated Water Systems

LRA Tables 3.2.2-1 through 3.2.2-8 summarize AMRs for the ESF systems components and 

indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate GALL

Report AMRs. The staff’s evaluation follows.

3.2.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.2.1, items 3.2.1-8, 3.2.1-9, 3.2.1-20 through 3.2.1-22, 3.2.1-24, 3.2.1-35, 

3.2.1-36, 3.2.1-45, 3.2.1-47, and 3.2.1-58, the applicant claimed that the corresponding AMR 

items in the GALL Report are not applicable because the associated items are only applicable 

to PWRs. The staff reviewed the SRP-LR, confirmed these items only apply to PWRs, and finds 

that these items are not applicable to GGNS.

For LRA Table 3.2.1, items 3.2.1-10, 3.2.1-30, 3.2.1-33, 3.2.1-34, 3.2.1-37, 3.2.1-41, 3.2.1-42, 

3.2.1-46, 3.2.1-52, 3.2.1-53, 3.2.1-55, 3.2.1-56, 3.2.1-61, and 3.2.1-62, the applicant claimed 

that the corresponding items in the GALL Report are not applicable. The staff reviewed the LRA 

and UFSAR and confirmed that the applicant’s LRA does not have any AMR results applicable 

for these items.

LRA Table 3.2.1, item 3.2.1-14, addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity”

program to manage loss of material due to general corrosion for this component group. The 

applicant stated that this item is not applicable because steam or water leakage is not 

considered a separate aspect of the indoor air environment. The staff evaluated the applicant’s 

claim and found it acceptable because (a) all ESF system bolting exposed to air is being 

managed for loss of material by the Bolting Integrity Program using item 3.2.1-13, (b) the 

program conducts periodic visual inspections capable of detecting loss of material due to 

general corrosion in bolting, and (c) use of this program is consistent with the GALL Report.

LRA Table 3.2.1, item 3.2.1-27, addresses stainless steel and steel heat exchanger 

components exposed to raw water that are being managed for reduction of heat transfer due to 

fouling. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System,” to manage reduction of heat transfer for this component group. The applicant stated 

that this item was not used because there are no steel heat exchanger tubes in ESF systems 

exposed to raw water, and the stainless steel heat exchanger tubes in ESF systems are being 

managed for reduction of heat transfer through Table 3.2.1, item 3.2.1-26. The staff finds the 

applicant’s determination acceptable.

LRA Table 3.2.1, item 3.2.1-53.5, addresses steel and stainless steel underground piping, 

piping components, and piping elements exposed to uncontrolled indoor air or condensation 

(external). The GALL Report recommends GALL Report AMP XI.M41, “Buried and 

Underground Piping and Tanks,” to manage loss of material due to general (steel only), pitting 

and crevice corrosion for this component group. The applicant stated that this item is not 

applicable because, “[t]his item was not used. There are no underground ESF system 
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components in the scope of license renewal.” The staff evaluated the applicant’s claim and 

lacked sufficient information to find it acceptable because an enhancement to LRA 

Section B.1.18, External Surfaces Monitoring Program, states that instructions will be provided 

for inspecting all underground components within the scope of this program. Based on the 

staff’s review during the AMP audit, the RHR pump suction barrels and HPCS pump suction 

barrels are two of the underground piping components associated with this enhancement. By 

letter dated April 16, 2012, the staff issued RAI B.1.5-1 requesting that the applicant provide a 

list of all underground in-scope components, state which AMP will be used to manage the aging 

of these underground in-scope components, and if a program other than the Buried Piping and 

Tanks Inspection Program will be used to age manage any of the underground components, 

state if any recommendations contained in AMP XI.M41 of the GALL Report will not be met and 

justify not meeting the recommendations. The applicant’s response and staff evaluation of this

RAI is documented in SER Section 3.0.3.1.4. The staff’s concern described in RAI B.1.5-1 is 

resolved and the staff finds the applicant’s use of item 3.2.1-40 to manage the steel RHR 

suction barrel HPCS suction barrel acceptable.

LRA Table 3.2.1, item 3.2.1-54, addresses stainless steel piping, piping components, and piping 

elements exposed to treated water greater than 60 °C (140 °F). The GALL Report recommends 

GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking,” and AMP XI.M2, “Water 

Chemistry,” to manage cracking due to SCC and IGSCC for this component group. The 

applicant stated that this item is not used because stainless steel components of the ESF

systems subject to evaluation under the BWR Stress Corrosion Cracking Program were 

reviewed as part of the RCPB (LRA Table 3.1.2-3).

In its review, the staff needed to further clarify whether the scope of the applicant’s BWR Stress 

Corrosion Cracking Program includes relevant piping and piping welds regardless of ASME 

Code classification, consistent with GALL Report AMP XI.M7. The staff noted that LRA 

Section B.1.9 for the BWR Stress Corrosion Cracking Program includes the RCPB components 

in the program scope, but does not clearly address whether the scope of the program includes 

non-Class 1 piping and associated welds.

By letter dated April 3, 2012, the staff issued RAI B.1.9-1 requesting that the applicant clarify 

whether the scope of the BWR Stress Corrosion Cracking Program includes non-Class 1 piping 

and piping welds made of austenitic stainless steel and nickel alloy materials. The staff also 

requested that if not included, the applicant justify why non-Class 1 piping and piping welds are 

excluded from the scope of the BWR Stress Corrosion Cracking Program.

In its response dated May 1, 2012, the applicant clarified that the BWR Stress Corrosion 

Cracking Program applies to relevant BWR piping and piping welds made of austenitic stainless 

steel and nickel alloy regardless of code classification, consistent with the GALL Report as 

described in LRA Section B.1.9. The applicant also clarified that non-Class 1 piping and piping 

welds were not excluded from the program. The applicant further clarified that at GGNS, all 

components included in the scope of this program are part of the RCPB and were subject to an 

AMR. In addition, the applicant indicated that the results of the AMR of these RCPB

components are documented in LRA Tables 3.1.2-1 and 3.1.2-3.

In its review of the applicant’s response to RAI B.1.9-1, the staff noted that the applicant clarified 

that its BWR Stress Corrosion Cracking Program applies to the relevant BWR piping and piping 

welds made of austenitic stainless steel and nickel alloy regardless of code classification, 

consistent with the GALL Report. However, LRA item 3.2.1-54 indicates that the components in 

the ESF systems, subject to the BWR Stress Corrosion Cracking Program, were reviewed as 
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part of the RCPB. Therefore, the staff needed justification as to why the components 

associated with LRA item 3.2.1-54 were reviewed as part of the RCPB, which consists of 

Class 1 components as discussed in LRA Section 2.3.1.2.

By letter dated July 23, 2012, the staff issued RAI B.1.9-1a requesting that the applicant justify 

why LRA Sections B.1.9 and A.1.9 indicate that the BWR Stress Corrosion Cracking Program 

manages only aging of the RCPB in contrast with the program scope recommended in the 

GALL Report that includes relevant piping and piping welds regardless of code classification. 

The staff also requested that the applicant clarify why LRA item 3.2.1-54 indicates that the 

components in the ESF systems, subject to the BWR Stress Corrosion Cracking Program, were 

reviewed as part of the RCPB, rather than against the relevant piping and piping welds 

(regardless of code classification) recommended in GALL Report AMP XI.M7.

In its response dated August 15, 2012, the applicant stated that there are no piping components 

or piping welds made of austenitic stainless steel or nickel alloy that are 4 inches or larger in 

nominal diameter and contain reactor coolant at a temperature above 93°C (200°F) during 

power operation in the non-Class 1 portions of the ESF system. The applicant further provided 

revisions to LRA item 3.2.1-54 to clarify that there are no components outside the reactor 

coolant pressure boundary subject to the BWR Stress Corrosion Cracking Program 

requirements. The staff finds that the applicant’s response acceptable because the applicant 

confirmed that the ESF system has no non-Class 1 components that should be included in the 

scope of the applicant’s BWR Stress Corrosion Cracking Program. The staff’s concerns 

described in RAIs B1.9-1 and B.1.9-1a is resolved.

The staff concludes that for LRA item 3.2.1-54, 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).

LRA Table 3.2.1, item 3.2.1-59 addresses galvanized steel ducting, piping, and components 

exposed to air-indoor, controlled. The GALL Report recommends that there are no aging 

effects, aging mechanisms, or AMPs. The applicant stated that this item is not applicable 

because galvanized steel components were evaluated as steel. The staff noted that the 

applicant also evaluated all air-indoor environments as uncontrolled in the ESF system, rather 

than controlled. The staff also noted that the LRA includes AMR evaluations for steel ducting 

and piping components exposed to plant indoor air that references LRA Table 3.2.1, 

items 3.2.1-40 (external environments) and 3.2.1-44 (internal environments) and credit the 

External Surfaces Monitoring and Internal Surfaces in Miscellaneous Piping and Ducting 

Components Programs, respectively, to manage loss of material due to general corrosion in 

ESF systems. The staff evaluated the applicant’s claim and finds it acceptable because the 

applicant chose to evaluate the subject components as being constructed of a more susceptible 

material and exposed to a more aggressive environment, referencing appropriate alternative

Table 1 items and managing aging consistent with GALL Report recommendations for those

Table 1 items.

LRA Table 3.2.1, item 3.2.1-60 addresses glass piping elements exposed to uncontrolled indoor 

air, lubricating oil, raw water, treated water, treated borated water, air with borated water 

leakage, condensation, gas, closed-cycle cooling water, and outdoor air. The applicant stated 

that it is consistent with the GALL Report for glass components exposed to indoor air and lube 

oil, but that for other environments there are no glass components within the ESF systems that 

are within the scope of license renewal. SRP-LR Table 3.2-1, item 3.2.1-60 states that there 
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are no aging effects or aging mechanisms, and that no AMP is recommended for this 

component group exposed to these environments; therefore, the staff finds the applicant’s 

determination acceptable.

LRA Table 3.2.1, item 3.2.1-64 addresses steel piping, piping components, and piping elements 

exposed to air – indoor, controlled (external) and gas and states that there are no aging effects,

aging mechanisms or AMPs. SRP-LR item 3.2.1-64 recommends that there is no aging effect

or aging mechanism, and that no AMP is recommended for this component group exposed to 

this environment; therefore, the staff finds the applicant’s determination acceptable.

3.2.2.1.2 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-16 addresses steel containment isolation piping and components 

(internal surfaces), piping, piping components, and piping elements exposed to treated water,

which will be managed for loss of material due to general, pitting, and crevice corrosion. For the 

AMR items that cite generic note E, the LRA credits the Water Chemistry Control – BWR, 

One-Time Inspection, and Periodic Surveillance and Preventive Maintenance Programs to 

manage the aging effect for steel containment isolation and other ESF system components. 

The GALL Report recommends GALL Report AMPs XI.M2, “Water Chemistry,” and XI.M32, 

“One-Time Inspection,” to ensure that these aging effects are adequately managed. GALL 

Report AMPs XI.M2 and XI.M32 recommend using water chemistry controls and a one-time 

visual or volumetric inspection to manage aging.

The staff’s evaluations of the applicant’s Water Chemistry Control – BWR, One-Time Inspection, 

and Periodic Surveillance and Preventive Maintenance Programs are documented in SER 

Sections 3.0.3.1.41, 3.0.3.1.32, and 3.0.3.2.2, respectively. The staff noted that the Water 

Chemistry Control – BWR and One-Time Inspection Programs propose to manage the aging of 

steel containment isolation and other ESF system components through the use of water 

chemistry controls and a one-time inspection using visual, ultrasonic, or surface techniques to 

ensure the effectiveness of the water chemistry control program. The staff also noted that the 

Periodic Surveillance and Preventive Maintenance Program proposes to manage aging through 

the use of periodic inspections, as least once every 5 years, using visual or other appropriate 

techniques. In its review of components associated with item 3.2.1-16, for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging using the Water 

Chemistry Control – BWR, One-Time Inspection, and Periodic Surveillance and Preventive 

Maintenance Programs acceptable because the Water Chemistry Control – BWR Program

establishes the plant water chemistry control parameters and their limits to mitigate the 

environmental effect on the aging and identifies the actions required if the parameters exceed 

the limits, and the One-Time Inspection and Periodic Surveillance and Preventive Maintenance 

Programs include visual, ultrasonic, surface inspection, or other appropriate techniques capable 

of detecting general, pitting, and crevice corrosion.

The staff concludes that for LRA item 3.2.1-16, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.3 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-17 addresses aluminum and stainless steel piping, piping 

components, and piping elements exposed to treated water, which will be managed for loss of 
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material due to pitting and crevice corrosion. For the AMR items that cite generic note E, the 

LRA credits the Water Chemistry Control – BWR, One-Time Inspection, and Periodic 

Surveillance and Preventive Maintenance Programs to manage the aging effect for stainless 

steel components. The GALL Report recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.M32, “One-Time Inspection,” to ensure that these aging effects are 

adequately managed. GALL Report AMPs XI.M2 and XI.M32 recommend using water 

chemistry controls and a one-time visual or volumetric inspection to manage aging.

The applicant stated that for item 3.2.1-17, the applicability is limited to stainless steel 

components. The staff noted that a search of the applicant’s UFSAR confirmed that no in-scope 

aluminum components exposed to treated water are present in the ESF systems.

The staff’s evaluations of the applicant’s Water Chemistry Control – BWR, One-Time Inspection, 

and Periodic Surveillance and Preventive Maintenance Programs are documented in SER 

Sections 3.0.3.1.41, 3.0.3.1.32, and 3.0.3.2.2, respectively. The staff noted that the Water 

Chemistry Control – BWR and One-Time Inspection Programs propose to manage the aging of 

stainless steel components through the use of water chemistry controls and a one-time 

inspection using visual, ultrasonic, or surface techniques to ensure the effectiveness of the 

water chemistry control program. The staff also noted that the Periodic Surveillance and 

Preventive Maintenance Program proposes to manage aging through the use of periodic 

inspections, as least once every 5 years, using visual or other appropriate techniques. In its 

review of components associated with item 3.2.1-17, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Water Chemistry 

Control – BWR, One-Time Inspection, and Periodic Surveillance and Preventive Maintenance 

Programs acceptable because the Water Chemistry Control – BWR Program establishes the 

plant water chemistry control parameters and their limits to mitigate the environmental effect on 

the aging and identifies the actions required if the parameters exceed the limits, and the 

One-Time Inspection and Periodic Surveillance and Preventive Maintenance Programs include 

visual, ultrasonic, surface inspection, or other appropriate techniques capable of detecting 

pitting and crevice corrosion.

The staff concludes that for LRA item 3.2.1-17, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.4 Cracking Due to Stress Corrosion Cracking

LRA Table 3.2.1, item 3.2.1-28 addresses stainless steel piping, piping components, and piping 

elements exposed to closed cycle cooling water greater than 60 °C (greater than 140 °F) that 

will be managed for cracking due to SCC. The staff noted that the applicant also applied this 

item to nickel alloy reactor recirculation pump heat exchanger assembly subcomponents. For 

the AMR item that cites generic note C, the LRA credits the Inservice Inspection and Water 

Chemistry Control – Closed Treated Water Systems Programs to manage the aging effect for 

heat exchanger assembly components. The GALL Report recommends GALL Report

AMP XI.M21A, “Closed Treated Water Systems,” to ensure that this aging effect is adequately 

managed for stainless steel components. GALL Report AMP XI.M21A recommends using 

water chemistry controls and visual inspections to manage aging.

The staff reviewed the associated items in the LRA and considered whether the nickel alloy 

aging effects proposed by the applicant constitute all of the credible aging effects for this 
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component, material, and environment description. The staff noted that the applicant addressed 

loss of material for this component, material, and environment combination in other AMR items 

in LRA Table 3.1.2-3. Based on its review of the ASM Handbook, Volume 13B, chapter on 

“Corrosion of Nickel and Nickel-Based Alloys” (ASM International, 2005), which states that 

nickel-base alloys are generally more resistant to SCC than stainless steels, but SCC can occur 

in specific environments, such as hot caustic, fluoride, and chloride-containing water, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluations of the applicant’s Inservice Inspection and Water Chemistry Control –

Closed Treated Water Systems Programs are documented in SER Sections 3.0.3.1.22 and 

3.0.3.1.42, respectively. The staff noted that the Inservice Inspection Program proposes to 

manage the aging through the use of volumetric, surface, or visual examinations in accordance 

with the ASME Boiler and Pressure Vessel Code, Section XI. The staff also noted that the 

Water Chemistry Control – Closed Treated Water Systems Program proposes to manage the 

aging with water chemistry controls and opportunistic and periodic inspections. In its review of 

components associated with item 3.2.1-28 for which the applicant cited generic note C, the staff 

finds the applicant’s proposal to manage aging using the Inservice Inspection and Water 

Chemistry Control – Closed Treated Water Systems Programs acceptable because the water 

chemistry controls are capable of mitigating the environmental effects on cracking and the 

opportunistic and periodic inspections can detect the presence or extent of cracking before loss 

of intended function.

The staff concludes that for LRA item 3.2.1-28, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.5 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.2.1, item 3.2.1-31 addresses stainless steel heat exchanger components, piping,

piping components, and piping elements exposed to closed cycle cooling water, which will be 

managed for loss of material due to pitting and crevice corrosion. The staff noted that the 

applicant also applied this item to nickel alloy heat exchanger components. The LRA credits the 

Water Chemistry Control – Closed Treated Water Systems Program to manage the aging effect 

for heat exchanger assembly components. The GALL Report recommends GALL Report

AMP XI.M21A, “Closed Treated Water Systems,” to ensure that this aging effect is 

adequately managed.

The staff reviewed the associated items in the LRA and considered whether the nickel alloy 

aging effects proposed by the applicant constitute all of the credible aging effects for this 

component, material, and environment description. The staff noted that the applicant addressed 

cracking for this component, material, and environment combination in other AMR items in LRA

Table 3.1.2-3. Based on its review of GALL Report items VII.C3.AP-206 and VII.E5.AP-276, 

which state that nickel-based alloys are subject to loss of material when exposed to raw water 

and waste water, respectively, which do not contain the corrosion inhibitors present in 

closed-cycle cooling water, the staff finds that the applicant has identified all credible aging 

effects for this component, material, and environment combination.

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.1.42. The staff finds the applicant’s 
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proposal to manage loss of material using the Water Chemistry Control – Closed Treated Water 

Systems Program acceptable because the water chemistry controls are capable of mitigating 

the environmental effects on loss of material and the opportunistic and periodic inspections can 

detect the presence or extent of corrosion before loss of intended function.

The staff concludes that for LRA item 3.2.1-31, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.6 No Aging Effects Requiring Aging Management for Stainless Steel Piping, Piping 

Components, and Piping Elements Exposed to Air-Indoor Uncontrolled, Air with 

Borated Water Leakage, Concrete, or Gas

LRA Table 3.2.1, item 3.2.1-63 addresses stainless steel piping, piping components, and piping 

elements exposed to air-indoor uncontrolled (both internally and externally), air with borated 

water leakage, concrete, or gas and states that the items have no aging effects and no AMP is 

proposed. The GALL Report recommends that no aging effects are applicable and no AMP is 

recommended.

During its review of components associated with item number 3.2.1-63 for which the applicant 

cited generic note A, the staff noted that the LRA credits this item for stainless steel moisture 

separators exposed internally and externally to indoor air in LRA Table 3.2.2-6. There are no 

other environments listed for the moisture separator. The staff noted that moisture separators 

are usually exposed to air containing significant amounts of water, and parts may be exposed to 

water where the moisture accumulates. The GALL Report recommends that stainless steel 

components exposed to condensation or raw water be managed for loss of material. By letter 

dated May 24, 2012, the staff issued RAI 3.2.1.63-1 requesting that the applicant explain why 

the stainless steel moisture separator is not susceptible to any aging effects and does not 

require aging management.

In its response dated June 22, 2012, the applicant stated that the component is in the SGTS, 

which under normal operating conditions is in standby with an internal environment of indoor air 

that does not contain significant moisture. However, the staff noted that the applicant’s 

definition of air-indoor states that it is air in an environment that is protected from precipitation. 

The LRA definition of air-indoor does not discuss the dew point or humidity of the air. SRP-LR 

Section A.1.2.1 states that aging effects should be considered that result from normal plant 

operation, including plant operating transients and shutdown. The staff noted that during normal 

operation, SGTSs are subject to periodic testing that is typically several hours in duration, and 

that the systems may be placed in-service at other times.

The staff finds the applicant’s response unacceptable because it is unclear how condensation or 

the accumulation of moisture is prevented during times when the SGTS is placed in service 

such that wetting and drying of the internal surfaces does not occur. By letter dated 

July 27, 2012, the staff issued RAI 3.2.1.63-1a requesting that the applicant provide justification 

for why aging will not occur in the moisture separator during the period of extended operation, 

such as evidence of the absence of condensation and corrosion.

In its response dated August 21, 2012, the applicant stated that the drain valves for the moisture 

separators are open when the system is in operation, preventing accumulation of moisture. The 

applicant also stated that the inside of each moisture separator is cleaned and inspected every 
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2 years. The applicant further stated that the inspections in 2010 and 2011 documented that 

each moisture separator was clean with no corrosion present, which justifies why the 

components have no aging effects requiring management.

The staff finds the applicant’s response acceptable because the moisture separators are 

normally in standby exposed to indoor air; when they are placed in service, moisture does not 

accumulate within the separators; the plant indoor air does not normally contain contaminants, 

such as chlorides, that would cause loss of material or cracking in stainless steel components if 

allowed to condense; and the inspections of the moisture separators have found no evidence of 

aging. The staff’s concerns described in RAI 3.2.1.63-1 and 3.2.1.63-1a are resolved.

The staff concludes that for LRA item 3.2.1-63, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.2.2.1.7 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results which the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.2.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff

also reviewed information pertaining to the applicant’s consideration of recent operating 

experience and proposals for managing aging effects. On the basis of its review, the staff 

concludes that the AMR results, which the applicant claimed to be consistent with the GALL 

Report, are consistent.

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).

3.2.2.2 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

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• loss of material due to erosion

• loss of material due to general corrosion and fouling that leads to corrosion

• cracking due to SCC

• 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 
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audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.2.2.2. The staff’s review of the applicant’s 

further evaluation follows.

3.2.2.2.1 Cumulative Fatigue Damage

LRA Section 3.2.2.2.1 is associated with LRA Table 3.2.1 item 3.2.1-1 that addresses steel and 

stainless steel piping, piping components, and piping elements in the engineered-safety 

systems and is being managed for cumulative fatigue damage. The applicant addressed the 

further evaluation criteria of the SRP-LR by stating that fatigue is a TLAA, as defined in 

10 CFR 54.3, and is required to be evaluated in accordance with 10 CFR 54.21(c). The 

applicant stated that its evaluation of the TLAA is addressed separately in LRA Section 4.3.

The staff reviewed LRA Section 3.2.2.2.1 against the criteria in SRP-LR Section 3.2.2.2.1 that

states that cumulative fatigue damage of steel and stainless steel piping, piping components, 

and piping elements in the ECCS is a TLAA, and that these TLAAs are to be evaluated in 

accordance with 10 CFR 54.21(c) and SRP-LR Section 4.3. The staff also reviewed the AMR 

items associated with LRA Section 3.2.2.2.1 and found that the AMR results are consistent with 

the GALL Report and SRP-LR, except as identified below.

The staff reviewed the applicant’s AMR results in the associated LRA tables within LRA 

Sections 3.2, 3.3, and 3.4. For LPCS system, HPCS system, SLC system, suppression pool 

makeup system, and SGTS, UFSAR Table 3.2-1 indicates these systems are non-Class 1 and 

the staff noted that there may be components that have been analyzed for cumulative fatigue 

damage. It is not clear to the staff why those components that may have been analyzed for 

cumulative fatigue damage, as discussed in LRA Section 4.3.2, are not included as AMR items 

in applicable tables in LRA Sections 3.2, 3.3 and 3.4.

By letter dated June 20, 2012, the staff issued RAI 3.2.2-1 requesting the applicant to justify that 

LRA Tables 3.2, 3.3, and 3.4 do not need to identify and list all the AMR results for non-Class 1 

piping associated with a TLAA for managing the aging effect of cumulative fatigue damage.

In its response dated July 19, 2012, the applicant stated that the non-Class 1 portions of the 

LPCS system, HPCS system, SLC system, suppression pool makeup system, and SGTS have 

normal temperatures below the temperature threshold for fatigue. The applicant explained that 

there are no fatigue time-limited aging analyses for these systems and no fatigue AMR items. 

The staff noted that thermal stress is proportional to the change of temperature from the 

reference temperature. When the system temperature is low, the difference between the 

reference temperature and system temperature is small; thus, the resulting thermal stress is 

small and metal fatigue would not be an aging effect required for managing these systems.

Based on its review, the staff finds the applicant’s response to RAI 3.2.2-1 acceptable because 

the applicant justified that AMR results are not required to identify metal fatigue as an aging 

effect for the non-Class 1 portions of the LPCS system, HPCS system, SLC system, 

suppression pool makeup system, and SGTS and that metal fatigue of these systems is not an 

aging effect requiring management due to low system temperature, as explained above. The 

staff’s concern described in RAI 3.2.2-1 is resolved.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.2.2.2.1 criteria. For those items that apply to LRA Section 3.2.2.2.1, the staff 
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determined 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). SER Section 4.3 documents the staff’s review of the 

applicant’s evaluation of the TLAA for these components.

3.2.2.2.2 Loss of Material Due to Cladding Breach

LRA Section 3.2.2.2.2, associated with LRA Table 3.2.1, item 3.2.1-2, addresses loss of 

material due to cladding breach in PWR steel pump casings with stainless steel cladding 

exposed to treated borated water. The applicant stated that this item is not applicable because 

it is applicable to PWRs only. The staff confirmed that this item is associated only with PWR 

plants and therefore, the staff finds the applicant’s determination acceptable.

3.2.2.2.3 Loss of Material Due to Pitting and Crevice Corrosion

The staff reviewed LRA Section 3.2.2.2.3 against the following criteria in SRP-LR 

Section 3.2.2.2.3:

(1) LRA Section 3.2.2.2.3.1, associated with LRA Table 3.2.1, item 3.2.1-3, addresses loss 

of material due to pitting and crevice corrosion in partially encased stainless steel tanks 

exposed to raw water. The applicant stated that this item is not applicable because the 

ESF systems do not include partially encased stainless steel tanks exposed to this 

environment. The staff reviewed LRA Sections 2.3.2 and 3.2, and the UFSAR and finds 

that no in-scope partially encased stainless steel tanks exposed to raw water are present 

in the ESF systems.

(2) LRA Section 3.2.2.2.3, which is associated with LRA Table 3.2.1 item 3.2.1-4, addresses 

stainless steel piping, piping components, piping elements and tanks exposed to 

air-outdoor that will be managed for loss of material due to pitting and crevice corrosion. 

The applicant stated that this item is not applicable because there are no in-scope 

stainless steel components exposed to outdoor air or located near unducted air intakes 

in the ESF systems. The staff reviewed LRA Sections 2.3.2 and 3.2 and the UFSAR 

and finds that no in-scope stainless steel piping, piping components, piping elements 

and tanks exposed to air-outdoor are present in the ESF systems.

3.2.2.2.4 Loss of Material Due to Erosion

LRA Section 3.2.2.2.4, associated with LRA Table 3.2.1, item 3.2.1-5, addresses loss of 

material in stainless steel minimum flow recirculation orifices exposed to treated borated water 

for PWR high pressure safety injection pumps. The applicant stated that item 3.2.1-5 is not 

applicable because it only applies to PWRs. The staff evaluated the applicant’s claim and finds 

it acceptable because item 3.2.1-5 is only applicable to PWRs and does not apply to GGNS.

3.2.2.2.5 Loss of Material Due to General Corrosion and Fouling that Leads to Corrosion

LRA Section 3.2.2.2.5, associated with LRA Table 3.2.1, item 3.2.1-6, addresses loss of 

material due to general corrosion and fouling for steel drywell and suppression chamber spray 

system nozzle and flow orifice internal surfaces exposed to indoor air. The applicant stated that 

this item is not applicable because the containment spray nozzles are stainless steel. The 

applicant also stated that there are no steel orifices in the containment spray subsystem of the 

RHR system internally exposed to an indoor air environment. The staff reviewed LRA 
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Sections 2.3.2 and 3.2 and the UFSAR and finds that no in-scope steel drywell and suppression 

chamber spray system nozzle and flow orifice internal surfaces exposed to indoor air are 

present in the ESF systems.

3.2.2.2.6 Cracking Due to Stress Corrosion Cracking

LRA Section 3.2.2.2.6, which is associated with LRA Table 3.2.1 item 3.2.1-7, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to air-outdoor 

that will be managed for cracking due to SCC. The applicant stated that this item is not 

applicable because there are no in-scope stainless steel components exposed to outdoor air or 

located near unducted air intakes in the ESF systems. The staff reviewed LRA Sections 2.3.2 

and 3.2 and the UFSAR and finds that no in-scope stainless steel piping, piping components, 

piping elements and tanks exposed to air-outdoor are present in the ESF systems.

3.2.2.2.7 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.

3.2.2.2.8 Loss of Material Due to Recurring Internal Corrosion

By letter dated May 13, 2014, the applicant addressed recurring internal corrosion that is 

described in Section A and Appendix B of LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation.” 

LR-ISG-2012-02 includes a new section (Section 3.2.2.2.9, Loss of Material Due to Recurring 

Internal Corrosion) in the SRP-LR for “AMR Results for Which Further Evaluation Is 

Recommended by the GALL Report.”

Based on its review of plant-specific operating experience for the past 5 years, the applicant 

stated that microbiologically-influenced corrosion of piping components is a recurring internal 

corrosion issue, as defined in LR-ISG-2012-02, Section A. The applicant also stated that it 

monitors loss of material in piping components due to microbiologically-influenced corrosion in 

the CW, SSW, plant service water, and fire protection systems. Based on this, the staff 

determines that recurring internal corrosion is not applicable to the ESF section, because these 

systems are addressed in the Auxiliary System, Section 3.3, and Steam and Power Conversion 

Systems, Section 3.4, of the LRA.

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

In LRA Tables 3.2.2-1 through 3.2.2-8, 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 3.2.2-1 through 3.2.2-8, the applicant indicated, via notes F through J that the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 
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neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

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 Residual Heat Removal - 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 

RHR component groups. The staff’s review did not identify any items with notes F through J, 

indicating that the combinations of component type, material, environment, and AERM for this 

system are consistent with the GALL Report.

3.2.2.3.2 Low Pressure Core Spray - 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 

Low Pressure Core Spray component groups.

Carbon Steel Piping Components Exposed to Treated Water. By letter dated 

December 18, 2012, the applicant revised LRA Tables 3.2.2-2, 3.2.2-3, 3.2.2-8-2, and 3.2.2-8-3 

and stated that carbon steel piping components exposed to treated water will be managed for 

loss of material by the Flow-Accelerated Corrosion Program. The AMR items cite generic 

note H and also cite plant-specific note 204, which states that the Flow-Accelerated Corrosion 

Program also manages loss of material due to erosion mechanisms other than flow-accelerated 

corrosion.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel piping components exposed to treated water are susceptible to 

loss of material due to general, pitting, crevice, and flow-accelerated corrosion and recommends 

GALL Report AMP XI.M2, AMP XI.M32, and AMP XI.M17 to manage the aging effect due to 

these mechanisms. However the applicant has identified additional aging mechanisms. The 

applicant addressed the GALL Report identified aging effects for this component, material and 

environment combination in other AMR items in LRA Tables 3.2.2-2, 3.2.2-3, 3.2.2-8-2, 

and 3.2.2-8-3.

The staff’s evaluation of the applicant’s Flow-Accelerated Corrosion Program is documented in 

SER Section 3.0.3.1.21. The staff finds the applicant’s proposal to manage loss of material due 

to erosion mechanisms other than flow-accelerated corrosion using the Flow-Accelerated 

Corrosion Program acceptable, because the associated components can be treated similar to 

“susceptible-not-modeled” components currently within the program, which ensures that the 

consequent wall thinning will be detected before loss of intended function.

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).

3.2.2.3.3 High Pressure Core Spray - Summary of Aging Management Review –

LRA Table 3.2.2-3

The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for the 

HPCS component groups.

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.2.2.3.2.

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).

3.2.2.3.4 Reactor Core Isolation Cooling - Summary of Aging Management Review –

LRA Table 3.2.2-4

The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for the 

RCIC component groups.

In LRA Table 3.2.2-4, the applicant stated there are TLAAs for stainless steel orifice and tubing 

exposed to steam, which cite generic note G. The staff confirmed that there is a TLAA, as 

documented in LRA Section 4.3.2, for these components and material. The staff’s evaluation of 

the fatigue TLAA for non-Class 1 components is documented in SER Section 4.3.2.

Stainless steel heat exchanger exposed to lubricating oil. In LRA Table 3.2.2-4, the applicant 

stated that stainless steel heat exchanger tubesheets, heat exchanger tubes, orifice, tubing, and 

valve bodies exposed to lubricating oil will be managed for cracking by the Oil Analysis 

Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report,

which states that stainless steel heat exchanger tubesheets, heat exchanger tubes, orifice, 

tubing, and valve bodies exposed to lubricating oil are susceptible to loss of material and 

recommends GALL Report AMP XI.M39 to manage the 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).

3.2.2.3.5 Pressure Relief – Summary of Aging Management Review – LRA Table 3.2.2-5

The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for the 

pressure relief component groups.
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In LRA Table 3.2.2-5, the applicant stated that there are TLAAs for stainless steel thermowell, 

tubing, and valve body exposed to steam, which cite generic note G. The staff confirmed that 

there is a TLAA, as documented in LRA Section 4.3.2, for these components and material. The 

staff’s evaluation of the fatigue TLAA for non-Class 1 components is documented in SER 

Section 4.3.2.

3.2.2.3.6 Standby Gas Treatment – Summary of Aging Management Review –

LRA Table 3.2.2-6

The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for the 

standby gas treatment component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system are consistent with the GALL Report.

3.2.2.3.7 Containment Penetrations – Summary of Aging Management Review –

LRA Table 3.2.2-7

The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for the 

containment penetrations component groups.

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. In LRA Tables 3.2.2-7, 3.3.2-7, 3.3.2-9, 3.3.2-14, 3.3.2-19-19, 3.3.2-19-25, and 

3.3.2-19-26, the applicant stated that stainless steel piping components, such as tubing, 

thermowells and value bodies, exposed to external condensation will be managed for loss of 

material by the External Surfaces Monitoring Program. As amended by letter dated 

October 25, 2013, the applicant revised LRA Table 3.3.2-9 to include stainless steel sight 

glasses exposed to external condensation, which will also be managed for loss of material by 

the External Surfaces Monitoring Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all of the credible aging effects for this component, material, 

and environment description. Based on its review of the GALL Report, which states that 

stainless steel exposed to condensation should be age managed for loss of material, the staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s External Surfaces Monitoring is documented in SER 

Section 3.0.3.1.17. The staff finds the applicant’s proposal to manage aging using the External 

Surfaces Monitoring acceptable because the AMP includes visual inspections capable of 

detecting loss of material in stainless components exposed to external condensation.

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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3.2.2.3.8 Miscellaneous ESF Systems in Scope for 10 CFR 54.4(a)(2) – Summary of Aging 

Management Review – LRA Table 3.2.2-8

The staff reviewed LRA Tables 3.2.2-8-1 through 3.2.2-8-4, which summarizes the results of 

AMR evaluations for the miscellaneous ESF systems in scope for 10 CFR 54.4(a)(2) component 

groups.

For LRA Tables 3.2.2-8-2 and 3.2.2-8-3

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.2.2.3.2.

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).

3.2.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the ESF system components within the scope of license renewal and 

subject to an AMR will be adequately managed so that the intended functions will remain 

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:

• CRD

• SLC

• suppression pool makeup

• leakage detection and control

• combustible gas control

• fuel pool cooling and cleanup

• SSW

• component cooling water

• plant service water

• floor and equipment drainage

• compressed air

• fire protection – water

• fire protection – Halon and CO2

• plant chilled water

• standby diesel generator

• HPCS diesel generator
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• control room Heating, Ventilation, and Air Conditioning (HVAC)

• HVAC

• miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2)

3.3.1 Summary of Technical Information in the Application

LRA Section 3.3 provides AMR results for the auxiliary systems components and component 

groups. LRA Table 3.3.1, “Summary of Aging Management Programs for Auxiliary Systems 

Evaluated in Chapter VII of NUREG-1801,” is a summary comparison of the applicant’s AMRs 

with those evaluated in the GALL Report for the auxiliary systems components and component 

groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.3.2 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 review of AMRs to ensure the applicant’s claim that certain AMRs are 

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.

During its review, 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 

are consistent with the SRP-LR Section 3.3.2.2 acceptance criteria. The staff’s evaluations are 

documented in SER Section 3.3.2.2.

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 3.3.2.3.

For SSCs which the applicant claimed were not applicable or required no aging management, 

the staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

Table 3.3-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.3 and addressed in the GALL Report.
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Table 3.3-1 Staff Evaluation for Auxiliary System Components in the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

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 

due to fatigue

Fatigue is a TLAA to 

be evaluated for the 

period of extended 

operation for 

structural girders of 

cranes that fall within 

the scope of 

10 CFR Part 54 

(Standard Review 

Plan, Section 4.7, 

“Other Plant-Specific 

Time-Limited Aging 

Analyses,” for 

generic guidance for 

meeting the 

requirements of 

10 CFR 54.21(c)(1))

Yes TLAA Consistent with the 

GALL Report (see 

Section 3.3.2.2.1)

Stainless steel, steel 

heat exchanger 

components and 

tubes, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water, air –

indoor, uncontrolled, 

treated water 

(3.3.1-2)

Cumulative 

fatigue damage 

due to fatigue

Fatigue is a TLAA to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.3.2.2.1)

Stainless steel heat 

exchanger 

components, 

non-regenerative 

exposed to treated 

borated water 

>60 °C (>140 °F) 

(3.3.1-3)

Cracking due to 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M2, 

“Water Chemistry”

The AMP is to be 

augmented by 

verifying the 

absence of cracking 

due to stress 

corrosion cracking 

and cyclic loading. 

An acceptable 

verification program 

is to include 

temperature and 

radioactivity 

monitoring of the 

shell side water, and 

eddy current testing 

of tubes.

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.2.2)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.3.1-4)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

GGNS (see 

Section 3.3.2.2.3)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with stainless 

steel or nickel-alloy 

cladding) pump 

casings exposed to 

treated borated 

water (3.3.1-5)

Loss of material 

due to cladding 

breach

A plant-specific AMP

is to be evaluated. 

Reference NRC 

Information Notice 

94-63, “Boric Acid 

Corrosion of 

Charging Pump 

Casings Caused by 

Cladding Cracks.”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.2.4)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.3.1-6)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes Not applicable Not applicable to 

GGNS (see 

Section 3.3.2.2.5)

Stainless steel 

high-pressure pump, 

casing exposed to 

treated borated 

water (3.3.1-7)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger 

components and 

tubes exposed to 

treated borated 

water >60 °C 

(>140 °F) (3.3.1-8)

Cracking due to 

cyclic loading

Chapter XI.M1, 

“ASME Section XI 

Inservice Inspection, 

Subsections IWB, 

IWC, and IWD”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel, aluminum, 

copper alloy (>15% 

Zn or >8% Al) 

external surfaces, 

piping, piping 

components, and 

piping elements, 

bolting exposed to 

air with borated 

water leakage 

(3.3.1-9)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Steel, high-strength 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-10)

Cracking due to 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel, high-strength 

high-pressure pump, 

closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-11)

Cracking due to 

stress corrosion 

cracking; cyclic 

loading

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

GGNS (see 

Section 3.3.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel; stainless steel 

closure bolting, 

bolting exposed to 

condensation, air –

indoor, uncontrolled 

(external), air –

outdoor (external) 

(3.3.1-12)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.3.1-13)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

GGNS (see 

Section 3.3.2.1.1)

Steel, stainless steel 

bolting exposed to 

soil (3.3.1-14)

Loss of preload Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel; stainless 

steel, copper alloy, 

nickel alloy, stainless 

steel closure bolting, 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), any 

environment, air –

outdoor (external), 

raw water, treated 

borated water, fuel 

oil, treated water 

(3.3.1-15)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) (3.3.1-16)

Cracking due to 

stress corrosion 

cracking, 

intergranular 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M25, 

“BWR Reactor 

Water Cleanup 

System”

No Not applicable Not applicable to 

GGNS (see 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-17)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

Consistent with the 

GALL Report

Stainless steel 

high-pressure pump, 

casing, piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

>60 °C (>140 °F), 

sodium pentaborate 

solution >60 °C 

(>140 °F) (3.3.1-18)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

regenerative heat 

exchanger 

components 

exposed to treated 

water >60 °C 

(>140 °F) (3.3.1-19)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel, steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to treated 

borated water 

>60 °C (>140 °F), 

treated water >60 °C 

(>140 °F) (3.3.1-20)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.3.1-21)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-22)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry 

Control – BWR 

and One-Time 

Inspection 

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-23)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-24)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel; steel 

with stainless steel 

cladding, aluminum 

piping, piping 

components, and 

piping elements, 

exchanger 

components 

exposed to treated 

water, sodium 

pentaborate solution 

(3.3.1-25)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water Chemistry

Control – BWR, 

One-Time 

Inspection, and 

Periodic 

Surveillance and 

Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.2)
3-323

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with elastomer 

lining), steel (with 

elastomer lining or 

stainless steel 

cladding) piping, 

piping components, 

and piping elements 

exposed to treated 

water (3.3.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion (only 

for steel after 

lining/cladding 

degradation)

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.3.1-27)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel, steel 

(with stainless steel 

or nickel-alloy 

cladding) spent fuel 

storage racks 

(BWR), spent fuel 

storage racks 

(PWR), piping, 

piping components, 

and piping elements; 

tanks exposed 

treated water >60 °C 

(>140 °F), treated 

borated water 

>60 °C (>140 °F) 

(3.3.1-28)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel (with stainless 

steel cladding); 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

borated water 

(3.3.1-29)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material Piping, 

piping components, 

and piping elements 

exposed to Raw 

Water (3.3.1-30)

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Fiberglass, HDPE 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (internal) 

3.3.1-30x)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
3-324

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-31)

Cracking due to 

settling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-32)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Elastomer seals and 

components 

exposed to raw 

water (3.3.1-32x)

Hardening and 

loss of strength 

due to 

elastomer 

degradation; 

loss of material 

due to erosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components 

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.3)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-33)

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Nickel alloy, copper 

alloy piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-34)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-35)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-36)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report
3-325

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel (with coating or 

lining) piping, piping 

components, and

piping elements 

exposed to raw 

water (3.3.1-37)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion; 

lining/coating 

degradation

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Copper alloy, steel 

heat exchanger 

components 

exposed to raw 

water (3.3.1-38)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.4)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-39)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-40)

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-41)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity

Consistent with the 

GALL Report

Copper alloy, 

titanium, stainless 

steel heat exchanger 

tubes exposed to 

raw water (3.3.1-42)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Service Water 

Integrity and Fire 

Water System

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.5)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.3.1-43)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report
3-326

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.3.1-44)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

closed-cycle cooling 

water (3.3.1-45)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report

Steel, copper alloy 

heat exchanger 

components, piping, 

piping components,

and piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-46)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report

Stainless steel; steel 

with stainless steel 

cladding heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water (3.3.1-47)

Loss of material 

due to 

microbiologically

-influenced 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.6)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water (3.3.1-49)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report

Stainless steel, 

copper alloy, steel 

heat exchanger 

tubes exposed to 

closed-cycle cooling 

water (3.3.1-50)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water Chemistry 

Control – Closed 

Treated Water 

Systems

Consistent with the 

GALL Report
3-327

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Boraflex spent fuel 

storage racks; 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks; 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-51)

Reduction of 

neutron-absorbi

ng capacity due 

to boraflex 

degradation

Chapter XI.M22, 

“Boraflex Monitoring”

No Boraflex 

Monitoring

Consistent with the 

GALL Report

Steel cranes; rails 

and structural 

girders exposed to 

air – indoor, 

uncontrolled 

(external) (3.3.1-52)

Loss of material 

due to general 

corrosion

Chapter XI.M23, 

“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

Consistent with the 

GALL Report

Steel cranes – rails 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-53)

Loss of material 

due to wear

Chapter XI.M23, 

“Inspection of 

Overhead Heavy 

Load and Light Load 

(Related to 

Refueling) Handling 

Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(3.3.1-54)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements: 

compressed air 

system exposed to 

condensation 

(internal) (3.3.1-55)

Loss of material 

due to general 

and pitting 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.3.1-56)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M24, 

“Compressed Air 

Monitoring”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report

Elastomers fire 

barrier penetration 

seals exposed to 

air – indoor, 

uncontrolled, air –

outdoor (3.3.1-57)

Increased 

hardness; 

shrinkage; loss 

of strength due 

to weathering

Chapter XI.M26, 

“Fire Protection”

No Fire Protection Consistent with the

GALL Report
3-328

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel halon/carbon 

dioxide fire 

suppression system 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-58)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M26, 

“Fire Protection”

No Fire Protection Consistent with the 

GALL Report

Steel fire rated doors 

exposed to air –

indoor, uncontrolled, 

air – outdoor 

(3.3.1-59)

Loss of material 

due to wear

Chapter XI.M26, 

“Fire Protection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings, and floors 

exposed to air –

indoor, uncontrolled 

(3.3.1-60)

Concrete 

cracking and 

spalling due to 

aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures 

Monitoring”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings, and floors 

exposed to air –

outdoor (3.3.1-61)

Cracking, loss 

of material due 

to freeze-thaw, 

aggressive 

chemical attack, 

and reaction 

with aggregates

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures 

Monitoring”

No Fire Protection 

and Structures 

Monitoring

Consistent with the 

GALL Report

Reinforced concrete 

structural fire 

barriers: walls, 

ceilings, and floors 

exposed to air –

indoor, uncontrolled, 

air – outdoor 

(3.3.1-62)

Loss of material 

due to corrosion 

of embedded 

steel

Chapter XI.M26, 

“Fire Protection,”

and Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel fire hydrants 

exposed to air –

outdoor (3.3.1-63)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Steel, copper alloy 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-64)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Fire Water 

System

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-65)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
3-329

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.3.1-66)

Loss of material 

due to pitting 

and crevice 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M27, 

“Fire Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel tanks exposed 

to air – outdoor 

(external) (3.3.1-67)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks 

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.17)

Steel piping, piping 

components, and 

piping elements 

exposed to fuel oil 

(3.3.1-68)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-69)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

fuel oil (3.3.1-70)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, 

aluminum piping, 

piping components, 

and piping elements 

exposed to fuel oil 

(3.3.1-71)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M30, 

“Fuel Oil Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Diesel Fuel 

Monitoring and 

One-Time 

Inspection

Consistent with the 

GALL Report

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to treated 

water, closed-cycle 

cooling water, soil, 

raw water (3.3.1-72)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

(see SER 

Sections 3.3.2.1.7

and 3.3.2.1.8)
3-330

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-73)

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-74)

Cracking due to 

settling

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to air –

outdoor (3.3.1-75)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Elastomer seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal/external) 

(3.3.1-76)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring 

Consistent with the 

GALL Report

Concrete; 

cementitious 

material piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.3.1-77)

Loss of material 

due to abrasion, 

cavitation, 

aggressive 

chemical attack, 

and leaching

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel piping and 

components 

(external surfaces), 

ducting and 

components 

(external surfaces), 

ducting; closure 

bolting exposed to 

air – indoor, 

uncontrolled 

(external), air –

indoor, uncontrolled 

(external), air –

outdoor (external), 

condensation 

(external) (3.3.1-78)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring, Fire 

Protection, and 

Service Water 

Integrity

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.9)
3-331

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(external) (3.3.1-79)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

Steel heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external), air –

outdoor (external) 

(3.3.1-80)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

Copper alloy, 

aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (external), 

air – outdoor 

(3.3.1-81)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring, Fire 

Protection, and 

Service Water 

Integrity

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.9)

Elastomers 

Elastomer: seals and 

components 

exposed to air –

indoor, uncontrolled 

(external) (3.3.1-82)

Loss of material 

due to wear

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.1)

Stainless steel diesel 

engine exhaust 

piping, piping 

components, and 

piping elements 

exposed to diesel 

exhaust (3.3.1-83)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.10)

Elastomers 

Elastomer seals and 

components 

exposed to 

closed-cycle cooling 

water (3.3.1-85)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Elastomers, linings, 

Elastomer: seals and 

components 

exposed to treated 

borated water, 

treated water, raw 

water (3.3.1-86)

Hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report
3-332

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Steel; stainless steel 

piping, piping 

components, and 

piping elements, 

piping, piping 

components, and 

piping elements, 

diesel engine 

exhaust exposed to 

raw water (potable), 

diesel exhaust 

(3.3.1-88)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.11)

Steel, copper alloy 

piping, piping 

components, and 

piping elements 

exposed to moist air 

or condensation 

(internal) (3.3.1-89)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Fire Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.12)

Steel ducting and 

components (internal 

surfaces) exposed to 

condensation 

(internal) (3.3.1-90)

Loss of material 

due to general, 

pitting, crevice, 

and (for drip 

pans and drain 

lines) 

microbiologically

-influenced 

corrosion 

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Fire Water 

System

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.12)

Steel piping, piping 

components, and 

piping elements; 

tanks exposed to 

waste water 

(3.3.1-91)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Periodic 

Surveillance and 

Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.13 

and 3.3.2.1.14)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

condensation 

(internal) (3.3.1-92)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Compressed Air 

Monitoring

Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.14)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to raw 

water (potable) 

(3.3.1-93)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

Stainless steel 

ducting and 

components 

exposed to 

condensation 

(3.3.1-94)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
3-333

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Copper alloy, 

stainless steel, 

nickel alloy, steel 

piping, piping 

components, and 

piping elements; 

heat exchanger 

components, piping, 

piping components, 

and piping elements; 

tanks exposed to 

waste water, 

condensation 

(internal) (3.3.1-95)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components and 

Periodic 

Surveillance and 

Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 33.3.2.1.16)

Elastomers 

Elastomer: seals and 

components 

exposed to air –

indoor, uncontrolled 

(internal) (3.3.1-96)

Loss of material 

due to wear

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Consistent with the 

GALL Report 

(see SER 

Section 3.3.2.1.1)

Steel piping, piping 

components, and 

piping elements, 

reactor coolant 

pump oil collection 

system: tanks, 

reactor coolant 

pump oil collection 

system: piping, 

tubing, valve bodies 

exposed to 

lubricating oil 

(3.3.1-97)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis, 

One-Time 

Inspection, and 

Internal Surfaces 

in Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.3.2.1.17)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil 

(3.3.1-98)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy,

aluminum piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.3.1-99)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.3.1-100)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report
3-334

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Aluminum heat 

exchanger tubes 

exposed to 

lubricating oil 

(3.3.1-101)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Boral®; boron steel, 

and other materials 

(excluding boraflex); 

fuel storage racks: 

neutron-absorbing 

sheets (PWR), spent 

fuel storage racks: 

neutron-absorbing 

sheets (BWR) 

exposed to treated 

borated water, 

treated water 

(3.3.1-102)

Reduction of 

neutron-absorbi

ng capacity; 

change in 

dimensions and 

loss of material 

due to effects of 

SFP 

environment

Chapter XI.M40, 

“Monitoring of 

Neutron-Absorbing 

Materials other than 

Boraflex”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Reinforced concrete, 

asbestos cement 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-103)

Cracking due to 

aggressive 

chemical attack 

and leaching; 

Changes in 

material 

properties due 

to aggressive 

chemical attack

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

HDPE, fiberglass 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-104)

Cracking, 

blistering, 

change in color 

due to water 

absorption

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Concrete cylinder 

piping, asbestos 

cement pipe piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-105)

Cracking, 

spalling, 

corrosion of 

rebar due to 

exposure of 

rebar

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements 

exposed to soil or 

concrete (3.3.1-106)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks 

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.3.1-107)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
3-335

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Titanium, super 

austenitic, 

aluminum, copper 

alloy, stainless steel 

piping, piping 

components, and 

piping elements, 

bolting exposed to 

soil or concrete 

(3.3.1-108)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel bolting 

exposed to soil or 

concrete (3.3.1-109)

Loss of material 

due to general, 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks 

Consistent with the 

GALL Report

Underground 

aluminum, copper 

alloy, stainless steel 

and steel piping, 

piping components, 

and piping elements 

(3.3.1-109x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to treated 

water >60 °C 

(>140 °F) 

(3.3.1-110)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M7, 

“BWR Stress 

Corrosion Cracking,” 

and Chapter XI.M2, 

“Water Chemistry” 

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Steel structural steel 

exposed to air –

indoor, uncontrolled 

(external) 

(3.3.1-111)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.3.1-112)

None None, provided

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and

2) plant operating 

experience indicates 

no degradation of 

the concrete

No, if 

conditions

are met.

Not applicable Consistent with the 

GALL Report
3-336

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Aluminum piping, 

piping components, 

and piping elements 

exposed to air – dry 

(internal/external), 

air – indoor, 

uncontrolled 

(internal/external), 

air – indoor, 

controlled (external), 

gas (3.3.1-113)

None None NA - No 

AEM or 

AMP

NA Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external), 

air – dry, gas 

(3.3.1-114)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.3.1-115)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

BWRs (see SER 

Section 3.3.2.1.1)

Galvanized steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(3.3.1-116)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Glass piping 

elements exposed to 

air – indoor, 

uncontrolled 

(external), lubricating 

oil, closed-cycle 

cooling water, air –

outdoor, fuel oil, raw 

water, treated water, 

treated borated 

water, air with 

borated water 

leakage, 

condensation 

(internal/external) 

gas (3.3.1-117)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) 

(3.3.1-118)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report
3-337

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR

AMP in LRA, 

Supplements, or 

Amendments

Staff Evaluation

Nickel alloy, PVC, 

glass piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal), waste 

water (3.3.1-119)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(internal/external), 

air – indoor, 

uncontrolled 

(external), air with 

borated water 

leakage, concrete, 

air – dry, gas 

(3.3.1-120)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor, controlled 

(external), air – dry, 

gas (3.3.1-121)

None None NA - No 

AEM or 

AMP

NA Consistent with the 

GALL Report

Titanium heat 

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

or air – outdoor 

(3.3.1-122)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)

Titanium (ASTM 

Grades 1,2, 7, 11, or 

12 that contains 

> 5% aluminum or 

more than 0.20% 

oxygen or any 

amount of tin) heat 

exchanger 

components other 

than tubes, piping, 

piping components, 

and piping elements 

exposed to raw 

water (3.3.1-123)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.3.2.1.1)
3-338

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:

• Aboveground Metallic Tanks

• Bolting Integrity

• Boraflex Monitoring

• Buried Piping and Tanks Inspection

• Compressed Air Monitoring

• Diesel Fuel Monitoring

• External Surfaces Monitoring

• Fire Protection

• Fire Water System

• Flow-Accelerated Corrosion

• Internal Surfaces in Miscellaneous Piping and Ducting Components

• Oil Analysis

• One-Time Inspection

• Periodic Surveillance and Preventive Maintenance

• Selective Leaching

• Service Water Integrity

• Water Chemistry Control – BWR

• Water Chemistry Control – Closed Treated Water Systems

LRA Tables 3.3.2-1 through 3.3.2-19 summarize AMRs for the auxiliary system components 

and indicate AMRs consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate 

GALL Report AMRs. The staff’s evaluation follows.

3.3.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.3.1, items 3.3.1-7, 3.3.1-8, 3.3.1-9, 3.3.1-115, the applicant stated that the 

corresponding AMR items in the GALL Report are not applicable because the associated items 

are only applicable to PWRs. The staff reviewed the SRP-LR, confirmed these items only apply 

to PWRs, and finds that these items are not applicable to GGNS.
3-339

For LRA Table 3.3.1, items 3.3.1-10, 3.3.1-11, 3.3.1-16, 3.3.1-18, 3.3.1-19, 3.3.1-27 through

3.3.1-33, 3.3.1-44, 3.3.1-48, 3.3.1-65, 3.3.1-66, 3.3.1-73 through 3.3.1-75, 3.3.1-77, 3.3.1-94,

3.3.1-101 through 3.3.1-108, 3.3.1-111, 3.3.1-122, and 3.3.1-123, the applicant stated that the 

corresponding items in the GALL Report are not applicable. The staff reviewed the LRA and 

UFSAR and confirmed that the applicant’s LRA does not have any AMR results applicable for 

these items.

LRA Table 3.3.1, item 3.3.1-13 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because steam or water leakage is not considered a 

separate aspect of the indoor air environment. The staff evaluated the applicant’s claim and 

found it acceptable because (a) all ESF system bolting exposed to air is being managed for loss 

of material by the Bolting Integrity Program using item 3.3.1-12, (b) the program conducts 

periodic visual inspections capable of detecting loss of material due to general corrosion in 

bolting, and (c) use of this program is consistent with the GALL Report.

LRA Table 3.3.1, items 3.3.1-23 and 3.3.1-24, address aluminum piping, piping components, 

and piping elements exposed to treated water. The GALL Report recommends GALL Report 

AMPs XI.M2, “Water Chemistry,” and XI.M32, “One-Time Inspection,” to manage loss of 

material due to pitting and crevice corrosion for this component group. The applicant stated that 

these items are not applicable because this material, environment, aging effect combination is 

addressed with LRA item 3.3.1-25. The staff evaluated the applicant’s claim and found it 

acceptable because the staff confirmed that aluminum piping components exposed to treated 

water in the auxiliary systems reference LRA item 3.3.1-25, which manages for loss of material 

in a manner consistent with LRA items 3.3.1-23 and 3.3.1-24 and GALL Report

recommendations.

LRA Table 3.3.1, item 3.3.1-26, addresses steel with elastomer lining and steel with elastomer 

lining or stainless steel cladding piping, piping components, and piping elements exposed to 

treated water. The GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,”

and AMP XI.M32, “One-Time Inspection.” to manage loss of material due to pitting and crevice 

corrosion (only for steel after lining/cladding degradation) for this component group. The 

applicant stated that this item was not used because elastomer linings are not credited for 

protection of piping in scope for license renewal. The staff evaluated the applicant’s claim and 

finds it acceptable because although the applicant has stated that they have not used this item, 

a review of the LRA application for all LRA Section 3.3 systems with carbon steel piping, piping 

components, or piping elements exposed to treated water, being managed for loss of material, 

demonstrated that appropriate AMPs are being used. With the exception of three AMR items 

associated with the Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program, the applicant uses a water chemistry program (i.e., Water Chemistry Control – BWR 

or Water Chemistry Control – Close Treated Water System) and either the One-Time Inspection 

Program or the water chemistry program includes a periodic inspection program, or the AMR 

item uses a periodic inspection program (i.e., Flow-Accelerated Corrosion, Internal Surfaces in 

Miscellaneous Piping and Ducting Components). In the case of the AMR items associated with 

the Internal Surfaces in Miscellaneous Piping and Ducting Components, these components are 

a filter housing, tank and valve body in the domestic water system which cite plant-specific note 

307, which states, “[t]his treated water is equivalent to the NUREG-1801 raw water (potable) 

environment.” The GALL Report, item AP-101 recommends only GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage 

aging of the elastomeric material exposed to treated water. Likewise, item AP-270 also only 
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recommends AMP XI.M38 for steel items exposed to raw water (potable). In summary, the 

applicant is using the appropriate AMPs to manage all the applicable components.

LRA Table 3.3.1, item 3.3.1-34, addresses nickel alloy and copper-alloy piping components 

exposed to raw water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle 

Cooling Water System,” to manage for loss of material due to general, pitting, and crevice 

corrosion. The applicant stated that this item was not used, because there are no nickel alloy 

components exposed to raw water in auxiliary systems and the associated copper-alloy piping 

components are addressed in item 3.3.1-35 and 3.3.1-36. The staff reviewed LRA 

Section 2.3.2, and 3.2, and the UFSAR and finds that no in-scope nickel alloy piping 

components exposed to raw water are present in the auxiliary systems. The staff evaluated the 

applicant’s claim and found it acceptable because the staff confirmed that copper-alloy piping 

components exposed to raw water in the auxiliary systems reference either LRA item 3.3.1-35 

or 3.3.1-36, which manage for loss of material in a manner consistent with LRA items 3.3.1-34 

and the GALL Report recommendations.

LRA Table 3.3.1, items 3.3.1-39 address stainless steel piping components exposed to raw 

water. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water 

System” to manage loss of material due to pitting and crevice corrosion for this component 

group. The applicant stated that this item was not used because this component group is 

addressed with LRA items 3.3.1-40 and 3.3.1-41. The staff noted that LRA items 3.3.1-40 and 

3.3.1-41 are similar to item 3.3.1-39, but these items are being managed for the additional aging 

effects of loss of material due to fouling that leads to corrosion, and microbiologically-influenced

corrosion. The staff evaluated the applicant’s claim and found it acceptable because the staff 

confirmed that stainless steel piping components exposed to raw water in the auxiliary systems 

reference either LRA item 3.3.1-40 or 3.3.1-41, which manage for loss of material in a manner 

consistent with LRA items 3.3.1-39, and the GALL Report recommendations.

LRA Table 3.3.1, item 3.3.1-53 addresses steel cranes: rails and structural girders exposed to 

air- indoor, uncontrolled (external). The GALL Report recommends GALL Report AMP XI.M23, 

“Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems,”

to manage loss of material due to wear for this component group. The applicant stated that this 

item is not applicable because wear of crane rails due to rolling or sliding wheels is not expected 

in any measurable amount owing to infrequent crane use. The staff evaluated the applicant’s 

claim and finds it acceptable because although the loss of material due to wear aging effect will 

not be specifically managed, the loss of material due to general corrosion aging effect will be 

managed under this AMP, which will monitor the condition of the steel crane rails, including the 

effects of wear if it were to occur.

LRA Table 3.3.1, item 3.3.1-59 addresses steel fire rated doors exposed to air-outdoor or 

air-indoor uncontrolled. The GALL Report recommends GALL Report AMP XI.M26, “Fire 

Protection,” to manage loss of material due to wear for this component group. The applicant 

stated that this item is not applicable because wear is an event driven effect and wear will not 

occur if a fire door is properly designed and maintained. The staff noted that loss of material is 

applicable since fire doors are designed for frequent repetitive motion that can result in wear. 

However, the staff also noted that in LRA Table 3.5.2-4, the applicant stated that carbon steel 

fire doors exposed to air-indoor uncontrolled and air-outdoor will be managed for loss of 

material by the Fire Protection Program. The staff evaluated the applicant’s claim and finds it 

acceptable because the applicant will manage loss of material using the Fire Protection 

Program and the methods for managing loss of material for fire doors are the same regardless 

of the aging mechanism.
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LRA Table 3.3.1, item 3.3.1-62 addresses reinforced concrete structural fire barrier walls, 

ceilings, and floors exposed to air-outdoor or air-indoor uncontrolled. The GALL Report

recommends GALL Report AMP XI.M26, “Fire Protection,” and XI.S6, “Structures Monitoring,”

to manage loss of material due to corrosion of embedded steel for this component group. The 

applicant stated that this item is not applicable because the concrete structural fire barriers are 

designed in accordance with ACI and ASTM standards that provide for good quality, 

high-strength, dense, low permeability concrete, and the concrete provides sufficient cover to 

prevent corrosion of the embedded steel. The staff noted that dense, low permeability concrete 

does not prevent loss of material from occurring. However, the staff also noted that all of the 

concrete fire barriers in the LRA are being managed for aging using the Fire Protection and 

Structures Monitoring Programs, regardless of whether the items claim to have any aging 

effects. The AMR items cite LRA Table 3.3.1, items 3.3.1-60 or 3.3.1-61. The staff evaluated 

the applicant’s claim and finds it acceptable because, regardless of whether the items claim to 

have any aging effects, the applicant will manage aging for its concrete structural fire barriers 

using the Fire Protection and Structures Monitoring Programs, which is consistent with the 

GALL Report recommendations.

LRA Table 3.3.1, items 3.3.1-82 and 3.3.1-96 address elastomer seals and components 

exposed to air-indoor, uncontrolled (external) and air-indoor, uncontrolled (internal), 

respectively, that are being managed for loss of material due to wear. The GALL Report

recommends GALL Report AMP XI.M36 “External Surfaces Monitoring of Mechanical 

Components” and GALL Report AMP XI.M38 “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” respectively, to manage loss of material due to wear for this 

component group. The applicant stated that this item is not applicable because, “[w]ear of 

elastomer components is considered an event driven condition rather than an aging effect. If 

the elastomer component is properly designed, installed and maintained, contact with other 

surfaces leading to wear will not occur.” The staff evaluated the applicant’s claim and 

determined that it lacks sufficient information to find it acceptable because the conclusion that 

properly designed, installed, and maintained components will not experience wear is not 

consistent with the GALL Report definition of wear. By letter dated June 20, 2012, the staff 

issued RAI 3.3.1.82-1 requesting that the applicant state whether any in-scope elastomeric 

components (a) are exposed to an internal or external environment that includes hard abrasive 

particles; (b) are susceptible to wear that over time, due to their frequent manipulation, could 

challenge the intended function(s) of the component; and (c) are designed with clamped joints 

where relative motion is not intended; however, they are susceptible to wear over time due to a 

loss of the clamping force, which could challenge the intended function(s) of the component; 

and if an AERM is applicable based on the configurations or aging mechanisms described in 

items (a) through (c), discuss how the AERM will be managed.

In its response dated July 19, 2012, the applicant stated that for flexible duct connections in 

LRA Tables 3.2.2-6, 3.3.2-17, 3.3.2-18, 3.3.2-19-10, 3.3.2-19-11, 3.3.2-19-31, 3.3.2-19-32, 

3.3.2-19-34, and 3.3.2-19-36, the indoor air environment on the external surfaces of the ducting 

does not contain hard abrasive particles. However, the joints are susceptible to frequent 

manipulation due to the frequent cycling of ventilation systems and relative motion due to loss of 

clamping force. New AMR items have been included in the above cited tables that address the 

external surfaces of elastomeric flexible duct connections being managed for loss of material 

due to wear by the External Surfaces Monitoring and Internal Surfaces in Miscellaneous Piping 

and Ducting Components Programs, citing item 3.3.1-82 with generic note A and item 3.3.1-96 

with generic note A, respectively.
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The staff finds the applicant’s response associated with the external and internal environment of 

flexible duct connections acceptable because the applicant has revised its LRA to include 

external and internal wear as an aging effect and, consistent with the GALL Report, the External 

Surfaces Monitoring and Internal Surfaces in Miscellaneous Piping and Ducting Components 

Programs will be used to manage aging.

In its response to RAI 3.3.1.82-1 dated July 19, 2012, the applicant also addressed elastomeric 

expansion joints as follows. The applicant stated that the elastomeric expansion joints cited in 

LRA Table 3.4.2.2-19 are periodically replaced and are not subject to AMR, as documented in 

its response to RAI 2.3.4.1-2, dated June 11, 2012. The staff’s evaluation of the applicant’s 

response to RAI 2.3.4.1-2 is documented in SER Section 2.3.4.1.2. In its response to

RAI 3.3.1-82, the applicant also stated that the drywell chilled water expansion joints cited in 

LRA Table 3.3.2-19-26 and CW expansion joints cited in LRA Table 3.4.2.2-18 are not subject 

to frequent cycling because the systems are continuously in use, and the joints are not 

susceptible to wear from loss of clamping force because they are bolted joints. The applicant 

further stated that the external indoor air environment does not contain hard abrasive particles. 

The internal environment for the drywell chilled water expansion joints is treated water. The 

internal environment for the CW expansion joints is raw water that can result in erosion of the 

elastomeric material. LRA Table 3.4.2-2-18 was amended to include loss of material as an 

aging effect for elastomeric expansion joints exposed to raw water being managed by the 

Internal Surfaces in Miscellaneous Piping and Ducting Components. The new item cites 

item 3.3.1-32.5 and generic note E because the GALL Report, item AP-76 recommends using 

AMP XI.M20, “Open-Cycle Cooling Water System,” to manage loss of material due to erosion. 

The staff noted that the scope of AMP XI.M20 includes systems that transfer heat to the ultimate 

heat sink; therefore, the CW expansion joints would not be in the scope of the applicant’s 

Service Water Integrity Program.

The staff finds the applicant’s response associated with the external environment of expansion 

joints acceptable because the systems are not subject to frequent cycling and therefore the 

components are not being routinely manipulated, the bolted joint configuration minimizes the 

potential for loss of clamping force due to the uniform loading of the flanged connection, and the 

indoor air environment does not contain hard abrasive particles. The staff finds the applicant’s 

response associated with the internal environment of expansion joints acceptable because the 

systems are not subject to frequent cycling and therefore the components are not being 

routinely manipulated, the bolted joint configuration minimizes the potential for loss of clamping 

force due to the uniform loading of the flanged connection, the indoor air and treated water 

environments do not contain hard abrasive particles and therefore there is no aging effect for 

this environment, and loss of material for the raw water environment is being managed by the 

Internal Surfaces in Miscellaneous Piping and Ducting Components, which includes periodic 

opportunistic visual inspections capable of detecting loss of material. The staff’s concerns 

described in RAI 3.3.1.82-1 are resolved.

LRA Table 3.3.1, item 3.3.1-109.5 addresses aluminum, copper-alloy, stainless steel, and steel 

underground piping, piping components, and piping elements. The GALL Report recommends 

GALL Report AMP XI.M41, “Buried and Underground Piping and Tanks,” to manage loss of 

material due to general (steel only), pitting and crevice corrosion for this component group. The 

applicant stated that this item is not applicable because, “[t]here are no underground aluminum, 

copper-alloy, stainless steel or steel components in systems in the scope of license renewal.” 

The staff evaluated the applicant’s claim and lacked sufficient information to find it acceptable 

because an enhancement to LRA Section B.1.18, External Surfaces Monitoring Program, states 

that instructions will be provided for inspecting all underground components within the scope of 
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this program. Based on the staff’s review during the AMP audit, the fuel oil pump discharge 

check valve is one of the underground piping components associated with this enhancement. 

By letter dated April 16, 2012, the staff issued RAI B.1.5-1 requesting that the applicant provide 

a list of all underground in-scope components, state which AMP will be used to manage the 

aging of these underground in-scope components, and if a program other than the Buried Piping 

and Tanks Inspection Program will be used to age manage any of the underground components

to state if any recommendations contained in AMP XI.M41 of the GALL Report will not be met 

and justify not meeting the recommendations. The applicant’s response and staff evaluation of 

this RAI is documented in SER Section 3.0.3.1.4. The staff’s concern described in RAI B.1.5-1 

is resolved and the staff finds the applicant’s use of item 3.3.1-78, which recommends the 

External Surfaces Monitoring Program to manage the fuel oil transfer pump discharge check 

valve, acceptable.

LRA Table 3.3.1, item 3.3.1-110 addresses stainless steel piping, piping components, and 

piping elements exposed to treated water greater than 60 °C (140 °F). The GALL Report

recommends GALL Report AMP XI.M7, “BWR Stress Corrosion Cracking,” and AMP XI.M2, 

“Water Chemistry,” to manage cracking due to SCC for this component group. The applicant 

stated that this item is not used because stainless steel components of the auxiliary systems 

subject to evaluation under the BWR Stress Corrosion Cracking Program were reviewed as part 

of the Class 1 RCPB.

In its review, the staff determined the need for clarification of whether the scope of the 

applicant’s BWR Stress Corrosion Cracking Program includes piping and piping welds 

regardless of ASME Code classification, consistent with GALL Report AMP XI.M7. The staff 

noted that LRA Section B.1.9 for the BWR Stress Corrosion Cracking Program includes the 

RCPB components in the program scope. However, the LRA does not clearly address whether 

the scope of the program includes non-Class 1 piping and its associated welds.

By letter dated April 3, 2012, the staff issued RAI B.1.9-1 requesting that the applicant clarify 

whether the scope of the BWR Stress Corrosion Cracking Program includes non-Class 1 piping 

and piping welds made of austenitic stainless steel and nickel alloy materials. The staff also 

requested that if not included, the applicant justify why non-Class 1 piping and piping welds are 

excluded from the scope of the BWR Stress Corrosion Cracking Program.

In its response dated May 1, 2012, the applicant clarified that the BWR Stress Corrosion 

Cracking Program applies to relevant BWR piping and piping welds made of austenitic stainless 

steel and nickel alloy regardless of code classification, consistent with the GALL Report as 

described in LRA Section B.1.9. The applicant also clarified that non-Class 1 piping and piping 

welds were not excluded from the program. The applicant further clarified that all components 

at GGNS included in the scope of this program are part of the RCPB and were subject to an 

AMR. In addition, the applicant indicated that the results of the AMR of these RCPB

components are documented in LRA Tables 3.1.2-1 and 3.1.2-3.

In its review of the applicant’s response to RAI B.1.9-1, the staff noted that the applicant clarified 

that its BWR Stress Corrosion Cracking Program applies to the relevant BWR piping and piping 

welds made of austenitic stainless steel and nickel alloy regardless of code classification, 

consistent with the GALL Report. However, LRA item 3.3.1-110 indicates that the components 

in the auxiliary systems, subject to the BWR Stress Corrosion Cracking Program, were reviewed 

as part of the RCPB. Therefore, the staff needed justification as to why the components 

associated with LRA item 3.3.1-110 were reviewed as part of the RCPB, which consists of 

Class 1 components as discussed in LRA Section 2.3.1.2.
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By letter dated July 23, 2012, the staff issued RAI B.1.9-1a requesting that the applicant justify 

why LRA Sections B.1.9 and A.1.9 indicate that the BWR Stress Corrosion Cracking Program 

manages only aging of the RCPB in contrast with the program scope recommended in the 

GALL Report that includes relevant piping and piping welds regardless of code classification. 

The staff also requested that the applicant clarify why LRA item 3.3.1-110 indicates that the 

components in the auxiliary systems, subject to the BWR Stress Corrosion Cracking Program, 

were reviewed as part of the RCPB, rather than against the relevant piping and piping welds 

(regardless of code classification).

In its response dated August 15, 2012, the applicant stated that there are no piping components 

or piping welds made of austenitic stainless steel or nickel alloy that are 4 inches or larger in 

nominal diameter and contain reactor coolant at a temperature above 93°C (200°F) during 

power operation in the non-Class 1 portions of the auxiliary systems. The applicant further

provided revisions to LRA item 3.3.1-110 to clarify that there are no components outside the 

reactor coolant pressure boundary subject to the BWR Stress Corrosion Cracking Program 

requirements. The staff finds that the applicant’s response acceptable because the applicant 

confirmed that the auxiliary systems have no non-Class 1 components that should be included 

in the scope of the applicant’s BWR Stress Corrosion Cracking Program. The staff’s concern 

described in RAIs B1.9-1 and B.1.9-1a is resolved.

The staff concludes that for LRA item 3.3.1-110, 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).

LRA Table 3.3.1, item 3.3.1-116 addresses galvanized steel piping, piping components, and 

piping elements exposed to air-indoor, uncontrolled. The GALL Report recommends that there 

are no aging effects, aging mechanisms, or AMPs. The applicant stated that this item is not 

applicable because the galvanized steel coating of some steel components were not credited for 

corrosion protection for license renewal. The staff noted that the LRA includes AMR evaluations 

for steel components exposed to indoor air that reference LRA Table 3.2.1, item 2.1-44 and 

LRA Table 3.3.1, items 3.2.1-78, and 3.2.1-80 and credit the External Surfaces Monitoring 

Program for external surfaces and the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program for internal surfaces to manage loss of material in auxiliary systems. The 

staff evaluated the applicant’s claim and finds it acceptable because the applicant chose to 

evaluate the subject components as being constructed of a more susceptible material, 

referencing appropriate alternative Table 1 items and managing aging consistent with 

GALL Report recommendations for those Table 1 items.

LRA Table 3.3.1, item 3.3.1-117 addresses glass piping elements exposed to uncontrolled 

indoor air, lubricating oil, closed-cycle cooling water, outdoor air, fuel oil, raw water, treated 

water, treated borated water, air with borated water leakage, condensation, and gas. The 

applicant stated that it is consistent with the GALL Report for glass components exposed to 

indoor air, condensation, gas, and treated water, but that for other environments there are no 

glass components within auxiliary systems that are within the scope of license renewal. 

SRP-LR Table 3.3-1, item 3.3.1-117 states that there are no aging effects, aging mechanisms,

and that no AMP is recommended for this component group exposed to these environments; 

therefore, the staff finds the applicant’s determination acceptable.

LRA Table 3.3.1, item 3.3.1-119 addresses nickel alloy, PVC, and glass piping, piping 

components, and piping elements exposed to air with borated water leakage, uncontrolled 
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indoor air, condensation, and waste water. The applicant stated that it is consistent with the 

GALL Report for glass components exposed to waste water, but that for other material and 

environment combinations encompassed by this item there are no components within the 

auxiliary systems that are within the scope of license renewal. SRP-LR Table 3.3-1, 

item 3.3.1-119 states that there are no aging effects, aging mechanisms, and that no AMP is 

recommended for this component group exposed to these environments; therefore, the staff 

finds the applicant’s determination acceptable.

3.3.2.1.2 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-25 addresses stainless steel, steel with stainless steel cladding, 

and aluminum piping, piping components, piping elements, and heat exchanger components 

exposed to treated water and sodium pentaborate, which will be managed for loss of material 

due to pitting and crevice corrosion. For the AMR items that cite generic note E, the LRA 

credits the Water Chemistry Control – BWR, One-Time Inspection, and Periodic Surveillance 

and Preventive Maintenance Programs to manage the aging effect for stainless steel and 

aluminum components. The GALL Report recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.M32, “One-Time Inspection,” to ensure that these aging effects are 

adequately managed. GALL Report AMPs XI.M2 and XI.M32 recommend using water 

chemistry controls and a one-time visual or volumetric inspection to manage aging.

The staff’s evaluations of the applicant’s Water Chemistry Control – BWR, One-Time Inspection, 

and Periodic Surveillance and Preventive Maintenance Programs are documented in SER 

Sections 3.0.3.1.41, 3.0.3.1.32, and 3.0.3.2.2, respectively. The staff noted that the Water 

Chemistry Control – BWR and One-Time Inspection Programs propose to manage the aging of 

stainless steel and aluminum components through the use of water chemistry controls and a 

one-time inspection using visual, ultrasonic, or surface techniques to ensure the effectiveness of 

the water chemistry control program. The staff also noted that the Periodic Surveillance and 

Preventive Maintenance Program proposes to manage aging through the use of periodic 

inspections, as least once every 5 years, using visual or other appropriate techniques. In its 

review of components associated with item 3.3.1-25, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Water Chemistry 

Control – BWR, One-Time Inspection, and Periodic Surveillance and Preventive Maintenance 

Programs acceptable because the Water Chemistry Control – BWR Program establishes the 

plant water chemistry control parameters and their limits to mitigate the environmental effect on 

the aging and identifies the actions required if the parameters exceed the limits, and the 

One-Time Inspection and Periodic Surveillance and Preventive Maintenance Programs include 

visual, ultrasonic, surface inspection, or other appropriate techniques capable of detecting 

pitting and crevice corrosion.

The staff concludes that for LRA item 3.3.1-25, 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).

3.3.2.1.3 Hardening and Loss of Strength Due to Elastomer Degradation; Loss of Material 

Due to Erosion

LRA Table 3.3.1, item 3.3.1-32.5, addresses elastomer seals and components exposed to raw 

water that will be managed for hardening and loss of strength due to elastomer degradation and 

loss of material due to erosion. For the AMR item that cites generic note E, the LRA credits the 
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Internal Surfaces in Miscellaneous Piping and Ducting Components Program to manage 

cracking and changes in material properties in elastomer components of the circulation water 

system. The GALL Report recommends GALL Report AMP XI.M20, “Open-Cycle Cooling 

Water System,” to ensure that these aging effects are adequately managed. GALL Report

AMP XI.M20 states that examinations of polymeric materials should be consistent with the 

examinations described in AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components.” The staff notes that AMP XI.M38 monitors internal surfaces 

of elastomeric components for hardening, loss of strength, cracking, and loss of material due to 

wear.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. In its review of components 

associated with item 3.3.1-32.5, the applicant cited generic note E. The staff finds the 

applicant’s proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program acceptable because this program also manages aging of 

elastomeric materials for hardening, loss of strength, and loss of material due to wear in raw 

water.

3.3.2.1.4 Gray Cast Iron Ejector Exposed to Raw Water

LRA Table 3.3.1, item 3.3.1-38 addresses steel heat exchanger components exposed to raw 

water that will be managed for managing loss of material due to general, pitting, crevice, 

galvanic, and microbiologically-influenced corrosion; and fouling. The GALL Report

recommends GALL Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that 

these aging effects are adequately managed.

During its review of components associated with item 3.3.1-38, the staff noted that LRA

Table 3.3.2-19-19 contains an AMR result for gray cast iron ejector internally exposed to raw 

water that will be managed for loss of material using the Service Water Integrity Program. 

Table IX.C of the GALL Report, Revision 2, defines steel as including gray cast iron, but 

cautions that gray cast iron is susceptible to selective leaching. However, loss of material due 

to selective leaching is not listed as an aging effect requiring management for the gray cast iron 

ejector. Therefore, by letter dated May 24, 2012, the staff issued RAI 3.3.2.19.-1 requesting 

that the applicant explain why the gray cast ejector exposed to raw water does not need to be 

managed for loss of material due to selective leaching.

In its response dated June 22, 2012, the applicant stated that LRA Table 3.3.2-19-19 should 

have included the Selective Leaching Program for the gray cast iron ejector exposed to raw 

water. The applicant revised LRA Table 3.3.2-19-19 to include gray cast iron ejector exposed to 

raw water to be managed by the Selective Leaching Program.

The staff finds the applicant’s response acceptable because the applicant revised the LRA table 

to include loss of material due to selective leaching as an aging effect to be managed, which is 

consistent with the recommendations in the GALL Report. Therefore, the staff’s concern 

described in RAI 3.3.2.19-1 is resolved.

3.3.2.1.5 Reduction of Heat Transfer Due to Fouling

LRA Table 3.3.1, item 3.3.1-42, addresses copper-alloy heat exchanger tubes exposed to raw 

water that will be managed for reduction of heat transfer due to fouling. For the AMR item that 

cites generic note E, the LRA credits the Fire Water System to manage the aging effects for 
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reduction of heat transfer due to fouling. The GALL Report recommends GALL Report

AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.M20 recommends using periodic performance 

testing or inspections to manage aging.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.1.20. The staff noted that the Fire Water System Program proposes to manage 

fouling of copper-alloy heat exchanger tubes in the fire protection – water system through the 

use of inspections and monitoring activities. In its review of components associated with 

item 3.3.1-42 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Fire Water System Program acceptable because the inspections and 

monitoring activities performed in the program are capable of detecting fouling of the heat 

exchanger tubes.

3.3.2.1.6 Loss of Material Due to Microbiologically-Influenced Corrosion

LRA Table 3.3.1, item 3.3.1-47, addresses stainless steel and steel with stainless steel cladding 

heat exchanger components exposed to closed-cycle cooling water that will be managed for 

loss of material due to microbiologically-influenced corrosion. The GALL Report recommends 

GALL Report AMP XI.M21A, “Closed Treated Water Systems” to ensure that these aging 

effects are adequately managed.

During its review of components associated with item 3.3.1-47 for which the applicant cited 

generic note C, the staff noted that the LRA credits the Water Chemistry Control – Closed 

Treated Water Systems Program to manage the aging effect for stainless steel heat exchanger 

tubes and tubesheets exposed to treated water. The staff also noted that the GALL Report

(e.g., items V.D2.EP-93 and VIII.E.S-25) also recommends that stainless steel heat exchanger 

components be managed for loss of material due to pitting and crevice corrosion. The staff 

further noted, however, that the microbiologically-influenced corrosion inspection activities in the 

Water Chemistry Control – Closed Treated Water Systems Program are also capable of 

detecting loss of material due to pitting and crevice corrosion.

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.1.42. The staff finds the applicant’s 

proposal to manage pitting corrosion, crevice corrosion, and microbiologically-influenced 

corrosion using the Water Chemistry Control – Closed Treated Water Systems Program

acceptable because the water chemistry controls are capable of mitigating the environmental 

effects on loss of material due to pitting, crevice, and microbiologically-influenced corrosion and 

the opportunistic and periodic inspections can detect the presence or extent of corrosion before

loss of intended function.

The staff concludes that for LRA item 3.3.1-47, 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 Copper Alloy with Greater than 15 Percent Zinc or 8 Percent Aluminum Strainers 

Exposed to Raw or Treated Water

LRA Table 3.3.1, item 3.3.1-72, addresses gray cast iron and copper alloy with greater than 

15 percent zinc or 8 percent aluminum piping, piping components, and piping elements exposed 
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to treated water, raw water, closed-cycle cooling water, or soil that will be managed for loss of 

material due to selective leaching. The GALL Report recommends GALL Report AMP XI.M33, 

“Selective Leaching,” to ensure that this aging effect is adequately managed.

During its review of components associated with item 3.3.1-72, the staff noted that LRA

Table 3.3.2-12 contains AMR results for copper alloy with greater than 15 percent zinc or 

8 percent aluminum strainers exposed internally and externally to raw water and treated water. 

The AMR items are being managed for loss of material due to selective leaching on the internal 

surfaces using the Selective Leaching Program. However, the AMR items are not being 

managed for loss of material due to selective leaching on the external surfaces. Therefore, by 

letter dated May 24, 2012, the staff issued RAI 3.3.1.72-1 requesting that the applicant explain 

why the external surfaces of the strainers do not need to be managed for loss of material due to 

selective leaching.

In its response dated June 22, 2012, the applicant revised LRA Table 3.3.2-12 to include loss of 

material due to selective leaching as an aging effect for the external surfaces of the strainers 

exposed to raw water and treated water. The applicant proposes to manage this aging effect 

with the Selective Leaching Program.

The staff finds the applicant’s response acceptable because the applicant will manage loss of 

material due to selective leaching for the copper-alloy strainers with greater than 15 percent zinc 

or 8 percent aluminum. This approach is consistent with the recommendations in the GALL 

Report. Therefore, the staff’s concern described in RAI 3.3.1.72-1 is resolved.

3.3.2.1.8 Copper Alloy with Greater than 15 percent Zinc or 8 percent Aluminum 

Components Exposed to Condensation

LRA Table 3.3.1, item 3.3.1-72 addresses gray cast iron and copper alloy with greater than 

15 percent zinc or 8 percent aluminum piping, piping components, and piping elements exposed 

to treated water, raw water, closed-cycle cooling water, or soil that will be managed for loss of 

material due to selective leaching. The GALL Report recommends GALL Report AMP XI.M33, 

“Selective Leaching,” to ensure that this aging effect is adequately managed.

During its review of components associated with item 3.3.1-72, the staff noted that LRA

Table 3.3.2-14 contains AMR results for copper alloy with greater than 15 percent zinc or 

8 percent aluminum and gray cast iron valve bodies and gray cast iron pump casing externally 

exposed to condensation that will be managed for loss of material using the Selective Leaching 

Program. Additionally, LRA Table 3.3.2-19-6 contains an AMR item for gray cast iron valve 

body internally exposed to condensation that will be managed for loss of material using the 

Selective Leaching Program. However, LRA Tables 3.3.2-11, 3.3.2-16, 3.3.2-19-16, 

3.3.2-19-19, 3.3.2-19-21, 3.3.2-19-26, 3.3.2-19-27, and 3.3.2-19-28 contain AMR results for 

copper alloy with greater than 15 percent zinc or 8 percent aluminum and/or gray cast iron valve 

bodies and piping internally or externally exposed to condensation, but loss of material due to 

selective leaching is not identified as an aging effect. Therefore, by letter dated May 24, 2012, 

the staff issued RAI 3.3.1.72-2 requesting that the applicant explain why the copper alloy with 

greater than 15 percent zinc or 8 percent aluminum and gray cast iron components exposed to 

condensation in the LRA tables identified above do not need to be managed for loss of material 

due to selective leaching.

In its response dated June 22, 2012, the applicant stated that copper alloy with greater than 

15 percent zinc or 8 percent aluminum or gray cast iron components identified in LRA
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Tables 3.3.2-11, 3.3.2-16, 3.3.2-19-21, 3.3.2-19-27, and 3.3.2-19-28 were conservatively 

assigned an internal environment of condensation and are part of compressed air systems. The 

applicant’s justification stated that, since the compressed air systems are equipped with dryers 

that maintain an acceptably low dew point, the components are not subject to significant 

moisture that would allow selective leaching to occur.

The staff finds this portion of the applicant’s response acceptable because the applicant clarified 

that the components in question are within compressed air systems and that it was conservative 

by assigning an environment of “condensation.” The staff reviewed the applicant’s UFSAR and 

confirmed that the instrument and plant air systems, and the standby diesel generator and 

HPCS diesel generator air start systems are equipped with air dryers designed to reduce the air 

dew point temperature to -40 °F at the designated pressure for the system. As such, there 

should not be significant pooling of moisture as to cause selective leaching.

The applicant also stated that copper alloy with greater than 15 percent zinc or 8 percent 

aluminum or gray cast iron components identified in LRA Tables 3.3.2-19-16, 3.3.2-19-19, and 

3.3.2-19-26 were conservatively assigned an external environment of condensation, but are 

subject to only infrequent intermittent wetting. Therefore, the applicant concluded that loss of 

material due to selective leaching is not an aging effect requiring management for these 

components.

The staff finds this portion of the applicant’s response acceptable because the applicant clarified 

that the components in question are subject to intermittent wetting. The presence of an 

electrolyte continuously is a key factor for selective leaching to initiate and propagate. The 

intermittent presence of electrolyte is expected to abate the selective leaching process. 

Additionally, the applicant selected AMR items from GALL Report (e.g., copper-alloy

components externally exposed to condensation), and the recommended aging effect and AMP 

in the GALL Report are loss of material due to general, pitting, and crevice corrosion, and 

XI.M36, “External Surfaces Monitoring of Mechanical Components,” respectively.

Lastly, the applicant stated that components identified in LRA Table 3.3.2-19-6 are 

conservatively identified as subject to condensation (internal) as part of the combustible gas 

control system. The applicant explained that the system normally operates only during quarterly 

testing, therefore, significant moisture will not be present and loss of material due to selective 

leaching is not an aging effect requiring management. The applicant stated it inadvertently 

applied the Selective Leaching Program to gray cast iron valves subject to internal condensation 

in LRA Table 3.3.2-19-6, but that it revised the table to delete the use of the Selective Leaching 

Program for gray cast iron valves subject to limited intermittent internal condensation.

The staff finds this portion of the response acceptable because, as explained above, the 

continuous presence of an electrolyte is a key factor for selective leaching to initiate and 

propagate, and its intermittent presence would abate the selective leaching process.

The staff’s concern described in RAI 3.3.1.72-2 is resolved.

3.3.2.1.9 Loss of Material Due to General Corrosion

LRA Table 3.3.1, item 3.3.1-78 addresses steel piping, piping components, ducting, ducting 

components, and closure bolting exposed externally to air-indoor uncontrolled, air-outdoor, or 

condensation that will be managed for loss of material. LRA Table 3.3.1-81 addresses copperalloy and aluminum piping, piping components, and piping elements exposed to air-outdoor that 
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will be managed for loss of material. The GALL Report recommends GALL Report

AMP XI.M36, “External Surface Monitoring of Mechanical Components,” to ensure that these 

aging effects are adequately managed. GALL Report AMP XI.M36 recommends using periodic 

visual inspections to manage loss of material for these components.

For the AMR items that cite generic note E in LRA Table 3.3.2-7, the LRA credits the Service 

Water Integrity Program to manage loss of material for carbon steel piping and copper-alloy

nozzles exposed to air-outdoor (external) in the SSW system. The staff’s evaluation of the 

applicant’s Service Water Integrity Program is documented in SER Section 3.0.3.1.39. The staff 

noted that the Service Water Integrity Program proposes to manage the aging of steel piping 

and copper-alloy nozzles through the use of surveillance and control techniques, and 

inspections of critical components. In its review of components associated with item 3.3.1-78 

and 3.3.1-81 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Service Water Integrity Program acceptable because the program 

includes visual inspections that are capable of identifying loss of material before loss of 

component intended function, which is consistent with the inspection method recommended in 

the GALL Report. For the AMR items that cite generic note E in LRA Table 3.3.2-13, the LRA 

credits the Fire Protection Program to manage loss of material for carbon steel and copper-alloy

piping, tubing, and valve bodies, exposed to air-outdoor in the halon and CO2 fire protection 

system. The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.1.19. The staff noted that the Fire Protection Program proposes to manage the 

aging of carbon steel and copper-alloy piping, valve bodies and tubing in the halon and CO2 

systems through the use of visual inspections. In its review of components associated with 

items 3.3.1-78 and 3.3.1-81 for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Fire Protection Program acceptable because 

the program includes visual inspections that are capable of identifying loss of material before

loss of component intended function, which is consistent with the inspection method 

recommended in the GALL Report.

As amended by letter dated May 13, 2014, for the AMR item that cites generic note E in LRA 

Table 3.3.2-12, the LRA credits the Fire Water System Program to manage loss of material for 

the fire water tank. Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, 

which revised several AMPs, including the guidance for AMP XI.M27, “Fire Water System.” The 

revised AMP XI.M27 recommends that aging effects associated with fire water tanks be 

managed by AMP XI.M27 in lieu of AMP XI.M29. The staff’s evaluation of the applicant’s Fire 

Water System Program is documented in SER Section 3.0.3.1.20. In its review of components 

associated with item 3.3.1-78 for which the applicant cited generic note E in LRA 

Table 3.3.2-12, the staff finds the applicant’s proposal to manage aging using the Fire Water 

System Program acceptable because it is consistent with LR-ISG-2012-02.

The staff concludes that for LRA items 3.3.1-78 and 3.3.1-81, 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).

3.3.2.1.10 Cracking Due to Stress Corrosion Cracking

LRA Table 3.3.1, item 3.3.1-83 addresses stainless steel diesel engine exhaust piping, piping 

components, and piping elements exposed to diesel exhaust that will be managed for cracking 

due to SCC. The GALL Report recommends GALL Report AMP XI.M38, “Inspection of Internal 
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Surfaces in Miscellaneous Piping and Ducting Components,” to ensure that these aging effects 

are adequately managed.

During its review of components associated with item 3.3.1-83 for which the applicant cited 

generic note A, the staff noted that the LRA credits the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to manage the aging effect for stainless steel 

expansion joints exposed to diesel exhaust in LRA Table 3.3.2-15; however, the LRA identifies 

other stainless steel piping, piping components, and piping elements exposed to diesel exhaust 

in LRA Table 3.3.2-16 that are not being managed for SCC. By letter dated May 24, 2012, the 

staff issued RAI 3.3.2.16-1 requesting that the applicant provide a technical basis for why the 

components in LRA Table 3.3.2-16 do not need to be managed for SCC.

In its response dated June 22, 2012, the applicant stated that the stainless steel expansion joint

listed in LRA Table 3.3.2-16 is mounted in a horizontal position, which could promote pooling of 

condensation from diesel engine exhaust, and lead to cracking due to SCC. As a result, the 

applicant revised LRA Table 3.3.2-16 to add this potential aging effect. The applicant also 

stated that the vertically oriented stainless steel flexible connections listed in LRA

Table 3.3.2-16 are not subject to pooling of condensation, and thus cracking due to SCC is not 

an aging effect requiring management. The applicant further stated that LRA Table 3.3.2-16 

was revised to replace the stainless steel subcomponents with carbon steel subcomponents for 

the HPCS diesel generator turbocharger, after a review of new, more detailed vendor 

information revealed an earlier error in the LRA.

The staff finds the applicant’s response acceptable because (1) stainless steel piping 

components exposed to diesel exhaust have been evaluated to determine their susceptibility to 

cracking due to SCC, (2) LRA Table 3.3.2-16 has been updated to correctly reflect the 

component material, and (3) stainless steel piping components exposed to diesel exhaust and 

that may be subject to cracking due to SCC have been identified and will be managed by the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program, consistent with 

the GALL Report recommendations. The staff’s concern described in RAI 3.3.2.16-1 is 

resolved.

3.3.2.1.11 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-88 addresses steel and stainless steel piping, piping components, 

piping elements, and tanks exposed to raw water (potable) or diesel exhaust, which will be 

managed for loss of material. The GALL Report recommends GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to ensure 

that these aging effects are adequately managed. GALL Report AMP XI.M38 recommends 

using visual inspections performed during maintenance activities, surveillances, and scheduled 

outages to manage loss of material for metallic components. GALL Report AMP XI.M38 also 

recommends that the acceptance criteria for metallic components be that no abnormal surface 

conditions are present.

During its review of components associated with item 3.3.1-88, for which the applicant cited 

generic note C, the staff noted that the LRA credits the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program to manage the aging effect for steel tanks exposed to 

treated water (internal) in LRA Table 3.3.2-19-24. However, the staff noted that corrosion may 

occur at inaccessible locations of metallic tanks supported on earthen or concrete foundations, 

such as the tank bottom. If the tanks are on earthen or concrete foundations, UT thickness 

measurements of the tank bottoms performed whenever the tank is drained, and at least once 
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within 5 years of entering the period of extended operation should be included within the 

applicant’s program. The Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program does not state that thickness measurements of tank bottoms are included in the 

program. By letter dated May 24, 2012, the staff issued RAI 3.3.2.19-2 requesting that the 

applicant identify the type of foundation for the domestic water system tank, how it is mounted 

or supported, and the inspection technique that will be used to manage aging.

In its response dated June 22, 2012, the applicant stated that the domestic water system tank is 

an indoor tank in the control building that is supported on a pedestal and managed for loss of 

material externally by the External Surfaces Monitoring Program. The applicant also stated that 

the external surface of the tank, and its bottom portion, is age managed through visual 

inspections for evidence of loss of material. The staff finds the applicant’s response acceptable 

because the external and internal portions of the tank are being managed for aging using the 

visual inspections associated with the External Surfaces Monitoring and the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Programs, which is consistent with the GALL 

Report recommendations. The staff’s concern described in RAI 3.3.2.19-2 is resolved.

The staff concludes that for LRA item 3.3.1-88, 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).

3.3.2.1.12 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, items 3.3.1-89 and 3.3.1-90 address steel and copper-alloy piping, piping 

components, and piping elements exposed to moist air or condensation (internal) and steel 

ducting components exposed to condensation, which will be managed for loss of material due to 

general, pitting, and crevice corrosion. Drip pans and drain lines also will be managed for loss 

of material due to microbiologically-influenced corrosion. For the AMR items that cite generic 

note E, the LRA credits the Fire Water System Program to manage the aging effects for carbon 

steel tanks and breather vents exposed internally to condensation in LRA Table 3.3.2-12. The 

GALL Report recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to ensure that this aging effect is adequately 

managed. GALL Report AMP XI.M38 recommends using visual inspections performed during 

maintenance activities, surveillances, and scheduled outages to manage loss of material for 

metallic components. GALL Report AMP XI.M38 also recommends that the acceptance criteria 

for metallic components be that no abnormal surface conditions are present.

The staff’s evaluation of the applicant’s Fire Water System Program is documented in SER 

Section 3.0.3.1.20. The staff noted that the Fire Water System Program proposes to manage 

the aging of components in the fire protection system through the use of preventive, inspection, 

and monitoring activities, including monitoring of system pressure, system flow tests, flushes, 

and piping wall thickness evaluations. However, the staff noted that corrosion may occur at 

inaccessible locations of metallic tanks supported on earthen or concrete foundations, such as 

the tank bottom. The Fire Water System Program does not state that it includes thickness 

measurements of tank bottoms. By letter dated May 24, 2012, the staff issued RAI 3.3.2.19-2 

requesting that the applicant identify how the fire water storage tanks are mounted or supported 

and the inspection technique that will be used to manage aging.

In its response dated June 22, 2012, the applicant stated that the tanks in question are the fire 

water storage tanks that are supported by soil and a concrete foundation ring. The applicant 
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also stated that the exterior surfaces, including the tank bottoms, are managed by the 

Aboveground Metallic Tanks Program, which includes measurements of the tank bottom 

thicknesses. The applicant further stated that the soil environment was not included in the LRA, 

and revised LRA Table 3.3.2-12 to include an AMR item for the carbon steel tanks exposed to 

soil being managed for loss of material using the Aboveground Metallic Tanks Program. The 

staff finds the applicant’s response acceptable because the inaccessible portions of the fire 

water storage tanks are being managed in other AMR items consistent with the GALL Report

recommendations. The staff’s concern described in RAI 3.3.2.19-2 is resolved.

In its review of components associated with items 3.3.1-89 and 3.3.1-90 for which the applicant 

cited generic note E, the staff finds the applicant’s proposal to manage aging for carbon steel 

components exposed internally to condensation using the Fire Water System Program

acceptable because the program includes internal visual inspections or other non-intrusive wall 

thickness evaluations that are capable of detecting loss of material for this component group.

The staff concludes that for LRA items 3.3.1-89 and 3.3.1-90, 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).

3.3.2.1.13 Loss of Material Due to General, Pitting, Crevice and Microbiologically-Influenced 

Corrosion

LRA Table 3.3.1, item 3.3.1-91, addresses steel piping, piping components, piping elements, 

and tanks exposed to waste water, which will be managed for loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion. The GALL Report recommends 

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

Components,” to ensure that this aging effect is adequately managed. GALL Report 

AMP XI.M38 recommends using visual inspections performed during maintenance activities, 

surveillances, and scheduled outages to manage the loss of material for metallic components. 

GALL Report AMP XI.M38 also recommends that the acceptance criteria for metallic 

components be that no abnormal surface conditions are present.

During its review of components associated with item 3.3.1-91, for which the applicant cited 

generic note C, the staff noted that the LRA credits the Internal Surfaces in the Miscellaneous 

Piping and Ducting Components Program to manage the aging effect for carbon steel tanks 

exposed to waste water in LRA Table 3.3.2-19-20. However, the staff noted that corrosion may 

occur at inaccessible locations of metallic tanks supported on earthen or concrete foundations, 

such as the tank bottom. If the tanks are on earthen or concrete foundations, UT thickness 

measurements of the tank bottoms performed whenever the tank is drained and at least once 

within 5 years of entering the period of extended operation should be included within the 

applicant’s program. The Internal Surfaces in the Miscellaneous Piping and Ducting 

Components Program does not state that thickness measurements of tank bottoms are included 

in the program. By letter dated May 24, 2012, the staff issued RAI 3.3.2.19-2 requesting that 

the applicant identify the type of foundation for the tanks, how they are mounted or supported, 

and the inspection technique that will be used to manage aging.

In its response dated June 22, 2012, the applicant stated that these tanks are indoor tanks in 

the auxiliary and turbine building that are not exposed to wetted external conditions. The 

applicant also stated that the tank bottom is in contact with dry concrete, and therefore, there is 

no aging effect requiring management for the external surface of the tank bottoms. The staff 
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noted that the GALL Report recommends that there be no aging effects requiring management 

for steel components exposed to dry concrete. The staff finds the applicant’s response 

acceptable because the tank bottoms are not subject to an aging effect externally, and the tank 

internal surfaces will be managed for loss of material by the Internal Surfaces in the 

Miscellaneous Piping and Ducting Components Program, which is consistent with the GALL 

Report recommendations. The staff’s concern described in RAI 3.3.2.19-2, for these tanks, is 

resolved.

By letter dated May 13, 2014, the applicant revised LRA Table 3.3.2-19-20, including 

item 3.3.1-91 associated with RAI 3.3.2.19-2. During an internal review, the applicant noted a 

discrepancy between the tank material identified in LRA Table 3.3.2-19-20 and the actual 

material used to fabricate the tank. LRA Table 3.3.2-19-20 included table entries for tanks 

constructed from carbon steel (material). All tanks subject to aging management review 

applicable to LRA Table 3.3.2-19-20 are constructed from stainless steel. The correction of this 

error has resulted in item 3.3.1-91, identified in RAI 3.3.2.19-2, being changed to item 3.3.1-95. 

The technical basis for the issuance of RAI 3.3.2.19-2 and the applicant’s response both remain 

valid. The staff’s concern described in RAI 3.3.2.19-2, for these tanks, is resolved.

LRA Table 3.3.1, items 3.3.1-91 addresses steel piping, piping components, piping elements, 

and tanks exposed to waste water, which will be managed for loss of material due to general, 

pitting, crevice, and microbiologically-influenced corrosion. For the AMR items that cite generic 

note E, the LRA credits the Periodic Surveillance and Preventive Maintenance Program to 

manage the aging effect for carbon steel drain housing, piping, and valve bodies. The GALL 

Report recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to ensure that this aging effect is adequately 

managed. GALL Report AMP XI.M38 recommends using visual inspections performed during 

maintenance activities, surveillances, and scheduled outages to manage loss of material for 

metallic components. GALL Report AMP XI.M38 also recommends that the acceptance criteria 

for metallic components be that no abnormal surface conditions are present.

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff noted that the Periodic Surveillance 

and Preventive Maintenance Program is a new plant-specific program that proposes to manage 

the aging of carbon steel drain housing, piping, and valve bodies through the use of visual 

inspections or other NDE techniques for the piping and visual inspections for the drain housing 

and valve bodies. The staff also noted that the Periodic Surveillance and Preventive 

Maintenance Program proposes to manage aging with inspections performed during 

preventative maintenance activities and periodic surveillances, with each inspection to occur at 

least once every 5 years. In its review of components associated with item 3.3.1-91, for which 

the applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using 

the Periodic Surveillance and Preventive Maintenance Program acceptable, because the 

program includes inspection techniques that are capable of detecting the loss of material from 

metallic components prior to the loss of the component intended function, which is consistent 

with the GALL Report recommendations.

The staff concludes that for LRA item 3.3.1-91, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).
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3.3.2.1.14 Loss of Material Due to Pitting and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-92 addresses aluminum piping, piping components, and piping 

elements exposed to condensation. The GALL Report recommends GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage 

loss of material due to pitting and crevice corrosion for this component group. The applicant 

stated that this item is applicable and consistent with the GALL Report; however, the staff noted 

that there are no Table 2 items that credit item 3.3.1-92. The lack of a Table 2 item indicates 

that the MEA combination is not applicable at the site, contradicting the information provided in 

LRA item 3.3.1-92. By letter dated May 24, 2012, the staff issued RAI 3.3.1.92-1 requesting 

that the applicant update the LRA to identify appropriate Table 2 items, or provide technical 

justification for why the item is not applicable.

In its response dated June 22, 2012, the applicant stated that LRA Tables 3.3.2-15 and 3.3.2-16 

include one aluminum component type internally exposed to condensation, which is managed 

by the Compressed Air Monitoring Program for loss of material. The applicant revised LRA

Table 3.3.1, item 3.3.1-92 to identify that the Compressed Air Monitoring Program will be used 

to manage loss of material for this component group. The applicant revised the aluminum 

components exposed internally to condensation in LRA Tables 3.3.2-15 and 3.3.2-16 to identify 

the corresponding link to Table 3.3.1, item 3.3.1-92, citing generic note E.

The staff finds the applicant’s response acceptable because the applicant has identified 

appropriate AMR items in Tables 3.3.2-15 and 3.3.2-16 that reference item 3.3.1-92. The staff’s 

concern described in RAI 3.3.1.92-1 is resolved.

The staff’s evaluation of the applicant’s Compressed Air Monitoring Program is documented in 

SER Section 3.0.3.1.11. The Compressed Air Monitoring Program consists of air quality 

monitoring and inspection of component internal surfaces to manage loss of material for 

components in compressed air systems. In its review of components associated with 

item 3.3.1-92 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Compressed Air Monitoring Program acceptable because the 

program will use internal surface inspections to detect a loss of material, which is consistent 

with the inspection method recommended in the GALL Report for aluminum components 

exposed to condensation.

The staff concludes that for LRA item 3.3.1-92, 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).

3.3.2.1.15 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion

LRA Table 3.3.1, item 3.3.1-95 addresses copper-alloy, stainless steel, nickel alloy, and steel 

piping, piping components, piping elements, heat exchangers, and tanks exposed to waste 

water (external), which will be managed for loss of material due to general, pitting, crevice, and 

microbiologically-influenced corrosion. For the AMR items that cite generic note E, the LRA 

credits the Periodic Surveillance and Preventive Maintenance Program to manage the aging 

effect for stainless steel piping in the floor and equipment drains system. The GALL Report

recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in Miscellaneous 

Piping and Ducting Components,” to ensure that this aging effect is adequately managed. 
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GALL Report AMP XI.M38 recommends using visual inspections performed during maintenance 

activities, surveillances, and scheduled outages to manage loss of material for metallic 

components. GALL Report AMP XI.M38 also recommends that the acceptance criteria for 

metallic components be that no abnormal surface conditions are present.

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff noted that the Periodic Surveillance 

and Preventive Maintenance Program proposes to manage the aging of stainless steel piping 

through the use of visual inspections or other NDE techniques. The staff also noted that the 

Periodic Surveillance and Preventive Maintenance Program proposed to manage aging with 

inspections held during preventive maintenance activities and periodic surveillances, with each 

inspection to occur at least once every 5 years. The staff also noted that inspections using NDE 

techniques are as effective at identifying loss of material in stainless steel floor and equipment 

drain system piping as visual inspections. In its review of components associated with 

item 3.3.1-95, for which the applicant cited generic note E, the staff finds the applicant’s 

proposal to manage aging using the Periodic Surveillance and Preventive Maintenance 

Program acceptable because the program includes inspection techniques that are capable of 

identifying loss of material in stainless steel piping before loss of component intended function.

The staff concludes that for LRA item 3.3.1-95, 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).

3.3.2.1.16 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-97, addresses steel piping, piping components, and piping 

elements and steel reactor coolant pump oil collection system components exposed to 

lubricating oil that will be managed for loss of material due to general, pitting, and crevice 

corrosion. For the AMR items that cite generic note E, the LRA credits the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program to manage the aging effect carbon 

steel filters and filter housing exposed to lubricating oil. The GALL Report recommends 

GALL Report AMP XI.M39, “Lubricating Oil Analysis,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.M39 recommends performing periodic sampling 

and testing of lubricating oil for moisture and corrosion particles in accordance with industry 

standards to manage aging.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff noted that the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to 

manage the aging of carbon steel filters, filter housing, and fan housing through the use of 

visual inspections. In its review of components associated with items 3.3.1-97 and 3.4.1-40 for 

which the applicant cited generic note E, the staff finds the applicant’s proposal to manage 

aging using the Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because visual inspections will ensure that existing environmental conditions are not 

causing material degradation that could result in a loss of component intended functions.

The staff concludes that for LRA item 3.3.1-97, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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3.3.2.1.17 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.3.1, item 3.3.1-67 addresses steel tanks exposed to air – outdoor (external), which 

will be managed for loss of material due to general, pitting, and crevice corrosion. As amended 

by letter dated May 13, 2014, for the AMR item that cites generic note E, the LRA credits the 

Fire Water System Program to manage the aging effect for the fire water tank. The GALL 

Report recommends GALL Report AMP XI.M29, “Aboveground Metallic Tanks,” to ensure that 

these aging effects are adequately managed. GALL Report AMP XI.M29 recommends using 

periodic visual examinations to manage aging.

Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, which revised several 

AMPs, including the guidance for AMP XI.M27, “Fire Water System.” The revised AMP XI.M27 

recommends that aging effects associated with fire water tanks be managed by AMP XI.M27 in 

lieu of AMP XI.M29. The staff’s evaluation of the applicant’s Fire Water System Program is 

documented in SER Section 3.0.3.1.20. In its review of components associated with 

item 3.3.1-67, for which the applicant cited generic note E, the staff finds the applicant’s 

proposal to manage aging using the Fire Water System Program acceptable, because it is 

consistent with LR-ISG-2012-02.

The staff concludes that, for LRA item 3.3.1-67, 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).

3.3.2.1.18 Loss of Material Due to General, Pitting, Crevice, and Microbiologically-Influenced 

Corrosion

LRA Table 3.3.1, item 3.3.1-64 addresses steel and copper alloy piping, piping components, 

piping elements, and tanks exposed to raw water, which will be managed for loss of material 

due to general, pitting, crevice, and microbiologically-influenced corrosion. For the AMR items 

that cite generic note E, the LRA credits the Internal Surfaces in Miscellaneous Piping and 

Ducting Components Program to manage the aging effect for carbon steel and copper alloy filter 

housings, nozzles, piping, strainer housings, and valve bodies. The GALL Report recommends 

GALL Report AMP XI.M27, “Fire Water System,” to ensure that this aging effect is adequately 

managed. GALL Report AMP XI.M27 recommends using the applicable NFPA codes and 

standards to manage loss of material for metallic components, which include visual inspections, 

non-destructive wall thickness measurements, and flow testing.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff noted that the 

applicant included the updated guidance for this program from LR-ISG-2012-02. In its review of 

components associated with item 3.3.1-64, for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program acceptable because the components are outside the 

scope of the Fire Water System Program, and the program includes inspection techniques 

capable of detecting loss of material from metallic components before the loss of component 

intended function.

The staff concludes that for LRA item 3.3.1-64, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 
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be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.3.2.1.19 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.3.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

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).

3.3.2.2 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

• cracking due to SCC and cyclic loading

• cracking due to SCC

• loss of material due to cladding breach

• loss of material due to pitting and crevice corrosion

• QA for aging management of nonsafety-related components

For component groups evaluated in the GALL Report, for which the applicant stated 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.

3.3.2.2.1 Cumulative Fatigue Damage

LRA Section 3.3.2.2.1, which is associated with LRA Table 3.3.1, items 3.3.1-1 and 3.3.1-2, 

addresses how steel cranes’ structural girders exposed to air-indoor uncontrolled (external), and 

steel and stainless steel piping, piping components, piping elements, and heat exchanger 

components exposed to air-indoor uncontrolled, treated borated water, or treated water are 

being managed for cumulative fatigue damage.
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The applicant stated that item 3.3.1-1 was not used. Steel cranes are evaluated as structural 

components in LRA Section 3.5.1. The staff noted that potential TLAAs identified for cranes are 

discussed in LRA Section 3.5.2.3. Furthermore, in LRA Table 4.1-2, the applicant identified that 

the CLB does not include any analysis for the polar crane that would need to be identified as a 

TLAA in the LRA. By letters dated June 5 and September 7, 2012, the staff issued RAIs 4.1-2

and 4.1-2a, requesting the applicant clarify why the time-dependent cycle analyses for the 

cranes would not need to be identified as TLAAs for the LRA, when assessed against the six 

criteria for identifying TLAAs in 10 CFR 54.3(a). The applicant responded to RAI 4.1-2a by 

letter dated October 2, 2012. In its response, the applicant resolved the request by amending 

the LRA to include a TLAA for the analyses for the spent fuel cask crane, new fuel handling 

crane and polar cranes. The details of RAI 4.1-2 and RAI 4.1-2a and the staff’s evaluation of 

the applicant’s response are documented in SER Section 4.1.2.1.2.7. As part of the response, 

the applicant amended AMR item 3.3.1-1 to identify that the analysis of fatigue for steel crane 

structural girders is a TLAA. The applicant addressed the further evaluation criteria of the SRPLR by stating that fatigue is a TLAA, as defined in 10 CFR 54.3, and is required to be evaluated 

in accordance with 10 CFR 54.21(c). The applicant stated that the evaluation of crane load 

cycles as a TLAA is discussed in LRA Section 4.7.4.

The applicant addressed, for item 3.3.1-2, the further evaluation criteria of the SRP-LR by 

stating that fatigue is a TLAA, as defined in 10 CFR 54.3, and required to be evaluated in 

accordance with 10 CFR 54.21(c). The applicant stated that fatigue TLAA identified for Class 2 

and 3 piping are discussed in LRA Section 4.3.

The staff reviewed LRA Section 3.3.2.2.1 against the criteria in SRP-LR Section 3.3.2.2.1, which 

states that fatigue of these auxiliary system components is a TLAA as defined in 10 CFR 54.3, 

and that these TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) and SRP-LR 

Section 4.3. The staff also reviewed the AMR items associated with LRA Section 3.3.2.2.1, and 

found that the AMR results are consistent with the GALL Report and SRP-LR, except as 

identified below.

The staff identified that the applicant did not include the applicable AMR items in LRA 

Tables 3.3 for the TLAAs associated with fatigue of non-Class 1. The staff noted that LRA 

Section 4.3.2 discusses the TLAAs associated with fatigue of non-Class 1 piping and states that 

these TLAAs will remain valid for the period of extended operation, in accordance with 

10 CFR 54.21(c)(1)(i). Therefore as part of the RAI 3.2.2-1, the staff requested the applicant 

justify this discrepancy. The details of RAI 3.2.2-1 and the staff’s evaluation of the applicant’s 

response are documented in SER Section 3.2.2.2.1.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.3.2.2.1 criteria. For those items that apply to LRA Section 3.3.2.2.1, the staff 

determined 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). SER Sections 4.3 and 4.7 document the staff’s review of 

the applicant’s evaluation of the TLAA for these components.

3.3.2.2.2 Cracking Due to Stress Corrosion Cracking and Cyclic Loading

LRA Section 3.3.2.2.2, associated with LRA Table 3.3.1, item 3.3.1-3, addresses cracking in 

stainless steel heat exchanger components exposed to treated borated water. The applicant 

stated that this item is not applicable because item 3.3.1-3 applies to PWRs. The staff 
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evaluated the applicant’s claim and finds it acceptable because treated borated water only 

applies to PWRs and the applicant is managing cracking of stainless steel heat exchanger 

components exposed to treated water through item 3.3.1-20, which applies to BWRs.

3.3.2.2.3 Cracking Due to Stress Corrosion Cracking

LRA Section 3.3.2.2.3, which is associated with LRA Table 3.3.1, item 3.3.1-4, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to air-outdoor 

that will be managed for cracking due to SCC. The applicant stated that this item is not 

applicable because there are no in-scope stainless steel components exposed to outdoor air or 

located near unducted air intakes in the auxiliary systems. The staff reviewed LRA 

Sections 2.3.3 and 3.3 and the UFSAR and finds that no in-scope stainless steel piping, piping 

components, piping elements and tanks exposed to air-outdoor are present in the auxiliary 

systems.

3.3.2.2.4 Loss of Material Due to Cladding Breach

LRA Section 3.3.2.2.4, associated with LRA Table 3.3.1, item 3.3.1-5, addresses loss of 

material due to cladding breach in PWR steel charging pump casings with stainless steel 

cladding exposed to treated borated water. The applicant stated that this item is not applicable 

because it is applicable to PWRs only. The staff confirmed that this item is associated only with 

PWR plants; therefore, the staff finds the applicant’s determination acceptable.

3.3.2.2.5 Loss of Material Due to Pitting and Crevice Corrosion

LRA Section 3.3.2.2.5, which is associated with LRA Table 3.3.1, item 3.3.1-6, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to air-outdoor 

that will be managed for loss of material due to pitting and crevice corrosion. The applicant 

stated that this item is not applicable because there are no in-scope stainless steel components 

exposed to outdoor air or located near unducted air intakes in the auxiliary systems. The staff 

reviewed LRA Sections 2.3.3 and 3.3 and the UFSAR and finds that no in-scope stainless steel 

piping, piping components, piping elements, and tanks exposed to air-outdoor are present in the 

auxiliary systems.

3.3.2.2.6 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.

3.3.2.2.7 Loss of Material Due to Recurring Internal Corrosion

By letter dated May 13, 2014, the applicant addressed recurring internal corrosion that is 

described in Section A and Appendix B of LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation.” 

LR-ISG-2012-02 includes a new section (Section 3.3.2.2.8, Loss of Material Due to Recurring 

Internal Corrosion) in the SRP-LR for “AMR Results for Which Further Evaluation Is 

Recommended by the GALL Report.” This section of the SER documents the staff’s evaluation 

of the applicant’s activities to address recurring internal corrosion, as described in SRP-LR 

Section 3.3.2.2.8 from LR-ISG-2012-02.

Based on its review of plant-specific operating experience for the past 5 years, the applicant 

stated that microbiologically-influenced corrosion of piping components is a recurring internal 
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corrosion issue, as defined in LR-ISG-2012-02, Section A. The applicant further stated that it 

monitors loss of material in piping components due to microbiologically-influenced corrosion in 

four systems: CW, SSW, plant service water, and fire protection.

The applicant stated that it monitors selected locations using UT and radiographic testing 

techniques to determine wall thickness. The selected locations provide a representative sample 

of the piping systems and are chosen based on configuration, flow conditions, and operating 

history. Locations can be added or deleted as new information becomes available. The 

applicant stated that, in the past 5 years, 60 inspections have been performed, and a minimum 

of 5 inspections per refueling cycle will be performed until microbiologically-influenced corrosion 

no longer meets the criteria for recurring internal corrosion. The applicant determines corrosion 

rates by comparing the measured wall thickness to the nominal thickness, or to previous 

thickness measurements, and determines when to perform subsequent measurements or to 

replace components, based on the corrosion rate and the estimated time to reach the ASME 

Code minimum wall thickness plus a thickness margin. In addition, the applicant considers 

multiple corrosion locations when determining structural integrity of the piping.

The applicant also stated that the current degradation monitoring has been effective in 

identifying internal pipe corrosion, and pipe wall thinning has not resulted in the loss of a 

component’s ability to support system pressure and flow requirements. Also, leakage caused 

by microbiologically-influenced corrosion onto nearby equipment has not resulted in the loss of 

any safety functions. For the buried portions of affected systems, the applicant will select an 

inspection method prior to the period of extended operation that provides a suitable indication of 

pipe wall thickness for a representative sample to supplement the existing inspection locations. 

The applicant further stated that underground leaks are detectable by changes in system 

performance, changes in system operation, or by the appearance of wetted ground, and leaks 

large enough to affect the function of systems are expected to develop slowly, due to the slow 

progression of pin-hole leaks from microbiologically-influenced corrosion. The applicant 

augmented the Periodic Surveillance and Preventive Maintenance Program to incorporate the 

above described monitoring activities associated with recurring internal corrosion and revised 

LRA Sections A.1.35 and B.1.35, and the tables in LRA Sections 3.3 and 3.4 to account for 

the changes.

During its review of the applicant’s information, it was unclear to the staff whether the 

augmented program would perform inspections of five locations in each of the four systems that 

had been identified or just five locations in all these systems as a collective population of 

components. By letter dated September 11, 2014, the staff issued RAI 3.0.3-1-RIC-1, part 2, 

requesting that the applicant clarify this issue. In its response dated November 6, 2014, the 

applicant stated that the number of inspections implemented by the Periodic Surveillance and 

Preventive Maintenance Program is based on the previous evaluations, the calculated 

remaining service life of components in the systems, and the previous selected areas of 

concern. The applicant stated that 16 inspections are scheduled for the next cycle; however; 

the number of inspections could change depending on the evaluation of the current cycle 

inspection results. The applicant clarified that a minimum of 5 inspections in the collective set of 

systems will be performed per cycle and that this minimum rate of 5 inspections per cycle will 

result in 25 inspections in a 10-year period.

The staff notes that LR-ISG-2012-02, Section B, recommends that a minimum of 20 percent for 

each population of in-scope components, with a maximum sample size of 25, be performed for 

inspections that are conducted in accordance with GALL Report AMP XI.M38, “Inspection of 

Internal Surfaces in Miscellaneous Piping and Ducting Components.” The staff also notes that 
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LR-ISG-2012-02 defines the population of components for inspection as those components that 

are subject to the same material, environment, and aging effect combination, and states that, 

where practical, inspection locations are selected from bounding or lead components (e.g., low 

or stagnant flow) most susceptible to aging because of time in service, severity of operating 

conditions, and lowest design margin. Thus, the staff found that the applicant had provided an 

acceptable minimum sample-size basis for performing inspections of the four susceptible 

systems under the Periodic Surveillance and Preventive Maintenance Program, because the 

staff has verified that this inspection basis is in conformance with the recommendations in 

Section B of LR-ISG-2012-02 for similar sampling-based programs, such as that for GALL 

Report AMP XI.M38. The staff’s concern described in RAI 3.0.3-1-RIC-1, part 2 is resolved.

Also during its review of the applicant’s information, the staff noted that the applicant’s bases for 

selecting inspection locations include piping configurations, flow conditions, and operating 

history and provide a representative sample of the piping system. The staff compared this to 

the recommendations in SRP-LR Section A.1.2.3.4, which states that samples should be biased 

towards locations most susceptible to the specific aging effect of concern. It was unclear to the 

staff how the specified sample selection criteria will be biased toward components that are most 

susceptible to microbiologically-influenced corrosion. By letter dated September 11, 2014, the 

staff issued RAI 3.0.3-1-RIC-1, part 3, requesting that the applicant clarify this issue.

In its response dated November 6, 2014, the applicant stated that component selections are 

biased toward locations most susceptible to microbiologically-influenced corrosion and consider 

a number of characteristics that cause components to be conducive to 

microbiologically-influenced corrosion. The applicant also stated that implementing procedures 

will be revised to clearly state that the most susceptible locations are selected for inspection and 

that it amended LRA Sections A.1.35 and B.1.35 to reflect this approach. The staff finds the 

applicant’s response to be acceptable, because the sample selection criteria for the Period 

Surveillance and Preventive Maintenance Program are consistent with the sample selection 

criteria in SRP-LR Section A.1.2.3.4. The staff’s concern described in RAI 3.0.3-1-RIC-1, part 3 

is resolved.

Also during its review of the applicant’s information, the staff noted that the applicant changed 

LRA Sections A.1.35 and B.1.35 by stating that inspections for recurring internal corrosion 

would use UT or other nondestructive wall thickness measurements of the components that are 

selected for inspection. However, the staff noted that the applicant did not define or justify the 

type of NDE method that would be applied as the inspection technique if UT is not used. By 

letter dated September 11, 2014, the staff issued RAI 3.0.3-1-RIC-1, part 4, requesting that the 

applicant clarify and justify the alternative inspection method if UT is not used for the 

inspections.

In its response dated November 6, 2014, the applicant revised LRA Sections A.1.35 and B.1.35 

to specify that UT or radiographic testing will be used for inspecting for loss of material due to 

microbiologically-influenced corrosion. The applicant stated that radiographic testing can be 

used for those configurations where UT is not effective, such as small-bore piping with socket 

welded fittings. The staff finds this response acceptable, because radiographic testing is an 

accepted volumetric NDE method capable of detecting loss of material. The staff’s concern 

described in RAI 3.0.3-1-RIC-1, part 4, is resolved.

Also during its review of the applicant’s information, the staff noted that the applicant had not 

provided any provisions for expanding the sample size or for identifying the inspection 

expansion criteria that will be applied if further corrosion is detected as a result of implementing 
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the augmented inspections. By letter dated September 11, 2014, the staff issued 

RAI 3.0.3-1-RIC-1, part 5, requesting that the applicant identify and justify the component 

inspection sample expansion criteria that will be applied to the systems, if further evidence of 

microbiologically-influenced corrosion or other corrosion effects is detected in these systems.

In its response dated November 6, 2014, the applicant stated that the scope of the examinations 

will be expanded if substantial microbiologically-influenced corrosion is detected during 

inspections. The applicant stated that scope expansion includes consideration of other 

locations for additional sampling, such as similar components in the same or redundant trains. 

The applicant clarified that it considers microbiologically-influenced corrosion to be substantial if 

there is either an increased rate of detection of new microbiologically-influenced corrosion sites, 

increased rates of wall thinning at known sites, or unexpected piping wall loss that results in a 

component wall thickness near or below the minimum wall thickness required by the design 

code for the component. The staff finds that the applicant’s response acceptable, because it 

provided adequate bases for expanding the sample size. The staff’s concern described in 

RAI 3.0.3-1-RIC-1, part 5 is resolved.

Based on the changes and clarifications provided above, the staff determines that the 

applicant’s Periodic Surveillance and Preventive Maintenance Program meets the criteria in 

SRP-LR Section 3.3.2.2.8, as modified by LR-ISG-2012-02. The staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3).

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

For LRA Tables 3.3.2-1 through 3.3.2-19, 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 3.3.2-19, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

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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3.3.2.3.1 Control Rod Drive – 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 

CRD component groups.

In LRA Table 3.3.2-1, the applicant stated there are TLAAs for stainless steel tubing, and valve 

body exposed to steam, which cite generic note G. The staff confirmed that there is a TLAA, as 

documented in LRA Section 4.3.2, for these components and material. The staff’s evaluation of 

the fatigue TLAA for non-Class 1 components is documented in SER Section 4.3.2.

Carbon Steel Piping Components Exposed to Treated Water. By letter dated 

December 18, 2012, and as modified by letter dated December 20, 2013, the applicant revised 

LRA Tables 3.3.2-1, 3.3.2-6, 3.3.2-19-1, 3.3.2-19-8, and 3.3.2-19-20, and stated that carbon 

steel piping components exposed to treated water will be managed for loss of material by the 

Flow-Accelerated Corrosion Program. The AMR items cite generic note H and also cite 

plant-specific note 309, which states that the aging effect used for this item refers to loss of 

material due to erosion.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel piping components exposed to treated water are susceptible to 

loss of material due to general, pitting, crevice, and flow-accelerated corrosion and recommends 

GALL Report AMP XI.M2, AMP XI.M32, and AMP XI.M17 to manage the aging effect due to 

these mechanisms. However the applicant has identified additional aging mechanisms. The 

applicant addressed the GALL Report identified aging effects for this component, material and 

environment combination in other AMR items in LRA Tables 3.3.2-1, 3.3.2-6, 3.3.2-19-1, 

3.3.2-19-8, and 3.3.2-19-20.

The staff’s evaluation of the applicant’s Flow-Accelerated Corrosion Program is documented in 

SER Section 3.0.3.1.21. The staff finds the applicant’s proposal to manage loss of material due 

to erosion mechanisms using the Flow-Accelerated Corrosion Program acceptable, because the 

associated components can be treated similar to “susceptible-not-modeled” components 

currently within the program, which ensures that the consequent wall thinning will be detected 

before loss of intended function.

3.3.2.3.2 Standby Liquid Control – 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 

SLC component groups.

Nickel Alloy Expansion Joint Exposed to Sodium Pentaborate. In LRA Table 3.3.2-2, the 

applicant stated that the nickel alloy expansion joints exposed to sodium pentaborate will be 

managed by for loss of material by the Water Chemistry Control – BWR Program. The AMR 

item cites generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that, based on the UFSAR, the 

components in the SLC system do not exceed 100 °F, which indicates that cracking is not an 
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aging effect requiring management. The staff also noted that the Metals Handbook, Desk 

Edition, Second Edition (ASM International, 1998) states that nickel and nickel-base alloys 

generally have very good corrosion resistance in distilled and fresh waters, and the ASM 

Handbook, Volume 13B, “Corrosion of Nickel and Nickel-Based Alloys” chapter (ASM 

International, 2005) states that nickel alloys are subject to SCC only in specific environments, 

such as hot caustic, fluoride, and chloride-containing water environments. Based on this 

review, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Water Chemistry Control – BWR Program is 

documented in SER Section 3.0.3.1.41. The staff finds the applicant’s proposal to manage 

aging using this program acceptable because the Water Chemistry Control – BWR Program

controls contaminants in the makeup water to the SLC system at levels to minimize loss 

of material.

In LRA Table 3.3.2-2, as amended by letter dated October 22, 2012, the applicant stated there 

is a TLAA for nickel alloy expansion joints exposed to sodium pentaborate solution which cite 

generic note G. The staff confirmed that there is a TLAA, as documented in LRA 

Section 4.3.2.2 for this component and material. The staff’s evaluation of the fatigue TLAA for 

non-Class 1 expansion joints is documented in SER Section 4.3.2.2.2.

Stainless Steel Expansion Joint Exposed to Sodium Pentaborate. In LRA Table 3.3.2-2, as 

amended by letter dated October 22, 2012, the applicant stated there is a TLAA for stainless 

steel expansion joints exposed to sodium pentaborate solution which cite generic note H. The 

staff confirmed that there is a TLAA as documented in LRA Section 4.3.2.2 for this component 

and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 expansion joints is 

documented in SER Section 4.3.2.2.2.

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).

3.3.2.3.3 Suppression Pool Makeup - 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 

suppression pool makeup component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system are consistent with the GALL Report.

3.3.2.3.4 Leakage Detection and Control – 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 

leakage detection and control component groups.

Stainless Steel Components, Piping, and Valves Exposed to Steam. In LRA Table 3.3.2-4, the 

applicant that stated there are TLAAs for stainless steel piping, tubing, and valve body exposed 

to steam, which cite generic note G. The staff confirmed that there is a TLAA, as documented 
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in LRA Section 4.3.2, for these components and material. The staff’s evaluation of the fatigue 

TLAA for non-Class 1 components is documented in SER Section 4.3.2.

Stainless Steel Expansion Joints Exposed to Condensation. In LRA Table 3.3.2-4, as amended 

by letter dated October 22, 2012, the applicant stated there is a TLAA for stainless steel 

expansion joints exposed to condensation which cite generic note H. The staff confirmed that 

there is a TLAA as documented in LRA Section 4.3.2.2 for this component and material. The 

staff’s evaluation of the fatigue TLAA for Non-Class 1 expansion joints is documented in SER 

Section 4.3.2.2.2.

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).

3.3.2.3.5 Combustible Gas Control – 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

combustible gas control component groups.

Stainless Steel Tubing Exposed to Indoor Air. In LRA Table 3.3.2-5, the applicant stated there 

are TLAAs for stainless steel tubing exposed to air-indoor (internal) and stainless steel tubing 

exposed to air-indoor (external), which cite generic note H. The staff confirmed that there is a 

TLAA, as documented in LRA Section 4.3.2, for these components and material. The staff’s 

evaluation of the fatigue TLAA for non-Class 1 components is documented in SER 

Section 4.3.2.

Copper-alloy Heat Exchanger Tubes Exposed to Condensation (Internal). In LRA Table 3.3.2-5, 

the applicant stated that copper-alloy heat exchanger tubes exposed to condensation (internal) 

will be managed for fouling by the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The AMR item cites generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper-alloy piping, piping components, and piping elements exposed to 

condensation (internal) are susceptible to loss of material due to general, pitting, and crevice 

corrosion and recommends GALL Report AMP XI.M38, “Inspection of Internal Surfaces in 

Miscellaneous Piping and Ducting Components,” to manage the aging effect. However, the 

applicant has identified the additional aging effect of fouling. The applicant addressed the GALL 

Report identified aging effects for this component, material, and environment combination in 

other AMR items in LRA Table 3.3.2-5.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because it includes visual inspections of metallic 

components, which are capable of detecting fouling before loss of component intended function.

Stainless Steel Tubing Exposed to Lubricating Oil. In LRA Tables 3.3.2-5, the applicant stated 

that stainless steel tubing exposed to lubricating oil will be managed for cracking by the Oil 
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Analysis Program. The AMR items cite generic note H. The staff notes that this material and 

environment combination is identified in the GALL Report but for a different aging effect, stating 

that stainless steel tubing exposed to lubricating oil is susceptible to loss of material and 

recommending that the Lubricating Oil Analysis Program be used to manage the aging effect.

The staff’s evaluation of the applicant’s Oil Analysis Program is documented in SER 

Section 3.0.3.1.31. Note: The aging mechanisms that cause cracking in the lubricating oil 

environment are SCC and IGA. A corrosive environment (e.g., water) and a susceptible 

material must be present for these aging mechanisms to occur. The components stated above 

may consist of susceptible material (austenitic stainless steel) and when subjected to a caustic 

environment, SSC and IGA are possible. The Oil Analysis Program described in LRA 

Section B.1.28 manages the oil environments through periodic sampling and analysis so that 

water content may be maintained at a level that precludes a corrosive environment and thereby 

manages cracking of stainless steel. The staff finds the applicant’s proposal to manage 

cracking using the Oil Analysis Program acceptable, because the Oil Analysis Program requires 

periodic sampling and testing of lubricating oil to ensure that contaminants (primarily water and 

particulates) are within acceptable limits.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. As amended by letter 

dated May 13, 2014, in LRA Tables 3.3.2-5, 3.3.2-7, 3.3.2-9, 3.3.2-12, 3.3.2-14, 3.3.2-15, 

3.3.2-16, 3.3.2-17, 3.3.2-19-7, 3.3.2-19-9, 3.3.2-19-16, 3.3.2-19-17, 3.3.2-19-18, 3.3.2-19-23, 

3.3.2-19-24, 3.3.2-19-25, 3.3.2-19-26, and 3.3.2-19-27, the applicant stated that metallic heat 

exchanger components, piping, and tanks with Service Level III or other internal coatings 

exposed to raw water, fuel oil, treated water, or lube oil will be managed for loss of coating 

integrity by the Periodic Surveillance and Preventive Maintenance or Service Water Integrity 

Programs. The new AMR items cite generic note H, indicating that this aging effect for the 

component, material, and environment combination is not included in the GALL Report.

Based on its reviews of LRAs and industry operating experience, the staff identified an issue 

concerning loss of coating integrity of internal coatings of piping, piping components, heat 

exchangers, and tanks. As a result, the staff issued RAI 3.0.3-2 on January 2, 2014, requesting 

that the applicant address loss of coating integrity for Service Level III and other coatings. In its 

response dated May 13, 2014, the applicant stated that it had identified components where 

coating degradation has the potential to adversely affect the passive functions of downstream 

components, which is an aging effect not addressed in the GALL Report.

The staff’s evaluation of the applicant’s use of the Periodic Surveillance and Preventive 

Maintenance and Service Water Integrity Programs to manage loss of coating integrity is 

documented in SER Section 3.0.3.3. The staff noted that the applicant will make a number of 

enhancements to the programs to address loss of coating integrity, including internal visual 

inspections of the coated components. The staff finds the applicant’s proposal to manage loss 

of coating integrity using the above programs acceptable, because the Periodic Surveillance 

and Preventive Maintenance and Service Water Integrity Programs will include periodic visual 

inspections by appropriately certified individuals, with specified acceptance criteria, and 

evaluations of inspection findings will be conducted by an appropriately qualified nuclear 

coatings subject matter expert, which will ensure that degradation of coating integrity is detected 

before causing a loss of intended function.

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 
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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 Fuel Pool Cooling and Cleanup – 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 

Fuel Pool Cooling and Cleanup component groups.

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.3.2.3.1.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.7 Standby Service Water – 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 

SSW component groups.

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation that will be managed for loss of material by the 

External Surfaces Monitoring Program and cite generic note G, is documented in SER Section 

3.2.2.3.7.

Carbon and Stainless Steel Closure Bolting Exposed to Condensation. In LRA Tables 3.3.2-7, 

3.3.2-9, 3.3.2-14, 3.3.2-19-16, and 3.3.2-19-26 the applicant stated that the carbon and 

stainless steel closure bolting exposed to condensation will be managed for loss of preload by 

the Bolting Integrity Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon and stainless steel closure bolting exposed to condensation is 

susceptible to loss of material and recommends GALL Report AMP XI.M18 to manage the aging 

effect. However the applicant has identified an additional aging effect. The applicant addressed 

the GALL Report, which identified aging effects for this component, material, and environment 

combination in other AMR items in LRA Tables 3.3.2-7, 3.3.2-9, 3.3.2-14, 3.3.2-19-16, and 

3.3.2-19-26.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage loss of preload using the 

Bolting Integrity Program acceptable because it includes bolting assembly and maintenance 

controls such as application of appropriate gasket alignment, torque, lubricants, and preload; 
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and inspects bolted connections for leakage to ensure detection of leakage occurs before the 

leakage becomes excessive.

Stainless Steel Piping Exposed to Soil. As amended by the 2012 Annual Update letter dated 

August 15, 2012, LRA Table 3.3.2-7 states that stainless steel piping exposed to soil will be 

managed for loss of material by the Buried Piping and Tanks Inspection program. The AMR 

item cites generic note G.

The staff noted that while the applicant cited generic note G, GALL Report item AP-56 states 

that stainless steel piping exposed to soil should be managed for loss of material by 

AMP XI.M41, “Buried and Underground Piping and Tanks.”

The staff’s evaluation of the applicant’s Buried Piping and Tanks Inspection program is 

documented in SER Section 3.0.3.1.4. The staff finds the applicant’s proposal to manage aging 

using the Buried Piping and Tanks Inspection program acceptable because periodic excavated 

direct visual examinations are capable of detecting loss of material and the applicant has 

committed to conduct soil sampling to determine if the soil is corrosive to stainless steel piping.

Stainless Steel Flexible Connections Exposed to Raw Water (Internal). In LRA Table 3.3.2-7, 

as amended by letter dated October 22, 2012, the applicant stated there is a TLAA for stainless 

steel flexible connections exposed to raw water (int) which cite generic note H. The staff 

confirmed that there is a TLAA as documented in LRA Section 4.3.2.2 for this component and 

material. The staff’s evaluation of the fatigue TLAA for Non-Class 1 expansion joints is 

documented in SER Section 4.3.2.2.2.

Carbon Steel and Stainless Steel Piping Components Exposed to Raw Water. As modified by 

letter dated May 13, 2014, LRA Tables 3.3.2-7, 3.3.2-9, 3.3.2-12, 3.3.2-19-16, 3.3.2-19-19, and 

3.3.2-19-23 state that carbon steel and stainless steel piping components exposed to raw water 

will be managed for recurring internal corrosion by the Periodic Surveillance and Preventive 

Maintenance Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel and stainless steel piping components exposed to raw water are 

susceptible to loss of material, and, depending on the system, recommends several different 

AMPs for managing aging. However the applicant has identified recurring internal corrosion as 

an additional aging effect requiring management, as described in LR-ISG-2012-02. The 

applicant addressed the aging effects identified in the GALL Report for this component, 

material, and environment combination in other AMR items in LRA Tables 3.3.2-7, 3.3.2-9, 

3.3.2-12, 3.3.2-19-16, 2.2.2-19-19, and 3.3.2-19-23.

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff finds the applicant’s proposal to 

manage recurring internal corrosion using this program acceptable as documented in SER 

Section 3.3.2.2.7.

Insulated Carbon Steel, Stainless Steel and Copper Alloy Piping and Piping Components 

Exposed to External Condensation. As modified by letters dated May 13, 2014, and 

November 6, 2014, LRA Tables 3.3.2-7, 3.3.2-9, 3.3.2-14, 3.3.2-17, 3.3.2-19-14, 3.3.2-19-15, 

3.3.2-19-16, 3.3.2-19-19, and 3.3.2-19-26 state that insulated carbon steel and stainless steel 

piping and piping components exposed to external condensation will be managed for loss of 

material by the External Surfaces Monitoring Program. In addition, as modified by letters dated 
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May 13, 2014, and November 6, 2014, LRA Tables 3.3.2-7, 3.3.2-9, 3.3.2-14, 3.3.2-17, 

3.3.2-19-14, 3.3.2-19-15, and 3.3.2-19-19 state that insulated stainless steel and copper alloy 

piping and pipe components exposed to external condensation will be managed for cracking by 

the External Surfaces Monitoring Program. The AMR items cite generic note H and include a 

plant-specific note stating that the program provisions apply for indoor insulated components 

operating below the dew point.

The staff noted that this material and environment combination is not identified for insulated 

piping components in the GALL Report. However corrosion under insulation is addressed in 

LR-ISG-2012-02, Section E, and the applicant addressed this aspect in its response dated 

May 13, 2014, to the staff’s RAI 3.0.3-1. The staff also noted that the applicant appropriately 

addressed the aging effects identified in the GALL Report for noninsulated components for this 

material and environment combination in other AMR items in LRA Tables 3.3.2-7, 3.3.2-9, 

3.3.2-14, 3.3.2-17, 3.3.2-19-14, 3.3.2-19-15, 3.3.2-19-16, 3.3.2-19-19, and 3.3.2-19-26.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in

SER Section 3.0.3.1.17. The staff finds the applicant’s proposal to use this program to manage 

loss of material for insulated carbon steel and stainless steel components exposed to an 

external condensation environment and cracking for stainless steel and copper alloy 

components exposed to an external condensation environment acceptable, because it is 

consistent with the staff recommendations for managing the loss of material that results from a 

“corrosion under insulation” aging mechanism, as established in Section E(iii)(b) of 

LR-ISG-2012-02 for insulated piping components.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.8 Component Cooling Water – 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 

component cooling water component groups. The staff’s review did not identify any items with 

notes F through J, indicating that the combinations of component type, material, environment, 

and AERM for this system are consistent with the GALL Report.

3.3.2.3.9 Plant Service Water – 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 

plant service water component groups.
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Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation which will be managed for loss of material by 

the External Surfaces Monitoring Program and cite generic note G, is documented in SER 

Section 3.2.2.3.7.

Carbon and Stainless Steel Closure Bolting Exposed to Condensation. The staff’s evaluation 

for carbon and stainless steel closure bolting exposed to condensation that will be managed for 

loss of preload by the Bolting Integrity Program and cite generic note H, is documented in SER 

Section 3.3.2.3.7.

Carbon Steel and Stainless Steel Piping Components Exposed to Raw Water. The staff’s 

evaluation for carbon steel and stainless steel piping components exposed to raw water, which 

will be managed for loss of material due to recurring internal corrosion by the Periodic 

Surveillance and Preventive Maintenance Program and are associated with generic note H, is 

documented in SER Section 3.3.2.3.7.

Insulated, Carbon Steel and Stainless Steel Piping and Piping Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel and stainless steel piping and 

piping components exposed to external condensation, which will be managed for loss of 

material and cracking by the External Surfaces Monitoring Program and which are associated 

with generic note H, is documented in SER Section 3.3.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

Plastic Sight Glasses Exposed to External Condensation. By letter dated October 25, 2013, the 

applicant amended LRA Table 3.3.2-9 to include plastic sight glasses exposed to external 

condensation, which will be managed for change in material properties by the External Surfaces 

Monitoring Program. The AMR items cite generic note F.

The staff noted that NUREG-1801 does not address change in material properties and cracking 

of plastic sight glass with an internal environment of raw water and an external environment of 

condensation. The staff reviewed the associated item in the LRA and considered whether the 

aging effects proposed by the applicant constitute all of the credible aging effects for this 

component, material, and environment combination. The staff noted that, for a condensation 

environment, the behavior of plastic materials would be similar to elastomeric materials. Based 

on its review of GALL Report Section IX.C, “Selected Definitions & Use of Terms for Describing 

and Standardizing, Materials,” which states that elastomeric materials are susceptible to 

hardening and loss of strength (change in material properties), the staff finds that the applicant 

has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.1.17. The staff finds the applicant’s proposal to manage aging using the 

External Surfaces Monitoring Program acceptable, because the AMP includes periodic visual 
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inspections that are capable of detecting a change in material properties (e.g., change in clarity, 

cracking, crazing, dimensional changes) prior to a loss of component intended function.

Plastic Sight Glasses Exposed to Raw Water (internal). As amended by letter dated 

October 25, 2013, the applicant revised LRA Table 3.3.2-9 to include plastic sight glasses 

exposed to raw water (internal), which will be managed for a change in material properties and 

cracking by the Internal Surfaces in Miscellaneous Piping and Ducting Components Program. 

The AMR items cite generic note F.

The staff noted that NUREG-1801 does not address change in material properties and cracking 

of plastic sight glass with an internal environment of raw water and an external environment of 

condensation. The staff reviewed the associated items in the LRA and considered whether the 

aging effects proposed by the applicant constitute all of the credible aging effects for this 

component, material, and environment combination. The staff noted that, for a raw water 

environment, the behavior of plastic materials would be similar to elastomeric materials. Based 

on its review of GALL Report Section IX.C, “Selected Definitions & Use of Terms for Describing 

and Standardizing, Materials,” which states that elastomeric materials are susceptible to 

hardening and loss of strength (change in material properties), the staff finds that the applicant 

has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable, because the program includes periodic visual inspections 

that are capable of detecting cracking and change in material properties (e.g., change in clarity, 

cracking, crazing) prior to a loss of component intended function.

Stainless Steel Exposed to Condensation. By letter dated October 25, 2013, the applicant 

amended LRA Table 3.3.2-9 to include stainless steel exposed to external condensation, which 

will be managed for loss of material by the External Surfaces Monitoring Program. The AMR 

item cites generic note G.

The staff reviewed the associated item in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA 

Table 3.3.2-10. Based on its review of the GALL Report, stainless steel exposed to 

condensation external, an environment similar to raw water, the staff finds that the applicant has 

identified all credible aging effects for this component, material, and environment combination.

The staff’s evaluation of the applicant’s External Monitoring Program is documented in SER 

Section 3.0.3.1.17. The staff finds the applicant’s proposal to manage loss of materials using 

the External Monitoring Program acceptable because it includes periodic visual inspections of 

component surfaces and will detect discoloration and surface discontinuities due to loss of 

materials.

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 
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GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.3.2.3.10 Floor and Equipment Drainage – 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 floor and equipment drainage component groups.

Carbon and Stainless Steel Closure Bolting Exposed to Waste Water. In LRA Table 3.3.2-10, 

the applicant stated that the carbon and stainless steel closure bolting exposed to waste water 

will be managed for loss of preload by the Bolting Integrity Program. The AMR items cite 

generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA

Table 3.3.2-10. Based on its review of the GALL Report, item AP-264 states that loss of 

preload is an appropriate aging effect for steel and stainless steel bolting exposed to raw water, 

an environment similar to waste water from a preload perspective, and the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage loss of preload using the 

Bolting Integrity Program acceptable because it includes bolting assembly and maintenance 

controls such as application of appropriate gasket alignment, torque, lubricants, and preload; 

and inspects for leakage bolted connections to ensure detection of leakage occurs before the 

leakage becomes excessive.

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 Compressed Air – 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 compressed air component groups.

Stainless Steel Flexible Connections Exposed to Condensation. In LRA Table 3.3.2-11, as 

amended by letter dated October 22, 2012, the applicant stated there is a TLAA for stainless 

steel flexible connections exposed to condensation which cite generic note H. The staff 

confirmed that there is a TLAA as documented in LRA Section 4.3.2.2 for this component and 

material. The staff’s evaluation of the fatigue TLAA for Non-Class 1 expansion joints is 

documented in SER Section 4.3.2.2.2.
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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).

3.3.2.3.12 Fire Protection – Water – 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 fire protection – water component groups.

Carbon Steel Piping Exposed to Exhaust Gas. In LRA Table 3.3.2-12, the applicant stated 

there is a TLAA for carbon steel piping exposed to exhaust gas (internal), which cites generic 

note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for 

these components and material. The staff’s evaluation of the metal fatigue TLAA for 

non-Class 1 components is documented in SER Section 4.3.2.

Copper Alloy Greater Than 15 Percent Zinc or Greater Than 8 Percent Aluminum Flame 

Arrestor and Nozzles Exposed to Air-Outdoor (Internal). In LRA Table 3.3.2-12, the applicant 

stated that copper alloy greater than 15 percent zinc or greater than 8 percent aluminum flame 

arrestor exposed to outdoor air (internal) will be managed for loss of material by the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program. By letter dated 

August 21, 2012, the applicant amended their LRA to include copper alloy with greater than 

15 percent zinc or greater than 8 percent aluminum nozzles exposed to outdoor air (internal), 

which will also be managed for loss of material by the Internal Surfaces in Miscellaneous Piping 

and Ducting Components Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, 

item VII.I.AP-159, which states that copper-alloy piping, piping components, and piping 

elements exposed to outdoor air should be managed for loss of material using GALL Report

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

Components,” the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program includes visual inspections of metallic 

components, which are capable of detecting loss of material before loss of component intended 

function.

Carbon Steel Piping and Gray Cast Iron Flame Arrestors Exposed to Air Outdoor (Internal). In 

LRA Tables 3.3.2-12, 3.3.2-15, and 3.3.2-16, the applicant stated that carbon steel piping and 

gray cast iron flame arrestors exposed to outdoor air (internal) will be managed for loss of 

material by the Internal Surfaces in Miscellaneous Piping and Ducting Components. The AMR 

item cites generic note G.
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that gray cast iron is considered steel in 

the GALL Report when selective leaching is not a concern. Based on its review of the GALL

Report, item VIII.B1-6 (SP-59), which states that steel components exposed internally to 

outdoor air should be managed for loss of material using GALL Report AMP XI.M38, “Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components,” the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because it includes visual inspections of metallic 

components, which are capable of detecting loss of material before loss of component intended 

function.

Carbon Steel Piping Components Exposed to Raw Water. The staff’s evaluation for carbon 

steel piping components exposed to raw water, which will be managed for loss of material due 

to recurring internal corrosion by the Periodic Surveillance and Preventive Maintenance 

Program and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Metallic Tanks with Service Level III or Other Internal Coatings Exposed to Raw Water. As 

amended by letter dated November 6, 2014, in LRA Table 3.3.2-12, the applicant stated that 

metallic tanks with Service Level III or other internal coatings exposed to raw water will be 

managed for loss of coating integrity by the Fire Water System Program. The new AMR item 

cites generic note H, indicating that this aging effect for the component, material, and 

environment combination is not included in the GALL Report.

Based on its reviews of LRAs and industry operating experience, the staff identified an issue 

concerning loss of coating integrity of internal coatings of piping, piping components, heat 

exchangers, and tanks. As a result, the staff issued RAI 3.0.3-2 on January 2, 2014, requesting 

that the applicant address loss of coating integrity for Service Level III and other coatings. In its 

response dated May 13, 2014, the applicant stated that it had identified components where 

coating degradation has the potential to adversely affect the passive functions of downstream 

components, which is an aging effect not addressed in the GALL Report. In its response dated 

November 6, 2014, the applicant added the internally coated fire water storage tanks to LRA 

Table 3.3.2-12.

The staff’s evaluation of the applicant’s use of the Fire Water System Program to manage loss 

of coating integrity is documented in SER Section 3.0.3.3. The staff noted that the applicant will 

make a number of enhancements to the programs to address loss of coating integrity, including 

internal visual inspections of the coated components. The staff finds the applicant’s proposal to 

manage loss of coating integrity using the Fire Water System Program acceptable, because the 

program will include periodic visual inspections conducted by appropriately certified individuals, 

with specified acceptance criteria, and evaluations of inspection findings will be conducted by an 

appropriately qualified nuclear coatings subject matter expert, which will ensure that 

degradation of coating integrity is detected before causing a loss of intended function.
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Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

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).

3.3.2.3.13 Fire Protection – Halon and CO2 – 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 Fire Protection – Halon and CO2 component groups. The staff’s review did not identify any 

items with notes F through J, indicating that the combinations of component type, material, 

environment, and AERM for this system are consistent with the GALL Report.

3.3.2.3.14 Plant Chilled Water – 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 plant chilled water component groups.

Insulated, Carbon Steel and Stainless Steel Piping and Piping Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel and stainless steel piping and 

piping components exposed to external condensation, which will be managed for loss of 

material and cracking by the External Surfaces Monitoring Program and which are associated 

with generic note H, is documented in SER Section 3.3.2.3.7.

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation that will be managed for loss of material by the 

External Surfaces Monitoring Program and cite generic note G, is documented in SER Section

3.2.2.3.7.

Carbon and Stainless Steel Closure Bolting Exposed to Condensation. The staff’s evaluation 

for carbon and stainless steel closure bolting exposed to condensation that will be managed for 

loss of preload by the Bolting Integrity Program and cite generic note H, is documented in SER 

Section 3.3.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 
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Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

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 Standby Diesel Generator – 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 standby diesel generator component groups.

Carbon Steel Piping and Gray Cast Iron Turbocharger Exposed Exhaust Gas. In LRA

Table 3.3.2-15, the applicant stated there are TLAAs for carbon steel piping, CASS 

turbocharger, and gray cast iron turbocharger exposed to exhaust gas (internal), which cite 

generic note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, 

for these components and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components is documented in SER Section 4.3.2.

Carbon and Stainless Steel Closure Bolting Exposed to Lube Oil. In LRA Table 3.3.2-15, the 

applicant stated that the carbon and stainless steel closure bolting exposed to lube oil will be 

managed for loss of preload by the Bolting Integrity Program. The AMR items cite generic

note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed loss of 

material for this component, material, and environment combination in other AMR items in LRA

Table 3.3.2-15. Based on its review of the GALL Report, item AP-264 states that loss of 

preload is an appropriate aging effect for steel and stainless steel bolting exposed to raw water, 

an environment similar to lube oil from a preload perspective, and the staff finds that the 

applicant has identified all credible aging effects for this component, material, and environment 

combination.

The staff’s evaluation of the applicant’s Bolting Integrity Program is documented in SER 

Section 3.0.3.1.2. The staff finds the applicant’s proposal to manage loss of preload using the 

Bolting Integrity Program acceptable because it includes bolting assembly and maintenance 

controls such as application of appropriate gasket alignment, torque, lubricants, and preload; 

and inspects for leakage bolted connections to ensure detection of leakage occurs before the 

leakage becomes excessive.

Nickel Alloy Expansion Joint Exposed to Treated Water. In LRA Table 3.3.2-15, the applicant 

stated that nickel alloy expansion joints exposed to treated water (internal) will be managed for 

loss of material by the Water Chemistry Control – Closed Treated Water Systems Program. 

The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 
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material, and environment description. The staff noted that GALL Report items VII.C1.AP-206 

and VII.E5.AP-279 for nickel alloys in raw water and waste water, respectively, state that nickel 

alloy piping components are subject to loss of material only. The staff also noted that the 

Metals Handbook, Desk Edition, Second Edition (ASM International, 1998) states that nickel 

and nickel-base alloys generally have very good corrosion resistance in distilled and fresh 

waters, and the ASM Handbook, Volume 13B, “Corrosion of Nickel and Nickel-Based Alloys”

chapter (ASM International, 2005) states that nickel alloys are subject to SCC only in specific 

environments, such as hot caustic, fluoride, and chloride-containing water environments. Based 

on this review, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Water Chemistry Control – Closed Treated Water 

Systems Program is documented in SER Section 3.0.3.1.42. The staff finds the applicant’s 

proposal to manage aging using the Water Chemistry Control – Closed Treated Water Systems 

Program acceptable because the water chemistry controls are capable of mitigating the 

environmental effects on loss of material and the opportunistic and periodic inspections can 

detect the presence or extent of corrosion prior to loss of intended function.

In LRA Table 3.3.2-15, as amended by letter dated October 22, 2012, the applicant stated there 

is a TLAA for nickel alloy expansion joints exposed to treated water (int) which cite generic 

note G. The staff confirmed that there is a TLAA as documented in LRA Section 4.3.2.2 for this 

component and material. The staff’s evaluation of the fatigue TLAA for Non-Class 1 expansion 

joints is documented in SER Section 4.3.2.2.2.

Aluminum Housings Exposed to Condensation. In LRA Table 3.3.2-15, the applicant stated that 

aluminum filter housings exposed to condensation will be managed for loss of material by the 

Compressed Air Monitoring Program. The AMR items cite generic note G. By letter dated 

June 22, 2012, the applicant amended the application and changed the AMR item to reference 

GALL Report item 3.3.1-92, and cite generic note E. As a result of the amendment, the staff’s 

evaluation of this item is documented in SER Section 3.3.2.1.15, “Loss of Material Due to Pitting 

and Crevice Corrosion.”

Copper Alloy Greater Than 15 Percent Zinc (Inhibited) Heat Exchanger Tubes Exposed to 

Air-Indoor (External). In LRA Table 3.3.2-15, the applicant stated that copper alloy greater than 

15 percent zinc (inhibited) heat exchanger tubes exposed to indoor air (external) will be 

managed for fouling by the Internal Surfaces in Miscellaneous Piping and Ducting Components 

Program. The AMR item cites generic note G.

The staff noted that this material and environment combination is identified in the GALL Report, 

item VII.J.AP-144, which states that copper-alloy components exposed to uncontrolled indoor 

air have no AERM and no AMP is proposed. However, the applicant has identified fouling as an 

aging effect.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program includes visual inspections of metallic 

components, which are capable of detecting fouling prior to loss of component intended 

function.
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Gray Cast Iron Flame Arrestors Exposed to Outdoor Air. The staff’s evaluation for gray cast 

iron flame arrestors exposed to outdoor air (internal), which will be managed for loss of material 

by the Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cites 

generic note G, is documented in 3.3.2.3.12.

Aluminum Heat Exchanger Fins Exposed to Air-Indoor (External). In LRA Tables 3.3.2-15 and 

3.3.2-16 the applicant stated that aluminum heat exchanger fins exposed to indoor air (external) 

will be managed for fouling by the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that aluminum piping, piping components, and piping elements exposed to 

air-indoor controlled (external) have no AERM and recommends no AMP. However, the 

applicant has fouling as an aging effect.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program includes visual inspections of metallic 

components, which are capable of detecting fouling prior to loss of component intended 

function.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

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).

3.3.2.3.16 HPCS Diesel Generator – 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 HPCS diesel generator component groups.

Carbon Steel and Gray Cast Iron Components Exposed to Exhaust Gas. In LRA

Table 3.3.2-16, the applicant stated that there are TLAAs for stainless steel flexible connection, 

carbon steel piping, carbon turbocharger, and gray cast iron turbocharger exposed to exhaust 

gas (internal), which cite generic note H. The staff confirmed that there is a TLAA, as 

documented in LRA Section 4.3.2, for these components and material. The staff’s evaluation of 

the fatigue TLAA for non-Class 1 components is documented in SER Section 4.3.2.

Aluminum Housings Exposed to Condensation. In LRA Table 3.3.2-16, the applicant stated that 

aluminum air start motor housings exposed to condensation will be managed for loss of material 
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by the Compressed Air Monitoring Program. The AMR items cite generic note G. By letter 

dated June 22, 2012, the applicant amended the application and changed the AMR item to 

reference GALL Report item 3.3.1-92 and cite generic note E. As a result of the amendment, 

the staff’s evaluation of this item is documented in SER Section 3.3.2.1.15, “Loss of Material 

Due to Pitting and Crevice Corrosion.”

Copper Alloy Greater Than 15 Percent Zinc or Greater Than 8 Percent Aluminum Valve Body 

Exposed to Exhaust Gas (Internal). In LRA Table 3.3.2-16 the applicant stated that copper alloy 

greater than 15 percent zinc or greater than 8 percent aluminum valve body exposed to exhaust 

gas (internal) will be managed for loss of material by the Internal Surfaces in Miscellaneous 

Piping and Ducting Components. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Based on its review of the GALL Report, the staff noted 

that copper alloy greater than 15 percent zinc or greater than 8 percent aluminum exposed to 

condensation is subject to a loss of material, and that exhaust gas usually contains 

condensation and other contaminants. The staff also noted that copper is only subject to 

cracking in the presence of ammonia, which is not expected to be part of exhaust gas. The staff 

finds that the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program includes visual inspections of metallic 

components, which are capable of detecting loss of material prior to loss of component intended 

function.

Carbon Steel Heat Exchanger Components Exposed to Raw Water. By letter dated 

December 20, 2013, the applicant revised LRA Table 3.3.2-16 and stated that carbon steel heat 

exchanger components exposed to raw water will be managed for loss of material due to 

erosion by the Service Water Integrity Program. The AMR item cites generic note H and also 

cites plant-specific note 309, which states that the aging effect used for this item refers to loss of 

material due to erosion.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel heat exchanger components exposed to raw water are 

susceptible to loss of material due to general, pitting, crevice, and microbiologically-influenced 

corrosion and recommends GALL Report AMP XI.M20 to manage loss of material due to these 

mechanisms. However, the applicant has identified an additional mechanism. The applicant 

addressed the aging effects identified in the GALL Report for this component, material, and 

environment combination in other AMR items in LRA Table 3.3.2-16.

The staff’s evaluation of the Service Water Integrity Program is documented in SER 

Section 3.0.3.2.5. The staff finds the applicant’s proposal to manage loss of material due to 

erosion mechanisms using the Service Water Integrity Program acceptable, because the 

program conducts periodic visual inspections of heat exchanger internals, which can detect loss 

of material prior to the loss of intended functions.
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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).

Gray Cast Iron Flame Arrestors Exposed to Outdoor Air. The staff’s evaluation for gray cast 

iron flame arrestors exposed to outdoor air (internal), which will be managed for loss of material 

by the Internal Surfaces in Miscellaneous Piping and Ducting Components Program and cites 

generic note G, is documented in 3.3.2.3.12.

Aluminum Heat Exchanger Fins Exposed to Indoor Air. The staff’s evaluation for aluminum heat 

exchanger fins exposed to indoor air (external), which will be managed for fouling by the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program and cites generic note H, 

is documented in 3.3.2.3.15.

Copper-alloy Heat Exchanger Tubes Exposed to Treated Water. In LRA Tables 3.3.2-15 and 

3.3.2-16 the applicant stated that copper-alloy heat exchanger tubes exposed to treated water 

will be managed for loss of material due to wear by the Service Water Integrity Program. The 

AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that copper-alloy heat exchanger tubes exposed to treated water are susceptible to 

loss of material due to corrosion and recommends GALL Report AMP XI.M21A to manage this 

aging effect. However the applicant has identified loss of material due to wear as an additional 

aging effect. The applicant addressed the GALL Report identified aging effects for this 

component, material, and environment combination in other AMR items in LRA Tables 3.3.2-15 

and 3.3.2-16.

The staff’s evaluation of the applicant’s Service Water Integrity Program is documented in SER 

Section 3.0.3.1.39, which includes loss of material. However, in its review of the this item, the 

staff could not determine the exact nature of the wear mechanism, and the LRA did not provide 

sufficient information for the staff to verify that the NDEs conducted through the Service Water 

Integrity Program will be effective in managing loss of material for the treated water side of the 

heat exchanger tubes. In order to address this concern, by letter dated June 27, 2012, the staff 

issued RAI 3.3.2.15-1 requesting the applicant to describe the nature of the aging mechanism 

and to describe the NDE method to be used on the heat exchanger tubes.

In its response dated July 25, 2012, the applicant stated that the wear is due to the relative 

motion between the tubes and tube support members and that this mechanism is evaluated for 

heat exchangers with very low run times because heat exchangers in continuous service will 

typically identify and correct these types of wear problems early in life. The applicant also 

stated that the Service Water Integrity Program conducts ongoing surveillances of heat 

exchangers subject to loss of material due to wear by periodically performing eddy current 

testing of tubes, which is capable of detecting wall thinning on the external surfaces of the tubes 

from the inside. The staff finds the applicant’s response acceptable and the applicant’s 

proposal to manage loss of material due to wear using the above program acceptable because 

the applicant clarified that the wear was caused by tube movement at the tube support plates 

and the periodic eddy current testing performed on these heat exchanger tubes by the Service 

Water Integrity Program can identify wall thinning prior to loss of intended function. The staff’s 

concerns described in RAI 3.3.2.15-1 are resolved.
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Stainless Steel Flexible Connections Exposed to Indoor Air. In LRA Table 3.3.2-16, as 

amended by letter dated October 22, 2012, the applicant stated there is a TLAA for stainless 

steel flexible connections exposed to air indoor (int), fuel oil, and condensation, respectively, 

which cite generic note H. The staff confirmed that there is a TLAA as documented in LRA 

Section 4.3.2.2 for this component and material. The staff’s evaluation of the fatigue TLAA for 

Non-Class 1 expansion joints is documented in SER Section 4.3.2.2.2.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

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).

3.3.2.3.17 Control Room Heating, Ventilation, and Air Conditioning – 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 Control Room Heating, Ventilation, and Air Conditioning component groups.

Insulated, Carbon Steel, Stainless Steel, and Copper Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel, stainless steel, and copper 

alloy piping components exposed to external condensation, which will be managed for loss of 

material and cracking by the External Surfaces Monitoring Program and which are associated 

with generic note H, is documented in SER Section 3.3.2.3.7.

Copper-Alloy Evaporator Tube Fins, Tubes, and Heat Exchanger Tubes Exposed to 

Condensation (External). In LRA Tables 3.3.2-17 and 3.3.2-18 the applicant stated that 

copper-alloy evaporator tube fins, evaporator tubes, and heat exchanger tubes exposed to 

condensation (external) will be managed for fouling by the Internal Surfaces in Miscellaneous 

Piping and Ducting Components Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that piping, piping components, and piping elements exposed to condensation 

(external) are susceptible to loss of material due to general, pitting, and crevice corrosion. 

However, the applicant has identified loss of material due to general, pitting, and crevice 

corrosion and fouling as an additional aging effect. The applicant addressed the GALL Reportidentified aging effects for this component, and material and environment combination in other 

AMR items, in LRA Tables 3.3.2-17 and 3.3.2-18.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff finds the applicant’s 

proposal to manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program acceptable because the program includes visual inspections of metallic 
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components, which are capable of detecting fouling prior to loss of component intended 

function.

Elastomeric Duct Flexible Connection Exposed to Interior Indoor Air. In LRA Table 3.3.2-17, the 

applicant stated that for elastomeric duct flexible connection exposed internally to indoor air, 

there is no aging effect and no AMP is proposed. The AMR item cites generic note I. The AMR 

item also cites plant-specific note 306 which states, “[c]hanges of material properties and 

cracking in elastomers are results of exposure to ultra-violet light or elevated temperatures 

(> 95 °F). The interior surfaces of these components are not exposed to ultra-violet light and 

are part of the control room HVAC system that is not exposed to elevated temperatures.” The 

applicant also cited LRA Table 3.3.1, item 3.3.1-76. The staff noted that SRP-LR item 3.3.1-76 

recommends managing elastomeric materials for hardening and loss of strength due to 

elastomer degradation with GALL Report AMP XI.M36, “External Surfaces Monitoring of 

Mechanical Components.” The staff also noted that LRA item 3.3.1-76 recommends the same.

The staff could not confirm that there are no aging effects for this material and environment 

combination for this component, material, and environmental combination. The staff noted that 

GALL Report Section IX.C states, “[h]ardening and loss of strength of elastomers can be 

induced by elevated temperature (over about 95 °F or 35 °C), and additional aging factors 

(e.g., exposure to ozone, oxidation, and radiation).” Nevertheless, the 95 °F is a general 

guideline and does not necessarily apply to all elastomeric material types. By letter dated 

June 20, 2012, the staff issued RAI 3.3.1.76-1 requesting that the applicant state the specific 

material type for these elastomeric duct flexible connection(s), state the basis why there are no 

AERM and no proposed AMP, and if the specific elastomeric material type does age despite 

being in an environment below 95 °F, state how the item will be managed for aging.

In its response dated July 19, 2012, the applicant stated that the elastomeric duct flexible 

connection is constructed from neoprene coated fiberglass cloth. The applicant also stated that, 

“[n]eoprene is chemically and structurally similar to natural rubber, with similar mechanical 

properties. It has high resistance to oils, chemicals, sunlight, weathering, aging, and ozone. It 

retains its properties at temperatures up to 250 °F (121.1 °C).” The applicant further stated that, 

“[n]o aging effects requiring management (AERM) and no proposed aging management 

programs (AMP) are identified for the internal surface of these elastomers since they are not 

exposed to ultra-violet light or elevated temperatures (greater than 95 °F).”

The staff finds the applicant’s response acceptable because neoprene is recognized for being 

weather and ozone resistant and it has excellent abrasion and tear resistance (Tank Linings for 

Chemical Process Industries, Chandrasekaran, V.C.© 2009 Smithers Rapra Technology) and as 

stated in plant-specific note I, the duct flexible connections are not exposed to ultraviolet light or 

temperatures above 95 °F. The staff’s concern described in RAI 3.3.1.76-1 is resolved.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

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 
3-384

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 Heating, Ventilation, and Air Conditioning – 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 HVAC component groups.

Copper-Alloy Evaporator Tube Fins, Tubes, and Heat Exchanger Tubes Exposed to 

Condensation (External). The staff’s evaluation for copper-alloy heat exchanger tubes exposed 

to condensation (external) that will be managed for fouling by the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program and cites generic note H, is 

documented in SER Section 3.3.2.3.17.

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).

3.3.2.3.19 Miscellaneous Auxiliary Systems in Scope for 10 CFR 54.4(a)(2) – 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 miscellaneous auxiliary systems in scope for 10 CFR 54.4(a)(2) component groups.

For LRA Table 3.3.2-19-1

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.3.2.3.1.

For LRA Table 3.3.2-19-2

Stainless Steel Expansion Joint Exposed to Treated Water. In LRA Table 3.3.2-19-2, the 

applicant stated there is a TLAA for stainless steel expansion joint exposed to treated water 

(int), which cite generic note H. The staff confirmed that there is a TLAA, as documented in 

LRA Section 4.3.2.2, for this component and material. The staff’s evaluation of the fatigue 

TLAA for non-Class 1 components is documented in SER Section 4.3.2.2.2.
3-385

For LRA Table 3.3.2-19-7

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-8

Teflon Flexible Connections Exposed to Treated Water (internal). In LRA Table 3.3.2-19-8, the 

applicant stated that for Teflon flexible connections exposed to treated water (internal), there is 

no aging effect and no AMP is proposed. The AMR item cites generic note G.

The staff reviewed the associated items in the LRA to confirm that no credible aging effects are 

applicable for this component, material, and environmental combination. The staff could not find 

the applicant’s proposal acceptable based on its review of NASA Technical Memorandum 

105753, High Temperature Dielectric Properties of Apical, Kapton, Peek, Teflon AF, and Upilex 

Polymers, A N Hammoud, 1992, Table 1, which states that Teflon can handle long-term 

temperatures up to 285 °C; however, there are studies which demonstrate that certain grades of 

Teflon degrade when exposed to radiation. By letter dated June 20, 2012, the staff issued

RAI 3.3.2.19-3 requesting that the applicant state the specific Teflon material type for these 

flexible connections, state the basis why there are no AERM and no proposed AMP, and if the 

specific Teflon material type does age, state how the item will be managed for aging.

In its response dated July 19, 2012, the applicant stated that:

After a review of operating use information for this component, it was determined 

that the flexible connection in question is a single short length of material located 

downstream of a normally closed sample valve. After use, the flexible 

connection sample line is allowed to drain and empty. The flexible connection is 

normally isolated and drained, not fluid-filled. This nonsafety-related component 

therefore has no potential for physical interaction with a safety-related 

component. Based on these details, this flexible connection is not subject to 

aging management review. LRA Table 3.3.2-19-8 is revised to reflect these 

details. Deletions are shown with strikethrough.

The staff finds the applicant’s response acceptable because it clearly explained why these 

components are not subject to an AMR and the LRA has been appropriately amended. The 

staff’s concern described in RAI 3.3.2.19-3 is resolved.

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.3.2.3.1.
3-386

For LRA Table 3.3.2-19-9

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-14

Insulated, Carbon Steel and Stainless Steel Piping Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel and stainless steel piping 

components exposed to external condensation, which will be managed for loss of material and 

cracking by the External Surfaces Monitoring Program and which are associated with generic 

note H, is documented in SER Section 3.3.2.3.7.

For LRA Table 3.3.2-19-15

Insulated, Carbon Steel and Stainless Steel Piping Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel and stainless steel piping 

components exposed to external condensation, which will be managed for loss of material and 

cracking by the External Surfaces Monitoring Program and which are associated with generic 

note H, is documented in SER Section 3.3.2.3.7.

For LRA Table 3.3.2-19-16

Carbon and Stainless Steel Closure Bolting Exposed to Condensation. The staff’s evaluation 

for carbon and stainless steel closure bolting exposed to condensation that will be managed for 

loss of preload by the Bolting Integrity Program and cite generic note H is documented in SER 

Section 3.3.2.3.7.

Carbon Steel Piping Components Exposed to Raw Water. The staff’s evaluation for carbon 

steel piping components exposed to raw water, which will be managed for loss of material due 

to recurring internal corrosion by the Periodic Surveillance and Preventive Maintenance 

Program and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Insulated Carbon Steel Piping and Piping Components Exposed to External Condensation. The 

staff’s evaluation for insulated carbon steel piping components exposed to external 

condensation, which will be managed for loss of material by the External Surfaces Monitoring 

Program and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 
3-387

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-17

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-18

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-19

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation that will be managed for loss of material by the 

External Surfaces Monitoring Program and cite generic note G is documented in SER 

Section 3.2.2.3.7.

Plastic Sight Glass Exposed to Raw Water or Condensation (Internal). By letter dated 

August 15, 2012, the applicant amended LRA Table 3.3.2-19-19 to include items for plastic sight 

glass exposed to raw water (internal) and condensation (external), which will be managed for a 

change in material properties by the Internal Surfaces in Miscellaneous Piping and Ducting 

Components and External Surfaces Monitoring Programs. The AMR items cite generic note F.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff reviewed the Engineering Materials 

Handbook – Engineering Plastics, American Society for Metals International, Copyright 1988, 

which states that rigid polymers are unaffected by water, concentrated alkalis, non-oxidizing 

acids, oils, ozone, sunlight, or humidity changes. The staff also noted that, unlike metals, 

thermoplastics do not display corrosion rates, and rather than depend on an oxide layer for 

protection, they depend on chemical resistance to the environments to which they are exposed. 

The staff further noted that thermoplastic materials are impervious and, once selected for the 

environment, will not have any significant age related degradation. Based on its review of the 

associated items in the LRA and the reference above, the staff confirmed that the applicant has 

identified all credible aging effects for this component, material and environmental combination.
3-388

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components and External Surfaces Monitoring Programs are documented in SER 

Sections 3.0.3.1.25 and 3.0.3.1.17. The staff finds the applicant’s proposal to manage aging 

using the Internal Surfaces in Miscellaneous Piping and Ducting Components and External 

Surfaces Monitoring Programs acceptable because the programs include periodic visual 

inspections which are capable of detecting a change in material properties (e.g., change in 

clarity, cracking, crazing) prior to a loss of component intended function.

Carbon Steel and Stainless Steel Piping Components Exposed to Raw Water. The staff’s 

evaluation for carbon steel and stainless steel piping components exposed to raw water, which 

will be managed for loss of material due to recurring internal corrosion by the Periodic 

Surveillance and Preventive Maintenance Program and which are associated with generic 

note H, is documented in SER Section 3.3.2.3.7.

Insulated, Carbon Steel and Stainless Steel Piping and Piping Components Exposed to External 

Condensation. The staff’s evaluation for insulated carbon steel and stainless steel piping and 

piping components exposed to external condensation, which will be managed for loss of 

material and cracking by the External Surfaces Monitoring Program and which are associated 

with generic note H, is documented in SER Section 3.3.2.3.7.

For LRA Table 3.3.2-19-20

Carbon Steel Piping Components Exposed to Treated Water. The staff’s evaluation for carbon 

steel piping components exposed to treated water, which will be managed for loss of material 

due to erosion mechanisms other than flow-accelerated corrosion by the Flow-Accelerated 

Corrosion Program and cite generic note H, is documented in SER Section 3.3.2.3.1.

For LRA Table 3.3.2-19-23

Carbon Steel Piping Components Exposed to Raw Water. The staff’s evaluation for carbon 

steel piping components exposed to raw water, which will be managed for loss of material due 

to recurring internal corrosion by the Periodic Surveillance and Preventive Maintenance 

Program and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-24

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 
3-389

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-25

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation that will be managed for loss of material by the 

External Surfaces Monitoring Program and cite generic note G is documented in 3.2.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-26

Stainless Steel Piping, Piping Elements, and Piping Components Exposed to External 

Condensation. The staff’s evaluation for stainless steel piping, piping elements, and piping 

components externally exposed to condensation that will be managed for loss of material by the 

External Surfaces Monitoring Program and cite generic note G, is documented in 3.2.2.3.7.

Insulated Carbon Steel Piping Components Exposed to an External Condensation Environment. 

The staff’s evaluation for insulated carbon steel piping components exposed to external 

condensation, which will be managed for loss of material and cracking by the External Surfaces 

Monitoring Program and are associated with generic note H, is documented in SER 

Section 3.3.2.3.7.

Carbon and Stainless Steel Closure Bolting Exposed to Condensation. The staff’s evaluation 

for carbon and stainless steel closure bolting exposed to condensation that will be managed for 

loss of preload by the Bolting Integrity Program and cite generic note H, is documented in SER 

Section 3.3.2.3.7.

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-27

Metallic Heat Exchanger Components, Piping, and Tanks with Service Level III or Other Internal 

Coatings Exposed to Raw Water, Fuel Oil, Treated Water, or Lube Oil. The staff’s evaluation 

for metallic heat exchanger components, piping, and tanks with Service Level III or other 

internal coatings exposed to raw water, fuel oil, treated water, or lube oil, which will be managed 

for loss of coating integrity by the Periodic Surveillance and Preventive Maintenance or Service 
3-390

Water Integrity Programs and which are associated with generic note H, is documented in SER 

Section 3.3.2.3.5.

For LRA Table 3.3.2-19-28

Stainless Steel Flexible Connections Exposed to Raw Water. In LRA Table 3.3.2-19-28, the 

applicant stated there is a TLAA for stainless steel flexible connections exposed to raw water

(int), which cite generic note H. The staff confirmed that there is a TLAA, as documented in 

LRA Section 4.3.2.2, for this component and material. The staff’s evaluation of the fatigue 

TLAA for non-Class 1 components is documented in SER Section 4.3.2.2.2.

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).

3.3.3 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 Systems

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:

• condensate and refueling water storage and transfer

• miscellaneous steam and power conversion systems in scope for 10 CFR 54.4(a)(2)

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 

Programs for Steam and Power Conversion Systems Evaluated in Chapter VIII of 

NUREG-1801,” 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 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.4.2 Staff Evaluation

The staff reviewed LRA Section 3.4 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the steam and power conversion 
3-391

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 AMRs to ensure the applicant’s claim that certain AMRs were 

consistent with the GALL Report. The staff did not repeat its review of the matters described in 

the GALL Report; however, the staff did verify that the material presented in the LRA was 

applicable and that the applicant identified the appropriate GALL Report AMRs. The staff’s 

evaluations of the AMPs are documented in SER Section 3.0.3.

During its review, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.4.2.2 acceptance criteria. The staff’s 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 items and the plant’s operating experience to verify the 

applicant’s claims.

Table 3.4-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.4 and addressed in the GALL Report.

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

the GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

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 

due to fatigue

Fatigue is a TLAA to 

be evaluated for the 

period of extended 

operation. See the 

SRP, Section 4.3 

“Metal Fatigue,” for 

acceptable methods 

for meeting the 

requirements of 

10 CFR 54.21(c)(1).

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.4.2.2.1)

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.4.1-2)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.2.2)
3-392

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements; 

tanks exposed to 

air – outdoor 

(3.4.1-3)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

Yes External 

Surfaces 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.2.3)

Steel external 

surfaces, bolting 

exposed to air with 

borated water 

leakage (3.4.1-4)

Loss of material 

due to boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to steam, 

treated water 

(3.4.1-5)

Wall thinning 

due to 

flow-accelerated 

corrosion

Chapter XI.M17, 

“Flow-Accelerated 

Corrosion”

No FlowAccelerated 

Corrosion

Consistent with the 

GALL Report

Steel, stainless steel 

bolting exposed to 

soil (3.4.1-6)

Loss of preload Chapter XI.M18, 

“Bolting Integrity “

No Bolting Integrity Consistent with the 

GALL Report

High-strength steel 

closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-7)

Cracking due to 

cyclic loading, 

stress corrosion 

cracking

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Steel; stainless steel 

bolting, closure 

bolting exposed to 

air – outdoor 

(external), air –

indoor, uncontrolled 

(external) (3.4.1-8)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report

Steel closure bolting 

exposed to air with 

steam or water 

leakage (3.4.1-9)

Loss of material 

due to general 

corrosion

Chapter XI.M18, 

“Bolting Integrity”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Copper alloy, nickel 

alloy, steel; stainless 

steel, steel; stainless 

steel bolting, closure 

bolting exposed to 

any environment, 

air – outdoor 

(external), air –

indoor, uncontrolled 

(external) (3.4.1-10)

Loss of preload 

due to thermal 

effects, gasket 

creep, and 

self-loosening

Chapter XI.M18, 

“Bolting Integrity”

No Bolting Integrity Consistent with the 

GALL Report
3-393

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Stainless steel 

piping, piping 

components, and 

piping elements, 

tanks, heat 

exchanger 

components 

exposed to steam, 

treated water >60 °C 

(>140 °F) (3.4.1-11)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry

Control – BWR

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel; stainless steel 

tanks exposed to 

treated water 

(3.4.1-12)

Loss of material 

due to general 

(steel only), 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel piping, piping 

components, and 

piping elements 

exposed to treated 

water (3.4.1-13)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements, 

PWR heat 

exchanger 

components 

exposed to steam, 

treated water 

(3.4.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Steel heat 

exchanger 

components 

exposed to treated 

water (3.4.1-15)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy, 

stainless steel, 

nickel alloy, 

aluminum piping, 

piping components, 

and piping elements, 

heat exchanger 

components and 

tubes, PWR heat 

exchanger 

components 

exposed to treated 

water, steam 

(3.4.1-16)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Copper alloy heat 

exchanger tubes 

exposed to treated

water (3.4.1-17)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)
3-394

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy, 

stainless steel heat 

exchanger tubes 

exposed to treated 

water (3.4.1-18)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.M32, 

“One-Time 

Inspection”

No Water 

Chemistry 

Control – BWR 

and One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel, steel 

heat exchanger 

components 

exposed to raw 

water (3.4.1-19)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components or 

Periodic 

Surveillance 

and Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.1.2)

Copper alloy, 

stainless steel 

piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.4.1-20)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.1.3)

Stainless steel heat 

exchanger 

components 

exposed to raw 

water (3.4.1-21)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel, 

copper alloy, Steel 

heat exchanger 

tubes, heat 

exchanger 

components 

exposed to raw 

water (3.4.1-22)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M20, 

“Open-Cycle Cooling 

Water System”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

closed-cycle cooling 

water >60 °C 

(>140 °F) (3.4.1-23)

Cracking due to 

stress corrosion 

cracking

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (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

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed

Treated Water 

Systems

Consistent with the 

GALL Report
3-395

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel heat 

exchanger 

components 

exposed to 

closed-cycle cooling 

water (3.4.1-25)

Loss of material 

due to general, 

pitting, crevice, 

and galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed

Treated Water 

Systems

Consistent with the 

GALL Report

Stainless steel heat

exchanger 

components, piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.4.1-26)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed

Treated Water 

Systems

Consistent with the 

GALL Report

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

closed-cycle cooling 

water (3.4.1-27)

Loss of material 

due to pitting, 

crevice, and 

galvanic 

corrosion

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Water 

Chemistry 

Control –

Closed

Treated Water 

Systems

Consistent with the 

GALL Report

Steel, stainless 

steel, copper alloy 

heat exchanger 

components and 

tubes, heat 

exchanger tubes 

exposed to 

closed-cycle cooling 

water (3.4.1-28)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M21A, 

“Closed Treated 

Water Systems”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Steel tanks exposed 

to air – outdoor 

(external) (3.4.1-29)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Steel, stainless 

steel, aluminum 

tanks exposed to soil 

or concrete, air –

outdoor (external) 

(3.4.1-30)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.1.5)

Stainless steel, 

aluminum tanks 

exposed to soil or 

concrete (3.4.1-31)

Loss of material 

due to pitting, 

and crevice 

corrosion

Chapter XI.M29, 

“Aboveground 

Metallic Tanks”

No Aboveground 

Metallic Tanks

Consistent with the 

GALL Report

Gray cast iron 

piping, piping 

components, and 

piping elements 

exposed to soil 

(3.4.1-32)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)
3-396

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Gray cast iron, 

copper alloy (>15% 

Zn or >8% Al) 

piping, piping 

components, and 

piping elements 

exposed to treated 

water, raw water, 

closed-cycle cooling 

water (3.4.1-33)

Loss of material 

due to selective 

leaching

Chapter XI.M33, 

“Selective Leaching”

No Selective 

Leaching

Consistent with the 

GALL Report

Steel external 

surfaces exposed to 

air – indoor, 

uncontrolled 

(external), air –

outdoor (external), 

condensation 

(external) (3.4.1-34)

Loss of material 

due to general 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No External 

Surfaces 

Monitoring 

Consistent with the 

GALL Report

Aluminum piping, 

piping components, 

and piping elements 

exposed to air –

outdoor (3.4.1-35)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M36, 

“External Surfaces 

Monitoring of 

Mechanical 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to air –

outdoor (internal) 

(3.4.1-36)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-37)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to raw 

water (3.4.1-38)

Loss of material 

due to general, 

pitting, crevice, 

galvanic, and 

microbiologically

-influenced 

corrosion; 

fouling that 

leads to 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to 

condensation 

(internal) (3.4.1-39)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M38, 

“Inspection of 

Internal Surfaces in 

Miscellaneous 

Piping and Ducting 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)
3-397

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to 

lubricating oil 

(3.4.1-40)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis,

One-Time 

Inspection, and 

Internal 

Surfaces in 

Miscellaneous 

Piping and 

Ducting 

Components

Consistent with the 

GALL Report

(see SER 

Section 3.4.2.1.4)

Steel heat 

exchanger 

components 

exposed to 

lubricating oil 

(3.4.1-41)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-42)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to 

lubricating oil 

(3.4.1-43)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements, 

heat exchanger 

components 

exposed to 

lubricating oil 

(3.4.1-44)

Loss of material 

due to pitting, 

crevice, and 

microbiologically

-influenced 

corrosion

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Oil Analysis and 

One-Time 

Inspection

Consistent with the 

GALL Report

Aluminum heat 

exchanger 

components and 

tubes exposed to 

lubricating oil 

(3.4.1-45)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Stainless steel, 

steel, copper alloy 

heat exchanger 

tubes exposed to 

lubricating oil 

(3.4.1-46)

Reduction of 

heat transfer 

due to fouling

Chapter XI.M39, 

“Lubricating Oil 

Analysis,” and 

Chapter XI.M32, 

“One-Time 

Inspection”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)
3-398

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel (with coating or 

wrapping) piping, 

piping components, 

and piping elements; 

tanks exposed to soil 

or concrete 

(3.4.1-47)

Loss of material 

due to general, 

pitting, crevice, 

and 

microbiologically

-influenced 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks

Inspection

Consistent with the 

GALL Report

Stainless steel 

bolting exposed to 

soil (3.4.1-48)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks 

Inspection

Consistent with the 

GALL Report

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to soil or 

concrete (3.4.1-49)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks 

Inspection

Consistent with the 

GALL Report

Steel bolting 

exposed to soil 

(3.4.1-50)

Loss of material 

due to general, 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Buried Piping 

and Tanks 

Inspection

Consistent with the 

GALL Report

Underground 

stainless steel and 

steel piping, piping 

components, and 

piping elements 

(3.4.1-50x)

Loss of material 

due to general 

(steel only), 

pitting and 

crevice 

corrosion

Chapter XI.M41, 

“Buried and 

Underground Piping 

and Tanks”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Steel piping, piping 

components, and 

piping elements 

exposed to concrete 

(3.4.1-51)

None None, provided

1) attributes of the 

concrete are 

consistent with 

ACI 318 or ACI 349 

(low water-to-cement 

ratio, low 

permeability, and 

adequate air 

entrainment) as cited 

in NUREG-1557, 

and

2) plant operating 

experience indicates 

no degradation of 

the concrete

No, if 

conditions 

are met.

Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Aluminum piping, 

piping components, 

and piping elements 

exposed to gas, air –

indoor, uncontrolled 

(internal/external) 

(3.4.1-52)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)
3-399

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Copper alloy (≤15% 

Zn and ≤8% Al) 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage (3.4.1-53)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

BWRs (see SER 

Section 3.4.2.1.1)

Copper alloy piping, 

piping components, 

and piping elements 

exposed to gas, air –

indoor, uncontrolled 

(external) (3.4.1-54)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Glass piping 

elements exposed to 

lubricating oil, air –

outdoor, 

condensation 

(internal/external), 

raw water, treated 

water, air with 

borated water 

leakage, gas, 

closed-cycle cooling 

water, air – indoor, 

uncontrolled 

(external) (3.4.1-55)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Nickel alloy piping, 

piping components, 

and piping elements 

exposed to air –

indoor, uncontrolled 

(external) (3.4.1-56)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report

Nickel alloy, PVC 

piping, piping 

components, and 

piping elements 

exposed to air with 

borated water 

leakage, air – indoor, 

uncontrolled, 

condensation 

(internal) (3.4.1-57)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

Stainless steel 

piping, piping 

components, and 

piping elements 

exposed to air –

indoor, uncontrolled 

(external), concrete, 

gas, air – indoor, 

uncontrolled 

(internal) (3.4.1-58)

None None NA - No 

AEM or 

AMP

Not applicable Consistent with the 

GALL Report
3-400

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation 

in SRP-LR 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel piping, piping 

components, and 

piping elements 

exposed to air –

indoor controlled 

(external), gas 

(3.4.1-59)

None None NA - No 

AEM or 

AMP

Not applicable Not applicable to 

GGNS (see SER 

Section 3.4.2.1.1)

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:

• Aboveground Metallic Tanks

• Bolting Integrity

• Buried Piping and Tanks Inspection

• Compressed Air Monitoring

• External Surfaces Monitoring

• Flow-Accelerated Corrosion

• Internal Surfaces in Miscellaneous Piping and Ducting Components

• Oil Analysis

• One-Time Inspection

• Periodic Surveillance and Preventive Maintenance

• Selective Leaching

• Water Chemistry Control – BWR

• Water Chemistry Control – Closed Treated Water Systems

LRA Tables 3.4.2-1 through 3.4.2-2 summarize AMRs for the steam and power conversion 

systems components and indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate 

GALL Report AMRs. The staff’s evaluation follows.
3-401

3.4.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.4.1, items 3.4.1-4, 3.4.1-17, 3.4.1-21, 3.4.1-36, 3.4.1-41, 3.4.1-42, 3.4.1-45, 

3.4.1-46, and 3.4.1-53, the applicant claimed that the corresponding AMR items in the 

GALL Report are not applicable because the associated items are only applicable to PWRs. 

The staff reviewed the SRP-LR, confirmed these items only apply to PWRs, and finds that these 

items are not applicable to GGNS.

For LRA Table 3.4.1, items 3.4.1-7, 3.4.1-22, 3.4.1-23, 3.4.1-28, 3.4.1-29, 3.4.1-32, 3.4.1-35,

3.4.1-51, 3.4.1-52, and 3.4.1-57, the applicant claimed that the corresponding items in the GALL 

Report are not applicable. The staff reviewed the LRA and UFSAR and confirmed that the 

applicant’s LRA does not have any AMR results applicable for these items.

LRA Table 3.4.1, item 3.4.1-9 addresses steel closure bolting exposed to air with steam or 

water leakage. The GALL Report recommends GALL Report AMP XI.M18, “Bolting Integrity,” to 

manage loss of material due to general corrosion for this component group. The applicant 

stated that this item is not applicable because steam or water leakage is not considered a 

separate aspect of the indoor air environment. The staff evaluated the applicant’s claim and 

found it acceptable because (a) all ESF system bolting exposed to air is being managed for loss 

of material by the Bolting Integrity Program using item 3.4.1-08, (b). The program conducts 

periodic visual inspections that are capable of detecting loss of material due to general 

corrosion in bolting, and (c) use of this program is consistent with the GALL Report.

LRA Table 3.4.1, item 3.4.1-13 addresses steel piping, piping components, and piping elements 

exposed to treated water. The GALL Report recommends GALL Report AMPs XI.M2, “Water 

Chemistry,” and XI.M32, “One-Time Inspection,” to manage loss of material due to general, 

pitting, and crevice corrosion for this component group. The applicant stated that this item is not 

applicable because it is applicable to PWR plants only. The staff evaluated the applicant’s claim 

and found it acceptable because, although the LRA contains steel piping components exposed 

to treated water in the steam and power conversion systems, the staff confirmed that those 

components reference LRA item 3.4.1-14, which manages loss of material due to general, 

pitting, and crevice corrosion in a manner consistent with LRA item 3.4.1-13 and GALL Report

recommendations.

LRA Table 3.4.1, item 3.4.1-37 addresses steel piping, piping components, and piping elements 

exposed to condensation (internal.) The GALL Report recommends GALL Report AMP XI.M38, 

“Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage 

loss of material for this component group. The applicant stated that this item is not applicable 

because it is only applicable to PWRs. The staff evaluated the applicant’s claim and finds it

acceptable because the GALL Report items that are referenced by item 3.4.1-37 are for the 

main steam and auxiliary feedwater systems, which are applicable only for PWRs. However, 

the staff noted that there are AMR items in LRA Table 3.4.2-2-16 with this material, 

environment, and aging effect combination for which the applicant credits LRA Table 3.3.1, 

item 3.3.1-95 and the Internal Surfaces in Miscellaneous Piping and Ducting Program to 

manage aging.

LRA Table 3.4.1, item 3.4.1-38 addresses steel piping, piping components, and piping elements 

exposed to raw water. The GALL Report recommends GALL Report AMP XI.M38, “Inspection 

of Internal Surfaces in Miscellaneous Piping and Ducting Components,” to manage loss of 

material due to general, pitting, crevice, galvanic, and microbiologically-influenced corrosion, 

and fouling that leads to corrosion, for this component group. The applicant stated that this item 
3-402

is not applicable because it is applicable to PWRs only. Nevertheless, the staff evaluated the 

applicant’s claim and found it acceptable because, although the LRA contains steel piping 

components exposed to raw water in the steam and power conversion systems, the applicant 

chose to reference LRA item 3.4.1-19, which manages aging with either the Internal Surfaces in 

Miscellaneous Piping and Ducting Components or Periodic Surveillance and Preventive 

Maintenance Programs. The staff also noted that the periodic visual examinations in the 

Internal Surfaces in Miscellaneous Piping and Ducting Components and Periodic Surveillance 

and Preventive Maintenance Programs are capable of detecting loss of material and fouling 

prior to loss of intended functions.

LRA Table 3.4.1, item 3.4.1-39 addresses stainless steel piping, piping components, and piping 

elements exposed to condensation (internal). The GALL Report recommends GALL Report

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

Components,” to manage loss of material for this component group. The applicant stated that 

this item is not used because loss of material for this component group is managed by the 

Compressed Air Monitoring System consistent with LRA Table 3.3.1, item 3.3.1-56. The staff 

evaluated the applicant’s claim and finds it acceptable because the applicant is managing aging 

for this material, environment, and aging effect combination consistent with the GALL Report

using alternative Table 1 items.

LRA Table 3.4.1, item 3.4.1-50.5 addresses stainless steel, and steel underground piping, 

piping components, and piping elements. The GALL Report recommends GALL Report

AMP XI.M41, “Buried and Underground Piping and Tanks,” to manage loss of material due to 

general (steel only), pitting and crevice corrosion for this component group. The applicant 

stated that this item is not applicable because “[t]here is no underground piping in areas of 

restricted access in the steam and power conversion systems in the scope of license renewal.” 

The staff evaluated the applicant’s claim and lacks sufficient information to find it acceptable 

because an enhancement to LRA Section B.1.18, External Surfaces Monitoring Program, states 

that instructions will be provided for inspecting all underground components within the scope of 

this program. Based on the staff’s review during the AMP audit, the RHR pump suction barrels 

and HPCS pump suction barrels are two of the underground piping components associated with 

this enhancement. Although these components are not within the scope of LRA Section 3.4, a 

similar non-applicability statement was made associated with item 3.2.1-53.5 when the 

enhancement demonstrates that there are underground components in LRA Section 3.2. By 

letter dated April 16, 2012, the staff issued RAI B.1.5-1 requesting that the applicant provide a 

list of all underground in-scope components, state which AMP will be used to manage the aging 

of these underground in-scope components, and if a program other than the Buried Piping and 

Tanks Inspection Program will be used to age manage any of the underground components, 

state if any recommendations contained in AMP XI.M41 of the GALL Report will not be met and 

justify not meeting the recommendations. In its response dated May 14, 2012, the applicant 

listed the underground components, none of which are steam and power conversion 

components. The staff finds the applicant’s response acceptable because there are no in-scope 

underground components in the steam and power conversion components systems. The staff’s 

concern described in RAI B.1.5-1 is resolved.

LRA Table 3.4.1, item 3.4.1-55, addresses glass piping elements exposed to lubricating oil, 

outdoor air, condensation, raw water, treated water, air with borated water leakage, gas, 

closed-cycle cooling water, and uncontrolled indoor air. The applicant stated that it is consistent 

with the GALL Report for glass components exposed to indoor air, lube oil, raw water, and 

treated water, but that for other environments there are no glass components within the steam 

and power conversion systems that are within the scope of license renewal. SRP-LR
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Table 3.4-1, item 3.4.1-55 states that there are no aging effects or aging mechanisms, and that 

no AMP is recommended for this component group exposed to these environments; therefore, 

the staff finds the applicant’s determination acceptable.

LRA Table 3.4.1, item 3.4.1-59 addresses steel piping, piping components, and piping elements 

exposed to air – indoor, controlled (external) and gas and states that there are no aging effects, 

aging mechanisms, or AMPs. SRP-LR item 3.4.1-59 recommends that there is no aging effect, 

aging mechanism, and that no AMP is recommended for this component group exposed to this 

environment; therefore, the staff finds the applicant’s determination acceptable.

3.4.2.1.2 Loss of Material Due to General, Pitting, Crevice, Galvanic, and 

Microbiologically-influenced Corrosion, Fouling That Leads to Corrosion

LRA Table 3.4.1, item 3.4.1-19 addresses steel and stainless steel heat exchanger components 

exposed to raw water, which are being managed for loss of material due to general, pitting, 

crevice, galvanic, and microbiologically-influenced corrosion and fouling that leads to corrosion. 

For the AMR items that cite generic note E, the LRA credits the Internal Surfaces in 

Miscellaneous Piping and Ducting Components and Periodic Surveillance and Preventive 

Maintenance Program to manage loss of material for carbon steel filter housings, flow elements, 

piping, pump casings, sight glasses, tanks, and valves, and cast iron valves. The GALL Report

recommends AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure that these aging 

effects are adequately managed. The GALL Report recommends using visual inspections to 

manage aging. The staff notes that these components are only associated with the CW system; 

therefore, it is not part of GALL Report AMP XI.M20 because the CW system is not within the 

scope of GL 89-13.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components and Periodic Surveillance and Preventive Maintenance Programs are documented 

in SER Sections 3.0.3.1.25 and 3.0.3.2.2, respectively. The staff notes that both programs 

propose to manage the aging of carbon steel and cast iron piping and components through the 

use of periodic visual inspections. In its review of components associated with item 3.4.1-19, for 

which the applicant cited generic note E, the staff finds the applicant’s proposal to manage 

aging using the above cited programs acceptable because the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program conducts periodic visual inspections 

and is the recommended AMP to manage the same aging effects for the same material for 

item 3.4.1-38, which would be appropriate since the CW system is not managed by 

GALL Report AMP XI.M20. The staff also notes that the Periodic Surveillance and Preventive 

Maintenance Program specifically states that the internal surfaces of a representative sample of 

piping and valve bodies in the CW system will be visually inspected as part of the program, 

which is capable of detecting loss of material due to various corrosion mechanisms.

The staff concludes that for LRA item 3.4.1-19, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.4.2.1.3 Loss of Material Due to Pitting, Crevice, and Microbiologically-influenced Corrosion; 

Fouling That Leads to Corrosion

LRA Table 3.4.1, item 3.4.1-20 addresses copper-alloy and stainless steel piping and piping 

components exposed to raw water, which will be managed for loss of material due to pitting, 
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crevice, and microbiologically-influenced corrosion and fouling that leads to corrosion. For the 

AMR items that cite generic note E, the LRA credits the Internal Surfaces in Miscellaneous 

Piping and Ducting program to manage loss of material for copper-alloy and stainless steel 

components exposed to raw water in piping components. The GALL Report recommends GALL 

Report AMP XI.M20, “Open-Cycle Cooling Water System,” to ensure these aging effects are 

adequately managed. The staff notes that these components are only associated with the CW

system, which is not part of GALL Report AMP XI.M20 because the CW system is not within the 

scope of GL 89-13.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff notes that this 

program proposes to manage the aging of copper-alloy and stainless steel piping and 

components through the use of periodic visual inspections. In its review of components 

associated with item 3.4.1-12, for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the above cited programs acceptable because the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program conducts periodic 

visual inspections capable of detecting loss of material due to various corrosion mechanisms, 

and because the CW system is not managed by GALL Report AMP XI.M20, since it is not within 

the scope of GL 89-13.

The staff concludes that for LRA item 3.4.1-20, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.4.2.1.4 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.4.1, item 3.4.1-40 addresses steel piping, piping components, and piping elements 

exposed to lubricating oil that will be managed for loss of material due to general, pitting, and 

crevice corrosion. For the AMR items that cite generic note E, the LRA credits the Internal 

Surfaces in Miscellaneous Piping and Ducting Components Program to manage the aging effect 

carbon steel fan housing exposed to lubricating oil. The GALL Report recommends 

GALL Report AMP XI.M39, “Lubricating Oil Analysis,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.M39 recommends performing periodic sampling 

and testing of lubricating oil for moisture and corrosion particles in accordance with industry 

standards to manage aging.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program is documented in SER Section 3.0.3.1.25. The staff noted that the 

Internal Surfaces in Miscellaneous Piping and Ducting Components Program proposes to 

manage the aging of carbon steel filters, filter housing, and fan housing through the use of 

visual inspections. In its review of components associated with items 3.3.1-97 and 3.4.1-40 for 

which the applicant cited generic note E, the staff finds the applicant’s proposal to manage 

aging using the Internal Surfaces in Miscellaneous Piping and Ducting Components Program 

acceptable because visual inspections will ensure that existing environmental conditions are not 

causing material degradation that could result in a loss of component intended functions.

The staff concludes that for LRA item 3.4.1-40, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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3.4.2.1.5 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.4.1, item 3.4.1-30 addresses steel, stainless steel, and aluminum tanks exposed to 

soil, concrete, or air – outdoor (external) which will be managed for loss of material due to 

general, pitting, and crevice corrosion. As amended by letter dated May 13, 2014, for the AMR 

items that cite generic note E, the LRA credits the Fire Water System Program to manage the 

aging effect for the fire water tank. The GALL Report recommends GALL Report AMP XI.M29, 

“Aboveground Metallic Tanks,” to ensure that these aging effects are adequately managed. 

GALL Report AMP XI.M29 recommends using periodic visual examinations to manage aging.

Subsequent to the submittal of the LRA, the staff issued LR-ISG-2012-02, which revised several 

AMPs, including the guidance for AMP XI.M27, “Fire Water System.” The revised AMP XI.M27 

recommends that aging effects associated with fire water tanks be managed by AMP XI.M27 in 

lieu of AMP XI.M29. The staff’s evaluation of the applicant’s Fire Water System Program is 

documented in SER Section 3.0.3.1.20. In its review of components associated with 

item 3.4.1-30 for which the applicant cited generic note E, the staff finds the applicant’s proposal 

to manage aging using the Fire Water System Program acceptable, because it is consistent with 

LR-ISG-2012-02.

The staff concludes that, for LRA item 3.4.1-30, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.4.2.1.6 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.4.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes 

that the AMR results, which the applicant claimed to be consistent with the GALL Report, 

are consistent.

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).

3.4.2.2 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

• cracking due to SCC
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• loss of material due to pitting and crevice 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, which is associated with LRA Table 3.4.1 item 3.4.1-1, addresses steel 

piping, piping components, and piping elements exposed to steam or treated water in the steam 

and power conversion system and are being managed for cumulative fatigue damage. The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that fatigue is a 

TLAA, as defined in 10 CFR 54.3, and is required to be evaluated in accordance with 

10 CFR 54.21(c). The applicant stated that the TLAA identified for the steam and power 

conversion systems is addressed separately in LRA Section 4.3.

The staff reviewed LRA Section 3.4.2.2.1 against the criteria in SRP-LR Section 3.4.2.2.1, which 

states that fatigue of steam and power conversion system components is a TLAA as defined in 

10 CFR 54.3, and that these TLAAs are to be evaluated in accordance with 10 CFR 54.21(c)(1) 

and SRP-LR Section 4.3. The staff also reviewed the AMR items associated with LRA 

Section 3.4.2.2.1, and found that the AMR results are consistent with the GALL Report and 

SRP-LR, except as identified below.

The staff identified that the applicant did not include the applicable AMR items in LRA

Tables 3.4 for the TLAAs associated with fatigue of non-Class 1. The staff noted that LRA 

Section 4.3.2 discusses the TLAAs associated with fatigue of non-Class 1 piping and states that 

these TLAAs will remain valid for the period of extended operation in accordance with 

10 CFR 54.21(c)(1)(i). Therefore, as part of the RAI 3.2.2-1, the staff requested the applicant to 

justify this discrepancy. The details of RAI 3.2.2-1 and the staff’s evaluation of the applicant’s 

response are documented in SER Section 3.2.2.2.1.

Based on its review, the staff concludes that the applicant has met the SRP-LR 

Section 3.4.2.2.1 criteria. For those items that apply to LRA Section 3.4.2.2.1, the staff 

determined that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that it will adequately manage the effects of aging 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). SER Section 4.3 documents the staff’s review of the applicant’s 

evaluation of the TLAA for these components.

3.4.2.2.2 Cracking Due to Stress Corrosion Cracking

LRA Section 3.4.2.2.2, which is associated with LRA Table 3.4.1 item 3.4.1-2, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to air-outdoor 

that will be managed for cracking due to SCC by the Aboveground Metallic Tanks or External 

Surfaces Monitoring Program. The criteria in SRP-LR Section 3.4.2.2.2 states that cracking due 

to SCC could occur for stainless steel piping, piping components, piping elements, and tanks 

exposed to outdoor air and that the possibility of cracking extends to components exposed to air 
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that has been recently introduced into the building, such as components near intake vents. The 

SRP-LR also states that GALL Report AMP XI.M36, “External Surfaces Monitoring,” is an 

acceptable method to manage the aging effect.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that cracking of 

stainless steel components directly exposed to outdoor air is managed by the External Surfaces 

Monitoring Program and there are no stainless steel components in the steam and power 

conversion systems within the scope of license renewal that are located next to unducted air 

intakes. The applicant also stated that the stainless steel CST exposed to air-outdoor that will 

be managed for cracking due to SCC by the Aboveground Metallic Tanks Program to be 

consistent with LR-ISG2012-02.

The staff’s reviews of the applicant’s Aboveground Metallic Tanks and External Surfaces 

Monitoring Programs are documented in SER Section 3.0.3.1.1 and 3.0.3.1.17, respectively. In 

its review of components associated with item 3.4.1-2, the staff finds that the applicant has met 

the further evaluation criteria as described below.

• The applicant’s proposal to manage cracking using the External Surfaces Monitoring 

Program is acceptable because the program includes visual inspections of metallic 

components that are capable of detecting cracking prior to loss of component intended 

function, consistent with the SRP-LR recommendations.

• The applicant’s proposal to manage cracking of the stainless steel CST using the 

Aboveground Metallic Tanks Program is acceptable because in addition to performing 

the periodic visual inspections recommended in GALL Report AMP XI.M36, the program 

also uses thickness measurements and preventive measures to manage aging.

The staff determines that the applicant’s program meets SRP-LR Section 3.4.2.2.2 criterion.

For those AMR items associated with LRA Section 3.4.2.2.2, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended 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 Pitting and Crevice Corrosion

LRA Section 3.4.2.2.3, which is associated with LRA Table 3.4.1 item 3.4.1-3, addresses 

stainless steel piping, piping components, piping elements, and tanks exposed to air-outdoor 

that will be managed for loss of material due to pitting and crevice corrosion by the External 

Surface Monitoring Program. The criteria in SRP-LR Section 3.4.2.2.3 states that loss of 

material due to pitting and crevice corrosion could occur for stainless steel piping, piping 

components, piping elements, and tanks exposed to outdoor air and that possibility of loss of 

material due to pitting and crevice corrosion extends to components exposed to air that has 

been recently introduced into the building, such as components near intake vents. The SRP-LR 

also states that GALL Report AMP XI.M36, “External Surfaces Monitoring,” is an acceptable 

method to manage the aging effect. The applicant addressed the further evaluation criteria of 

the SRP-LR by stating that loss of material from stainless steel components directly exposed to 

outdoor air is managed by the External Surfaces Monitoring Program and there are no stainless 

steel components in the steam and power conversion systems within the scope of license 

renewal that are located next to unducted air intakes.

The staff’s review of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.1.17. In its review of components associated with item 3.4.1-3, the staff finds 
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that the applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

loss of material using the External Surfaces Monitoring Program is acceptable because the 

program includes visual inspections of metallic components that are capable of detecting loss of 

material prior to loss of component intended function, consistent with the SRP-LR 

recommendations.

The staff determines that the applicant’s program meets SRP-LR Section 3.4.2.2.3 criterion. 

For those AMR items associated with LRA Section 3.4.2.2.3, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended 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 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.

3.4.2.2.5 Loss of Material Due to Recurring Internal Corrosion

By letter dated May 5, 2014, the applicant addressed recurring internal corrosion that is 

described in Section A and Appendix B of LR-ISG-2012-02, “Aging Management of Internal 

Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion under Insulation.” 

LR-ISG-2012-02 includes a new section (Section 3.4.2.2.6, Loss of Material Due to Recurring 

Internal Corrosion) in the SRP-LR for “AMR Results for Which Further Evaluation Is 

Recommended by the GALL Report.”

Based on its review of plant-specific operating experience for the past 5 years, the applicant 

stated that microbiologically-influenced corrosion of piping components is a recurring internal 

corrosion issue as defined in LR-ISG-2012-02, Section A. The applicant further stated that it 

monitors loss of material in piping components due to microbiologically-influenced corrosion in 

the CW system, which is part of the Steam and Power Conversion section of the LRA. The 

staff’s evaluation of the applicant’s activities to manage recurring internal corrosion in all of the 

plant systems is documented in SER Section 3.3.2.2.7.

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

In LRA Tables 3.4.2-1 through 3.4.2-2, 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 3.4.2-2, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.
3-409

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.4.2.3.1 Condensate and Refueling Water Storage and Transfer – 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 

condensate and refueling water storage and transfer component groups. The staff’s review did 

not identify any items with notes F through J, indicating that the combinations of component 

type, material, environment, and AERM for this system are consistent with the GALL Report.

3.4.2.3.2 Miscellaneous Steam and Power Conversion Systems in Scope for 

10 CFR 54.4(a)(2) - Summary of Aging Management Review – LRA Table 3.4.2-2

The staff reviewed the 19 LRA tables associated with Table 3.4.2-2, which summarizes the 

results of AMR evaluations for the miscellaneous steam and power conversion systems in 

scope for 10 CFR 54.4(a)(2) component groups.

For LRA Table 3.4.2-2-2

Stainless Steel Thermowell Exposed to Steam. In LRA Table 3.4.2-2-2, the applicant stated 

there is a TLAA for stainless steel thermowell exposed to steam (internal), which cite generic 

note H. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for 

these components and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components is documented in SER Section 4.3.2.

For LRA Tables 3.4.2-2-3 and 3.4.2-2-4

Stainless Steel Expansion Joint Exposed to Steam. In LRA Table 3.4.2-2-3, the applicant 

stated there is a TLAA for stainless steel expansion joint exposed to steam (internal), which cite 

generic note G. The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, 

for these components and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components is documented in SER Section 4.3.2.

Metallic Tanks with Service Level III or Other Internal Coatings Exposed to Treated Water. As 

amended by letter dated May 13, 2014, in LRA Tables 3.4.2-2-3 and 3.4.2-2-4 the applicant 

stated that metallic tanks with Service Level III or other internal coatings exposed to treated 

water will be managed for loss of coating integrity by the Periodic Surveillance and Preventive 

Maintenance Program. The new AMR items cite generic note H, indicating that this aging effect 

for the component, material, and environment combination is not included in the GALL Report.

Based on its reviews of LRAs and industry operating experience, the staff identified an issue 

concerning loss of coating integrity of internal coatings of piping, piping components, heat 

exchangers, and tanks. As a result, the staff issued RAI 3.0.3-2 on January 2, 2014, requesting

that the applicant address loss of coating integrity for Service Level III and other coatings. In its 

response dated May 13, 2014, the applicant stated that it had identified components where 

coating degradation has the potential to adversely affect the passive functions of downstream 

components, which is an aging effect not addressed in the GALL Report.
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The staff’s evaluation of the applicant’s use of the Periodic Surveillance and Preventive 

Maintenance Program to manage loss of coating integrity is documented in SER 

Section 3.0.3.3. The staff noted that the applicant will make a number of enhancements to the 

programs to address loss of coating integrity, including internal visual inspections of the coated 

components. The staff finds the applicant’s proposal to manage loss of coating integrity using 

the above program acceptable, because the Periodic Surveillance and Preventive Maintenance 

Program will include periodic visual inspections conducted by appropriately certified individuals, 

with specified acceptance criteria, and evaluations of inspection findings will be conducted by an 

appropriately qualified nuclear coatings subject matter expert, which will ensure that 

degradation of coating integrity is detected before causing a loss of intended function.

For LRA Tables 3.4.2-2-4, 3.4.2-2-6, and 3.4.2-2-11

Carbon Steel Piping Components Exposed to Treated Water. By letter dated 

December 18, 2012, the applicant revised LRA Tables 3.4.2-2-4, 3.4.2-2-6, and 3.4.2-2-11, and 

stated that carbon steel piping components exposed to treated water will be managed for loss of 

material by the Flow-Accelerated Corrosion Program. The AMR items cite generic note H and 

also cite plant-specific note 403 which states that the Flow-Accelerated Corrosion Program also 

manages loss of material due to erosion mechanisms other than flow-accelerated corrosion.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel piping components exposed to treated water are susceptible to 

loss of material due to general, pitting, crevice, and flow-accelerated corrosion and recommends 

GALL Report AMP XI.M2, AMP XI.M32, and AMP XI.M17 to manage the aging effect due to 

these mechanisms. However the applicant has identified additional aging mechanisms. The 

applicant addressed the GALL Report identified aging effects for this component, material and 

environment combination in other AMR items in LRA Tables 3.4.2-2-4, 3.4.2-2-6, and 

3.4.2-2-11.

The staff’s evaluation of the applicant’s Flow-Accelerated Corrosion Program is documented in 

SER Section 3.0.3.1.21. The staff finds the applicant’s proposal to manage loss of material due 

to erosion mechanisms other than flow-accelerated corrosion using the Flow-Accelerated 

Corrosion Program acceptable, because the associated components can be treated similar to 

“susceptible-not-modeled” components currently within the program, which ensures that the 

consequent wall thinning will be detected before loss of intended function.

For LRA Table 3.4.2-2-5

Insulated Carbon Steel Piping and Piping Components Exposed to External Condensation. As 

modified by letter dated May 13, 2014, LRA Table 3.4.2-2-5 states that insulated carbon steel 

piping and piping components exposed to external condensation will be managed for loss of 

material by the External Surfaces Monitoring Program. The AMR item cites generic note H and 

includes a plant-specific note stating that the program provisions apply for indoor insulated 

components operating below the dew point.

The staff noted that this material and environment combination is not identified for insulated 

piping components in the GALL Report. Corrosion under insulation is addressed in 

LR-ISG-2012-02, Section E, and the applicant addressed this aspect in its response dated 

May 13, 2014, to the staff’s RAI 3.0.3-1. The staff noted that the applicant appropriately 

addressed the aging effects identified in the GALL Report for noninsulated components for this 

material and environment combination in other AMR items in LRA Table 3.4.2-2-5.
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The staff’s evaluation of the applicant’s External Surfaces Monitoring Program is documented in 

SER Section 3.0.3.1.17. The staff finds the applicant’s proposal to use this program to manage 

loss of material for insulated carbon steel components exposed to an external condensation 

environment acceptable, because it is consistent with the staff recommendations for managing 

this material and environment combination that may be subject to a “corrosion under insulation” 

aging mechanism, as established in Section E(iii)(b) of LR-ISG-2012-02.

For LRA Table 3.4.2-2-7

Stainless Steel Components Exposed to Steam. In LRA Table 3.4.2-2-7, the applicant stated 

there are TLAAs for stainless steel orifice, thermowell, tubing, and valve body exposed to steam 

(internal), which cite generic note G. The staff confirmed that there is a TLAA, as documented 

in LRA Section 4.3.2, for these components and material. The staff’s evaluation of the fatigue 

TLAA for non-Class 1 components is documented in SER Section 4.3.2.

For LRA Table 3.4.2-2-9

Carbon Steel Separator Components Exposed to Treated Water. By letter dated 

December 20, 2013, the applicant revised LRA Table 3.4.2-2-9 and stated that carbon steel 

separator components exposed to treated water will be managed for loss of material due to 

erosion by the Periodic Surveillance and Preventive Maintenance Program. The AMR item cites 

generic note H and also cites plant-specific note 403, which states that the aging effect used for 

this item refers to loss of material due to erosion.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel components exposed to treated water are susceptible to loss of 

material due to general, pitting, and crevice corrosion and wall thinning. The GALL Report 

recommends the Water Chemistry and Flow-Accelerated Corrosion Programs. However, the 

applicant has identified an additional aging mechanism. The applicant addressed the GALL 

Report identified aging effects for this component, material, and environment combination in 

other AMR items in LRA Table 3.4.2-2-9.

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff finds the applicant’s proposal to

use the above program to manage loss of material due to erosion acceptable because, as part 

of its letter dated December 20, 2013, the applicant added specific activities to the Periodic 

Surveillance and Preventive Maintenance Program to perform visual or other NDE inspections 

that are capable of managing this mechanism.

For LRA Table 3.4.2-2-10

Stainless Steel Components and Piping Exposed to Steam. In LRA Table 3.4.2-2-10, the 

applicant stated there are TLAAs for stainless steel orifice, thermowell, tubing, and piping 

exposed to steam (internal), which cite generic note G. The staff confirmed that there is a 

TLAA, as documented in LRA Section 4.3.2, for these components and material. The staff’s 

evaluation of the fatigue TLAA for non-Class 1 components is documented in SER 

Section 4.3.2.

Nickel Alloy Expansion Joint Exposed to Steam. In LRA Table 3.4.2-2-10, the applicant stated 

that nickel alloy expansion joints exposed to steam will be managed for cracking and loss of 

material by the Water Chemistry Control – BWR Program. The AMR items cite generic note G.
3-412

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff also noted that the Metals Handbook, Desk 

Edition, Second Edition (ASM International, 1998) states that nickel and nickel-base alloys 

generally have very good corrosion resistance in distilled and fresh waters, and the ASM 

Handbook, Volume 13B, “Corrosion of Nickel and Nickel-Based Alloys” chapter (ASM 

International, 2005) states that nickel alloys are subject to SCC only in specific environments, 

such as hot caustic, fluoride, and chloride-containing water environments. Based on this 

review, the staff finds that the applicant has identified all credible aging effects for this 

component, material, and environment combination.

The staff’s evaluation of the applicant’s Water Chemistry Control – BWR Program is 

documented in SER Section 3.0.3.1.41. The staff finds the applicant’s proposal to manage 

aging using this program acceptable because the Water Chemistry Control – BWR Program

controls contaminants in the condensate system at levels to minimize loss of material 

and cracking.

In LRA Table 3.4.2-2-10, the applicant stated there is a TLAA for nickel alloy expansion joints 

exposed to steam (int), which cite generic note G. The staff confirmed that there is a TLAA, as 

documented in LRA Section 4.3.2.2, for this component and material. The staff’s evaluation of 

the fatigue TLAA for non-Class 1 components is documented in SER Section 4.3.2.2.2.

For LRA Table 3.4.2-2-14

Plastic Tanks Exposed to Treated Water and Indoor Air. By letter dated May 13, 2014, the 

applicant amended LRA Table 3.4.2-2-14 to include plastic tanks exposed to treated water or 

indoor air to be managed for changes in material properties by the Internal Surfaces in 

Miscellaneous Piping and Ducting Components Program or External Surfaces Monitoring 

Program, respectively. These AMR items cite generic note F.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. The staff noted that the applicant addressed plastic 

components exposed to raw water (internal) and condensation (external) in other AMR items in 

LRA Table 3.3.2-19-19. The plastic sight glass in LRA Table 3.3.2-19-19 will be managed for a 

change in material properties by the Internal Surfaces in Miscellaneous Piping and Ducting 

Components and External Surfaces Monitoring Programs. The staff reviewed the AMPs 

associated with these items and found them acceptable, as discussed in SER 

Section 3.3.2.3.19. Based on SER Section 3.3.2.3.19 and the staff’s review of RIS 2012-02, the 

staff finds that the applicant has identified all credible aging effects for this component, material, 

and environment combination.

The staff’s evaluation of the applicant’s Internal Surfaces in Miscellaneous Piping and Ducting 

Components and External Surfaces Monitoring Programs are documented in SER 

Sections 3.0.3.1.25 and 3.0.3.1.17, respectively. The staff finds the applicant’s proposal to 

manage aging using the Internal Surfaces in Miscellaneous Piping and Ducting Components 

and External Surfaces Monitoring Programs acceptable because the programs include periodic 

visual inspections that are capable of detecting a change in material properties (e.g., change in 

clarity, cracking, crazing) prior to a loss of component intended function.
3-413

For LRA Table 3.4.2-2-17

Stainless Steel Valves Exposed to Steam. In LRA Table 3.4.2-2-17, the applicant stated there 

is a TLAA for stainless steel valve body exposed to steam (internal), which cite generic note G. 

The staff confirmed that there is a TLAA, as documented in LRA Section 4.3.2, for these 

components and material. The staff’s evaluation of the fatigue TLAA for non-Class 1 

components is documented in SER Section 4.3.2.

For LRA Table 3.4.2-2-18

Carbon Steel Piping Components Exposed to Raw Water. As modified by letter dated 

May 13, 2014, LRA Table 3.4.2-2-18 states that carbon steel piping components exposed to raw 

water will be managed for recurring internal corrosion by the Periodic Surveillance and 

Preventive Maintenance Program. The AMR items cite generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

which states that carbon steel piping components exposed to raw water are susceptible to loss 

of material and, depending on the system, recommends several different AMPs for managing 

aging. However, the applicant has identified recurring internal corrosion as an additional aging 

effect requiring management, as described in LR-ISG-2012-02. The applicant addressed the 

aging effects identified in the GALL Report for this component, material, and environment 

combination in other AMR items in LRA Table 3.4.2-2-18.

The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff finds the applicant’s proposal to 

use this program to manage recurring internal corrosion acceptable, as documented in SER 

Section 3.3.2.2.7.

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).

3.4.3 Conclusion

The staff concludes that the applicant has provided sufficient information to demonstrate that 

the effects of aging for the steam and power conversion system components within the scope of 

license renewal and subject to an AMR will be adequately managed so that the intended 

functions will remain 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:

• containment building

• water control structures

• turbine building, process facilities, and yard structures

• bulk commodities
3-414

3.5.1 Summary of Technical Information in the Application

LRA Section 3.5 provides AMR results for the structures and component supports components 

and component groups. LRA Table 3.5.1, “Summary of Aging Management Programs for 

Structures and Component Supports Evaluated in Chapters II and III of NUREG-1801,” is a 

summary comparison of the applicant’s AMRs with those evaluated in the GALL Report for the 

structures and component supports components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the issuance of the GALL Report.

3.5.2 Staff Evaluation

The staff reviewed LRA Section 3.5 to determine whether the applicant provided sufficient 

information to demonstrate that the effects of aging for the 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 AMRs to ensure the applicant’s claim that certain AMRs are 

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.

During its review, 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 

are 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 items and the plant’s operating experience to verify the applicant’s 

claims.

Table 3.5-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.5 and addressed in the GALL Report.
3-415

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

GALL Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

BWR Concrete and Steel (Mark I, II, and III) Containments

Concrete: dome; 

wall; basemat; ring 

girders; buttresses, 

concrete elements, 

all (3.5.1-1)

Cracking and 

distortion due 

to increased 

stress levels 

from 

settlement

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL” or 

Chapter XI.S6, 

“Structure 

Monitoring” 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, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete: 

foundation; 

subfoundation 

(3.5.1-2)

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” If a 

de-watering system 

is relied upon for 

control of erosion, 

then the licensee is 

to ensure proper 

functioning of the 

de-watering system 

through the period of 

extended operation.

Yes, if a 

de-watering 

system is 

relied upon to 

control 

settlement 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete: dome; 

wall; basemat; ring 

girders; buttresses; 

concrete: 

containment; wall; 

basemat; concrete: 

basemat, concrete 

fill-in annulus 

(3.5.1-3)

Reduction of 

strength and

modulus due to 

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific AMP

is to be evaluated.

Yes, if 

temperature 

limits are 

exceeded 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Steel elements 

(inaccessible 

areas): drywell 

shell; drywell head; 

and drywell shell 

(3.5.1-4)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)
3-416

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements 

(inaccessible 

areas): liner; liner 

anchors; integral 

attachments; steel 

elements 

(inaccessible 

areas): suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable) 

(3.5.1-5)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

indicated from 

the IWE 

examinations 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Steel elements: 

torus shell (3.5.1-6)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

Yes, if 

corrosion is 

significant. 

Recoating of 

the torus is 

recommende

d. 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Steel elements: 

torus ring girders; 

downcomers; steel 

elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-7)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

Yes, if 

corrosion is 

significant 

Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Pre-stressing 

system: tendons 

(3.5.1-8)

Loss of 

prestress due 

to relaxation; 

shrinkage; 

creep; elevated 

temperature

Yes, TLAA Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Penetration 

sleeves; 

penetration bellows 

steel elements: 

torus; vent line; 

vent header; vent 

line bellows; 

downcomers, 

suppression pool 

shell; unbraced 

downcomers, steel 

elements: vent 

header; 

downcomers 

(3.5.1-9)

Cumulative 

fatigue 

damage due to 

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.5.2.2.1)
3-417

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Penetration 

sleeves; 

penetration bellows 

(3.5.1-10)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): dome; wall; 

basemat (3.5.1-11)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

needed for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557). 

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): 

containment; wall; 

basemat, concrete 

(inaccessible 

areas): basemat, 

concrete fill-in 

annulus (3.5.1-12)

Cracking due 

to expansion 

from reaction 

with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed. 

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible 

areas): basemat, 

concrete 

(inaccessible 

areas): dome; wall; 

basemat (3.5.1-13)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed. 

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): 

containment; wall; 

basemat (3.5.1-14)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed. 

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.1)
3-418

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(accessible areas): 

basemat (3.5.1-15)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

basemat, concrete: 

containment; wall; 

basemat (3.5.1-16)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) due to 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses 

(3.5.1-17)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) due to 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

basemat (3.5.1-18)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

basemat, concrete 

(accessible areas): 

containment; wall; 

basemat, concrete 

(accessible areas): 

basemat, concrete 

fill-in annulus 

(3.5.1-19)

Cracking due 

to expansion 

from reaction 

with 

aggregates

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-419

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(accessible areas): 

containment; wall; 

basemat (3.5.1-20)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(accessible areas): 

dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel, 

concrete 

(accessible areas): 

basemat; 

reinforcing steel, 

concrete 

(accessible areas): 

dome; wall; 

basemat; 

reinforcing steel 

(3.5.1-21)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(inaccessible 

areas): basemat; 

reinforcing steel 

(3.5.1-22)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Concrete 

(inaccessible 

areas): basemat; 

reinforcing steel, 

concrete 

(inaccessible 

areas): dome; wall; 

basemat; 

reinforcing steel 

(3.5.1-23)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Containment

Inservice 

Inspection –

IWL

Consistent with the 

GALL Report

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses, 

concrete 

(inaccessible 

areas): basemat, 

concrete 

(accessible areas): 

dome; wall; 

basemat (3.5.1-24)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) due to 

aggressive 

chemical 

attack

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
3-420

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete 

(inaccessible 

areas): dome; wall; 

basemat; ring 

girders; buttresses; 

reinforcing steel 

(3.5.1-25)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL,” or 

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.5.2.1.1)

Moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-26)

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other 

defects

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Containment 

Inservice 

Inspection –

IWE, 

Containment 

Leak Rate, 

Structures 

Monitoring, and 

Periodic 

Surveillance 

and Preventive 

Maintenance

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.2)

Penetration 

sleeves; 

penetration 

bellows, steel 

elements: torus; 

vent line; vent 

header; vent line 

bellows; 

downcomers, 

suppression pool 

shell (3.5.1-27)

Cracking due 

to cyclic 

loading (CLB 

fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Personnel airlock, 

equipment hatch, 

CRD hatch 

(3.5.1-28)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Containment 

Inservice 

Inspection –

IWE and 

Containment 

Leak Rate

Consistent with the 

GALL Report

Personnel airlock, 

equipment hatch, 

CRD hatch: locks, 

hinges, and closure 

mechanisms 

(3.5.1-29)

Loss of leak 

tightness due 

to mechanical 

wear of locks, 

hinges and 

closure 

mechanisms

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Pressure-retaining 

bolting (3.5.1-30)

Loss of preload 

due to 

self-loosening

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Pressure-retaining 

bolting, steel 

elements: 

downcomer pipes 

(3.5.1-31)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.3)
3-421

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Prestressing 

system: tendons; 

anchorage 

components 

(3.5.1-32)

Loss of 

material due to 

corrosion

Chapter XI.S2, 

“ASME Section XI, 

Subsection IWL”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Seals and gaskets 

(3.5.1-33)

Loss of sealing 

due to wear, 

damage, 

erosion, tear, 

surface cracks, 

or other 

defects

Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J “

No Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.4)

Service Level I 

coatings (3.5.1-34)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, 

peeling, or 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance

Consistent with the 

GALL Report

Steel elements 

(accessible areas): 

liner; liner anchors; 

integral 

attachments, 

penetration 

sleeves, steel 

elements 

(accessible areas): 

drywell shell; 

drywell head; 

drywell shell in 

sand pocket 

regions; steel 

elements 

(accessible areas): 

suppression 

chamber; drywell; 

drywell head; 

embedded shell; 

region shielded by 

diaphragm floor (as 

applicable), steel 

elements 

(accessible areas): 

drywell shell; 

drywell head 

(3.5.1-35)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Containment 

Inservice 

Inspection –

IWE and 

Containment 

Leak Rate

Consistent with the 

GALL Report

Steel elements: 

drywell head; 

downcomers 

(3.5.1-36)

Fretting or 

lockup due to 

mechanical 

wear

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-422

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel elements: 

suppression 

chamber (torus) 

liner (interior 

surface) (3.5.1-37)

Loss of 

material due to 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Containment 

Inservice 

Inspection –

IWE and 

Containment 

Leak Rate

Consistent with the 

GALL Report

Steel elements: 

suppression 

chamber shell 

(interior surface) 

(3.5.1-38)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Steel elements: 

vent line bellows 

(3.5.1-39)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE,”

and Chapter XI.S4, 

“10 CFR Part 50, 

Appendix J”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Unbraced 

downcomers, steel 

elements: vent 

header; 

downcomers 

(3.5.1-40)

Cracking due 

to cyclic 

loading (CLB 

fatigue 

analysis does 

not exist)

Chapter XI.S1, 

“ASME Section XI, 

Subsection IWE”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Steel elements: 

drywell support 

skirt, steel elements 

(inaccessible 

areas): support skirt 

(3.5.1-41)

None None NA - No AEM 

or AMP

Not applicable Consistent with the 

GALL Report

Safety-Related and Other Structures; and Component Supports

Groups 1-3, 5, 7-9:

concrete 

(inaccessible 

areas): foundation 

(3.5.1-42)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

All groups except 

Group 6: concrete 

(inaccessible 

areas): all 

(3.5.1-43)

Cracking due 

to expansion 

from reaction 

with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed.

Yes Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.2.2)
3-423

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

All groups: 

concrete: all 

(3.5.1-44)

Cracking and 

distortion due 

to increased 

stress levels 

from 

settlement

Chapter XI.S6, 

“Structures 

Monitoring” 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 to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-45)

Reduction in 

foundation 

strength, 

cracking due to 

differential 

settlement, 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” 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 to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 1-3, 5-9: 

concrete: 

foundation; 

subfoundation 

(3.5.1-46)

Reduction of 

foundation 

strength and 

cracking due to 

differential 

settlement and 

erosion of 

porous 

concrete 

subfoundation

Chapter XI.S6, 

“Structures 

Monitoring” 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 See SER 

Section 3.5.2.2.2

Groups 1-5, 7-9: 

concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation 

(3.5.1-47)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed.

Yes, Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 1-5: 

concrete: all 

(3.5.1-48)

Reduction of 

strength and 

modulus due to 

elevated 

temperature 

(>150 °F 

general; 

>200 °F local)

A plant-specific AMP

is to be evaluated.

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)
3-424

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 6 - concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-49)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Further evaluation is 

required for plants 

that are located in 

moderate to severe 

weathering 

conditions 

(weathering index 

>100 day-inch/yr) 

(NUREG-1557)

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 6: concrete 

(inaccessible

areas): all 

(3.5.1-50)

Cracking due 

to expansion 

from reaction 

with 

aggregates

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed.

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 6: concrete 

(inaccessible 

areas): exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-51)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Further evaluation is 

required to 

determine if a 

plant-specific AMP is 

needed.

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

Groups 7, 8 - steel 

components: tank 

liner (3.5.1-52)

Cracking due 

to stress 

corrosion 

cracking; Loss 

of material due 

to pitting and 

crevice 

corrosion

A plant-specific AMP

is to be evaluated.

Yes Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.6)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-53)

Cumulative 

fatigue 

damage due to 

fatigue (Only if 

CLB fatigue 

analysis exists)

Yes, TLAA Yes, Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

All groups except 6: 

concrete 

(accessible areas): 

all (3.5.1-54)

Cracking due 

to expansion 

from reaction 

with 

aggregates

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.2.2)

Building concrete at 

locations of 

expansion and 

grouted anchors; 

grout pads for 

support base plates 

(3.5.1-55)

Reduction in 

concrete 

anchor 

capacity due to 

local concrete 

degradation/ 

service-induce

d cracking or 

other concrete 

aging 

mechanisms

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-425

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Concrete: exterior 

above- and 

below-grade; 

foundation; interior 

slab (3.5.1-56)

Loss of 

material due to 

abrasion; 

cavitation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

Federal Energy 

Regulatory 

Commission 

(FERC)/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants and 

Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.7)

Constant and 

variable load spring 

hangers; guides; 

stops (3.5.1-57)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, 

fatigue due to 

vibratory and 

cyclic thermal 

loads

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Earthen 

water-control 

structures: dams; 

embankments; 

reservoirs; 

channels; canals 

and ponds 

(3.5.1-58)

Loss of 

material; loss 

of form due to 

erosion, 

settlement, 

sedimentation, 

frost action, 

waves, 

currents, 

surface runoff, 

seepage

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: concrete 

(accessible areas): 

all (3.5.1-59)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report
3-426

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-60)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Group 6: concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation; interior 

slab (3.5.1-61)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

Group 6: wooden 

piles; sheeting 

(3.5.1-62)

Loss of 

material; 

change in 

material 

properties due 

to weathering, 

chemical 

degradation, 

and insect 

infestation 

repeated 

wetting and 

drying, fungal 

decay

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.8)

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-63)

Increase in 

porosity and 

permeability; 

loss of strength 

due to leaching 

of calcium 

hydroxide and 

carbonation

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

exterior above- and 

below-grade; 

foundation 

(3.5.1-64)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-427

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Groups 1-3, 5, 7-9: 

concrete 

(inaccessible 

areas): 

below-grade 

exterior; foundation, 

Groups 1-3, 5, 7-9: 

concrete 

(accessible areas): 

below-grade 

exterior; foundation, 

Groups 6: concrete 

(inaccessible 

areas): all 

(3.5.1-65)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-5, 7, 9: 

concrete 

(accessible areas): 

interior and 

above-grade 

exterior (3.5.1-66)

Cracking; loss 

of bond; and 

loss of material 

(spalling, 

scaling) due to 

corrosion of 

embedded 

steel

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Groups 1-5, 7, 9: 

Concrete: interior; 

above-grade 

exterior, Groups 

1-3, 5, 

7-9 - concrete 

(inaccessible 

areas): 

below-grade 

exterior; foundation, 

Group 6: concrete 

(inaccessible 

areas): all 

(3.5.1-67)

Increase in 

porosity and 

permeability; 

cracking; loss 

of material 

(spalling, 

scaling) due to 

aggressive 

chemical 

attack

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

High-strength 

structural bolting 

(3.5.1-68)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

High-strength 

structural bolting 

(3.5.1-69)

Cracking due 

to stress 

corrosion 

cracking

Chapter XI.S6, 

“Structures 

Monitoring” Note: 

ASTM A 325, F 

1852, and ASTM A 

490 bolts used in 

civil structures have 

not shown to be 

prone to SCC. SCC 

potential need not be 

evaluated for these 

bolts.

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-428

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Masonry walls: all 

(3.5.1-70)

Cracking due 

to restraint 

shrinkage, 

creep, and 

aggressive 

environment

Chapter XI.S5, 

“Masonry Walls”

No Masonry Walls

and Fire 

Protection

Consistent with the 

GALL Report

Masonry walls: all 

(3.5.1-71)

Loss of 

material 

(spalling, 

scaling) and 

cracking due to 

freeze-thaw

Chapter XI.S5, 

“Masonry Walls”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Seals; gasket; 

moisture barriers 

(caulking, flashing, 

and other sealants) 

(3.5.1-72)

Loss of sealing 

due to 

deterioration of 

seals, gaskets, 

and moisture 

barriers 

(caulking, 

flashing, and 

other sealants)

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Service Level I 

coatings (3.5.1-73)

Loss of coating 

integrity due to 

blistering, 

cracking, 

flaking, 

peeling, 

physical 

damage

Chapter XI.S8, 

“Protective Coating 

Monitoring and 

Maintenance”

No Protective 

Coating 

Monitoring and 

Maintenance

Consistent with the 

GALL Report

Sliding support 

bearings; sliding 

support surfaces 

(3.5.1-74)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Sliding surfaces 

(3.5.1-75)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

debris, 

overload, wear

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Sliding surfaces: 

radial beam seats 

in BWR drywell 

(3.5.1-76)

Loss of 

mechanical 

function due to 

corrosion, 

distortion, dirt, 

overload, wear

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)
3-429

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Steel components: 

all structural steel 

(3.5.1-77)

Loss of 

material due to 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring” 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.

No Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.9)

Steel components: 

fuel pool liner

(3.5.1-78)

Cracking due 

to stress 

corrosion 

cracking; Loss 

of material due 

to pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Monitoring of 

the spent fuel pool 

water level in 

accordance with TS

and leakage from 

the leak chase 

channels.

No, unless 

leakages 

have been 

detected 

through the 

SFP liner that 

cannot be 

accounted for 

from the leak 

chase 

channels

Water 

Chemistry

Control – BWR

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.10)

Steel components: 

piles (3.5.1-79)

Loss of 

material due to 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-80)

Loss of 

material due to 

general, pitting 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring 

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-81)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-82)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

Structural bolting 

(3.5.1-83)

Loss of 

material due to 

general, pitting, 

and crevice 

corrosion

Chapter XI.S7, 

“Regulatory Guide 

1.127, Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants” or the 

FERC/US Army 

Corp of Engineers 

dam inspections and 

maintenance 

programs.

No RG 1.127, 

Inspection of 

Water-Control 

Structures 

Associated with 

Nuclear Power 

Plants

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.3)
3-430

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Structural bolting 

(3.5.1-84)

Loss of 

material due to 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

and Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-85)

Loss of 

material due to 

pitting and 

crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-86)

Loss of 

material due to 

pitting and 

crevice 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-87)

Loss of preload 

due to 

self-loosening

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Structural bolting 

(3.5.1-88)

Loss of preload 

due to 

self-loosening

Chapter XI.S6, 

“Structures 

Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-89)

Loss of 

material due to 

boric acid 

corrosion

Chapter XI.M10, 

“Boric Acid 

Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.5.2.1.1)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-90)

Loss of 

material due to 

general (steel 

only), pitting, 

and crevice 

corrosion

Chapter XI.M2, 

“Water Chemistry,”

for BWR water, and 

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Water 

Chemistry 

Control – BWR 

and Inservice 

Inspection –

IWF

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-91)

Loss of 

material due to 

general and 

pitting 

corrosion

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Inservice 

Inspection –

IWF

Consistent with the 

GALL Report

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-92)

Loss of 

material due to 

general and 

pitting 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report

(see SER 

Section 3.5.2.1.11)

Support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

(3.5.1-93)

Loss of 

material due to 

pitting and 

crevice 

corrosion

Chapter XI.S6, 

“Structures 

Monitoring”

No Structures 

Monitoring

Consistent with the 

GALL Report
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Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluation in 

the GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Vibration isolation 

elements (3.5.1-94)

Reduction or 

loss of isolation 

function due to 

radiation 

hardening, 

temperature, 

humidity, 

sustained 

vibratory 

loading

Chapter XI.S3, 

“ASME Section XI, 

Subsection IWF”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.5.2.1.1)

Aluminum, 

galvanized steel 

and stainless steel 

support members; 

welds; bolted 

connections; 

support anchorage 

to building structure 

exposed to air –

indoor, uncontrolled 

(3.5.1-95)

None None NA - No AEM 

or AMP

Not applicable Consistent with the 

GALL Report

The staff’s review of the structures and component supports component groups followed any 

one of several approaches. One approach, documented in SER Section 3.5.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.5.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.5.2.3, reviewed AMR results for components that the applicant indicated are not 

consistent with, or not addressed in, the GALL Report. The staff’s review of AMPs credited to 

manage or monitor aging effects of the structures and component supports components is 

documented in SER Section 3.0.3.

3.5.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.5.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the structures and component supports components:

• Containment Inservice Inspection – IWE

• Containment Inservice Inspection – IWL

• Fire Protection

• Fire Water System

• Inservice Inspection – IWF

• Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling 

Systems

• Masonry Wall

• Periodic Surveillance and Preventive Maintenance
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• Protective Coating Monitoring and Maintenance

• RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants

• Structures Monitoring

• Water Chemistry Control – BWR

LRA Tables 3.5.2-1 through 3.5.2-4 summarize AMRs for the structures and component 

supports and indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate 

GALL Report AMRs. The staff’s evaluation follows.

3.5.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.5.1, for items 3.5.1-25, 3.5.1-32, and 3.5.1-76, the applicant stated that the 

corresponding AMR items in the GALL Report are not applicable because GGNS is a 

BWR/Mark III reactor design having a reinforced concrete primary containment with a reinforced 

concrete drywell and wet well lined with carbon steel, and the AMR items in the GALL Report 

are only applicable to particular components of PWR and BWR MK I designs, and prestressed 

concrete primary containments. The staff confirmed that the stated AMR items in the 

GALL Report are only applicable to PWR and BWR MK I designs, and prestressed concrete 

containments, and are not applicable to the GGNS LRA.

For LRA Table 3.5.1, items 3.5.1-39, 3.5.1-40, and 3.5.1-79, the applicant stated that the 

corresponding AMR items in the GALL Report are not applicable. The staff reviewed the LRA 

and UFSAR and confirmed that the applicant’s LRA does not have any AMR results that are 

applicable for these items.

For those items in LRA Table 3.5.1, where no further evaluation is recommended, and that the 

applicant has identified as not applicable but stated that the components are included in the 

GALL Report recommended program to verify the absence of other aging effects, the staff 

determined the need for additional information. Therefore, by letter dated October 19, 2012, the 

staff issued RAI 3.5.1-1 requesting that the applicant provide the technical justification as to why 

the aging effect does not apply to GGNS or why that aging effect does not require management. 

The staff also requested, that if the aging effect requires management, the applicant identify 

which aging management program(s) will be used to manage the identified aging effect during 

the period of extended operation.

In its response dated November 19, 2012, the applicant revised several LRA Table 3.5.1 items. 

The staff’s evaluation of this response is below.

In response to RAI 3.5.1-1, the applicant revised items 3.5.1-15 and 3.5.1-20, which address 

concrete (accessible areas): basemat; dome; wall; ring girders; buttresses; containment; wall 

exposed to water-flowing, to indicate that increase in porosity and permeability and loss of 

strength due to leaching of calcium hydroxide and carbonation do not require management at 

GGNS. The GALL Report recommends GALL Report AMP XI.S2, “ASME Section XI, 

Subsection IWL,” to manage this aging effect. The applicant stated that leaching of calcium 

hydroxide and carbonation is significant only if concrete is exposed to flowing water. The 

applicant also stated that the concrete containment basemat and primary containment concrete 
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is not exposed to flowing water. The applicant further stated that components are included in 

the Containment Inservice Inspection – IWL Program to confirm the absence of the listed aging 

effects. The staff finds the applicant’s response acceptable because the applicant clarified that 

the components are within the scope of the Containment Inservice Inspection – IWL Program, 

and that the visual inspection activities used to confirm the absence of the potential aging 

effects are the same visual inspection activities that the GALL Report recommends to manage 

the effects of aging. Potential leaching of calcium hydroxide would be detected as water stains 

on accessible surfaces by the IWL visual examinations.

In response to RAI 3.5.1-1, the applicant revised items 3.5.1-16 and 3.5.1-17, which address 

concrete (accessible areas): basemat, containment; wall; dome; ring girders; buttresses 

exposed to ground water/soil and air-indoor, uncontrolled or air-outdoor, to indicate that 

increase in porosity and permeability; cracking; and loss of material due to aggressive chemical 

attack do not require management at GGNS. The GALL Report recommends GALL Report 

AMPs XI.S2, “ASME Section XI, Subsection IWL,” or XI.S6, “Structures Monitoring,” to manage 

this aging effect. The applicant stated that concrete structures and concrete components are 

constructed of a dense, well-cured concrete with an amount of cement suitable for strength 

development, and achievement of a water-to-cement ratio which is characteristic of concrete 

with low permeability. The applicant also stated that GGNS does not have an aggressive 

chemical environment indoors and that the outdoor-air environment is not applicable to the 

GGNS containment, since it is completely enclosed by an enclosure building. The applicant 

further stated that components are included in the Containment Inservice Inspection – IWL 

Program to confirm the absence of the listed aging effects. The staff finds the applicant’s 

response acceptable because the applicant clarified that the components are within the scope 

of the Containment Inservice Inspection – IWL Program, and that the visual inspection activities 

used to confirm the absence of the potential aging effects are the same visual inspection 

activities that the GALL Report recommends to manage the effects of aging. Potential 

aggressive chemical attack would be detected by the IWL visual examinations.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-18, which addresses concrete 

(accessible areas): dome; wall; basemat; ring girders; buttresses exposed to air-outdoor or 

groundwater/soil, to indicate that loss of material (spalling, scaling) and cracking due to freeze 

thaw do not require management at GGNS. The GALL Report recommends GALL Report 

AMP XI.S2, “ASME Section XI, Subsection IWL” to manage this aging effect. The applicant 

stated that the GGNS primary containment concrete is enclosed by the enclosure building and 

is not exposed to an air-outdoor environment that would subject the concrete containment to 

freeze-thaw conditions. The applicant further stated that the components are included in the 

Containment Inservice Inspection – IWL Program to confirm the absence of the listed aging 

effects. The staff finds the applicant’s response acceptable because the applicant clarified that 

the components are within the scope of the Containment Inservice Inspection – IWL Program, 

and that the visual inspection activities used to confirm the absence of the potential aging 

effects are the same visual inspection activities that the GALL Report recommends to manage 

the effects of aging. ASME Section XI, Subsection IWL, Examination Category L-A, requires 

periodic visual examination of accessible concrete surfaces and would detect any freeze-thaw 

damage of the concrete containment.

LRA Table 3.5.1, item 3.5.1-19, addresses concrete (accessible areas): concrete (accessible 

areas): dome; wall; basemat; ring girders; buttresses; concrete (accessible areas): basemat, 

concrete (accessible areas) containment; wall; basemat, concrete fill-in annulus. The GALL

Report recommends GALL Report AMPs XI.S2 “ASME Section XI, Subsection IWL” to manage 

cracking due to expansion from reaction with aggregates. The applicant stated that the item is 
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not applicable and the listed aging effects do not require management at GGNS. Nonetheless, 

the components are included in the Containment Inservice Inspection – IWL Program to verify 

the absence of other aging effects, such as cracking, for components in these listings. The LRA 

does not provide sufficient information for the staff to verify the non-applicability of this item; 

therefore, by letter dated August 15, 2012, the staff issued RAI 3.5.1.12-1 requesting the 

technical justification for the non-applicability of cracking due to expansion from reaction with 

aggregates as a possible aging effect for the components listed in LRA Table 3.5.1, 

item 3.5.1-19. The staff’s review and acceptance of the applicant’s response to RAI 3.5.1.12-1, 

is documented in SER Section 3.5.2.2.1. The staff finds the applicant’s proposal acceptable 

because it is consistent with the GALL Report recommendations for managing aging for these 

structures and components, as documented in item II.A1.CP-33, II.A2.CP-58, II.B1.2.CP-59, 

II.B2.2.CP-59, II.B3.1.CP-66, and II.B3.2.CP-60 (SRP-LR Table 3.5-1, item 19).

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-21, which addresses concrete 

(accessible areas): dome; wall; basemat; ring girders; buttresses; reinforcing steel, concrete 

(accessible areas): basemat; reinforcing steel, concrete (accessible areas): dome; wall; 

basemat; reinforcing steel exposed to either an air-indoor uncontrolled or air-outdoor 

environment, to indicate that cracking; loss of bond; and loss of material (spalling, scaling) due 

to corrosion of embedded steel does not require management at GGNS. The GALL Report

recommends GALL Report AMP XI.S2, “ASME Section XI, Subsection IWL,” to manage this 

aging effect. The applicant stated that for exterior above-grade and interior embedded steel, 

corrosion is not significant if the steel is not exposed to an aggressive environment (concrete 

pH less than 11.5 or chlorides greater than 500 ppm) or if the environment surrounding the 

concrete is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, sulfates less than

1,500 ppm). The applicant also stated that GGNS concrete embedded steel is not exposed to 

an aggressive environment and concrete is constructed of a dense, well-cured concrete mix 

with an amount of cement suitable for strength development, and achievement of a water-tocement ratio which is characteristic of concrete with low permeability, designed in accordance 

with ACI-318 with adequate air-entrainment. The applicant further stated that the components 

in this listing are included in the Containment Inservice Inspection – IWL Program to confirm the 

absence of the listed aging effects. The staff finds the applicant’s response acceptable because 

the applicant clarified that the components are within the scope of the Containment Inservice 

Inspection – IWL Program, and that the visual inspection activities used to confirm the absence 

of the potential aging effects are the same visual inspection activities that the GALL Report 

recommends to manage the effects of aging. Corrosion of embedded steel results in cracking 

and spalling of concrete and would be detected by the IWL visual examinations.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-22, which addresses concrete 

(inaccessible areas): basemat; reinforcing steel exposed to either an air-indoor uncontrolled or 

air-outdoor environment, to indicate that cracking; loss of bond; and loss of material (spalling, 

scaling) due to corrosion of embedded steel does not require management at GGNS. The 

GALL Report recommends GALL Report AMP XI.S6, “Structures Monitoring,” to manage this 

aging effect. The applicant stated that for exterior above-grade and interior embedded steel, 

corrosion is not significant if the steel is not exposed to an aggressive environment (concrete 

pH less than 11.5 or chlorides greater than 500 ppm) or if the environment surrounding the 

concrete is not aggressive (pH greater than 5.5, chlorides less than 500 ppm, sulfates less than

1,500 ppm). The applicant also stated that GGNS concrete embedded steel is not exposed to 

an aggressive environment and concrete is constructed of a dense, well-cured concrete mix 

with an amount of cement suitable for strength development, and achievement of a 

water-to-cement ratio which is characteristic of concrete with low permeability, designed in 

accordance with ACI-318 with adequate air-entrainment. The applicant further stated that the 
3-435

components in this listing are included in the Structures Monitoring Program to confirm the 

absence of the listed aging effects. The staff finds the applicant’s response acceptable because 

the applicant clarified that the components are within the scope of the Structures Monitoring 

Program and that the visual inspection activities used to confirm the absence of the potential 

aging effects are the same visual inspection activities that the GALL Report recommends to 

manage the effects of aging.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-27, which addresses stainless steel 

components exposed to either an air-indoor uncontrolled or air-outdoor environment, to indicate 

that GGNS has a CLB fatigue analysis associated with penetration sleeves and suppression 

pool liner at the containment wall, and therefore this aging effect is addressed under item 3.5.1-

9. The staff reviewed LRA Table 3.5.1, item 3.5.1-9, verified that the applicant does have a CLB 

fatigue analysis associated with penetration sleeves and suppression pool liner at the 

containment wall, and that a TLAA has been provided for these components; therefore, the staff 

finds the applicants claim acceptable. The staff’s evaluation of TLAA 4.6, “Containment Liner 

Plate, Metal Containments, and Penetrations Fatigue Analysis,” is documented in Section 4.6 of 

this SER.

LRA Table 3.5.1, item 3.5.1-29 addresses the steel personnel airlock, equipment hatch, CRD 

hatch: locks, hinges, and closure mechanisms exposed to air-indoor uncontrolled or 

air-outdoor. The GALL Report recommends GALL Report AMP XI.S1, “ASME Section XI, 

Subsection IWE,” and XI.S4, “10 CFR Part 50, Appendix J,” programs to manage loss of leak 

tightness due to mechanical wear of locks, hinges, and closure mechanisms for this component 

group. The applicant stated that this item is not applicable because locks, hinges, and closure 

mechanisms are active components and are therefore not subject to an AMR. The applicant 

also stated that 10 CRF Part 50, Appendix J, and plant TS require testing to ensure leak 

tightness of airlocks and hatches. The staff evaluated the applicant’s claim and noted that 

Section 3.8.3.1.1, “Drywell Structure,” part (d) of the UFSAR states “[t]he equipment hatch is 

designed to be removed during plant maintenance. During plant operation the drywell 

equipment hatch is part of the drywell pressure retention boundary and as such uses two 

compression seals around its periphery to maintain its leak tightness along the mating surfaces. 

The staff also noted that the NRC by letter dated April 26, 1995, under 10 CFR 50.12(a)(2)(ii), 

has granted an exemption to GGNS from 10 CFR Part 50, Appendix J, scheduled testing. The 

exemption allows the applicant to apply specific performance criteria to Type B tests for each 

containment air lock test. It does not alleviate the applicant from surveillance requirements. 

The rule states that “Type B Tests” for “[a]ir lock door seals, includ[e] door operating mechanism 

penetrations which are part of the containment pressure boundary.” As stated in 10 CFR 54.35, 

“Requirements During Term of Renewed License,” for the term of a renewed license, licensees 

shall be subject to and shall continue to comply with all NRC regulations, including those 

contained in 10 CFR Part 50 and the relevant appendices. It is not clear how the applicant 

manages wear of the airlock and equipment hatch hardware and mechanisms when assessing 

leak tightness. By letter dated September 12, 2012, the staff issued RAI 3.5.1-29 requesting the 

applicant to describe how it plans to manage any aging effects due to wear of locks, hinges, and 

closure mechanisms.

In its response dated October 9, 2012, the applicant stated that the containment personnel 

airlocks have hardware components that secure each door in position and perform their 

functions with moving parts, and therefore, are not subject to aging management review as 

stated in 10 CFR 54.21. The applicant further stated that the seals which maintain the 

containment pressure boundary function are managed for aging by the ASME Section XI, 

Subsection IWE and 10 CFR Part 50, Appendix J, programs. The applicant also noted that the 
3-436

airlock and equipment hatch discussed in UFSAR Section 3.8.3.1.1 are located in the drywell 

and are not part of the containment pressure boundary. Therefore, the components are not 

subject to ASME Section XI, Subsection IWE or 10 CFR Part 50, Appendix J, inspections, but 

are inspected under the Structures Monitoring Program. Finally, the applicant explained that the 

containment equipment hatch is subject to an aging management review and the ASME 

Section XI, Subsection IWE and 10 CFR Part 50, Appendix J, programs manage the effects 

of aging on this component. The applicant updated the corresponding items to reflect 

the changes.

The staff reviewed the applicant’s response and verified that the drywell airlock and equipment 

hatch discussed in UFSAR Section 3.8.3.1.1 is not part of the containment boundary, and 

therefore, not subject to ASME Section XI, Subsection IWE or 10 CFR Part 50, Appendix J,

inspections. The staff also noted that the pressure retaining components of the containment 

equipment hatch and the personnel airlock are subject to aging management review and are 

within the scope of the ASME Section XI, Subsection IWE and 10 CFR Part 50, Appendix J,

Programs. Based on its review, the staff finds the applicant's response acceptable because the 

applicant verified that all of the pressure retaining components of the containment personnel 

airlock and containment equipment hatch are being managed by the appropriate GALL Report 

recommended programs. The staff’s concern in RAI 3.5.1.29-1 is resolved.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-30, which addresses pressureretaining bolting exposed to any environment, to indicate that GGNS pressure-retaining bolting 

is associated with securing the equipment hatch and mounting hardware for the personnel 

airlocks addressed by item 3.5.1-29. The GALL Report recommends GALL Report 

AMPs XI.S1, “ASME Section XI, Subsection IWE,” and XI.S4, “10 CFR Part 50, Appendix J,” to 

manage this aging effect. The applicant further stated that the aging effect loss of preload due 

to self loosening would result in loss of leak tightness of the pressure boundary; therefore, 

managing the aging effect loss of leak tightness provides reasonable assurance that the 

intended function of the containment pressure boundary is maintained and the aging effect loss 

of preload due to self loosening is managed in accordance with item 3.5.1-29. The staff finds 

the applicant’s response acceptable because the applicant has included these components 

within the scope of the Containment Inservice Inspection – IWE and Containment Leak Rate 

Programs which is consistent with the recommendations in the GALL Report.

LRA Table 3.5.1, item 3.5.1-36 addresses steel elements: drywell head and downcomers 

exposed to air-indoor uncontrolled. The GALL Report recommends GALL Report AMP XI.S1, 

“ASME Section XI, Subsection IWE,” to manage fretting or lockup due to mechanical wear for 

this component group. The applicant stated that this item is not applicable because GGNS 

plant operating experience has not identified fretting or lockup due to mechanical wear for the 

drywell head, and downcomers are not common to the GGNS Mark III containment. GGNS 

inspects the drywell head per the requirement of ASME Section XI; and the drywell head is a 

stationary or fixed component and the spatial distance between connecting components makes 

it unlikely for fretting and lockup to occur. The staff evaluated the applicant’s claim of a fixed 

drywell head and noted Section 3.8.3.1.1, “Drywell Structure,” part (d) of the UFSAR states, “at 

each refueling outage the drywell head is removed to permit unobstructed access to the top of 

the reactor pressure vessel.” It is not clear if the drywell head is fixed or removable, because a 

removable drywell head may very well experience mechanical wear. Furthermore the applicant 

did not state if fleet or industry operating experience has been considered for managing aging 

effects due to fretting or lockup due to mechanical wear. By letter dated September 12, 2012, 

the staff issued RAI 3.5.1-36 requesting the applicant to identify whether the drywell head is 
3-437

fixed or removable, and if removable, how the applicant would manage the aging effects due to 

fretting or mechanical wear associated with its removal during refueling operation.

In its response dated October 9, 2012, the applicant stated that the drywell head is removable; 

however, it is not part of the containment pressure boundary and therefore is not subject to 

ASME Section XI, Subsection IWE inspections. The drywell head is inspected under the 

Structures Monitoring Program. The applicant also stated that plant specific and industry 

operating experience was reviewed for fretting or lockup due to mechanical wear of the drywell 

head and none was identified. The applicant updated the discussion portion of LRA 

Table 3.5.1, item 36, to reflect this information.

The staff reviewed the applicant’s response and noted that the drywell head and the drywell 

mating surfaces are inspected under the Structures Monitoring Program and no wear or fretting 

has been identified. The staff also verified that the drywell head is not part of the containment 

pressure boundary and therefore it is appropriate for the component to be inspected under the 

Structures Monitoring Program. Based on its review, the staff finds the applicant's response 

acceptable because the appropriate AMP is being used to monitor the component, and the 

applicant reviewed plant and industry operating experience and found no relevant experience 

that would indicate the current program is inadequate. The staff’s concern in RAI 3.5.1.36-1 

is resolved.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-38, which addresses steel elements: 

suppression chamber shell (interior surface) exposed to an air-indoor uncontrolled environment, 

to indicate that the stainless steel elements of the GGNS suppression pool are not susceptible 

to SCC because these elements are not exposed to an aggressive chemical environment or 

concentration of contaminants, and temperatures are not greater than 140°F. The GALL Report

recommends GALL Report AMPs XI.S1, “ASME Section XI, Subsection IWE” and XI.S4,

“10 CFR Part 50, Appendix J,” to manage this aging effect. The staff finds the applicant’s 

response acceptable because the applicant clarified that these components are not exposed to 

an environment conducive to SCC, and that the components in this listing are included in the 

Containment Inservice Inspection – IWE and Containment Leak Rate Program to confirm the 

absence of the listed aging effect.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-55, which addresses building 

concrete at locations of expansion and grouted anchors; grout pads for support base plates 

exposed to an indoor-air uncontrolled or air-outdoor environment, to indicate that reduction in 

concrete anchor capacity due to local concrete degradation/service induced cracking, or other 

concrete aging mechanisms will be managed in accordance with items 3.5.1-59 and 3.5.1-66 

under the Structures Monitoring and RG 1.127 Programs. The GALL Report recommends 

GALL Report AMP XI.S6, “Structures Monitoring,” to manage this aging effect. The staff finds 

the applicants response acceptable because the reduction in anchor capacity will be managed 

using both the Structures Monitoring Program, consistent with the GALL Report

recommendations, as well as the RG 1.127 Program.

LRA Table 3.5.1, item 3.5.1-57, addresses steel constant and variable load spring hangers, 

guides, and stops exposed to air-indoor uncontrolled or air-outdoor. The GALL Report

recommends GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF,” to manage loss of 

mechanical function due to corrosion, distortion, dirt, overload, and fatigue due to vibratory and 

cyclic thermal loads for this component group. The applicant stated that this item is not 

applicable and the listed aging effect does not require management because such failures 

typically result from inadequate design or events rather than the effects of aging. The applicant 
3-438

further stated that loss of material due to corrosion, which could cause loss of mechanical 

function, is addressed under items 3.5.1-91 and 3.5.1-92 related to component support 

members. The staff evaluated the applicant’s claim and noted that the components are 

included in the Inservice Inspection – IWF Program, which, with enhancements, is consistent 

with the GALL Report. The staff also noted that the Inservice Inspection – IWF AMP uses VT-3 

examination to inspect for loss of material due to corrosion, deformation, or misalignment of 

supports; missing, detached, or loosened support items; improper clearances of guides and 

stops; and improper hot or cold settings of spring and constant load supports. The staff further 

noted that the inspections that are part of the Inservice Inspection – IWF Program will 

adequately detect for loss of mechanical function. The staff finds this acceptable because the 

effects of aging will be managed so that the intended functions of the constant and variable load 

spring hangers, guides, and stops will be maintained for the period of extended operation.

LRA Table 3.5.1, item 3.5.1-60, addresses Group 6: concrete (accessible areas) exterior 

above- and below-grade; foundation exposed to air-outdoor. The GALL Report recommends 

GALL Report AMP XI.S7, “Regulatory Guide 1.127 Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” to manage loss of material (spalling, scaling) and 

cracking due to freeze-thaw for this component group. The applicant stated that this item is not 

applicable and the aging effects are not significant for accessible and inaccessible areas. The 

applicant further stated the these concrete structures are exposed to saturated water conditions 

near the ground surface; however, the concrete used at GGNS is designed with entrained air 

content in conformance with ACI-318, and plant experience has not identified any degradation 

related to freeze-thaw. Nonetheless, the RG 1.127 program will confirm the absence of AERM

for GGNS Group 6 concrete components. Therefore, the staff finds the applicant’s proposal 

acceptable because the applicant has included the Group 6: concrete (accessible and 

inaccessible) areas within the scope of the RG 1.127 program to manage cracking as 

documented in LRA Table 3.5.1, items 43, 59, and 61.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-63, which addresses Groups 1-3, 5, 

7-9: concrete (accessible areas): exterior above- and below-grade; foundation exposed to 

water flowing, to indicate that increase in porosity and permeability and loss of strength due to 

leaching of calcium hydroxide and carbonation do not require management at GGNS. The 

GALL Report recommends GALL Report AMP XI.S6, “Structures Monitoring,” to manage this 

aging effect. The applicant stated that leaching of calcium hydroxide and carbonation is 

significant only if concrete is exposed to flowing water. The applicant also stated that GGNS 

below-grade exterior reinforced concrete is not exposed to flowing water or an aggressive 

environment (pH less than 5.5), or to chloride or sulfate solutions beyond defined limits (greater 

than 500 ppm chloride, or greater than 1,500 ppm sulfate). The applicant further stated that 

components are included in the Structures Monitoring Program to confirm the absence of the 

listed aging effects. The staff finds the applicant’s response acceptable because the applicant 

clarified that the components are within the scope of the Structures Monitoring Program, and 

that the visual inspection activities used to confirm the absence of the potential aging effects are 

the same visual inspection activities that the GALL Report recommends to manage the effects 

of aging.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-64, which addresses Groups 1-3, 5, 

7-9: concrete (accessible areas): above- and below-grade; foundation exposed to air-outdoor, 

to indicate that loss of material (spalling, scaling) and cracking due to freeze-thaw do not require 

management at GGNS. The GALL Report recommends GALL Report AMP XI.S6, “Structures 

Monitoring,” to manage this aging effect. The applicant stated that inaccessible and accessible 

concrete areas are designed in accordance with ACI 318, which results in low permeability and 
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resistance to aggressive chemical solutions. The applicant also stated that the components in 

this listing are included in the Structures Monitoring Program to confirm the absence of the listed 

aging effects. The staff finds the applicant’s response acceptable because the applicant 

clarified that the components are within the scope of the Structures Monitoring Program, and 

that the visual inspection activities used to confirm the absence of the potential aging effects are 

the same visual inspection activities that the GALL Report recommends to manage the effects 

of aging.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-68, which addresses low-alloy steel 

high-strength structural bolting (measured yield strength greater than or equal to 150 ksi) 

exposed to air-indoor, uncontrolled, to indicate that cracking due to stress corrosion cracking 

does not require management at GGNS. The GALL Report recommends GALL Report 

AMP XI.S3, “ASME Section XI, Subsection IWF,” to manage this aging effect. The applicant 

stated that GGNS does not have high strength bolts that are subject to sustained high tensile 

stress in a corrosive environment. The applicant also stated that the bolting components in this 

listing are included in the Inservice Inspection – IWF Program to confirm the absence of the 

listed aging effect. The staff finds the applicant’s response acceptable because the applicant 

clarified that the components are within the scope of the Inservice Inspection – IWF Program, 

and that the visual inspection activities used to confirm the absence of the potential aging 

effects are the same visual inspection activities that NUREG-1801 recommends to manage the 

effects of aging.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-69, which addresses high-strength 

structural bolting exposed to indoor-air uncontrolled or air-outdoor, to indicate that cracking due 

to stress corrosion cracking does not require management at GGNS. The GALL Report 

recommends GALL Report AMP XI.S6, “Structures Monitoring,” to manage this aging effect. 

The applicant stated that GGNS does not have high strength bolts that are subject to sustained 

high tensile stress in a corrosive environment. The applicant also stated that the bolting 

components in this listing are included in the Structures Monitoring Program to confirm the 

absence of the listed aging effect. The staff finds the applicant’s response acceptable because 

the applicant clarified that the components are within the scope of the Structures Monitoring 

Program, and that the visual inspection activities used to confirm the absence of the potential 

aging effects are the same visual inspection activities that the GALL Report recommends to 

manage the effects of aging.

In response to RAI 3.5.1-1, the applicant revised item 3.5.1-71, which addresses all masonry 

walls exposed to air-outdoor, to indicate the GGNS does not have any masonry walls with the 

scope of LR in an air-outdoor environment exposed to freeze-thaw conditions. The staff 

reviewed LRA Section 2.4 and finds the applicant’s response acceptable because the applicant 

does not have any masonry walls exposed to air-outdoor within the scope of license renewal; 

therefore, this aging effect for these components is not applicable.

LRA Table 3.5.1, items 3.5.1-74 and 3.5.1-75, address sliding support bearings and surfaces 

made of Lubrite® type material, exposed to air – indoor, uncontrolled or air – outdoor. The 

GALL Report recommends GALL Report AMP XI.S6, “Structures Monitoring,” to manage loss of 

mechanical function due to corrosion, distortion, dirt, debris, overload, and wear for this 

component group. The applicant stated that this item is not applicable and loss of mechanical 

function due to the listed mechanisms is not an aging effect. The applicant also stated that such 

failures typically result from inadequate design or operating events rather than from the effects 

of aging. The staff confirmed the applicant’s claim that properly installed surfaces are practically 

maintenance-free, noting that SRP-LR ascertains that such plates generally have not shown 
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adverse aging conditions, provided precise tolerances and bearing-specific examinations were 

maintained during installation. The SRP-LR also states that precautions such as careful 

installation and clearing out any obstructions during installation ensures that the required 

tolerances of the bearings are met and reduces the likelihood of functional problems during 

challenging loading conditions, such as DBAs or safe-shutdown earthquakes. The SRP-LR 

further affirms that potential aging effects, ranging from malfunctioning, distortion, and dirt 

accumulation to fatigue under vibratory and cyclic thermal loads, could be managed through the 

Structures Monitoring and Inservice Inspection – IWF Programs. The staff reviewed the 

applicant’s Structures Monitoring and Inservice Inspection – IWF Programs and confirmed that 

the programs have their “parameters monitored or inspected,” program element enhanced to 

monitor sliding and bearing surfaces, such as Lubrite® plates, for loss of material due to wear or 

corrosion, debris, or dirt.

The staff concludes that for LRA items 3.5.1-74 and 3.5.1-75, the applicant’s claim is 

substantiated and 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).

In response to RAI 3.5.1-1, the applicant revised items 3.5.1-81 and 3.5.1-86, which address 

steel and galvanized steel structural bolting exposed to air-indoor uncontrolled and air-outdoor, 

to indicate that structural bolts associated with ISI (IWF) components are addressed under 

bolted connections in item 3.5.1-91. The GALL Report recommends GALL Report AMP XI.S3,

“ASME Section XI, Subsection IWF,” to manage this aging effect. LRA Table 3.5.1, 

item 3.5.1-91 addresses loss of material due to general and pitting corrosion in support 

members; welds; bolted connections; and support anchorage to building structures. The staff 

finds the applicants proposal to manage loss of material in structural bolts using the Inservice 

Inspection – IWF Program acceptable, because it is consistent with the recommendations in 

item 3.5.1-91 for the same material and environment combination.

In response to RAI 3.5.1-1, the applicant revised items 3.5.1-84 and 3.5.1-85, which addresses 

stainless steel structural bolting for Class MC components and stainless steel structural bolting 

for Class 1, 2 and 3 piping and support components exposed to treated water, to indicate the 

GGNS does not have this component, material, and environment combination. The staff 

reviewed the applicant’s response and finds it acceptable because this item is not applicable in 

the absence of this component, material, and environment combination.

LRA Table 3.5.1, items 3.5.1-87, addresses structural bolting exposed to any environment. The 

GALL Report recommends GALL Report AMP XI.S3, “ASME Section XI, Subsection IWF,” to 

manage loss of preload due to self-loosening for this component group. The applicant stated 

that this item is not applicable and the listed aging effects do not require management at GGNS. 

The applicant did not provide any further discussion. The staff determined it needed more 

information to complete its review. Therefore, by letter dated June 27, 2012, the staff issued

RAI 3.5.1.87-1 requesting that the applicant explain why loss of preload is not an aging effect for 

structural bolting within the scope of license renewal, or to provide an acceptable AMP to 

manage the loss of preload during the period of extended operation. The applicant responded 

by letter dated July 25, 2012, stating that vibration, flexing of the joint, cyclic shear loads, 

thermal cycles, and other conditions can cause self-loosening of a fastener; however, these 

causes are minor contributors in structural steel and steel component threaded connections and 

are eliminated by initial preload bolt torquing. The applicant further stated that GGNS uses site 

procedures and manufacturer recommendations to provide guidance for proper torquing of nuts 

and bolts used in structural applications, and operating experience has not shown self-loosening 
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of structural bolting at GGNS. The staff finds the response acceptable because the applicant 

will include structural bolting in the “Inservice Inspection – IWF” AMP, which has been enhanced 

to include inspection of structural bolting (ASTM A325, ASTM F1852, and ASTM A490 bolts), in 

part, for loose or missing nuts, and loss of preload. This enhancement, once implemented, will 

ensure that loss of preload will be managed for structural bolts for the period of extended 

operation. The staff’s evaluation of the applicant’s Inservice Inspection – IWF Program is 

documented in SER Section 3.0.3.1.23.

LRA Table 3.5.1, item 3.5.1-88 addresses structural bolting exposed to any environment. The 

GALL Report recommends GALL Report AMP XI.S6, “Structures Monitoring,” to manage loss of 

preload due to self-loosening for this component group. The applicant stated that this item is 

not applicable and the listed aging effects do not require management at GGNS. The applicant 

did not provide any further discussion. The staff determined additional information was needed 

to complete its review. Therefore, by letter dated June 27, 2012, the staff issued RAI 3.5.1.87-1 

requesting that the applicant explain why loss of preload due to self-loosening is not an aging 

effect for structural bolting within the scope of license renewal, or to provide an acceptable AMP

to manage the loss of preload during the period of extended operation. The applicant 

responded by letter dated July 25, 2012, stating that vibration, flexing of the joint, cyclic shear 

loads, thermal cycles and other conditions can cause self-loosening of a fastener; however, 

these causes are minor contributors in structural steel and steel component threaded 

connections and are eliminated by initial preload bolt torquing. The applicant further stated that 

GGNS uses site procedures and manufacturer recommendations to provide guidance for proper 

torquing of nuts and bolts used in structural applications, and operating experience has not 

shown self-loosening of structural bolting at GGNS. The staff finds the response acceptable 

because the applicant will include structural bolting in the Structures Monitoring Program, which 

has been enhanced to include inspection of structural bolting for missing nuts for structural 

connections. The staff’s evaluation of the applicant’s Structures Monitoring Program is 

documented in SER Section 3.0.3.1.40.

For LRA Table 3.5.1, item 3.5.1-89, the applicant claimed that the corresponding AMR items in 

the GALL Report are not applicable because the associated items are only applicable to PWRs. 

The staff reviewed the SRP-LR, confirmed these items only apply to PWRs, and finds that these 

items are not applicable to GGNS, which is a BWR.

LRA Table 3.5.1, item 3.5.1-94 addresses nonmetallic (e.g., rubber) vibration isolation elements 

exposed to air-indoor, uncontrolled or air-outdoor. The GALL Report recommends GALL Report

AMP XI.S3, “ASME Section XI, Subsection IWF,” to manage reduction or loss of isolation 

function due to radiation hardening, temperature, humidity, and sustained vibratory loading for 

this component group. The applicant stated that this item is not applicable and no vibration 

isolation elements at GGNS are in scope and subject to an AMR. The staff reviewed the 

Inservice Inspection – IWF Program and noted that in LRA Section B.1.24, the applicant stated

that it is enhancing the “parameters monitored or inspected” program element to monitor 

elastomeric vibration elements for cracking, loss of material, and hardening. The staff also 

noted that in LRA Section A.1.42, the applicant stated that the Structures Monitoring Program

will be enhanced such that vibration isolators will receive augmented inspections by feel or 

touch to detect hardening if the vibration isolation function is suspect. The staff found these 

enhancements to be inconsistent with the claim that there are no vibration isolation elements in 

scope for license renewal, and thus needed more information to complete its review. Therefore, 

by letter dated August 21, 2012, the staff issued RAI 3.5.1.94-1 requesting that the applicant 

resolve this discrepancy.
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The applicant responded by letter dated September 13, 2012, and stated that while there are 

vibration isolation elements within the scope of license renewal, none of those in scope are nonmetallic. The vibration isolation elements that are within the scope of license renewal are 

integral parts of structural support assemblies and are included in LRA Table 2.4-4 as bulk 

commodities subject to aging management review and LRA Table 3.5.2-4, where they are 

included with the items for component and piping supports; and component and piping supports 

for ASME Class 1, 2, 3, and MC. The applicant also stated that the aging effects for those 

components are managed by the Structures Monitoring Program and ISI-IWF aging 

management programs. The applicant revised its enhancement to the ISI-IWF “parameters 

monitored or inspected” program element to reflect this issue.

The staff evaluated the applicant’s claim and finds it acceptable because the applicant does not 

have non-metallic vibration isolation elements within the scope of license renewal and is

therefore not required to include those components in its aging management program. The 

vibration isolation elements that are within the scope of license renewal are being managed by 

the appropriate AMPs.

3.5.2.1.2 Loss of Sealing Due to Wear, Damage, Erosion, Tear, Surface Cracks, or Other 

Defects

LRA Table 3.5.1, item 3.5.1-26 addresses elastomer moisture barriers (caulking, flashing, and 

other sealants) exposed to an air-indoor uncontrolled environment that will be managed for loss 

of sealing due to wear, damage, erosion, tear, surface cracks, or other defects; however, the 

applicant stated that loss of sealing is a consequence of the aging effects cracking and change 

in material properties. For the AMR item that cites generic note E, the LRA credits the 

Containment Leak Rate Program to manage the cracking and change in material properties for 

elastomer containment building electrical penetration seals and sealant. The GALL Report

recommends using GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” to ensure 

that these aging effects are adequately managed. GALL Report AMP XI.S1 recommends using 

visual examinations (general visual, VT-3, and VT-1) of moisture barriers for wear, damage, 

erosion, tear, surface cracks, and other defects that permit intrusion of moisture into the 

inaccessible areas of pressure-retaining surfaces of the metal containment shell or liner.

The staff’s evaluation of the Containment Leak Rate Program is documented in SER 

Section 3.0.3.1.14. The staff noted that the Containment Leak Rate Program proposes to 

manage the aging of elastomer containment building electrical penetration seals and sealants 

through performance of containment leakage rate tests at frequencies that comply with the 

requirements of 10 CFR Part 50, Appendix J, and Option B. In its review of components 

associated with item 3.5.1-26, for which the applicant cited generic note E, the staff finds the 

applicant’s proposal to manage aging using the Containment Leak Rate Program unacceptable 

because the Containment Leak Rate Program is a performance monitoring program that 

monitors parameters related to leakage rates and does not by itself provide information that 

would indicate aging degradation has initiated. The staff is unable to determine that visual 

examinations are performed of elastomer containment building electrical penetration seals and 

sealants to manage aging in the form of cracking or change in material properties, or how the 

Containment Leak Rate Program will evaluate change in material properties. By letter dated 

June 27, 2012, the staff issued RAI 3.5.2.1-1 requesting that the applicant describe how the 

applicant’s Containment Leak Rate Program meets the recommendations in GALL Report

item II.B4.CP-40 related to aging management of cracking and change in material properties of 

elastomer containment building electrical penetration seals and sealant.
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In its response dated July 25, 2012, the applicant stated that this item addresses containment 

building electrical penetration seals and gaskets and that LRA Table 3.5.2-1 has been revised 

so that the appropriate NUREG-1801 item is identified (II.B4.CP-41), Table 1 item is changed to 

3.5.1-33, and the Note “E” has been changed to Note “A” indicating consistency with 

NUREG-1801.

The staff finds the applicant‘s response acceptable because the component, material, 

environment, aging effect, and AMP are now consistent with the GALL Report. The staff’s 

concern described in RAI 3.5.2.1-1 is resolved.

LRA Table 3.5.1, item 3.5.1-26 addresses elastomer moisture barriers (caulking, flashing, and 

other sealants) exposed to an air-indoor uncontrolled environment that will be managed for loss 

of sealing due to wear, damage, erosion, tear, surface cracks, or other defects; however, the 

applicant stated that loss of sealing is a consequence of the aging effects cracking and change 

in material properties. For the AMR items that cite generic note E, the LRA credits the 

Structures Monitoring Program to manage the aging effects for elastomer containment building 

moisture barriers. The GALL Report recommends GALL Report AMP XI.S1, “ASME Section XI, 

Subsection IWE,” to ensure that these aging effects are adequately managed. GALL Report

AMP XI.S1 recommends using visual examinations (general visual, VT-3, and VT-1) of moisture 

barriers for wear, damage, erosion, tear, surface cracks, and other defects that permit intrusion 

of moisture in the inaccessible areas of pressure-retaining surfaces of the metal containment 

shell or liner.

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of moisture barriers through performance of visual inspections at 5-year intervals by 

qualified personnel using acceptance criteria provided in industry codes, standards, and 

guidelines including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-96. In its review of 

components associated with item 3.5.1-26, for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Structures Monitoring Program

acceptable because hardening, shrinkage, and loss of sealing of elastomers will be managed 

through visual inspections conducted by qualified personnel at intervals not to exceed 5 years in 

accordance with recommendations in NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-02. The 

applicant’s AMP meets the recommendations in GALL Report item II.B4.CP-40 and therefore is 

consistent with GALL Report AMP XI.S1 “ASME Section XI, Subsection IWE,” which is identified 

as the appropriate AMP in the GALL Report.

LRA Table 3.5.1, item 3.5.1-26 addresses elastomer moisture barriers (caulking, flashing, and 

other sealants) exposed to an air-indoor uncontrolled environment that will be managed for loss 

of sealing due to wear, damage, erosion, tear, surface, cracks, or other defects; however, the 

applicant stated that loss of sealing is a consequence of the aging effects cracking and change 

in material properties. For the AMR items that cite generic note E, the LRA credits the Periodic 

Surveillance and Preventive Maintenance Program to manage the cracking and change in 

material properties of elastomer upper containment pool gates rubber gasket/seal. The 

GALL Report recommends AMP XI.S1, “ASME Section XI, Subsection IWE,” to ensure that 

these aging effects are adequately managed. GALL Report AMP XI.S1 recommends using 

visual examinations (general visual, VT-3, and VT-1) of moisture barriers for wear, damage, 

erosion, tear, surface cracks, and other defects that permit intrusion of moisture in the 

inaccessible areas of pressure-retaining surfaces of the metal containment shell or liner.
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The staff’s evaluation of the applicant’s Periodic Surveillance and Preventive Maintenance 

Program is documented in SER Section 3.0.3.2.2. The staff noted that the Periodic Surveillance 

and Preventive Maintenance Program proposes to manage aging of elastomer upper 

containment pool gates rubber gasket/seal through visual inspections and manually flexing the 

rubber gasket/seal for upper containment pool gates to verify the absence of cracks and 

significant changes of material properties. The Periodic Surveillance and Preventive

Maintenance Program is an existing program that manages aging effects not managed by other 

AMPs, including loss of material, cracking, and change in material properties, and there is no 

corresponding GALL Report AMP. In its review of components associated with item 3.5.1-26, 

for which the applicant cited generic note E, the staff finds the applicant’s proposal to manage 

aging using the Periodic Surveillance and Preventive Maintenance Program acceptable 

because the program visually inspects and manually flexes the rubber gasket/seal for the upper 

containment pool gates at least once every 5 years to verify the absence of cracks and 

significant change in material properties. The applicant’s AMP meets the recommendations in 

GALL Report item II.B4.CP-40 and therefore is consistent with GALL Report AMP XI.S1, “ASME 

Section XI, Subsection IWE,” which is identified as the appropriate AMP in the GALL Report.

The staff concludes that for LRA items 3.5.1-26, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.3 Loss of Material Due to General, Pitting, and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-31 addresses pressure-retaining bolting, and steel elements: 

downcomer pipes exposed to a fluid environment that will be managed for loss of material due 

to general, pitting, and crevice corrosion. For the AMR item that cites generic note E, the LRA 

credits the Inservice Inspection – IWF Program and the Water Chemistry Control – BWR 

Program to manage the aging effect for carbon steel quencher supports. The GALL Report

recommends GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE Program,” to 

ensure that these aging effects are adequately managed. GALL Report AMP XI.S1 

recommends using visual examinations of non-coated surfaces to detect evidence of cracking, 

discoloration, wear, pitting, excessive corrosion, arc strikes, gouges, surface discontinuities, 

dents, and other signs of surface irregularities for components of steel containments and steel 

liners of concrete containments.

The staff’s evaluation of the Inservice Inspection – IWF Program and the Water Chemistry 

Control - BWR Program is documented in SER Sections 3.0.3.1.23 and 3.0.3.1.41, respectively. 

The staff noted that the Inservice Inspection – IWF Program proposes to manage the aging of 

carbon steel quencher supports through visual examinations to identify loss of material due to 

corrosion or wear that reduces the load-bearing capacity of the component support. The staff 

also noted that the Water Chemistry Control – BWR Program proposes to manage the aging of 

carbon steel quencher supports through monitoring and control of water chemistry using EPRI 

water chemistry guidelines. In its review of components associated with item 3.5.1-31, for which 

the applicant cited generic note E, the staff finds the applicant‘s proposal to manage aging using 

the Inservice Inspection – IWF Program and the Water Chemistry Control – BWR Program 

acceptable because loss of material will be managed through periodic visual examinations 

(VT-3) performed by qualified personnel and through monitoring and control of water chemistry 

using EPRI water chemistry guidelines. The applicant‘s VT-3 examinations for loss of material 

are consistent with GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE Program,”

which is identified as the appropriate AMP in the GALL Report.
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The staff concludes that for LRA items 3.5.1-31, 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).

LRA Table 3.5.1, item 3.5.1-83 addresses structural bolting exposed to a fluid environment that 

will be managed for loss of material due to general, pitting, and crevice corrosion. For the AMR 

items that cite generic note E, the LRA credits the Structures Monitoring Program to manage the 

aging effect for carbon steel anchorage/embedments, component and piping supports, and 

structural bolting. The GALL Report recommends GALL Report AMP XI.S7 “Regulatory 

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants,” to 

ensure that these aging effects are adequately managed. GALL Report AMP XI.S7 

recommends monitoring and visual inspection at intervals not to exceed 5 years for indications 

of loss of material in bolted connections and other structural bolting.

The staff’s evaluation of the applicant’s Structures Monitoring Programs documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of carbon steel anchorage/embedments, components and piping supports, and 

structural bolting through the use of visual inspections at 5-year intervals using qualified 

personnel and acceptance criteria based on information provided in industry codes, standards, 

and guidelines including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-96. In its review of 

components associated with item 3.5.1-83 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Structures Monitoring Program

acceptable because loss of material will be managed through visual inspections conducted by 

qualified personnel at intervals not to exceed 5 years, in accordance with recommendations in 

NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-02. The applicant’s AMP meets the 

recommendations in the GALL Report item III.A6.TP-221 and therefore is consistent with 

GALL Report AMP XI.S7 “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” which is identified as the appropriate AMP in the 

GALL Report.

The staff concludes that for LRA item 3.5.1-83, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.4 Loss of Sealing Due to Wear, Damage, Erosion, Tear, Surface Cracks, or Other 

Defects

LRA Table 3.5.1, item 3.5.1-33 addresses seals and gaskets that will be managed for loss of 

sealing due to wear, damage, erosion, tear, surface cracks, or other defects. The LRA states 

that these items are associated with components outside of containment. For the AMR items 

that cite generic note E, the LRA credits the Structures Monitoring Program to manage the 

aging effect for roof membranes exposed to outdoor air, and seals and gaskets (doors, 

manways, and hatches) exposed to uncontrolled indoor air. The GALL Report recommends 

GALL Report AMP XI.S4, “10 CFR Part 50, Appendix J,” to ensure that these aging effects are 

adequately managed. GALL Report AMP XI.S4 recommends using containment leak rate 

testing to manage aging for containment pressure boundary components, including seals 

and gaskets.
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The staff noted that item 3.5.1-33 states, “GGNS items referring to seals and gaskets are 

associated with components outside containment and are managed by the Structures 

Monitoring Program for cracking and change in material properties.” The staff also noted that, 

although item 3.5.1-33 states that the seals and gaskets are “outside containment,” the seals 

and gaskets can be outside containment and still be associated with the containment 

penetration boundary. By letter dated June 20, 2012, the staff issued RAI 3.5.1.33-1 requesting 

that the applicant state whether any of the seals and gaskets (doors, manways, and hatches) 

which are included in LRA Table 3.5.2-4 and cite item 3.5.1-33 are associated with the 

containment penetration function. Furthermore if they are, the staff asked the applicant to state 

the basis for using the Structures Monitoring Program in lieu of the Containment Leak Rate 

Program, or to revise the LRA to reflect that the Containment Leak Rate Program will be used to 

manage their aging.

In its response dated July 19, 2012, the applicant stated that, “[t]he seals and gaskets (doors, 

manways, and hatches) that are included in LRA Table 3.5.2-4 and cite item 3.5.1-33 are not 

associated with containment penetrations.”

The staff finds the applicant’s response acceptable because utilization of GALL Report

AMP XI.S4 is not appropriate for items that are not associated with containment penetrations, 

and the visual inspections conducted by the Structures Monitoring Program are sufficient to 

detect wear, damage, erosion, tear, surface cracks, or other defects. The staff’s concern 

described in RAI 3.5.1.33-1 is resolved.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of roof membranes exposed to outdoor air, and seals and gaskets (doors, manways, 

and hatches) exposed to uncontrolled indoor air through the use of periodic visual inspections to 

detect hardening, shrinkage, and loss of sealing. The staff noted that the Structures Monitoring 

Program includes an enhancement to perform physical manipulation of vibration isolaters if the 

vibration isolation function is suspect; however, neither the program nor the implementing 

procedures contain a requirement to augment the visual examinations with physical 

manipulation for roof membranes, and seals and gaskets (doors, manways, and hatches). In 

addition the staff noted that the “detection of aging effects” program element of GALL Report

AMPs XI.M36 and XI.M38 recommend that 10 percent of available surface area of flexible 

polymeric components be manipulated; however neither the Structures Monitoring Program nor 

the implementing procedures contain a requirement to conduct this sample size inspection. By 

letter dated June 20, 2012, the staff issued RAI 3.5.1.33-2 requesting that the applicant 

enhance the Structures Monitoring Program to include physical manipulation of 10 percent of 

the available surface area of flexible roof membranes, and seals and gaskets (doors, manways, 

and hatches), or state the reason why there is a reasonable assurance that the components will 

meet their CLB intended function(s) absent physical manipulation.

In its response dated July 19, 2012, the applicant stated that, “[t]he Structures Monitoring 

Program will be enhanced to include instructions to augment the visual examinations of roof 

membranes, and seals and gaskets (doors, manways, and hatches) with physical manipulation 

of at least 10 percent of available surface area.” The staff noted that the applicant revised LRA 

Sections A.1.42 and B.1.42 to reflect the new enhancement.

In its review of components associated with item 3.5.1-33, for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Structures Monitoring 

Program and its response to RAI 3.5.1.33-2 acceptable because the Structures Monitoring 
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Program conducts periodic visual examinations enhanced by physical manipulation of at least 

10 percent of the available surface area of flexible polymeric materials and age managing of 

seals; gasket; moisture barriers (caulking, flashing, and other sealants) with the Structures 

Monitoring Program is consistent with the GALL Report. The staff’s concern described in

RAI 3.5.1.33-2 is resolved.

During its evaluation of this item, the staff reviewed UFSAR Chapters 6 and 9. This review 

resulted in the following two RAIs:

The staff noted that UFSAR Table 6.2-49 includes a footnote that applies to penetrations 

associated with the equipment hatch, personnel locks, fuel transfer tube, and guard pipe 

inspection ports that states that the, “[p]enetration is sealed by a blind flange or door with 

double O-ring seals, double expandable seals, double gasket seals, or a weld. These seals are 

leakage rate tested by pressurizing between the seals or gaskets. Because the guard pipe 

inspection ports inboard seal is a weld, Type B testing is not required.” It was not clear to the 

staff whether the seals or gaskets associated with the fuel transfer tube and guard pipe 

inspection ports are being managed by the Containment Leak Rate Program or whether they 

are not considered long-lived passive items. By letter dated June 20, 2012, the staff issued

RAI 3.5.1.33-1 requesting that the applicant state how the seals or gaskets associated with the 

fuel transfer tube and guard pipe inspection ports are being managed, or state that they are not 

considered to be long-lived passive items.

In its response dated July 19, 2012, the applicant stated that there are no seals or gaskets 

associated with the guard pipe inspections ports because sealing of this component is 

accomplished by welding. The applicant also stated that, “[t]he seal for the fuel transfer tube is 

included in LRA Table 3.5.2-1, as part of the AMR item for “rubber seal for airlock doors, 

equipment hatch.” The applicant amended LRA Table 3.5.2-1 to include the wording, “fuel 

transfer tube” within the description of the AMR item for rubber seal for airlock doors, equipment 

hatch. The staff noted that this item is being managed for cracking and change in material 

properties by the Containment Inservice Inspection – IWE and Containment Leak Rate 

Programs and cites item 3.5-1-26 and generic note B. The staff also noted that SRP-LR

Table 3.5-1, item 3.5.1-26 states that the Chapter XI.S1, “ASME Section XI, Subsection IWE,”

should be used to manage loss of sealing due to wear, damage, erosion, tear, surface cracks, 

or other defects.

The staff finds the applicant’s response acceptable because the visual examination and leak 

rate testing performed as part of the Containment Inservice Inspection – IWE and Containment 

Leak Rate Programs are capable of detecting cracking and change in material properties of 

elastomeric seals. The staff noted that typical visual inspections of elastomeric materials are 

accompanied by physical manipulation to detect hardening or loss of strength; however, the 

pressure testing included in the Containment Leak Rate will demonstrate leak tightness that is 

only achievable if the elastomeric materials have not hardened or lost strength. The staff’s 

concern described in RAI 3.5.1.33-1 is resolved.

The staff noted that UFSAR Chapter 9, page 769, 9A.5.2.3n, states, “[t]he blowout shaft, Fire 

Zone 1A124, consists of the remaining horizontal separation distance, which contains concrete 

joint sealant (Rodofoam 11).” It is not clear to the staff whether this concrete joint sealant fulfills 

a license renewal intended function. The staff reviewed the LRA and did not identify an AMR 

item that corresponds to the description of this material. By letter dated June 20, 2012, the staff 

issued RAI 3.5.2.4-2 requesting that the applicant (a) state whether the concrete joint sealant 

(Rodofoam II) has a license renewal intended function, (b) if it does have a license renewal 
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intended function, state whether it is a long-lived passive component, and (c) if both of these 

responses are positive, state what AMR item includes this item.

In its response dated July 19, 2012, the applicant stated that “[t]he concrete joint sealant 

(Rodofoam II) has license renewal intended functions of “fire barrier” and “support for 

Criterion (a)(1) equipment” (SSR). The concrete joint sealant (Rodofoam II) is a long-lived

passive component subject to AMR as indicated in LRA Table 3.5.2-4 by component “Seismic 

isolation joint.” As shown in Table 3.5.2-4, the Fire Protection Program is credited to manage 

aging effects.”

The staff finds the applicant’s response acceptable because the applicant stated that the item is 

in-scope, and it is being age managed by the Fire Protection Program, which is consistent with 

the GALL Report items A-19 and A-20. The staff’s concern described in RAI 3.5.2.4-2 

is resolved.

The staff concludes that for LRA item 3.5.1-33, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.5 Loss of Material Due to General (Steel Only), Pitting, and Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-78, as revised by letter dated June 6, 2012, addresses steel 

components: fuel pool liner exposed to a fluid environment which will be managed for loss of 

material due to pitting and crevice corrosion. The staff noted that SRP item 3.5.1-78 also states 

stainless steel in a treated water environment is susceptible to stress corrosion cracking. 

However, the staff reviewed UFSAR Section 6.2 and noted that the suppression pool 

temperature is at the maximum for normal conditions, which is 95°F, and is below the 

140°F (60°C) threshold for stainless steel in treated water as defined in GALL Report 

Chapter IX.D. For the AMR items that cite generic note E, the LRA credits AMP XI.S6, 

“Structures Monitoring” to manage loss of material for stainless steel weir wall liner plates. The 

GALL Report recommends AMP XI.M2, “Water Chemistry” to ensure that these aging effects 

are adequately managed. GALL Report AMP XI.M2 recommends periodic monitoring of treated 

water in order to minimize loss of material or cracking.

The staff's evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of stainless steel weir wall liner plates through periodic visual examinations. The staff 

also notes, that in its response to RAI B.2.1.13-4, the applicant stated that because the 

Structures Monitoring program specifies opportunistic inspection, the submerged portion of the 

weir wall is typically inspected during the ASME Section XI, Subsection IWE inspections. 

Additional information regarding the inspection of the weir wall liner plates is addressed in SER 

Section 3.0.3.1.12. In its review of components associated with item 3.5.1-78, for which the 

applicant cited generic note E, the staff finds the applicant's proposal to manage aging using the 

Structures Monitoring Program acceptable because surfaces of the stainless steel weir wall liner 

plates are periodically visually inspected for loss of material due to pitting and crevice corrosion.

The staff concludes that for LRA items 3.5.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function will be 

maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).
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3.5.2.1.6 Loss of Material Due to Pitting and Crevice Corrosion, and Cracking Due to Stress

Corrosion Cracking

LRA Table 3.5.1, item 3.5.1-52, addresses Groups 7,8 – steel components: tank liner exposed 

to a fluid environment that will be managed for loss of material due to pitting or crevice corrosion 

and cracking due to SCC. For the AMR items that cite generic note E, the LRA credits the 

Structures Monitoring Program to manage the loss of material due to pitting and crevice 

corrosion aging effect for containment building and RPV pedestal stainless steel sump liners 

and penetrations; water control structures basin debris stainless steel screen and grating, 

stainless steel cooling tower fill, and fan stack stainless steel grating; and turbine building, 

process facilities, and yard structures stainless steel sump liners. The GALL Report

recommends using a plant-specific AMP to ensure that these aging effects are adequately 

managed. The staff noted that the Structures Monitoring Program proposes to manage the 

aging of containment building and RPV pedestal stainless steel sump liners and penetrations; 

water control structures basin debris stainless steel screen and grating, stainless steel cooling 

tower fill, and fan stack stainless steel grating; and turbine building, process facilities, and yard 

structures stainless steel sump liners through the use of visual inspections at 5-year intervals 

using qualified personnel and acceptance criteria based on information provided in industry 

codes, standards, and guidelines, including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R- 96.

The staff's evaluation of the applicant's Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. In its review of components associated with item 3.5.1-52, for which the 

applicant cited generic note E, the staff noted that item 3.5.1-52 addresses both loss of material 

due to pitting and crevice corrosion, and cracking due to stress corrosion cracking. However, in 

LRA Section 3.5.2.2.2.4, the applicant states that there are no tanks with stainless steel liners in 

the structural scope of license renewal. The applicant has indicated that the corresponding 

GALL Report items can be compared to the stainless steel liners of other components, such as 

reactor cavity and containment sump, which are exposed to a fluid environment and may be 

subject to loss of material. The staff also notes that the applicant stated the fluid temperatures, 

for which these components are exposed to, are below the threshold for stress corrosion 

cracking. Therefore, the staff finds the applicant's proposal to manage loss of material due to 

pitting and crevice corrosion using the Structures Monitoring Program is acceptable because 

loss of material will be managed through visual inspections conducted by qualified personnel at 

intervals not to exceed 5 years in accordance with recommendations in NEI 96-03, ANSI/ASCE 

11-99, and ACI 349.3R-02. The applicant's visual examinations for loss of material under the 

Structures Monitoring program are consistent with the recommendations in the GALL Report 

that identifies use of a plant-specific aging management program.

LRA Table 3.5.1, item 3.5.1-52 addresses Groups 7, 8 - steel components: tank liner exposed 

to a fluid environment that will be managed for loss of material due to pitting or crevice 

corrosion. For the AMR items that cite generic note E, the LRA credits the Water Chemistry 

Control – BWR Program to manage the loss of material due to pitting and crevice corrosion for 

containment building upper containment pool stainless steel liner plate and grating, and 

stainless steel spent fuel pool storage racks. The GALL Report recommends using a 

plant-specific AMP to ensure that these aging effects are adequately managed. The staff noted 

that the Water Chemistry Control - BWR Program proposes to manage the aging of containment 

building upper containment pool stainless steel liner plate and grating, and stainless steel spent 

fuel pool storage racks through monitoring and control of water chemistry using EPRI water 

chemistry guidelines.
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The staff’s evaluation of the applicant’s Water Chemistry Control – BWR Program is 

documented in SER Section 3.0.3.1.41. In its review of components associated with 

item 3.5.1-52, for which the applicant cited generic note E, the staff determined the need for 

additional information. Therefore, by letter dated September 12, 2012, the staff issued 

RAI 3.5.1.52-3 requesting the applicant explain how cracking due to stress corrosion cracking of 

these components will be managed to meet the recommendations of GALL Report 

items III.A7.T-23 and III.A8.T-23.

In its response dated October 9, 2012, the applicant stated that,

For stress corrosion cracking (SCC) of stainless steel material in a fluid 

environment (treated water), the temperature of the fluid environment must be 

> 140° F (> 60° C) [NUREG-1801, IX.D Environments, discussed temperature 

thresholds for SCC]. The Grand Gulf Nuclear Station (GGNS) structural 

stainless steel components identified in this RAI are exposed to a fluid 

environment (treated water) at temperatures < 140° F (< 60° C). Therefore, 

cracking due to SCC is not an aging effect requiring management.

The staff noted that the applicant also revised the LRA to reference Table 3.5.1, item 3.5.1-78 

and GALL Report item III.A5.T-14.

The staff reviewed the applicant’s response, and finds that because the components in this 

listing are not exposed to fluid environment (treated water) and temperatures greater than 

140° F (60° C), stress corrosion cracking for these components would not be a concern. 

Additionally, the staff notes that the applicant revised the LRA to reference Table 3.5.1, 

item 3.5.1-78, which appropriately represents the component, material, and environment 

combination, and is consistent with GALL Report item III.A5.T-14. The staff’s concern 

described in RAI 3.5.1.52-3 is resolved.

The staff finds the applicant's proposal to manage loss of material due to pitting and crevice 

corrosion using the Water Chemistry Control - BWR Program acceptable because loss of 

material will be managed by the Water Chemistry Control - BWR Program through monitoring 

and control of water chemistry using EPRI water chemistry guidelines. Additionally, the spent 

fuel pool water level is monitored in accordance with TS, and monitoring leakage from the leak 

test channels will continue during the period of extended operation, which is consistent with the 

GALL Report recommendations and therefore, acceptable.

The staff concludes that for LRA items 3.5.1- 52, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.7 Loss of Material Due to Abrasion and Cavitation

LRA Table 3.5.1, item 3.5.1-56 addresses concrete: exterior above- and below-grade; 

foundation; and interior slab exposed to a fluid environment that will be managed for loss of 

material due to abrasion and cavitation. For the AMR item that cites generic note E, the LRA 

credits the Structures Monitoring Program to manage the aging effect for concrete support 

pedestals. The GALL Report recommends GALL Report AMP XI.S7, “Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” or the 

FERC/US Army Corp of Engineers dam inspections and maintenance programs to ensure that 
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these aging effects are adequately managed. GALL Report AMP XI.S7 recommends 

monitoring and visual inspection at intervals not to exceed 5 years for indications of cracking, 

movements (e.g., settlement, heaving, deflection), conditions at junctions with abutments and 

embankments, loss of material, increase in porosity and permeability, seepage, and leakage to 

manage the aging of these items.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of concrete support pedestals through the use of visual inspections at 5-year intervals 

using qualified personnel and acceptance criteria based on information provided in industry 

codes, standards, and guidelines, including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-96. 

In its review of components associated with item 3.5.1-56 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Structures Monitoring 

Program acceptable because loss of material will be managed through visual inspections 

conducted by qualified personnel at intervals not to exceed 5 years in accordance with 

recommendations in NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-02. The applicant’s AMP 

meets the recommendations in the GALL Report item III.A6.T-20 and therefore is consistent 

with GALL Report AMP XI.S7 “Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants,” which is identified as the appropriate AMP in the GALL

Report.

The staff concludes that for LRA item 3.5.1-56, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.8 Loss of Material and Change in Material Properties Due to Weathering, Chemical 

Degradation, Insect Infestation, Repeated Wetting and Drying, and Fungal Decay

LRA Table 3.5.1, item 3.5.1-62 addresses Group 6: wooden piles and sheeting exposed to 

air – outdoor or soil environments that will be managed for loss of material and change in 

material properties due to weathering, chemical degradation, insect infestation, repeated wetting 

and drying, and fungal decay. For the AMR items that cite generic note E, the LRA credits the 

Structures Monitoring Program to manage the aging effect for treated wooden utility poles and

towers. The GALL Report recommends GALL Report AMP XI.S7, Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants,” to ensure that 

these aging effects are adequately managed. GALL Report AMP XI.S7 recommends 

monitoring and visual inspection at intervals not to exceed 5 years for indications of cracking, 

movements (e.g., settlement, heaving, deflection), conditions at junctions with abutments and 

embankments, erosion, cavitation, seepage, and leakage to manage the aging of these items.

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of wooden utility poles and towers through the use of visual inspections at 5-year 

intervals using qualified personnel and acceptance criteria based on information provided in 

industry codes, standards, and guidelines, including NEI 96-03, ANSI/ASCE 11-99, and 

ACI 349.3R-96. In its review of components associated with item 3.5.1-62, for which the 

applicant cited generic note E, the staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because it meets recommendations in the GALL

Report item III.A6.TP-223 in that its visual inspection requirements are consistent with GALL 
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Report AMP XI.S7, “Regulatory Guide 1.127, Inspection of Water-Control Structures Associated 

with Nuclear Power Plants,” which is identified as the appropriate AMP in the GALL Report.

The staff concludes that for LRA item 3.5.1-62, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation as required by 

10 CFR 54.21(a)(3).

3.5.2.1.9 Loss of Material Due to Corrosion

LRA Table 3.5.1, item 3.5.1-77 addresses steel components: all structural steel exposed to 

air – indoor uncontrolled environment that will be managed for loss of material due to corrosion. 

For the AMR item that cites generic note E, the LRA credits the Structures Monitoring Program

to manage the aging effect for carbon steel monorails. The GALL Report recommends GALL 

Report AMP XI.S6, “Structures Monitoring Program,” and 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. GALL Report AMP XI.S6 recommends 

using periodic visual inspections by qualified personnel, at a frequency not to exceed 5 years, to 

monitor steel components for loss of material.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that the Structures Monitoring Program proposes to manage 

the aging of carbon steel monorails through the use of visual inspections at 5-year intervals 

using qualified personnel and acceptance criteria based on information provided in industry 

codes, standards, and guidelines, including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-96. 

In its review of components associated with item 3.5.1-77 for which the applicant cited generic 

note E, the staff finds the applicant’s proposal to manage aging using the Structures Monitoring 

Program acceptable because loss of material will be managed through visual inspections 

conducted by qualified personnel at intervals not to exceed 5 years in accordance with 

recommendations in NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R-02. The applicant’s AMP 

meets the recommendations in the GALL Report item III.A1.TP-302 and therefore is consistent 

with GALL Report AMP XI.S6,”Structures Monitoring Program,” which is identified as the 

appropriate AMP in the GALL Report.

The staff concludes that for LRA item 3.5.1-77, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.10 Cracking Due to Stress Corrosion Cracking and Loss of Material Due to Pitting and 

Crevice Corrosion

LRA Table 3.5.1, item 3.5.1-78 addresses steel fuel pool liner components that will be managed 

for loss of material due to pitting and crevice corrosion. The LRA states that cracking due to 

SCC is not an aging effect requiring management because there are no in-scope stainless steel 

fuel pool components exposed to treated water greater than 60 °C (140 °F). The staff noted 

that the GALL Report recommends GALL Report AMP XI.M2, “Water Chemistry,” and 

monitoring of the spent fuel pool water level and leakage from the leak chase channels to 

ensure that these aging effects are adequately managed.
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The applicant stated that for item 3.5.1-78, the applicability is limited to the aging effect of loss 

of material. The staff noted that UFSAR Section 9.1.3.2 states that the spent fuel pool water is 

normally maintained below 140 °F, the threshold for SCC defined in the GALL Report

Table IX.D, and therefore, finds the applicant’s claim acceptable.

During its review of components associated with item 3.5.1-78, for which the applicant cited 

generic note A, the staff noted that the LRA credits the Water Chemistry Control – BWR 

Program, the One-Time Inspection Program (as cited in plant-specific note 504), and monitoring 

of the spent fuel pool water level to manage cracking for the spent fuel pool liner and gate. 

However, the staff also noted that LRA item 3.5.1-78 states that loss of material is the only 

applicable aging effect and monitoring of leakage in the leak chase channels is an additional 

aging management activity. The staff further noted that the applicant credits monitoring of the 

spent fuel pool water level as an aging management activity for the spent fuel storage racks. By 

letter dated May 24, 2012, the staff issued RAI 3.5.1.78-1 requesting that the applicant 

(a) clarify which aging effects are applicable to the spent fuel pool liner and gate; (b) remove 

monitoring of the spent fuel pool water level as an aging management activity for the spent fuel 

storage racks, or justify why this activity is capable of managing degradation of the racks; 

(c) resolve a discrepancy between LRA item 3.5.1-78 and the associated ARM items regarding 

the use of the One-Time Inspection Program; and (d) revise the AMR items associated with 

spent fuel pool liner and gate to include monitoring of leakage in the leak chase channels.

In its response dated June 22, 2012, the applicant (a) revised the AMR item for the spent fuel 

pool liner and gate to state that loss of material is the only applicable aging effect; (b) revised 

the AMR item for the spent fuel storage racks to delete monitoring of pool water level as an 

aging management activity; (c) clarified that the One-Time Inspection Program is used to verify 

the effectiveness of the Water Chemistry program for items associated with LRA item 3.5.1-78, 

although the description of this item in LRA Table 3.5.1 does not discuss this activity; and 

(d) revised the AMR item associated with the spent fuel pool liner plate and gate to state that 

monitoring of leakage from the leak chase channels is an aging management activity for 

these structures.

The staff finds the applicant’s response acceptable because the management of loss of material 

for the spent fuel pool liner and gate with the Water Chemistry Control – BWR Program and 

monitoring of water level and leakage is consistent with SRP-LR Table 3.5-1, item 78, given that 

cracking is not an expected aging effect for water environments below 60 °C (140 °F). Also, the 

use of the One-Time Inspection Program to verify the effectiveness of water chemistry controls 

provides additional assurance that degradation of spent fuel pool liner and gate will be identified 

prior to loss of intended functions. Further, the management of the spent fuel storage racks for 

loss of material with the Water Chemistry Control – BWR and One-Time Inspection Programs is 

consistent with the guidance in the GALL Report item VII.A2.A-98, as revised by license 

renewal interim staff guidance, LR-ISG-2011-01. The staff’s concern described in

RAI 3.5.1.78-1 is resolved.

The staff concludes that for LRA item 3.5.1-78, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).
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3.5.2.1.11 Loss of Material Due to General and Pitting Corrosion

LRA Table 3.5.1, item 3.5.1-92 addresses support members; welds; bolted connections; and 

support anchorage to building structures exposed to an air – indoor uncontrolled environment 

that will be managed for loss of material due to general and pitting corrosion. For the AMR item 

that cites generic note E, the LRA credits the Fire Water System Program to manage the aging 

effect for fire hose reels. The GALL Report recommends using GALL Report AMP XI.S6,

“Structures Monitoring,” to ensure that these aging effects are adequately managed. GALL

Report AMP XI.S6 recommends using periodic visual inspections by qualified personnel, at a 

frequency not to exceed 5 years, to monitor steel components for loss of material.

The staff’s evaluation of the Fire Water System Program is documented in SER 

Section 3.0.3.1.20. The staff noted that the Fire Water System Program proposes to manage 

the aging of carbon steel fire hose reels through the use of periodic inspections of hose reels for 

degradation using acceptance criteria that specify no unacceptable degradation. In its review of 

components associated with item 3.5.1-92 for which the applicant cited generic note E, the staff 

finds the applicant’s proposal to manage aging using the Fire Water System Program

unacceptable because insufficient information is provided to demonstrate that the program 

meets the recommendations provided in GALL Report item III.B2.TP-43 with respect to 

frequency of inspections, qualifications of inspection personnel, and acceptance criteria. By 

letter dated June 27, 2012, the staff issued RAI 3.5.2.4-4 requesting that the applicant describe 

how the applicant’s Fire Water System Program meets the recommendations in GALL Report

item III.B2.TP-43.

In its response dated July 25, 2012, the applicant stated that Element 4 of the Fire Water 

System AMP includes an enhancement for visual inspection of the hose reels that aligns it with 

the XI.S6, “Structures Monitoring,” for detection of loss of material due to corrosion of steel 

components. The applicant stated that the acceptance criteria have been revised to verify the 

presence of no unacceptable degradation, that inspections are performed annually, and 

qualifications of the personnel performing inspections are consistent with industry guidelines 

and standards, including the requirements of 10 CFR 50.65.

The staff finds the applicant‘s response acceptable because the fire hose reels will be inspected 

by qualified personnel, at an interval more frequent than the 5-year interval recommended by 

the Structures Monitoring Program, and because the inspections will verify the presence of no 

unacceptable degradation. The staff’s concern described in RAI 3.5.2.4-4 is resolved.

The staff concludes that for LRA item 3.5.1-92, the applicant has demonstrated that the effects 

of aging for these components will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as required by 

10 CFR 54.21(a)(3).

3.5.2.1.12 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.5.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 
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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 

consistent.

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 structures and component supports components and provides 

information concerning how it will manage aging effects in the following three areas:

(1) PWR and BWR containments:

• 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

• reduction of strength and modulus 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

• loss of material (scaling, spalling) and cracking due to freeze-thaw

• cracking due to expansion and reaction with aggregates

• increase in porosity and permeability due to leaching of calcium hydroxide and 

carbonation

(2) safety-related and other structures and component supports:

• aging management of inaccessible areas

• reduction of strength and modulus 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

• cumulative fatigue damage due to fatigue

(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 

audited and reviewed the applicant’s evaluation to determine whether it adequately addressed 

the issues further evaluated. In addition, the staff reviewed the applicant’s further evaluations 

against the criteria contained in SRP-LR Section 3.5.2.2. The staff’s review of the applicant’s 

further evaluation follows.
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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 

address several areas:

Cracking and Distortion Due to Increased Stress Levels from Settlement; Reduction of 

Foundation Strength, and Cracking Due to Differential Settlement and Erosion of Porous 

Concrete Subfoundations. LRA Section 3.5.2.2.1.1, associated with LRA Table 3.5.1, 

items 3.5.1-1 and 3.5.1-2, addresses concrete components exposed to either a soil or flowing 

water environment. Cracking and distortion due to increased stress levels from settlement 

could occur in PWR and BWR concrete and steel containments. The existing program relies on 

ASME Section XI, Subsection IWL, to manage these aging effects. Also, reduction of 

foundation strength and cracking, due to differential settlement and erosion of porous concrete 

subfoundations could occur in all types of PWR and BWR containments. The existing program 

relies on the Structures Monitoring Program to manage these aging effects. However, some 

plants may rely on a dewatering system to lower the site groundwater level. If the plant’s CLB

credits a dewatering system to control settlement, the GALL Report recommends further 

evaluation to verify the continued functionality of the dewatering system during the period of 

extended operation. The GALL Report recommends GALL Report AMP XI.S2, “ASME 

Section XI, Subsection IWL Program,” to manage for cracks and distortion due to increased 

stress levels from settlement, and GALL Report AMP XI.S6,”Structures Monitoring,” to manage 

for a reduction of foundation strength, cracking, and differential settlement due to erosion of 

porous concrete subfoundations. For plants that rely on a dewatering system to lower the site 

groundwater level and control settlement in CLB, the GALL Report recommends further 

evaluation to verify the continued functionality of the dewatering system during the period of 

extended operation.

The applicant stated that these items: cracking and distortion due to increased stress levels 

from settlement are managed by the Containment Inservice Inspection – IWL Program; GGNS 

does not employ a dewatering system; GGNS does not have an aggressive groundwater, does 

not utilize porous concrete subfoundations, and was not identified as a plant susceptible to 

subfoundation erosion (see IN 97-11); Category I structures, except the diesel generator 

building which is founded on compacted structural backfill, are founded on the Catahoula 

Formation consisting of hard-to-very-hard silty-to-sandy clay, clayey silt, and locally indurated or 

cemented clay, silt, and sand layers; and a settlement monitoring program exists. The staff 

evaluated the applicant’s claim by reviewing UFSAR Section 3.8.5, “Foundations,” and LRA 

Section 3.5 and finds it acceptable because the containment foundations are founded on the 

Catahoula Formation, GGNS does not employ a dewatering system or use porous concrete 

subfoundations, and the containment structure is monitored for cracking and distortion by the 

Containment Inservice Inspection – IWL Program.

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.1.2 

associated with LRA Table 3.5.1, item 3.5.1-3 addresses concrete structures exposed to either 

an air- indoor uncontrolled or air-outdoor environment that will be managed for reduction of 

strength and modulus of elasticity due to elevated temperature exposure by the Containment 

Inservice Inspection – IWL Program and Structures Monitoring Program. The criteria in SRP-LR 

Section 3.5.2.2.1.2 states that reduction in strength and modulus of concrete could occur for 

PWR and BWR concrete and steel containments exposed to temperatures in excess of those 

specified in Subsection CC-3440 of ASME Section III, Division 2, for general areas 66  ̊C 

(150  ̊F) and local areas 93  ̊C (200  ̊F). The SRP-LR also states that the GALL Report

recommends further evaluation of a plant-specific AMP if any portion of the concrete 
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containment components exceed specified temperature limits (i.e., general area temperature 

greater than 66  ̊C [150  ̊F] and local area temperature greater than 93  ̊C [200  ̊F]). The 

applicant addressed the further evaluation criteria of the SRP-LR by stating that this item is not 

applicable because during normal operation areas within containment are maintained below a 

bulk average temperature of 57  ̊C (135  ̊F), and for areas in the cylinder wall where piping 

penetrations carry hot fluid (pipe temperature greater than 93  ̊C [200  ̊F]) cooling of the 

concrete is provided by either cooling fins or water jackets to maintain the concrete temperature 

adjoining the embedded sleeve at or below 93  ̊C (200  ̊F). The applicant also stated that the 

containment structure is monitored for cracking or indications of a change in material properties 

by the Containment Inservice Inspection – IWL Program.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and Structure 

Monitoring Programs are documented in SER Sections 3.0.3.1.13 and 3.0.3.1.40, respectively. 

In its review of components associated with item 3.5.1-3, the staff finds that the applicant has 

met the further evaluation criteria, and the applicant’s proposal to manage aging using the 

Containment Inservice Inspection – IWL and Structure Monitoring Programs are acceptable 

because the applicant noted that the containment concrete temperatures are below the limits 

provided in Subsection CC-3440 of ASME Section III, Division 2, for both general and 

local areas.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.1.2 criteria. 

For the AMR items associated with LRA Section 3.5.2.2.1.2, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Loss of Material Due to General, Pitting, and Crevice Corrosion.

(1) Steel elements of inaccessible areas for all types of PWR and BWR containments. LRA 

Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-4 addresses 

inaccessible areas steel elements (drywell shell, drywell head, and drywell shell) 

exposed to either an air-indoor uncontrolled or concrete environment. The GALL Report

recommends GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE Program,”

and GALL Report AMP XI.S4, “10 CFR Part 50, Appendix J Program,” to manage for 

loss of material due to general, pitting, and crevice corrosion for this component group. 

The applicant stated that this item is not applicable because it applies only to Mark III 

steel containments, however, the applicant stated that the steel liner plate and areas 

where the steel liner becomes embedded in the concrete floor will be monitored through 

inspections in accordance with the Containment Inservice Inspection – IWE and 

Containment Leak Rate Programs. The staff evaluated the applicant‘s claim by 

reviewing LRA Sections 2.4.1 and 3.5 and finds it acceptable because the GGNS 

containment uses a Mark III reinforced concrete containment. The staff also noted that 

the applicant’s AMPs meet the recommendations in GALL Report item II.B3.1.CP-113 

and therefore is consistent with inspections performed under GALL Report AMP XI.S1, 

“ASME Section XI, Subsection IWE Program,” and GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J Program,” which are identified as the appropriate AMPs in 

the GALL Report for steel elements in inaccessible areas.

LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-5, addresses 

inaccessible areas steel elements (liner, liner anchors, and integral attachments) 

exposed to air-indoor uncontrolled environment that will be managed for loss of material 

due to general, pitting, or crevice corrosion by the Containment Inservice Inspection –
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IWE and Containment Leak Rate Programs. The criteria in SRP-LR Section 3.5.2.2.1.3 

item 1 state that loss of material due to general, pitting, and crevice corrosion could 

occur in steel elements of inaccessible areas for all types of PWR and BWR 

containments. The SRP-LR recommends further evaluation if corrosion is indicated by 

ASME Section XI Subsection IWE examinations. GALL Report item II.B3.2.CP-98 

states that for inaccessible areas (embedded steel shell or liner); loss of material due to 

corrosion is not significant if the following four conditions are satisfied:

(1) Concrete meeting the specifications 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 is not 

common and when detected is cleaned up in a timely manner

The applicant addressed the further evaluation criteria of the SRP-LR by stating that this 

item is not applicable because the GGNS reinforced concrete containment interior and 

exterior surfaces of the liner in inaccessible areas are protected from contact with the 

atmosphere by complete concrete encasement. The applicant also stated that it is not 

credible for groundwater to reach this portion of the liner since the base mat concrete at 

this location is greater than 5-foot-thick and poured in multiple horizontal planes. The 

applicant further stated that a waterproof membrane and work slab is constructed below 

this area, interior concrete is monitored for cracks under the Structures Monitoring 

Program, and areas where the steel liner becomes embedded in the concrete floor are 

inspected in accordance with the Containment Inservice Inspection – IWE and 

Containment Leak Rate Programs.

In its review of components associated with item 3.5.1-5 the staff found that conditions 

two and four above were adequately addressed, however, the LRA did not discuss 

condition one and three adequately in that it was not specified how guidance contained 

in ACI 201.2R as specified in GALL Report item II.B3.2.CP-98 was met and whether or 

not a moisture barrier was located at the junction where the liner becomes embedded in 

the concrete. By letter dated June 27, 2012, the staff issued RAI 3.5.2.2.1.3-1 

requesting that the applicant explain how the containment concrete in contact with the 

embedded steel liner met the guidance contained in ACI 201.2R as specified in the 

GALL Report, and if a moisture barrier was employed at the junction where the liner 

becomes embedded in the concrete.

In its response dated July 25, 2012, the applicant stated that the GGNS concrete 

structures were designed and constructed in accordance with ACI 318-72, which meets 

many of the recommendations of ACI 201.2R by providing low permeability concrete 

using a low water-cement ratio based on minimum slump. ACI 318 provides 

recommendations for selection of cement, aggregates, air-entraining admixtures, 

water-cement ratio, and reinforcing bar to attain a workable, consistent concrete mixture 

to produce a durable concrete structure with required compressive strength (i.e., original 

construction specification for GGNS containment structure required 5,000 psi concrete 

compressive strength). ACI 318 also provides requirements for concrete placement and 

curing to ensure that the required concrete quality, durability, and strength are attained. 
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The applicant further stated that GGNS does not have a moisture barrier at the junction 

where the containment liner becomes embedded in the concrete, but the liner plate is 

stainless steel at the lower containment elevations where it is embedded in concrete.

The staff finds the applicant’s response acceptable because the applicant designed the 

structures, selected the materials, developed the concrete mix designs, and placed and 

cured the concrete in compliance with ACI 318-71 requirements designed to ensure the 

required concrete quality, durability, and strength are attained. The staff noted that the 

original construction specification for GGNS containment structure required 5,000 psi 

concrete compressive strength, which would indicate that the concrete was dense and of 

high quality. Therefore, the concrete in contact with the embedded steel liner meets the 

guidance contained in ACI 201.2R. The staff also finds the applicant’s response 

acceptable that a moisture barrier is not provided at the junction where the containment 

liner becomes embedded in the concrete because, as noted in UFSAR 

Section 3.8.1.1.2, the containment base mat liner was fabricated from ASTM A240 

Type 304 stainless steel plates. The staff’s concern described in RAI 3.5.2.2.1.3-1 is 

resolved.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWE and 

Containment Leak Rate Programs is documented in SER Sections 3.0.3.1.12 and 

3.0.3.1.14, respectively. The staff finds that the applicant has met the further evaluation 

criteria, and the applicant’s proposal to manage aging using the Containment Inservice 

Inspection – IWE and Containment Leak Rate Programs is acceptable because the 

applicant proposes to manage the aging of inaccessible areas of steel elements using 

the Containment Inservice Inspection – IWE and Containment Leak Rate Program, 

which are the GALL Report recommended programs, and because the applicant has 

satisfied the four conditions identified in GALL Report item II.B3.2.CP-98.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.1.3 

item 1 criteria. For those AMR items associated with LRA Section 3.5.2.2.1.3, item 1, 

the staff concludes that the LRA is consistent with the GALL Report and that the 

applicant has demonstrated that the effects of aging will be adequately managed so that 

the intended 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) Steel torus shell of Mark I containments. LRA Table 3.5.1, item 3.5.1-6 addresses the 

steel torus shell of Mark I containments exposed to either an air-indoor uncontrolled or 

treated water environment. The GALL Report recommends GALL Report AMP XI.S1, 

“ASME Section XI, Subsection IWE Program,” and GALL Report AMP XI.S4, 

“10 CFR Part 50, Appendix J, Program,” to manage for loss of material due to general, 

pitting, and crevice corrosion for this component group. The applicant stated that this 

item is not applicable because GGNS uses a Mark III reinforced concrete containment 

that does not contain a steel torus shell. The staff evaluated the applicant’s claim by 

reviewing LRA Sections 2.4.1 and 3.5 and finds it acceptable because the GGNS uses a 

Mark III reinforced concrete containment that does not include a torus.

(3) Steel torus ring girders and downcomers of Mark I containments, downcomers of Mark II 

containments, and interior surface of suppression chamber shell of Mark III 

containments. LRA Section 3.5.2.2.1.3 associated with LRA Table 3.5.1, item 3.5.1-7 

addresses steel torus ring girders and downcomers of Mark I containments, 

downcomers of Mark II containments, and the interior surface of the suppression 

chamber shell of Mark III containments exposed to either a treated water or air-indoor 

uncontrolled environment that will be managed for loss of material due to general, 

pitting, and crevice corrosion by the Containment Inservice Inspection – IWE Program. 
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The criteria in SRP-LR Section 3.5.2.2.1.3 item 3 state that loss of material due to 

general, pitting, or crevice corrosion could occur for steel torus ring girders and 

downcomers of Mark I containments, downcomers of Mark II containments, and the 

interior surface of the suppression chamber shell of Mark III containments. The SRP-LR 

also states that further evaluation is required if plant operating experience has identified 

significant corrosion and recommends GALL Report AMP XI.S1, “ASME Section XI, 

Subsection IWE.” The applicant addressed the further evaluation criteria of the SRP-LR 

by stating that GGNS is a reinforced concrete Mark III containment with a steel liner and 

suppression chamber and does not have a torus ring girder or downcomers. The 

applicant also stated that although this item is only applicable to Mark I and Mark III steel 

containments, the steel liner plate, suppression pool interior surface, and areas where 

the steel liner becomes embedded in the concrete floor will be inspected in accordance 

with the Containment Inservice Inspection – IWE Program for aging effects such as loss 

of material.

The staff’s evaluation of the applicant‘s Containment Inservice Inspection – IWE 

Program is documented in SER Sections 3.0.3.1.12. The staff noted that the 

Containment Inservice Inspection – IWE Program will be used to manage the loss of 

material of the GGNS suppression chamber shell interior surface. In its review of 

components associated with item 3.5.1-7, the staff finds the applicant has met the further 

evaluation criteria, and the applicant’s proposal to manage aging using the Containment 

Inservice Inspection – IWE Program is acceptable because the applicant’s AMP is 

consistent with inspections performed under GALL Report AMP XI.S1, “ASME 

Section XI, Subsection IWE Program,” which is identified as the appropriate AMP in the 

GALL Report.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.1.3 

criteria. For those items associated with LRA Section 3.5.2.2.1.3 item 3, the staff 

concludes that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB during the period of extended 

operation, as required by 10 CFR 54.21(a)(3).

Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. LRA 

Section 3.5.2.2.1.4 associated with LRA Table 3.5.1, item 3.5.1-8, addresses steel prestressing 

tendons exposed to either an air- indoor uncontrolled or air-outdoor environment. The 

GALL Report identifies the loss of prestress due to relaxation, shrinkage, creep and elevated 

temperature as a TLAA. The applicant stated that this item is not applicable because the GGNS 

concrete containment is not prestressed and therefore does not incorporate steel prestressing 

tendons so a TLAA is not required. The staff evaluated the applicant’s claim by reviewing 

Chapter 3.8 of the UFSAR and LRA Sections 2.4.1 and 3.5 and finds it acceptable because the 

GGNS has a Mark III containment, which is a “[r]einforced concrete cylindrical structure (not 

prestressed) with hemispherical head; steel lined,” per UFSAR Table 1.3-4, “Comparison of 

Containment Design Characteristic.”

Cumulative Fatigue Damage. LRA Section 3.5.2.2.1.5 associated with LRA Table 3.5.1, 

item 3.5.1-9 addresses suppression pool steel shells (including welded joints) and penetrations 

(including penetration sleeves, DM welds, and penetration bellows) for all types of PWR and 

BWR containments and BWR vent header, vent line bellows, and downcomers exposed to 

either an air-indoor uncontrolled, treated water, or air-outdoor environment that will be managed 

for cumulative fatigue damage due to cyclic loading by a TLAA only if CLB fatigue analysis 

exists. The criteria in SRP-LR Section 3.5.2.2.1.5 state that if included in the CLB, fatigue 
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analyses of suppression pool steel shells (including welded joints) and penetrations (including 

penetration sleeves, DM welds, and penetration bellows) for all types of PWR and BWR 

containments and BWR vent header, vent line bellows, and downcomers are TLAAs as defined 

in 10 CFR 54.3, and TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c). 

The evaluation of this TLAA is addressed in Section 4.6 of the SRP-LR.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that fatigue is a 

TLAA and is required to be evaluated in accordance with 10 CFR 54.21(c) and is documented in 

LRA Section 4.6, “Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analysis.”

The staff’s evaluation of the applicant’s TLAAs is documented in SER Chapter 4. The staff 

noted that TLAAs of the containment liner plate, metal containments, and containment 

penetrations are addressed in LRA Sections 4.6.1 and 4.6.2. In its review of components 

associated with item 3.5.1-9, the staff finds that the applicant has met the further evaluation 

criteria, and the applicant’s proposal to manage aging using TLAAs is acceptable because the 

required TLAAs have been completed.

Cracking Due to Stress Corrosion Cracking. LRA Section 3.5.2.2.1.6 associated with

Table 3.5.1, item 3.5.1-10, addresses stainless steel penetration sleeves and penetration 

bellows, exposed to air-indoor uncontrolled and will be manage for cracking by Containment 

Leak Rate, Containment Inservice Inspection – IWE, and Fatigue Monitoring programs.

The criteria in SRP-LR Section 3.5.2.2.1, item 6, states that cracking could occur for stainless 

steel penetration sleeves and bellows exposed to air-indoor uncontrolled. The SRP-LR also 

states that cracking due to SCC of stainless steel penetration bellows and DM welds could 

occur in all types of PWR and BWR containments. The SRP-LR also states that the existing 

program relies on GALL Report AMP XI.S1, “ASME Section XI, Subsection IWE,” and 

AMP XI.S4, “10 CFR Part 50, Appendix J,” to manage this aging effect. The SRP-LR further 

states that the GALL Report recommends further evaluation of additional appropriate 

examinations and evaluations implemented to detect these aging effects for stainless steel 

penetration bellows and DM welds.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that SCC is an 

aging mechanism that requires the simultaneous action of an aggressive chemical environment, 

sustained tensile stress, and a susceptible material and elimination of any one of these 

elements will eliminate susceptibility to SCC. The applicant also stated that stainless steel 

elements of containment, including dissimilar welds, are not susceptible to SCC, because they

are not subject to an aggressive chemical environment. The applicant further stated that a 

review of plant operating experience did not identify cracking of these components and 

containment pressure boundary functions have not been identified as a concern. The absence 

of SCC aging effects is confirmed under the Fatigue Monitoring, Containment Inservice 

Inspection – IWE and Containment Leak Rate Programs.

The staff evaluations of the applicant’s Containment Leak Rate, Containment Inservice 

Inspection – IWE, and Fatigue Monitoring Programs are documented in SER 

Sections 3.0.3.1.14, 3.0.3.1.12 and 3.0.3.1.18, respectively. The staff noted that the 

Containment Inservice Inspection – IWE Program includes augmented surface examinations to 

detect fine cracks.
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In its review of the components associated with LRA Table 3.5.1, item 3.5.1-10, the staff finds 

that the applicant has met the further evaluation criteria, and the applicant’s proposal to manage 

aging using the Containment Leak Rate, Containment Inservice Inspection – IWE and Fatigue 

Monitoring Programs are adequate because the existing Containment Inservice Inspection –

IWE Program includes augmented examinations to detect fine cracks which will adequately 

manage aging during the period of extended operation, consistent with the GALL Report.

Based on the programs identified, the staff determines that the applicant’s program meets the 

SRP-LR Section 3.5.2.2.1, item 6, criteria. For those items associated with LRA 

Section 3.5.2.2.1.6, item 6, the staff concludes that the LRA is consistent with the GALL Report 

and that the applicant has demonstrated that the effects of aging will be adequately manage so 

that the intended function will be maintained consistent with the CLB during the period of 

extended operation as required by 10 CFR 54.21(a)(3).

Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw. LRA Section 3.5.2.2.1.7 

associated with LRA Table 3.5.1, item 3.5.1-11 addresses concrete in inaccessible areas of 

dome, wall, basemat, ring girders, and buttresses exposed to a freeze-thaw environment that 

will be managed for loss of material and cracking due to freeze-thaw by the Containment 

Inservice Inspection – IWL and Structures Monitoring Programs. The criteria in SRP-LR 

Section 3.5.2.2.1.7 state that loss of material (scaling, spalling) and cracking due to freeze-thaw 

could occur in inaccessible areas of PWR and BWR containments and the GALL Report

recommends further evaluation of this aging effect for plants located in moderate to severe 

weathering conditions. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that this item is not applicable because GGNS inaccessible and accessible concrete 

areas are designed in accordance with ACI 318, “Building Code Requirements for Reinforced 

Concrete.” Concrete quality was determined by following guidance in Subsection 4.2.5 and

Table 4.2.5 in ACI 318; and the concrete meets requirements specified in American Society for 

Testing and Materials (ASTM) standards for selection, application, and testing of concrete and 

concrete aggregate. The applicant also stated that the absence of concrete aging effects is 

confirmed under the Containment Inservice Inspection – IWL and Structures Monitoring 

Programs.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and Structures 

Monitoring Programs is documented in SER Sections 3.0.3.1.13, and 3.0.3.1.40, respectively. 

The staff noted that the concrete structures were designed in accordance with ACI 318; the 

concrete structures meet requirements for selection, application, and testing of concrete and 

aggregate; and loss of material (scaling, spalling) and cracking due to freeze-thaw are managed 

by the Containment Inservice Inspection – IWL and Structures Monitoring Programs. In its 

review of components associated with item 3.5.1-11, the staff finds that the applicant has met 

the further evaluation criteria, and the applicant’s proposal to manage aging using the 

Containment Inservice Inspection – IWL and Structures Monitoring Programs acceptable 

because: a review of Section 3.8.1, “Concrete Containment,” of the UFSAR, LRA 

Sections 2.4.1 and 3.5, and plant operating experience noted that the entrained air content is 

within 2 to 6 percent and no degradation due to freeze-thaw effects has been identified in 

accessible concrete areas. Concrete structures were designed in accordance with ACI 318, 

and the concrete structures meet requirements for selection, application, and testing of concrete 

and aggregate.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.1.7 criteria. 

For those items associated with LRA Section 3.5.2.2.1.7, the staff concludes that the LRA is 

consistent with the GALL Report and 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 during the period of extended operation, as required by 10 CFR 54.21(a)(3).

Cracking Due to Expansion and Reaction with Aggregates. LRA Section 3.5.2.2.1.8 associated 

with LRA Table 3.5.1 item 3.5.1-12 addresses concrete in inaccessible areas (containment, 

dome, wall, basemat, ring girders, buttresses, and concrete fill-in annulus) exposed to any 

environment that will be managed for cracking due to expansion from reaction with aggregates 

by the Containment Inservice Inspection – IWL and Structures Monitoring Programs. The 

criteria in SRP-LR Section 3.5.2.2.1.8 state that cracking due to expansion from reaction with 

aggregates could occur in inaccessible areas of concrete elements of PWR and BWR concrete 

and steel containments. The SRP-LR also states that a plant-specific AMP is not required to 

manage cracking and expansion due to reaction with aggregate or concrete in inaccessible 

areas if: (1) as described in NUREG-1557, “Summary of Technical Information and Agreements 

from Nuclear Management and Resources Council Industry Reports Addressing License 

Renewal,” investigations, tests, and petrographic examinations of aggregates performed in 

accordance with ASTM C295 and other ASTM reactivity tests, as required, can demonstrate 

that those aggregates do not adversely react within concrete; or (2) for potentially reactive 

aggregates, aggregate concrete reaction is not significant if it is demonstrated that the in-place 

concrete can perform its intended function. The applicant addressed the further evaluation 

criteria of the SRP-LR by stating that is not applicable because GGNS concrete was designed in 

accordance with ACI 318, “Building Code Requirements for Reinforced Concrete,” which 

requires the potential reactivity of aggregates to be tested in accordance with ASTM C289 and 

ASTM C227. The applicant also stated that the aggregate materials were evaluated in 

accordance with ASTM C295 and the absence of concrete aging effects is confirmed under the 

Containment Inservice Inspection – IWL and Structures Monitoring Programs.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and Structures 

Monitoring Programs is documented in SER Sections 3.0.3.1.13, and 3.0.3.1.40, respectively. 

The staff noted that GGNS concrete was designed in accordance with ACI 318, “Building Code 

Requirements for Reinforced Concrete,” which requires the potential reactivity of aggregates to 

be tested in accordance with ASTM C289 and ASTM C227; aggregate materials were evaluated 

in accordance with ASTM C295; and the absence of concrete aging effects is confirmed under 

the Containment Inservice Inspection – IWL and Structures Monitoring Programs. In its review 

of components associated with item 3.5.1-12, the staff finds that the applicant has met the 

further evaluation criteria; however, the staff determined the need for additional information. 

NRC IN 2011-20, “Concrete Degradation by Alkali-Silica Reaction (ASR),” was issued to inform 

industry of operating experience related to concrete degradation due to ASR. IN 2011-20 was 

issued on November 18, 2011, which is after the NRC received the GGNS LRA on 

November 1, 2011. Therefore, by letter dated August 16, 2012, the staff issued RAI 3.5.1.12-1 

requesting the following information:

(a) State whether this operating experience is applicable to GGNS; and, if applicable, 

provide action(s) and/or program to manage this aging effect during the period of 

extended operation.

(b) Provide the technical justification as to why the AMR items associated with cracking due 

to expansion from reaction with late- or slow-expanding aggregates are not applicable, 

and why this aging effect does not require aging management at GGNS.

(c) If it is determined that a revision is needed to LRA Table 3.5.1, items 3.5.1-12, 3.5.1-43, 

and 3.5.1-50, as necessary, revise further evaluation Sections 3.5.2.2.1.8, 3.5.2.2.2.1.2, 

and 3.5.2.2.2.3.2; respectively, provide clarification in the evaluation of these sections.
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In its response dated September 13, 2012, the applicant stated:

(a) Grand Gulf Nuclear Station (GGNS) operating experience has not identified cracking 

due to expansion from reaction with aggregates as an aging effect requiring 

management for accessible and inaccessible concrete areas of structures. Furthermore, 

inspections of concrete structures at GGNS which are routinely performed under the 

Structures Monitoring, RG 1.127 and Containment Inservice Inspection – IWL Programs 

have shown no evidence of alkali-silica reaction (ASR) on concrete. However, as shown 

in LRA Table 3.5.1, concrete GGNS structures within the scope of license renewal will 

continue to be inspected during the period of extended operation (PEO) for any evidence 

of ASR. If concrete inspection results reveal cracking or any evidence of ASR, the site 

corrective action program requires evaluation of the condition and determination of 

appropriate corrective action.

(b) Consistent with NUREG-1801 (the GALL Report) (e.g., item II.A1.CP-67), an aging 

management program is not required if (1) as described in NUREG-1557, investigations, 

tests, and petrographic examinations of aggregates performed in accordance with 

ASTM C 295 and other ASTM reactivity tests, as required, can demonstrate that those 

aggregates do not adversely react within concrete, or (2) for potentially reactive 

aggregates, aggregate concrete reaction is not significant if it is demonstrated that the 

in-place concrete can perform its intended function. GGNS Class I structures and 

containment accessible and inaccessible concrete (walls, dome, and basemat ring 

girder) is designed in accordance with ACI standard ACI 318, (Building Code 

Requirements for reinforced concrete) and GGNS concrete specification requires that 

the potential reactivity of aggregates be tested in accordance with ASTM C 289 and 

ASTM C 227. Also ASTM C 295 was used to identify elements in the aggregate, such 

as aggregates containing strained quartz or microcrystalline quartz, which may be 

unfavorably reactive with alkalis in cement. Furthermore GGNS concrete structures are 

constructed of a dense, durable mixture of sound coarse aggregate, fine aggregate, 

cement, water, and admixture resulting in low permeability concrete which reduces the 

effects of ASR. Cement used in construction of GGNS was Portland Cement Type II, 

low alkali, conforming to ASTM C 150-72, Standard Specification for Portland Cement. 

The sum of the tricalcium silicate and tricalcium aluminate did not exceed 55 percent (in 

accordance with Footnote C, Table 1A on optional Chemical Requirements, ASTM C 

150-72). GGNS cement does not contain more than 0.60 percent total alkali equivalent 

and concrete included pozzolan as an admixture. Furthermore, as discussed in part a. 

above, inspections of concrete at GGNS have been routinely completed with no 

evidence of ASR. Therefore cracking, due to expansion from reaction with late- or slowexpanding aggregates, is not an aging effect requiring management for GGNS concrete 

structures. Nevertheless, ongoing activities of the Structures Monitoring, RG 1.127 and 

Containment lnservice Inspection IWL programs include inspections that are capable of 

identifying degradation, if any, attributable to ASR.

(c) A revision to the LRA is not required.

The staff's evaluations of the applicant’s Containment Inservice Inspection IWL, Structures 

Monitoring and RG 1.127 Programs are documented in SER Sections 3.0.3.1.13, 3.0.3.1.40, 

3.0.3.1.37, respectively. The staff noted that the concrete structures were constructed from 

aggregates selected in conformance with specifications and materials conforming to ACI and 

ASTM standards at the time of construction, water/cement ratios and air entrainment 

percentages are within limits provided in ACI 318, “Building Code Requirements for Structural 

Concrete and Commentary” and degradation due to ASR would be identified during inspections 
3-465

performed under the Containment Inservice Inspection – IWL, Structures Monitoring and 

RG 1.127 Programs. In its review of components associated with LRA items 3.5.1-12, 19, 43,

50, and 54 the staff finds the applicant's proposal to manage aging using the Containment 

Inservice Inspection – IWL, Structures Monitoring or RG 1.127 programs are acceptable 

because Section 3.8.1.6.2, “Concrete,” of the UFSAR indicates that the aggregate materials 

complied with ASTM C33, “Standard Specifications for Concrete Aggregates” which notes that 

the aggregate materials should be evaluated for potential reactivity using ASTM C289, 

“Standard Test Method for Potential Alkali-Silica Reactivity of Aggregates.” For test results that 

exhibit potentially deleterious character subsequent testing in accordance with ASTM C227, 

“Standard Test Method for Potential Alkali Reactivity of Cement-Aggregates Combinations” or 

C1293, “Test Method for Concrete Aggregates by Determination of Length Change of Concrete 

Due to Alkali-Silica Reaction,” to verify the potential for expansion in concrete may be 

warranted. Furthermore, a review of operating experience has not identified cracking due to 

expansion from reaction with aggregate materials in accessible concrete structures. The staff’s 

concern described in RAI 3.5.1.12-1 is resolved.

The staff determines that the applicant's evaluation meets SRP-LR Section 3.5.2.2.1.8 criteria. 

For those items associated with LRA Section 3.5.2.2.1.8, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3).

Increase in Porosity and Permeability Due to Leaching of Calcium Hydroxide and Carbonation. 

LRA Section 3.5.2.2.1.9 associated with LRA Table 3.5.1, items 3.5.1-13 and 3.5.1-14 

addresses concrete in inaccessible areas (containment, dome, wall, basemat, and ring girders, 

buttresses) exposed to water-flowing environment that will be managed for increase in porosity 

and permeability due to leaching of calcium hydroxide and carbonation by the Containment 

Inservice Inspection – IWL and Structures Monitoring Programs. The criteria in SRP-LR 

Section 3.5.2.2.1.9 note that increase in porosity and permeability due to leaching of calcium 

hydroxide and carbonation could occur in inaccessible areas of concrete elements of PWR and 

BWR concrete and steel containments. The SRP-LR also states that a plant-specific AMP is 

not required to manage increase in porosity and permeability and loss of strength due to 

leaching of calcium hydroxide and carbonation of concrete in inaccessible areas if: (1) there is 

evidence in the accessible areas that the flowing water has not caused leaching and 

carbonation, and (2) evaluation determines that the observed leaching of calcium hydroxide and 

carbonation in accessible areas has no impact on intended functions of the concrete structure. 

The applicant addressed the further evaluation criteria by stating that this item is not applicable 

because the concrete was provided with at least the minimum required air content and a low 

water/cement ratio as specified in ACI 318, “Building Code Requirements for Reinforced 

Concrete.” The applicant also stated that the absence of concrete aging effects has been 

confirmed by inspections performed under the Containment Inservice Inspection – IWL and 

Structures Monitoring Programs.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and Structures 

Monitoring Programs is documented in SER Sections 3.0.3.1.13 and 3.0.3.1.40, respectively. 

The staff noted that operating experience has not identified increases in porosity and 

permeability due to leaching of calcium hydroxide and carbonation in accessible areas and 

accessible concrete structures will be inspected for these aging effects. In its review of 

components associated with items 3.5.1-13 and 3.5.1-14, the staff finds the applicant has met 

the further evaluation criteria, and the applicant’s proposal to manage aging using the 

Containment Inservice Inspection – IWL and Structures Monitoring Programs is acceptable 
3-466

because these AMPs will be used to identify occurrence of porosity and permeability due to 

leaching of calcium hydroxide and carbonation in accessible areas as a precursor to occurrence 

of these aging effects in inaccessible areas.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.1.9 criteria. 

For those items associated with LRA Section 3.5.2.2.1.9, the staff concludes that the LRA is 

consistent with the GALL Report and that the applicant has demonstrated that the effects of 

aging will be adequately managed so that the intended function(s) will be maintained consistent 

with the CLB during the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.2.2 Safety-Related and Other Structures and Component Supports

The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2, which 

address several areas:

Aging Management of Inaccessible Areas.

(1) 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.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, item 3.5.1-42 addresses 

inaccessible areas of Groups 1-3, 5, and 7-9 concrete structures exposed to freeze-thaw 

conditions that will be managed for loss of material (spalling, scaling) and cracking by 

the Containment Inservice Inspection – IWL and Structures Monitoring Programs. The 

criteria in SRP-LR Section 3.5.2.2.2.1 item 1 state that loss of material (spalling, scaling) 

and cracking due to freeze-thaw could occur in below-grade inaccessible areas of 

Groups 1-3, 5, and 7-9 concrete structures exposed to a freeze-thaw environment. The 

SRP-LR also states that further evaluation is required for plants located in moderate to 

severe-weathering conditions (weathering index greater than 100 day-inch/yr) as noted 

in NUREG-1557; however, per the GALL Report, a plant-specific AMP is not required if 

documented evidence confirms that the existing concrete had an adequate air 

entrainment content (as per Table CC-2231-2 of ASME Section III Division 2), and 

subsequent inspections of accessible areas did not exhibit degradation related to 

freeze-thaw. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that this item is not applicable because GGNS inaccessible and accessible 

concrete areas are designed in accordance with ACI 318, “Building Code Requirements 

for Reinforced Concrete;” aggregates were selected in accordance with specifications 

and materials conforming to ACI and ASTM standards; water/cement ratios and air 

entrainment percentages are within the limits provided in ACI 318; and the absence of 

aging effects is confirmed under the Containment Inservice Inspection – IWL and 

Structures Monitoring Programs.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and 

Structures Monitoring Programs is documented in SER Sections 3.0.3.1.13 and 

3.0.3.1.40, respectively. The staff reviewed Section 3.8.1.2, “Applicable Codes, 

Standards, and Specifications,” and Section 3.8.1.6, “Materials, Quality Control, and 

Special Construction Techniques,” of the UFSAR and noted that (1) concrete structures 

were designed in accordance with ACI 318; and (2) aggregates were selected in 

accordance with specifications and materials conforming to ACI and ASTM standards. 

Conformance to ACI 318 ensures that water/cement ratios and air entrainment 

percentages are within the limits provided by the code and the absence of aging effects 

is confirmed under the Containment Inservice Inspection – IWL and Structures 
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Monitoring Programs. In its review of components associated with item 3.5.1-42, the 

staff finds that the applicant has met the further evaluation criteria, and the applicant’s 

proposal to manage aging using the Containment Inservice Inspection – IWL and 

Structures Monitoring Programs acceptable because: a review of UFSAR Section 3.8.1, 

“Concrete Containment,” LRA Sections 2.4.1 and 3.5, and plant operating experience 

noted that the entrained air content is within 2 to 6 percent and no degradation due to 

freeze-thaw effects has been identified in accessible concrete areas. Furthermore, 

concrete structures were designed in accordance with ACI 318, which also provides 

guidelines for (1) air content for concrete to resist damage from cycles of freezing and 

thawing; and (2) for selection, application, and testing of concrete and aggregate.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.2.1 

criteria. For those items associated with LRA Section 3.5.2.2.2.1.1, the staff concludes 

that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

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) Cracking due to expansion and reaction with aggregates of Groups 1-5 and 7-9 

structures.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, item 3.5.1-43 addresses 

concrete in inaccessible areas of Groups 1-5, and 7-9 concrete structures exposed to 

any environment that will be managed for cracking due to expansion from reaction with 

aggregates by the Containment Inservice Inspection – IWL and Structures Monitoring 

Programs. The criteria in SRP-LR Section 3.5.2.2.2.1 item 2 state that cracking due to 

expansion and reaction with aggregates could occur in below-grade inaccessible 

concrete areas for Groups 1-5 and 7-9 structures. The SRP-LR also states that further 

evaluation is required to determine if a plant-specific AMP is needed to manage cracking 

and expansion due to reaction with aggregate of concrete in inaccessible areas if the 

concrete was not constructed in accordance with the recommendations in the GALL

Report. The GALL Report states that a plant-specific AMP is not required to manage 

cracking and expansion due to reaction with aggregate or concrete in inaccessible areas 

if (1) as described in NUREG-1557, investigations, tests, and petrographic examinations 

of aggregates performed in accordance with ASTM C295 and other ASTM reactivity 

tests, as required, can demonstrate that those aggregates do not adversely react within 

concrete; or (2) for potentially reactive aggregates, aggregate concrete reaction is not 

significant if it is demonstrated that the in-place concrete can perform its intended 

function. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that aggregates were selected locally and were in accordance with specifications 

and materials conforming to ACI and ASTM standards at the time of construction.

Furthermore, GGNS structures are constructed of a dense, durable mixture of sound 

coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios 

and air entrainment percentages were within the limits provided in ACI 318, “Building 

Code Requirements for Reinforced Concrete,” which requires that the potential for 

aggregate reactivity be tested in accordance with ASTM C289, “Standard Test Method 

for Potential Alkali-Silica Reactivity of Aggregates (Chemical Method),” and ASTM C227, 

“Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate 

Combinations (Mortar-Bar Method).” Moreover the aggregate materials were evaluated 

in accordance with ASTM C295, “Standard Guide for Petrographic Examination of 

Aggregates for Concrete.” Therefore, cracking due to expansion and reaction with 

aggregates for Groups 1–5, 7–9 structures is not an aging effect requiring management.
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The absence of concrete aging effects is confirmed under the Containment Inservice 

Inspection – IWL and Structures Monitoring Programs.

The staff‘s evaluations of the applicant‘s Containment Inservice Inspection – IWL and 

Structures Monitoring Programs are documented in SER Sections 3.0.3.1.13 and 

3.0.3.1.40, respectively. The staff noted that the concrete structures were constructed 

from aggregates selected in conformance with specifications and materials conforming 

to ACI and ASTM standards at the time of construction, water/cement ratios and air 

entrainment percentages are within limits provided in ACI 318, and degradation due to 

ASR would be identified during inspections performed under the Containment Inservice 

Inspection – IWL and Structures Monitoring Programs. In its review of components 

associated with item 3.5.1-43, the staff finds that the applicant has met the further 

evaluation criteria, however, the staff determined the need for additional information. 

NRC IN 2011-20 “Concrete Degradation by Alkali-Silica Reaction (ASR)” was issued to 

inform industry of operating experience related to concrete degradation due to ASR. IN

2011-20 was issued on November 18, 2011, which is after the NRC received the GGNS 

license renewal application (LRA) on November 1, 2011. Therefore, by letter dated 

August 15, 2012, the staff issued RAI 3.5.1.12-1 requesting additional information for

cracking due to expansion from reaction with aggregates as a possible aging effect for 

the components listed in item 3.5.1-43. The staff’s review of the applicant’s response to 

RAI 3.5.1.12-1, and justification for acceptance is provided in SER Section 3.5.2.2.1.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.2.1 

criteria. For those items associated with LRA Section 3.5.2.2.2.1.2, the staff concludes 

that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

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) Cracking and distortion due to increased stress levels from settlement for below-grade 

inaccessible concrete areas of structures for all groups and reduction in foundation 

strength and cracking due to differential settlement and erosion of porous concrete 

subfoundations in below grade inaccessible concrete areas for Groups 1-3, and 5-9 

structures.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, (1) item 3 5.1-44 addresses 

concrete for all Groups of structures exposed to increased stress levels due to 

differential settlement in soil that will be managed for cracking and distortion, and

(2) items 3.5.1-45, and 3.5.1-46 address concrete/porous concrete foundations and 

subfoundations exposed to increased stress levels due to differential settlement as a 

result of water-flowing under the foundations that will be managed for reduction in 

foundation strength, cracking due to the differential settlement, erosion of porous 

concrete subfoundation. Aging effects for these items will be managed by the 

Containment Inservice Inspection – IWL (for item 3.5.1-45) and Structures Monitoring 

(for items 3.5.1-44, 3.5.1-45, and 3.5.1-46) programs. The criteria in the SRP-LR 

3.5.2.2.2.1 item state that cracking and distortion due to increased stress levels from 

settlement could occur in below-grade inaccessible concrete areas of structures for all 

Groups, and reduction in foundation strength and cracking due to differential settlement 

and erosion of porous concrete sub-foundations could occur in below-grade inaccessible 

concrete areas of Groups 1-3, 5-9 structures. The SRP-LR also recommends no further 

evaluation if this activity is included in the scope of the applicant’s structures monitoring 

program, and recommends verification of the continued functionality of the dewatering 

system to lower the site groundwater level during the period of extended operation if the 
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plant’s CLB credits a dewatering program. The applicant addressed the further 

evaluation criteria of the SRP-LR by stating that this item does not require management 

or it is not applicable because with the exception of the diesel generator building, which 

is founded on compacted structural backfill, the station’s foundations, subfoundations, 

and inaccessible below-grade structures are founded on the Catahoula Formation of 

Miocene origin, consisting primarily of hard-to-very-hard silty-to-sandy clay, clayey silt, 

and locally indurated or cemented clay, silt, and sand layers. The applicant also stated 

that the total settlement is elastic, expected to be less than 1 inch and primarily occurred 

when the load was applied during construction. Subsequent to construction, onsite 

monitoring of Category I structures has been shown to be negligible. The applicant 

further stated that GGNS containment was not identified in IN 97-11 as a plant 

susceptible to erosion of porous concrete subfoundations and that its groundwater is not 

aggressive or its chemistry and groundwater conditions have significantly changed. 

Moreover, any potential total and differential settlements is addressed in the design of 

foundations at the site. A settlement monitoring program was established to monitor 

settlements of Category I structures during plant construction and thereafter. Therefore, 

cracks and distortion due to increased stress levels from settlement for below-grade 

inaccessible concrete areas of structures for all groups and reduction in foundation 

strength, and cracking, due to differential settlement and erosion of porous concrete 

subfoundation in below-grade inaccessible concrete areas for Groups 1–3, 5–9 

structures is not an aging effect requiring management for GGNS concrete. 

Nonetheless, accessible concrete components will be monitored by the Structures 

Monitoring Program or the Containment Inservice Inspection – IWL Program to confirm 

the absence of aging effects for cracking and distortion.

The staff’s evaluation of the applicant‘s Inservice Inspection – IWL and Structures 

Monitoring Programs are documented in SER Sections 3.0.3.1.13 and 3.0.3.1.40, 

respectively. The staff noted that the applicant will manage aging of inaccessible 

concrete areas of structures due to increased stress levels from settlement using the 

Containment Inservice Inspection – IWL and Structures Monitoring Programs. The staff 

reviewed the UFSAR and noted that there was not a discussion for either porous 

foundations or for an active dewatering system and concluded that the applicant does 

not employ either a dewatering system or have porous concrete subfoundations. The 

staff also confirmed in UFSAR Section 2.5.4.13.1, “Foundation Rebound and 

Settlement,” that for the containment structure the predicted settlements based on the 

elastic properties of the Catahoula Formation were about 0.1 inch. Furthermore, 

differential settlements between adjacent buildings were less than 0.5 inch. For the 

diesel generator building, the predicted and observed settlements were 0.8 and 0.2 inch 

respectively. Finally, the staff reviewed UFSAR Figure 2.5, “Instrumentation Location 

Plan,” and confirmed the existence of differential settlement monitoring stations at the 

containment, auxiliary, turbine and diesel buildings. In its review of components 

associated with items 3.5.1-44, 3.5.1-45, and 3.5.1-46, the staff finds that the applicant 

has met the further evaluation criteria, and the applicant’s proposal to manage aging 

using the Containment Inservice Inspection – IWL and Structures Monitoring Programs 

is acceptable because a search of applicable UFSAR sections and LRA Sections 2.4 

and 3.5 indicate that GGNS does not employ porous concrete subfoundations or rely on 

a dewatering system to lower the site groundwater table to control settlement, and that in 

the event of potential differential settlement, monitoring stations exist to monitor potential 

settlements, if any.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.2.1 

criteria. For those items associated with LRA Section 3.5.2.2.2.1.3, the staff concludes 
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that the LRA is consistent with the GALL Report and that the application 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) Increase in porosity and permeability and loss of strength due to leaching of calcium 

hydroxide and carbonation for Groups 1-5 and 7-9 structures.

LRA Section 3.5.2.2.2.1 associated with LRA Table 3.5.1, item 3.5.1-47 addresses 

concrete in inaccessible areas (exterior above- and below-grade locations and 

foundations) for Groups 1-5 and 7-9 structures exposed to water flowing that will be 

managed for increase in porosity and permeability and loss of strength due to leaching 

of calcium hydroxide and carbonation by the Containment Inservice Inspection – IWL 

and Structures Monitoring Programs. The criteria in SRP-LR 3.5.2.2.2.1 item 4 states 

that increases in porosity and permeability, and loss of strength due to leaching of 

calcium hydroxide and carbonation could occur in below-grade inaccessible areas of 

Groups 1-5 and 7-9 structures. The SRP-LR also states that further evaluation is 

recommended if leaching is observed in accessible areas that impact intended functions 

to determine if a plant-specific AMP is needed to manage increase in porosity and 

permeability and loss of strength due to leaching of calcium hydroxide and carbonation. 

However, the GALL Report states that a plant-specific AMP is not required if: (1) there 

is evidence in the accessible areas that the flowing water has not caused leaching and 

carbonation, or (2) evaluation determines that the observed leaching of calcium 

hydroxide and carbonation in accessible areas has no effect on the intended function of 

the concrete structure. The applicant addressed the further evaluation criteria by stating 

that this item is not applicable because the concrete was provided with at least the 

minimum required air content and a low water/cement ratio as specified in ACI 318, 

“Building Code Requirements for Reinforced Concrete.” Furthermore, aggregates were 

selected locally and were in accordance with specifications and materials conforming to 

ACI and ASTM standards at the time of construction to ensure concrete durability. The 

applicant also stated that GGNS structures are constructed of a dense, durable mixture 

of sound coarse aggregate, fine aggregate, cement, water, and admixture. Groups 1–5 

and 7–9 concrete structures at GGNS use a dense low permeable concrete with an 

acceptable water-to-cement ratio, which provides an acceptable degree of protection 

against aggressive chemical attack. The applicant further stated that the water chemical 

analysis results have confirmed that the site groundwater is considered to be 

non-aggressive. Therefore, increase in porosity and permeability, and loss of strength 

due to leaching of calcium hydroxide and carbonation of below-grade inaccessible 

concrete areas are not AERM and the absence of concrete aging effects has been 

confirmed by inspections performed under the Containment Inservice Inspection – IWL 

and Structures Monitoring Programs.

The staff’s evaluation of the applicant’s Inservice Inspection – IWL and Structures 

Monitoring Programs is documented in SER Sections 3.0.3.1.13 and 3.0.3.1.40, 

respectively. The staff reviewed USFAR Section 2.4.13.1.3.3, “Chemical Quality of 

Water,” and verified that groundwater samples obtained from test and observation wells 

on site and from selected private wells, as well as surface water samples taken from the 

Mississippi River and Bayou Pierre confirmed that the groundwater is not aggressive. 

The results of chemical analyses of water samples are presented in UFSAR 

Table 2.4-21 and indicate that pH, chlorides, and sulfates are below the aggressive 

environment limits of pH less than 5.5, chlorides in excess of 500 ppm, or sulfates in 

excess of 1,500 ppm. The staff noted that the applicant will manage increase in porosity 
3-471

and permeability and loss of strength due to leaching of calcium hydroxide and 

carbonation using the Containment Inservice Inspection – IWL and Structures Monitoring 

Programs. The staff also noted that a review of plant operating experience did not 

identify incidences of leaching or carbonation in accessible concrete areas that affected 

intended functions. In its review of components associated with item 3.5.1-47, the staff 

finds the applicant has met the further evaluation criteria, and the applicant’s proposal to 

manage aging using the Containment Inservice Inspection – IWL and Structures 

Monitoring Programs is acceptable, because (1) these AMPs will be used to identify the 

occurrence of porosity and permeability due to leaching of calcium hydroxide and 

carbonation, if any, in accessible areas as a precursor to occurrence of the associated 

aging effects in inaccessible areas; and (2) plant operating experience thus far has not 

identified the occurrence of porosity or permeability due to leaching of calcium hydroxide 

and carbonation in accessible areas.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.2.1 

criteria. For those items that apply to LRA Section 3.5.2.2.2.1.4, the staff concludes that 

the LRA is consistent with the GALL Report and that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Reduction of Strength and Modulus Due to Elevated Temperature. LRA Section 3.5.2.2.2.2 

associated with LRA Table 3.5.1, item 3.5.1-48 addresses Groups 1-5 concrete exposed to 

elevated temperature environment. The applicant stated that this item is not applicable because 

during normal operation areas within containment are maintained below a bulk average 

temperature of 57 °C (135 °F), and for areas in the cylinder wall where piping penetrations carry 

hot fluid (pipe temperature greater than 93 °C [200 °F]) cooling of the concrete is provided by 

either cooling fins or water jackets to maintain the concrete temperature adjoining the 

embedded sleeve at or below 93 °C (200 °F). The applicant also stated that for areas outside 

the containment, the concrete is not exposed to temperatures that exceed the limits associated 

with aging degradation due to elevated temperature, and piping penetration temperatures are 

not in excess of 66 °C (150 °F). In its review of components associated with item 3.5.1-48, the 

staff finds that the applicant has met the further evaluation criteria because the applicant noted 

that the Group 1-5 concrete temperatures are below the limits provided in Subsection CC-3440 

of ASME Section III, Division 2 for both general and local areas.

Aging Management of Inaccessible Areas for Group 6 Structures. SRP-LR Section 3.5.2.2.2.3 

addresses aging management of inaccessible areas for Group 6 structures (below-grade 

inaccessible concrete areas). It recommends further evaluation for the structure/aging effect 

combinations as identified below in accordance with GALL Report, AMP XI.S7, “Regulatory 

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants,” or 

FERC/US Army Corps of Engineers dam inspection and maintenance procedures.

(1) Loss of material (spalling, scaling) and cracking due to freeze-thaw that could occur in 

below-grade inaccessible concrete areas of Group 6 structures.

LRA Section 3.5.2.2.2 associated with LRA Table 3.5.1, item 3.5.1-49 addresses 

below-grade concrete components of Group 6 structures (inaccessible areas) and 

exterior above- and below-grade foundation and interior slab concrete exposed to 

air-outdoor environment that will be managed for loss of material (spalling, scaling) and 

cracking due to freeze-thaw by the Structures Monitoring and Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Programs. 
3-472

The criteria in SRP-LR Section 3.5.2.2.2.3 item 1 state that loss of material (spalling, 

scaling) and cracking due to freeze-thaw could occur in below-grade inaccessible 

concrete areas of Group 6 structures. The GALL Report recommends further evaluation 

of this aging effect for inaccessible areas for plants located in moderate to severe 

weathering conditions (index greater than 100 day-inch/yr) as noted in NUREG-1557; 

however, a plant-specific AMP is not required if documented evidence confirms that the 

existing concrete had an adequate air entrainment content (as per Table CC-2231-2 of 

ASME Section III Division 2), and subsequent inspections of accessible areas did not 

exhibit degradation related to freeze-thaw. Such inspections, per the GALL Report, 

should be considered as part of the evaluation process and if degradation is witnessed, 

then a plant-specific AMP is necessary to manage loss of material (spalling, scaling) and 

cracking due to freeze-thaw of concrete in inaccessible areas.

The applicant addressed the further evaluation criteria of the SRP-LR by stating that 

these aging effects are not applicable and do not require management because GGNS 

inaccessible and accessible concrete areas are designed in accordance with American 

Concrete Institute Specification ACI 318, “Building Code Requirements for Reinforced 

Concrete”; aggregates were selected in accordance with specifications and materials 

conforming to ACI and ASTM standards for a dense durable concrete; water/cement 

ratios and air entrainment percentages are within the limits provided in ACI 318; and the 

absence of aging effects is confirmed under the Structures Monitoring and Regulatory 

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Programs. The staff’s evaluation of the applicant’s Structures Monitoring and 

Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear 

Power Plants Programs are documented in SER Sections 3.0.3.1.40 and 3.0.3.1.37, 

respectively. The staff reviewed UFSAR Section 2.3.1, “Regional Climatology,” and 

noted that snowfall is not a rare event in Mississippi. In addition, the staff noted that the 

area experiences ice storms. UFSAR Tables 2.3-11 and Table 2.3-12 summarize the 

frequencies and duration for ice storms for each month and year. The staff also 

reviewed ASTM C33, Figure 1, which provides information on the weathering index for 

the continental United States, and noted that the GGNS is in the moderate weathering 

region with potential annual freeze thaw cycles. The staff noted that the concrete 

structures were designed in accordance with ACI 318; the concrete structures meet 

requirements for selection, application, and testing of concrete and aggregate; and loss 

of material (scaling, spalling) and cracking due to freeze-thaw are managed by the 

Structures Monitoring Program that incorporates ACI 349-3, “Evaluation of Existing 

Nuclear Safety-Related Concrete Structures,” which provide guidelines for inspection,

and references NUREG/CR-4652, “Concrete Component Aging and Its Significance 

Relative to Life Extension of Nuclear Power Plants,” according to which operating 

experience indicated that overall very little damage has been reported in safety-related 

structures as a direct result of cycles of freezing and thawing. This, in accordance with

NUREG/CR-4652, has been attributed to prudent materials selection, concrete testing, 

quality control, and structural design. In addition the staff noted that the applicant also 

uses Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plants Programs to verify potential cracking. In its review of components 

associated with item 3.5.1-49, the staff finds that the applicant has met the further 

evaluation criteria, and the applicant‘s proposal to manage aging using the Structures 

Monitoring and the Regulatory Guide 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Programs is acceptable because: a review of 

Section 3.8 of the UFSAR, LRA Sections 2.4.1 and 3.5, and plant operating experience 

noted that the entrained air content is within 2 to 6 percent and no degradation due to 
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freeze-thaw effects has been identified in accessible concrete areas; concrete structures 

were designed in accordance with ACI 318; and the concrete structures meet 

requirements for selection, application, and testing of concrete and aggregate.

The staff determines that the applicant‘s evaluation meets SRP-LR Section 3.5.2.2.2.3 

criteria. For those items associated with LRA Section 3.5.2.2.2.3.1, the staff concludes 

that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

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) Cracking due to expansion and reaction with aggregates that could occur in below-grade 

inaccessible concrete areas of Group 6 structures.

LRA Section 3.5.2.2.2.3 associated with LRA Table 3.5.1, item 3.5.1-50 addresses 

below-grade concrete components of Group 6 structures (inaccessible areas) and 

exterior above- and below-grade foundation and interior slab concrete exposed to 

air-outdoor environment that will be managed for cracking due to expansion from 

reaction with aggregates by the Structures Monitoring and Regulatory Guide 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Programs. 

The criteria in SRP-LR Section 3.5.2.2.2.3 item 2 state that cracking due to expansion 

and reaction of aggregates could occur in below-grade inaccessible areas of Group 6 

structures. The SRP-LR also states that further evaluation is recommended to 

determine if a plant-specific AMP is needed to manage cracking and expansion due to 

reaction with aggregate of concrete in inaccessible areas. The GALL Report states that 

a plant-specific AMP is not required to manage cracking and expansion due to reaction 

with aggregate or concrete in inaccessible areas if: (1) as described in NUREG-1557, 

investigations, tests, and petrographic examinations of aggregates performed in 

accordance with ASTM C295 and other ASTM reactivity tests, as required, can 

demonstrate that those aggregates do not adversely react within concrete; or (2) for 

potentially reactive aggregates, aggregate-concrete reaction is not significant if it is 

demonstrated that the in-place concrete can perform its intended function. The applicant 

addressed the further evaluation criteria of the SRP-LR by stating that this item is not 

applicable. Cracking due to expansion from reaction with aggregates is an aging effect 

that does not require management because GGNS concrete was designed in 

accordance with ACI 318, “Building Code Requirements for Reinforced Concrete,” which 

requires the potential reactivity of aggregates to be tested in accordance with 

ASTM C289 and ASTM C227. Concrete is made from a durable mixture of sound 

coarse aggregate, fine aggregate, cement, water, and admixture. Water/cement ratios 

and air entrainment percentages are within the limits provided in ACI 318 that require the 

potential for aggregate reactivity to be tested in accordance with ASTM C289 and ASTM 

C227 and aggregate materials to be evaluated in accordance with ASTM C295. 

Furthermore, the applicant stated that the GGNS below-grade environment, exhibiting a 

pH greater than 5.5, chlorides less than 500 ppm, and sulfates less than 1,500 ppm, is 

not aggressive. The absence of concrete aging effects is confirmed under the 

Structures Monitoring and the Regulatory Guide 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Programs.

The staff’s evaluation of the applicant’s Structures Monitoring and Regulatory 

Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Programs is documented in SER Sections 3.0.3.1.40 and 3.0.3.1.37, respectively. 

The staff reviewed UFSAR Table 2.4-21, “Results of Chemical Analyses of Water 

Samples,” and confirmed that the groundwater (as calcium carbonate in nearby wells) or 
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alluvium alkalinity within 2 miles radius from the plant to be 0, which translates to a pH 

of 7 or slightly more. Total chlorides and sulfates are well below the 500 and 1,500 ppm 

marks. The staff also reviewed UFSAR Chapter 3 and confirmed that the applicant has 

used ACI 318, “American Concrete Institute (ACI), Building Code Requirement for 

Reinforced Concrete,” throughout the plant construction, which requires that the 

potential for aggregate reactivity be tested in accordance with ASTM C289, “Standard 

Test Method for Potential Alkali-Silica Reactivity of Aggregates (Chemical Method),” and 

ASTM C227, “Standard Test Method for Potential Alkali Reactivity of Cement-Aggregate 

Combinations (Mortar-Bar Method).” Moreover the aggregate materials were evaluated 

in accordance with ASTM C295, “Standard Guide for Petrographic Examination of 

Aggregates for Concrete” and selected locally. The staff also noted at the time of 

construction, water/cement ratios and air entrainment percentages are within limits 

provided in ACI 318, and the absence of concrete aging effects is confirmed under the 

Structures Monitoring and Regulatory Guide 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Programs. In its review of components 

associated with item 3.5.1-50, the staff finds that the applicant has met the further 

evaluation criteria, however, the staff determined the need for additional information. 

IN 2011-20 “Concrete Degradation by Alkali-Silica Reaction (ASR)” was issued to inform 

industry of operating experience related to concrete degradation due to ASR and was 

issued on November 18, 2011, which is after the NRC received the LRA on 

November 1, 2011. Therefore, by letter dated August 15, 2012, the staff issued 

RAI 3.5.1.12-1 requesting additional information for cracking due to expansion from 

reaction with aggregates as a possible aging effect for the components listed in 

item 3.5.1-43. The staff’s review of the applicant’s response to RAI 3.5.1.12-1, and 

justification for acceptance is provided in SER Section 3.5.2.2.1.

The staff determines that the applicant‘s evaluation meets SRP-LR Section 3.5.2.2.2.3 

criteria. For those items associated with LRA Section 3.5.2.2.2.3.2, the staff concludes 

that the LRA is consistent with the GALL Report and that the applicant has 

demonstrated that the effects of aging will be adequately managed so that the intended 

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) Increase in porosity and permeability and loss of strength due to leaching of calcium 

hydroxide and carbonation that could occur in below-grade inaccessible concrete areas 

of Group 6 structures.

LRA Section 3.5.2.2.2.3 associated with LRA Table 3.5.1, item 3.5.1-51 addresses 

concrete in inaccessible areas of Group 6 concrete structures exposed to water flowing 

that will be managed for increase in porosity and permeability and loss of strength due to 

leaching of calcium hydroxide and carbonation by the Structures Monitoring Program. 

The SRP-LR states that further evaluation is recommended to determine if a 

plant-specific AMP is needed to manage increase in porosity and permeability and loss 

of strength due to leaching of calcium hydroxide and carbonation of concrete in 

inaccessible areas. The SRP-LR also states that a plant-specific AMP is not required for 

reinforced concrete structures exposed to flowing water if: (1) there is evidence in the 

accessible areas that the flowing water has not caused leaching and carbonation, and 

(2) evaluation determines that the observed leaching of calcium hydroxide and 

carbonation in accessible areas has no impact on intended functions of the concrete 

structure. The applicant addressed the further evaluation criteria of the SRP-LR by 

stating that this item is not applicable as the listed aging effects do not require 

management because the GGNS below-grade environment is not aggressive and the 
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concrete was provided with at least the minimum required air content and a low 

water/cement ratio as specified in ACI 318, “Building Code Requirements for Reinforced 

Concrete.” The applicant also stated that the absence of concrete aging effects in 

accessible areas has been confirmed by inspections performed under the Structures 

Monitoring Program (see LRA Section 3.5.2.2.2.1 item 4 associated with LRA

Table 3.5.1, item 3.5.1-47).

The staff‘s evaluation of the applicant‘s Structures Monitoring Program is documented in 

SER Section 3.0.3.1.40. The staff noted that the GGNS below-grade environment as 

indicated above in the evaluation of 3.5.2.2.2.3 item (2) associated with LRA Table 3.5.1, 

item 3.5.1-50 is not aggressive (alkalinity at or near zero, chlorides and sulfates well 

below the 500 and 1,500 ppm marks) and therefore it could adversely affect below-grade 

concrete and its constituents. Furthermore, concrete was placed with the minimum 

required air content and had a water/cement ratio in compliance with ACI 318 

requirements. Absence of similar aging effects also have been noted in LRA 

Section 3.5.2.2.2 associated with LRA Table 3.5.1, item 3.5.1-47, and the Structures 

Monitoring Program will be used to manage aging of the Group 6 concrete structures for 

increase in porosity and permeability and loss of strength due to leaching of calcium 

hydroxide and carbonation. In its review of components associated with item 3.5.1-51, 

the staff finds that the applicant has met the further evaluation criteria, and the 

applicant’s proposal to manage aging using the Structures Monitoring Program is 

acceptable because the below-grade concrete is not exposed to an aggressive 

environment, has met the minimum required air content, had a water/cement ratio in 

compliance with ACI 318 requirements, and a review of plant operating experience did 

not identify any incidences of leaching or carbonation in accessible areas that may affect 

intended functions.

The staff determines that the applicant’s evaluation meets SRP-LR Section 3.5.2.2.2.3 

criteria. For those items that apply to LRA Section 3.5.2.2.2.3.3, the staff concludes that 

the LRA is consistent with the GALL Report and that the applicant has demonstrated 

that the effects of aging will be adequately managed so that the intended function(s) will 

be maintained consistent with the CLB during the period of extended operation, as 

required by 10 CFR 54.21(a)(3).

Cracking Due to Stress Corrosion Cracking, and Loss of Material Due to Pitting and Crevice 

Corrosion. LRA Section 3.5.2.2.2.4, associated with LRA Table 3.5.1, item 3.5.1-52 addresses 

cracking and loss of material due to pitting and crevice corrosion of Groups 7 and 8 stainless 

steel tank liners exposed to water standing. The applicant stated that this item is not applicable 

because GGNS does not have Group 7 or Group 8 structures with stainless steel liners. The 

staff reviewed LRA Section 2.4 and the UFSAR and confirmed that the applicant‘s LRA does not 

have any AMR results that are applicable to these items.

Cumulative Fatigue Damage Due to Fatigue. LRA Section 3.5.2.2.2.5, which is associated with 

LRA Table 3.5.1, item 3.5.1-53, addresses cumulative fatigue damage due to cyclic loading in 

component support members, anchor bolts, and welds for Groups B1.1, B1.2, and B1.3 

component supports exposed to air-indoor uncontrolled. The applicant stated its CLB does not 

contain any fatigue analysis for component support members, bolted connections, or support 

anchorage to building structures. The staff reviewed the applicant’s UFSAR and LRA Section 4 

and confirmed that the applicant’s CLB does not contain fatigue analyses that were identified as 

TLAAs as required by 10 CFR 54.21(c)(1) for component support members, anchor bolts, and 

welds for Groups B1.1, B1.2, and B1.3 and, therefore, the staff finds the applicant’s claim 

acceptable.
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3.5.2.2.3 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.

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

In LRA Tables 3.5.2-1 through 3.5.2-4, 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 3.5.2-4, the applicant indicated, via notes F through J, that the 

combination of component type, material, environment, and AERM does not correspond to an

item in the GALL Report. The applicant provided further information about how it will manage 

the aging effects. Specifically, note F indicates that the material for the AMR item component is 

not evaluated in the GALL Report. Note G indicates that the environment for the AMR item

component and material is not evaluated in the GALL Report. Note H indicates that the aging 

effect for the AMR item component, material, and environment combination is not evaluated in 

the GALL Report. Note I indicates that the aging effect identified in the GALL Report for the 

item component, material, and environment combination is not applicable. Note J indicates that 

neither the component nor the material and environment combination for the item is evaluated in 

the GALL Report.

For component type, material, and environment combinations not evaluated in the GALL 

Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 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.

For the LRA Table 3.5.2 items that the applicant identified as generic note I, plant specific 

note 501, the applicant did not provide sufficient information as to why the GGNS environment 

is not conducive to the listed aging effects. Therefore, by letter dated October 19, 2012, the 

staff issued RAI 3.5.1-2 requesting that the applicant clarify if the listed aging effects will be 

managed by the proposed program(s) when the “Discussion” column states that listed aging 

effect does not require management at GGNS, and if the aging effect will not be managed, to 

provide technical justification as to why the GGNS environment would not be conducive to the 

listed aging effects.

In its response dated November 19, 2012, the applicant clarified that for each GGNS LRA 

Table 3.5.2 item where generic note I and plant-specific note 501 are cited, the listed aging 

effects will be managed by the identified program(s). In addition, the applicant provided 

technical justification as to why the environment would not be conducive to the listed aging 

effects.

The staff finds the applicant’s response acceptable because the applicant provided clarification 

that the listed aging effects will be managed by the identified program(s), which are consistent 

with the recommendations in the GALL Report.
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3.5.2.3.1 Containment Building - 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 

containment building component groups.

Concrete Elements Exposed to Soil. In LRA Table 3.5.2-1, the applicant stated that for concrete 

containment foundation exposed to soil, cracking and distortion due to increased stress levels 

from settlement are not applicable. The AMR items cite generic note I. The AMR items also 

cite a plant-specific note that states that the given environment is not conducive to the stated 

aging effects but that an AMP will be used to confirm the absence of aging effects during the 

period of extended operation. The applicant credited the Containment Inservice Inspection –

IWL Program to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL program is 

documented in SER Section 3.0.3.1.13. Although the applicant stated that cracking and 

distortion due to increased stress levels from settlement are not applicable because the 

environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-1 is consistent with the aging management program identified in the 

GALL Report and the components are included in the Containment Inservice Inspection – IWL 

Program to confirm the absence of these aging effects. Therefore, the staff finds the applicant’s 

proposal acceptable because it is consistent with the GALL Report recommendations for 

managing aging for these structures and components, as documented in item II.B3.2.CP-105 

(SRP-LR Table 3.5-1, item 1).

Concrete Elements Exposed to Air–Indoor Uncontrolled or Air–Outdoor Environments. In LRA

Table 3.5.2-1, the applicant stated that for concrete containment base slab/foundation exposed 

to air-indoor and concrete main steam pipe tunnel exposed to air-outdoor, cracking, loss of 

bond, and loss of material (spalling, scaling) due to corrosion of embedded steel are not 

applicable. The AMR items cite generic note I. The AMR items also cite a plant-specific note 

that states that the given environment is not conducive to the stated aging effects, but an AMP

will be used to confirm the absence of aging effects during the period of extended operation.

The applicant credited the Containment Inservice Inspection – IWL and Structures Monitoring 

Programs, respectively, to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Containment Inservice Inspection – IWL and Structures 

Monitoring Programs are documented in SER Sections 3.0.3.1.13 and 3.0.3.1.40, respectively. 

Although the applicant stated that cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel are not applicable because the environment is not 

conducive to these aging effects, in response to RAI 3.5.1-2, the applicant clarified that 

item 3.5.1-23 is consistent with the aging management program identified in the GALL Report 

and the components are included in the Containment Inservice Inspection – IWL and Structures 

Monitoring Programs to confirm the absence of these aging effects. Therefore, the staff finds 

the applicant’s proposal acceptable because it is consistent with the GALL Report

recommendations for managing aging for these components, as documented in 

item II.B3.2.CP-89 (SRP-LR Table 3.5-1, item 23).

Concrete Elements Exposed to Air–Indoor Uncontrolled or Fluid Environments. In LRA

Table 3.5.2-1, the applicant stated that for concrete beams, columns, floor slabs, interior walls, 

drywell wall and floor slab, and reactor pedestal exposed to air-indoor uncontrolled and concrete 

drywell floor slab exposed to a fluid environment, increase in porosity and permeability, 
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cracking, and loss of material (spalling, scaling) due to aggressive chemical attack are not 

applicable. The AMR items cite generic note I. The AMR items also cite a plant-specific note 

that states that the given environment is not conducive to the stated aging effects, but an AMP

will be used to confirm the absence of aging effects during the period of extended operation.

The applicant credited the Structures Monitoring Programs to confirm the absence of 

aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that increase in porosity and permeability, 

cracking and loss of material (spalling, scaling) due to aggressive chemical attack are not 

applicable because the environment is not conducive to these aging effects, in response to 

RAI 3.5.1-2, the applicant clarified that item 3.5.1-24 is consistent with the aging management 

program identified in the GALL Report and the components are included in the Structures 

Monitoring Program to confirm the absence of these aging effects. Therefore, the staff finds the 

applicant’s proposal acceptable because it is consistent with the GALL Report

recommendations for managing aging for these structures and/or components, as documented 

in item II.B3.2.CP-84 (SRP-LR Table 3.5-1, item 24).

Group 1, Concrete Structures Exposed to Air-Indoor Uncontrolled Environment. In LRA

Table 3.5.2-1, the applicant stated that for concrete containment sump structures, and upper 

containment pool floor and walls exposed to air-indoor uncontrolled, cracking due to expansion 

from reaction with aggregates is not applicable. The AMR items cite generic note I. The AMR 

items also cite a plant-specific note that states that the given environment is not conducive to 

the stated aging effects, but an AMP will be used to confirm the absence of aging effects during 

the period of extended operation. The applicant credited the Structures Monitoring Program to 

confirm the absence of aging effects.

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination and determined the 

need for additional information. By letter dated August 15, 2012, the staff issued RAI 3.5.1.12-1 

requesting the technical justification for the non-applicability of cracking due to expansion from 

reaction with aggregates as a possible aging effect for the components listed in item 3.5.1-54. 

The staff’s review of the applicant’s response to RAI 3.5.1.12-1, and justification for acceptance 

is provided in SER Section 3.5.2.2.1.

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 Water Control Structures - 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 

water control structures component groups.

Group 6 Concrete Structures Exposed to Air–Indoor Uncontrolled or Air-Outdoor. In LRA

Table 3.5.2-2, the applicant stated that for concrete floor slab, interior walls, roof hatches, and 

roof slabs exposed to air-indoor uncontrolled or air-outdoor, cracking, loss of bond, and loss of 

material (spalling, scaling) due to corrosion of embedded steel are not applicable. The AMR 
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items cite generic note I. The AMR items also cite a plant-specific note that states that the 

given environment is not conducive to the stated aging effects, but an AMP will be used to 

confirm the absence of aging effects during the period of extended operation. The applicant 

credited the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power 

Plants Program to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program is documented in SER Section 3.0.3.1.37. 

Although the applicant stated that cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel are not applicable because the environment is not 

conducive to these aging effects, in response to RAI 3.5.1-2, the applicant clarified that 

item 3.5.1-59 is consistent with the aging management program identified in the GALL Report 

and the components are included in the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program to confirm the absence of these aging effects. 

Therefore, the staff finds the applicant’s proposal acceptable because it is consistent with the 

GALL Report recommendations for managing aging for these components, as documented in 

item III.A6.TP-38 (SRP-LR Table 3.5-1, item 59).

Group 6 Concrete Structures Exposed to a Fluid Environment. In LRA Table 3.5.2-2, the 

applicant stated that for concrete beams, columns, floor slab, foundation, and interior walls 

exposed to a fluid environment, increase in porosity and permeability, and loss of strength due 

to leaching of calcium hydroxide and carbonation are not applicable. The AMR items cite 

generic note I. The AMR items also cite a plant-specific note that states that the given 

environment is not conducive to the stated aging effects, but an AMP will be used to confirm the 

absence of aging effects during the period of extended operation. The applicant credited the 

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants 

Program to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program is documented in SER Section 3.0.3.1.37. 

Although the applicant stated that increase in porosity and permeability, and loss of strength 

due to leaching of calcium hydroxide and carbonation are not applicable because the 

environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-61 is consistent with the aging management program identified in the 

GALL Report and the components are included in the RG 1.127, Inspection of Water-Control 

Structures Associated with Nuclear Power Plants Program to confirm the absence of these 

aging effects. Therefore, the staff finds the applicant’s proposal acceptable because it is 

consistent with the GALL Report recommendations for managing aging for these components, 

as documented in item III.A6.TP-37 (SRP-LR Table 3.5-1, item 61).

Groups 6 Concrete Structures Exposed to Soil. In LRA Table 3.5.2-2, the applicant stated that 

for concrete foundation exposed to soil, cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel are not applicable. The AMR items cite generic 

note I. The AMR items also cite a plant-specific note that states that the given environment is 

not conducive to the stated aging effects, but an AMP will be used to confirm the absence of 

aging effects during the period of extended operation. The applicant credited the Structures 

Monitoring Program to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that cracking, loss of bond, and loss of 

material (spalling, scaling) due to corrosion of embedded steel are not applicable because the 
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environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-65 is consistent with the aging management program identified in the 

GALL Report and the components are included in the Structures Monitoring Program to confirm 

the absence of these aging effects. Therefore, the staff finds the applicant’s proposal 

acceptable because it is consistent with the GALL Report recommendations for managing aging 

for these components, as documented in item III.A6.TP-104 (SRP-LR Table 3.5-1, item 65).

Galvanized Steel Exposed to Fluid Environment. In LRA Table 3.5.2-2, the applicant stated that 

the galvanized steel structural beams, columns, and plates exposed to a fluid environment will 

be managed for loss of material by the Structures Monitoring Program. The AMR item cites 

generic note J.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted in GALL Report Section IX.C, “Selected 

Definitions and Use of Terms for Describing and Standardizing Materials,” that galvanized steel 

in the presence of moisture should be classified under the category “steel.” Based on its review 

of the GALL Report and M.G. Fontana, “Corrosion Engineering,” Third Edition, McGraw-Hill, 

1986, which states galvanized steel in an outdoor environment (where it would be exposed to 

moisture) has no AERM as a result of the corrosion protection provided by the zinc coating that 

is enhanced by the buildup of corrosion products deposited out of solution, the staff finds that 

the applicant has identified all credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program, with enhancements, acceptable because the galvanized steel 

structural, beams, columns, and plates exposed to a fluid environment will be inspected at 

intervals not to exceed 5 years and evaluated using acceptance criteria based on industry 

codes, standards, and guidelines, including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R, and 

the book “Corrosion Engineering” indicates that the zinc coating will provide corrosion protection 

in a moist environment.

Fiber Reinforced Polyester Exposed to Fluid Environment. In LRA Table 3.5.2-2, the applicant 

stated that fiber reinforced polyester cooling tower drift eliminators will be managed for cracking 

by the Structures Monitoring Program. The AMR cites generic note J.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all the credible aging effects for this component, material, and 

environment description. The staff noted that fiberglass is a composite material comprised of 

glass fibers and a polyester or epoxy resin. Fiberglass composites have excellent moisture 

resistance and chemical resistance to many corrosive materials, including acids (specifically 

including boric acid), chlorides, nitrates, and sulfates, and that the maximum recommended 

operating temperature for fiberglass is 200 ̊F. The staff also noted that the fiber reinforced 

cooling tower drift eliminators will not be exposed to temperatures above ambient, and cracking 

resulting from exposure to fluid environment will be managed by the Structures Monitoring 

Program.

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff finds the applicant’s proposal to manage aging using the 

Structures Monitoring Program acceptable because the fiber-reinforced polyester cooling tower 
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drift eliminators exposed to a fluid environment will be inspected at intervals not to exceed 

5 years in accordance with guidelines in NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R, and 

operating experience indicates that the fiber-reinforced polyester materials have good chemical 

and moisture resistance.

Ceramic Tile Cooling Tower Fill Exposed to Fluid Environment. In LRA Table 3.5.2-2, the 

applicant stated that ceramic tile cooling tower fill exposed to fluid environment has no AERMs, 

but will be managed for cracking by the Structures Monitoring Program. The AMR cites generic 

note J.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all the credible aging effects for this component, material, and 

environment description. The staff noted ceramic tiles are a mixture of clays and other natural 

materials that are mined from the earth, shaped, and fired at high temperature, and thus provide

a durable material with closed surface pore structure that is resistant to water absorption. The 

staff also noted that the durability of ceramic tiles has been demonstrated through their use for 

many years as roof tiles, and although no AERMs were identified for the ceramic tile cooling 

tower fill, the applicant will use the Structures Monitoring Program as an AMP.

The staff’s evaluation of the Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff noted that under the Structures Monitoring Program, after 

enhancement, these components will be inspected at intervals not to exceed 5 years, and 

evaluated using acceptance criteria based on industry codes, standards, and guidelines 

including NEI 96-03, ANSI/ASCE 11-99, and ACI 349.3R. The staff finds the applicant’s 

proposal to manage aging using the Structures Monitoring Program acceptable because the 

ceramic tile cooling tower fill exposed to a fluid environment will be inspected at intervals not to 

exceed 5 years in accordance with guidelines in NEI 96-03, ANSI/ASCE 11-99, and 

ACI 349.3R, and a review of operating experience indicates that the ceramic tile materials have 

good chemical and moisture resistance.

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 Turbine Building, Process Facilities, and Yard Structures - 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 

turbine building, process facilities, and yard structures component groups.

Concrete Fire Barriers Exposed to Uncontrolled Indoor Air. In LRA Tables 3.5.2-3 and 3.5.2-4, 

the applicant stated that for concrete walls, beams, columns, floor slabs, roof slabs, manways, 

hatches, manhole covers, hatch covers, and floor curbs exposed to uncontrolled indoor air, 

concrete cracking and spalling are not applicable. The AMR items cite generic note I. The 

AMR items also cite a plant-specific note that states that the given environment is not conducive 

to the stated aging effects, but an AMP will be used to confirm the absence of aging effects 

during the period of extended operation. The applicant credited the Fire Protection and 

Structures Monitoring Programs to confirm the absence of aging effects.
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The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. Based on its review of 

the GALL Report, item VII.G.A-90, the staff noted that cracking and spalling are applicable 

aging effects for concrete fire barriers exposed to indoor air. However, since the applicant will 

inspect these components for aging effects using the Fire Protection and Structures Monitoring 

Program, the staff finds the applicant’s proposal acceptable because it is consistent with the 

GALL Report recommendations for managing aging for these components, as documented in 

item VII.G.A-90 (SRP-LR Table 3.3-1, item 60).

Concrete Fire Barriers Exposed to Outdoor Air. In LRA Tables 3.5.2-3 and 3.5.2-4, the 

applicant stated that for concrete walls, roof slabs, manways, hatches, manhole covers, and 

hatch covers exposed to outdoor air, concrete cracking and loss of material are not applicable. 

The AMR items cite generic note I. The AMR items also cite a plant-specific note that states 

that the given environment is not conducive to the stated aging effects, but an AMP will be used 

to confirm the absence of aging effects during the period of extended operation. The applicant 

credited the Fire Protection and Structures Monitoring Programs to confirm the absence of 

aging effects.

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination. Based on its review of 

the GALL Report, item VII.G.A-92, the staff noted that cracking and loss of material are 

applicable aging effects for concrete fire barriers exposed to outdoor air. However, since the 

applicant will inspect these components for aging effects using the Fire Protection and 

Structures Monitoring Programs, the staff finds the applicant’s proposal acceptable because it is 

consistent with the GALL Report recommendations for managing aging for these components, 

as documented in item VII.G.A-92 (SRP-LR Table 3.3-1, item 61).

Inaccessible Areas, Group 3 Concrete Structures Exposed to Air-Outdoor Environment. In LRA

Table 3.5.2-3, the applicant stated that for concrete CST/RWST retaining basin (wall) and diesel 

fuel tank access tunnel slab exposed to air-outdoor, cracking due to expansion from reaction 

with aggregates are not applicable. The AMR items cite generic note I. The AMR items also 

cite a plant-specific note that states that the given environment is not conducive to the stated 

aging effects, but an AMP will be used to confirm the absence of aging effects during the period 

of extended operation. The applicant credited the Structures Monitoring Program to confirm the 

absence of aging effects.

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination and determined the 

need for additional information. By letter dated August 15, 2012, the staff issued RAI 3.5.1.12-1 

requesting the technical justification for the non-applicability of cracking due to expansion from 

reaction with aggregates as a possible aging effect for the components listed in item 3.5.1-54. 

The staff’s review of the applicant’s response to RAI 3.5.1.12-1, and justification for acceptance 

is provided in SER Section 3.5.2.2.1.

Concrete Structures Exposed to Soil. In LRA Table 3.5.2-3, the applicant stated that for 

concrete sumps exposed to soil, cracking, and distortion due to increased stress levels from 

settlement are not applicable. The AMR items cite generic note I. The AMR items also cite a 

plant-specific note that states that the given environment is not conducive to the stated aging 

effects, but an AMP will be used to confirm the absence of aging effects during the period of 

extended operation. The applicant credited the Structures Monitoring Program to confirm the 

absence of aging effects.
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The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that cracking and distortion due to increased 

stress levels from settlement are not applicable because the environment is not conducive to 

these aging effects, in response to RAI 3.5.1-2, the applicant clarified that item 3.5.1-44 is 

consistent with the aging management program identified in the GALL Report and the 

components are included in the Structures Monitoring Program to confirm the absence of these 

aging effects. Therefore, the staff finds the applicant’s proposal acceptable because it is 

consistent with the GALL Report recommendations for managing aging for these components, 

as documented in item III.A7.TP-30 (SRP-LR Table 3.5-1, item 44).

Groups 1, 3, and 5, Concrete Structures Exposed to Soil. In LRA Table 3.5.2-3, the applicant 

stated that for concrete CST/RWST retaining basin (wall), duct banks, exterior walls 

(below-grade), foundations (buildings, transformers, tanks, circuit breakers), and manholes 

exposed to soil, cracking, loss of bond, and loss of material (spalling, scaling) due to corrosion 

of embedded steel are not applicable. The AMR items cite generic note I. The AMR items also 

cite a plant-specific note that states that the given environment is not conducive to the stated 

aging effects, but an AMP will be used to confirm the absence of aging effects during the period 

of extended operation. The applicant credited the Structures Monitoring Program to confirm the 

absence of aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that cracking, loss of bond, and loss of 

material (spalling, scaling) due to corrosion of embedded steel are not applicable because the 

environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-65 is consistent with the aging management program identified in the 

GALL Report and the components are included in the Structures Monitoring Program to confirm 

the absence of these aging effects. Therefore, the staff finds the applicant’s proposal 

acceptable because it is consistent with the GALL Report recommendations for managing aging 

for these components, as documented in items III.A1.TP-27, III.A3.TP-27, and III.A5.TP-27, 

(SRP-LR Table 3.5-1, item 65).

Groups 1-5, 7, and 9 Concrete Structures Exposed to Air-Indoor Uncontrolled or Air-Outdoor. In 

LRA Table 3.5.2-3, the applicant stated that for concrete roof slabs exposed to air-indoor 

uncontrolled or air-outdoor, cracking, loss of bond, and loss of material (spalling, scaling) due to 

corrosion of embedded steel are not applicable. The AMR items cite generic note I. The AMR 

items also cite a plant-specific note that states that the given environment is not conducive to 

the stated aging effects, but an AMP will be used to confirm the absence of aging effects during 

the period of extended operation. The applicant credited the Structures Monitoring Program to 

confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER

Section 3.0.3.1.40. Although the applicant stated that cracking, loss of bond, and loss of 

material (spalling, scaling) due to corrosion of embedded steel are not applicable because the 

environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-66 is consistent with the aging management program identified in the 

GALL Report and the components are included in the Structures Monitoring Program to confirm 

the absence of these aging effects. Therefore, the staff finds the applicant’s proposal 

acceptable because it is consistent with the GALL Report recommendations for managing aging 

for these components, as documented in items III.A1.TP-26, III.A3.TP-26, and III.A5.TP-26 

(SRP-LR Table 3.5-1, item 66).
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Groups 1-5, and 7-9 Concrete Structures Exposed to Air-Indoor Uncontrolled. In LRA

Table 3.5.2-3, the applicant stated that for concrete sumps exposed to air-indoor uncontrolled, 

increase in porosity and permeability, cracking, and loss of material (spalling, scaling) due to 

aggressive chemical attack are not applicable. The AMR items cite generic note I. The AMR 

items also cite a plant-specific note that states that the given environment is not conducive to 

the stated aging effects, but an AMP will be used to confirm the absence of aging effects during 

the period of extended operation. The applicant credited the Structures Monitoring Program to 

confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that increase in porosity and permeability, 

cracking, and loss of material (spalling, scaling) due to aggressive chemical attack are not 

applicable because the environment is not conducive to these aging effects, in response to 

RAI 3.5.1-2, the applicant clarified that item 3.5.1-67 is consistent with the aging management 

program identified in the GALL Report and the components are included in the Structures 

Monitoring Program to confirm the absence of these aging effects. Therefore, the staff finds the 

applicant’s proposal acceptable because it is consistent with the GALL Report

recommendations for managing aging for these components, as documented in 

item III.A7.TP-28 (SRP-LR Table 3.5-1, item 67).

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended function(s) will be maintained consistent with the 

CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3.5.2.3.4 Bulk Commodities - 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 

bulk commodities component groups.

Carbon Steel Fire Doors Exposed to Air-Outdoor. In LRA Table 3.5.2-4, the applicant stated 

that carbon steel fire doors exposed to air-outdoor will be managed for loss of material by the 

Fire Protection Program. The AMR item cites generic note H.

The staff noted that this material and environment combination is identified in the GALL Report, 

item VII.G.A-22, which states that steel fire doors exposed to outdoor air are susceptible to loss 

of material due to wear and recommends GALL Report AMP XI.M26, “Fire Protection,” to 

manage the aging effect. However the applicant stated in LRA Table 3.3.1, item 3.3.1-59, that 

loss of material due to wear is not an applicable aging effect for fire doors because wear is an 

event driven effect. Instead, the applicant will manage fire doors for other types of loss of 

material. The staff finds the applicant’s proposal to manage loss of material due to mechanisms 

other than wear acceptable because the inspection methods used to detect loss of material due 

to other aging mechanisms are the same as those used to detect wear.

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.1.19. The staff finds the applicant’s proposal to manage aging using the Fire 

Protection Program acceptable because the program includes visual inspections and functional 

tests of fire doors that are capable of identifying loss of material, regardless of mechanism, to 

ensure the fire door’s operability is maintained.
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Concrete Fire Barriers Exposed to Air-Indoor Uncontrolled or Air-Outdoor. The staff’s 

evaluation for concrete fire barriers exposed to uncontrolled indoor and outdoor air, which will 

be managed for aging using the Fire Protection and Structures Monitoring Programs and cite 

generic note I, is documented in SER Section 3.5.2.3.3.

Aluminum Vents and Louvers Exposed to Air-Outdoor. In LRA Table 3.5.2-4, the applicant 

stated that for aluminum vents and louvers exposed to air-outdoor, no AERM or AMP is 

proposed. The AMR item cites generic note I. The AMR item also cites plant-specific note 503 

that states, “[v]apors of sulfur dioxide or other similar substances do not chemically pollute the 

ambient outdoor environment and the external environment does not contain saltwater or high 

chloride content; therefore aging management is not required for aluminum and stainless steel 

components exposed to the external environment.”

The staff reviewed the associated LRA items to confirm that this aging effect is not applicable 

for this component, material, and environmental combination. The SRP-LR states, in

Table 3.4.1, item 35, that aluminum components exposed to outdoor air are susceptible to loss 

of material due to pitting and crevice corrosion. By letter dated June 20, 2012, the staff issued

RAI 3.5.2.3.4-3, requesting that the applicant explain why loss of material due to pitting and 

crevice corrosion is not an applicable aging effect for aluminum components exposed to 

outdoor air.

In its response dated July 19, 2012, the applicant stated, “[t]he aluminum vents and louvers in 

an air-outdoor environment will be treated as susceptible to an aging effect of loss of material.” 

LRA Table 3.5.2-4 was amended to state that the aluminum vents and louvers exposed to an 

outdoor air environment will be managed for loss of material by the Structures Monitoring 

Program. The amended item cites LRA Table 3.5.1, item 3.5.1-93 and generic note A, and 

plant-specific note 503 was deleted.

The staff noted that item 3.5.1-93, GALL Report item TP-6, states that galvanized steel, 

aluminum, and stainless steel support members, welds, bolted connections, and support 

anchorages to building structure exposed to outdoor air may be managed for loss of material 

due to pitting and crevice corrosion by GALL Report AMP XI.S6, “Structures Monitoring,”

program. The staff noted that generic note A was not appropriately cited given that vents and 

louvers are not support members, welds, bolted connections, or support anchorages to building 

structures. Nevertheless, the staff does agree that the vents and louvers are closely aligned to 

structural members based on a review of LRA Sections 2.3.3.18, 2.4.2, 2.4.3, and Table 2.4-4, 

because the vents and louvers are associated with building structures.

The staff finds the applicant’s response and its proposal to manage aging for aluminum vents 

and louvers exposed to outdoor air using the Structures Monitoring Program acceptable 

because the LRA has been amended to manage loss of material for aluminum vents and 

louvers and the Structures Monitoring Program includes visual inspections that are capable of 

detecting pitting and crevice corrosion. The staff’s concern described in RAI 3.5.2.3.4-3 is 

resolved.

Non-Metallic Fire Barriers Exposed to Uncontrolled Indoor Air. In LRA Table 3.5.2-4, the 

applicant stated that cerafiber, cerablanket, Thermo-lag, and 3M Interam fire wraps exposed to 

uncontrolled indoor air will be managed for loss of material and cerafiber and elastomer fire 

stops exposed to air-indoor uncontrolled will be managed for cracking, delamination, and 

separation by the Fire Protection Program. The AMR items cite generic note J.
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The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all of the credible aging effects for this component, 

material, and environment description. Although the GALL Report does not have any AMR 

items for non-metallic fire barriers, the staff noted that GALL Report AMP XI.M26, “Fire 

Protection,” does include fire resistant materials, including fire wrapping, within the scope of the 

AMP. GALL Report AMP XI.M26 recommends that these materials be managed for cracking, 

and loss of material and seal separation. Based on its review of the GALL Report, the staff 

finds that the applicant has identified the credible aging effects for this component, material, and 

environment combination.

The staff’s evaluation of the applicant’s Fire Protection Program is documented in SER 

Section 3.0.3.1.19. The staff finds the applicant’s proposal to manage aging using the Fire 

Protection Program acceptable because the program includes visual inspections of fire barriers 

of various material types that are capable of detecting degradation of the fire barrier prior to loss 

of intended function.

Pyrocrete Fire Proofing Exposed to Air-Indoor Uncontrolled. In LRA Table 3.5.2-4, the applicant 

stated that pyrocrete fire proofing exposed to air-indoor uncontrolled will be managed for no 

aging effects by the Fire Protection and Structures Monitoring Programs. The AMR items cite 

generic note J. The AMR items also cite a plant-specific note that states that the given 

environment is not conducive to the stated aging effects, but an AMP will be used to confirm the 

absence of aging effects during the period of extended operation.

Although the GALL Report does not have any AMR items for non-metallic fire barriers, the staff 

noted that GALL Report AMP XI.M26, “Fire Protection,” does include fire resistant materials, 

including spray-on fireproofing, within the scope of the AMP. The staff noted that pyrocrete is a 

cementitious spray-on fire proofing material. GALL Report AMP XI.M26 recommends that 

concrete materials be managed for cracking, spalling, and loss of material. The staff noted that 

pyrocrete has applicable aging effects when exposed to indoor air. However, the staff finds the 

applicant’s proposal acceptable because the applicant will inspect these components to confirm 

the absence of aging effects using programs that inspect for the GALL Report identified aging 

effects of cracking, spalling, and loss of material.

The staff’s evaluation of the applicant’s Fire Protection and Structures Monitoring Programs are 

documented in SER Sections 3.0.3.1.19 and 3.0.3.1.40. The staff finds the applicant’s proposal 

to manage aging using the Fire Protection and Structures Monitoring Programs acceptable 

because the programs include visual inspections of fire barriers of various material types that

are capable of detecting cracking, spalling, and loss of material prior to loss of intended 

function.

Stainless Steel Supports, Base Plates, and Bolting Exposed to Air-Outdoor. In LRA

Table 3.5.2-4, the applicant stated that for stainless steel base plates, anchor bolts, structural 

bolting, ASME Class 1, 2, 3, and MC support bolting, and component and piping supports 

exposed to air-outdoor, there are no aging effects and no AMP is proposed. The AMR items 

cite generic note I. The AMR items also cite a plant-specific note that states that sulfur dioxide 

vapors or other similar substances do not chemically pollute the ambient outdoor environment at 

GGNS and the external environment does not contain saltwater or high chloride content; 

therefore, aging management is not required for aluminum and stainless steel components 

exposed to the external environment.
3-487

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all of the credible aging effects for this component, material, 

and environment description. The GALL Report states that stainless steel components exposed 

to outdoor air can be susceptible to cracking and loss of material depending on the outdoor 

environmental conditions. SRP-LR Sections 3.4.2.2.2 and 3.4.2.2.3 state that cracking and loss 

of material are applicable in outdoor environments high in chlorides, such as those near a 

saltwater coastline, near a highway treated with salt, with chlorides in the soil, or that have a 

cooling tower treated with chlorine. LRA Section 3.4.2.2.2 states that the applicant has a 

cooling tower treated with hypochlorite. By letter dated May 24, 2012, the staff issued

RAI 3.5.2.4-1 requesting that the applicant explain why cracking and loss of material are not 

applicable aging effects for stainless steel components exposed to outdoor air given that the 

outdoor air environment contains cooling tower vapor that contains chlorides.

In its response dated June 22, 2012, the applicant stated that stainless steel structural 

components exposed to outdoor air are susceptible to cracking and loss of material. The 

applicant revised the LRA to credit the Structures Monitoring Program to manage cracking and 

loss of material for the stainless steel base plates, anchor bolts, structural bolting, and 

component and piping supports exposed to air-outdoor, citing generic note G. The applicant 

also revised the LRA to credit the ASME Section XI, Subsection IWF, program to manage 

cracking and loss of material for ASME Class 1, 2, 3, and MC supports bolting, citing generic 

note G. The staff’s review of the applicant’s Structures Monitoring and ISI – IWF Programs are 

documented in SER Section 3.0.3.1.40 and 3.0.3.1.23, respectively. The staff noted that GALL

Report item III.B2.TP-6 recommends that stainless steel support members, bolted connections, 

and support anchorage exposed to outdoor air be managed for loss of material using GALL 

Report AMP XI.S6, “Structures Monitoring.” GALL Report AMP XI.S6 recommends performing 

visual inspections to manage loss of material. The staff also noted that GALL Report

item V.B.EP-103 recommends that stainless steel components exposed to outdoor air be 

managed for cracking using GALL Report AMP XI.36, “External Surfaces Monitoring of 

Mechanical Components,” which uses visual inspections to manage cracking for this component 

group. The staff finds the applicant’s response and its proposal to manage cracking and loss of 

material for these components using the Structures Monitoring and ISI – IWF Programs 

acceptable because the programs include visual inspections that are capable of detecting 

cracking and loss of material, and are consistent with the inspection methods recommended by 

the GALL Report to manage aging for this component group. The staff’s concern described in 

RAI 3.5.2.4-1 is resolved.

Structural Bolting Exposed to Air-Outdoor. In LRA Table 3.5.2-4, the applicant stated that 

stainless steel base plates, component and piping supports, anchor bolts, and structural bolting 

exposed to air-outdoor will be managed for cracking and loss of material by the Structures 

Monitoring Program. The AMR items cite generic note G.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all of the credible aging effects for this component, material, 

and environment description. Based on its review of GALL Report items III.B2.TP-6 and 

III.B4.TP-6, which states that support members; welds; bolted connections; and support 

anchorage to building structures exposed to air-outdoor are susceptible to loss of material, the 

staff finds that the applicant has identified all credible aging effects for this component, material, 

and environment combination.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. The staff finds the applicant’s proposal to manage aging using the 
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Structures Monitoring Program acceptable because these components are within the scope of 

the Structures Monitoring Program and the inspections will be done by qualified personnel 

consistent with the recommendations in GALL Report AMP XI.S6.

Groups 1-5 and 7-9 Concrete Structures Exposed to Air-Indoor Uncontrolled or Air-Outdoor. In 

LRA Table 3.5.2-4, the applicant stated that for concrete equipment pads/foundations, flood 

curbs, manways, hatches, manhole covers, hatch covers, and support pedestals exposed to 

air-indoor uncontrolled or air-outdoor, cracking due to expansion from reaction with aggregates 

is not applicable. The AMR items cite generic note I. The AMR items also cite a plant-specific 

note that states that the given environment is not conducive to the stated aging effects, but an 

AMP will be used to confirm the absence of aging effects during the period of extended 

operation. The applicant credited the Structures Monitoring Program to confirm the absence of 

aging effects.

The staff reviewed the associated items in the LRA to confirm that these aging effects are not 

applicable for this component, material, and environmental combination and determined the 

need for additional information. By letter dated August 15, 2012, the staff issued RAI 3.5.1.12-1 

requesting the technical justification for the non-applicability of cracking due to expansion from 

reaction with aggregates as a possible aging effect for the components listed in item 3.5.1-54. 

The staff’s review of the applicant’s response to RAI 3.5.1.12-1, and justification for acceptance 

is provided in SER Section 3.5.2.2.1.

Group 6 Concrete Structures Exposed to Air-Indoor Uncontrolled or Air-Outdoor. In LRA

Table 3.5.2-4, the applicant stated that for concrete equipment pads/foundations exposed to 

air-indoor uncontrolled or air-outdoor, cracking, loss of bond, and loss of material (spalling, 

scaling) due to corrosion of embedded steel are not applicable. The AMR items cite generic 

note I. The AMR items also cite a plant-specific note that states that the given environment is 

not conducive to the stated aging effects, but an AMP will be used to confirm the absence of 

aging effects during the period of extended operation. The applicant credited the RG 1.127, 

Inspection of Water-Control Structures Associated with Nuclear Power Plants Program to 

confirm the absence of aging effects.

The staff’s evaluation of the applicant’s RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program is documented in SER Section 3.0.3.1.37. 

Although the applicant stated that cracking, loss of bond, and loss of material (spalling, scaling) 

due to corrosion of embedded steel are not applicable because the environment is not 

conducive to these aging effects, in response to RAI 3.5.1-2, the applicant clarified that 

item 3.5.1-59 is consistent with the aging management program identified in the GALL Report 

and the components are included in the RG 1.127, Inspection of Water-Control Structures 

Associated with Nuclear Power Plants Program to confirm the absence of these aging effects. 

Therefore, the staff finds the applicant’s proposal acceptable because it is consistent with the 

GALL Report recommendations for managing aging for these components, as documented in 

items III.A6.TP-38 (SRP-LR Table 3.5-1, item 59).

Groups 1-5, 7, and 9 Concrete Structures Exposed to Air-Indoor Uncontrolled or Air-Outdoor. In 

LRA Table 3.5.2-4, the applicant stated that for concrete manways, hatches, manhole covers, 

and missile shields exposed to air-indoor uncontrolled or air-outdoor, cracking, loss of bond, and 

loss of material (spalling, scaling) due to corrosion of embedded steel are not applicable. The 

AMR items cite generic note I. The AMR items also cite a plant-specific note that states that the 

given environment is not conducive to the stated aging effects, but an AMP will be used to 
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confirm the absence of aging effects during the period of extended operation. The applicant 

credited the Structures Monitoring Program to confirm the absence of aging effects.

The staff’s evaluation of the applicant’s Structures Monitoring Program is documented in SER 

Section 3.0.3.1.40. Although the applicant stated that cracking, loss of bond, and loss of 

material (spalling, scaling) due to corrosion of embedded steel are not applicable because the 

environment is not conducive to these aging effects, in response to RAI 3.5.1-2, the applicant 

clarified that item 3.5.1-66 is consistent with the aging management program identified in the 

GALL Report and the components are included in the Structures Monitoring Program to confirm 

the absence of these aging effects. Therefore, the staff finds the applicant’s proposal 

acceptable because it is consistent with the GALL Report recommendations for managing aging 

for these components, as documented in items III.A3.TP-26 and III.A7.TP-26 (SRP-LR

Table 3.5-1, item 66).

Fiberglass/Calcium Silicate Insulation Exposed to Air-Indoor Uncontrolled. In LRA

Table 3.5.2-4, the applicant stated that for fiberglass/calcium silicate insulation exposed to 

air-indoor uncontrolled environment aging effects are not applicable and no AMP is proposed. 

The applicant cites generic note J and plant-specific note 501. Plant-specific note 501 states 

that the GGNS environment is not conducive to the listed aging effects. However, the identified 

AMP will be used to confirm the absence of significant aging effects for the period of extended 

operation.

The staff reviewed the associated items in the LRA to confirm that there are no aging effects 

applicable for this component, material, and environment combination. The staff noted that the 

thermal resistance (insulating) characteristics of mass insulation systems are not expected to 

naturally degrade over the course of their service life as proper selection, design, and 

installation for the specific service and condition is assumed. The staff also noted that unless 

protective coverings of mass insulation systems are damaged, loss/degradation of insulating 

material is not a concern and mass insulation systems used in nuclear plant applications 

typically are sealed and include a combination of insulating material and a weather barrier, 

vapor barrier, condensate barrier, or covering for the specific service; and this outer covering (or 

barrier) protects mass insulation from the weather, solar/UV radiation, or atmospheric 

contaminants, and mechanical damage, but permits the evaporation of any moisture vapor. The 

staff finds the applicant’s proposal acceptable because these materials perform well when 

exposed to air and are properly jacketed to prevent moisture intrusion.

Rubber Water Stops Exposed to Air-Indoor Uncontrolled. In LRA Table 3.5.2-4, the applicant 

stated that for rubber water stops exposed to air-indoor uncontrolled environment aging effects 

are not applicable and no AMP is proposed. The applicant cites generic note J.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

proposed by the applicant constitute all the credible aging effects for this component, material, 

and environment description. The staff noted that in GALL Report Section IX.F, “Selected 

Definitions and Use of Terms for Describing and Standardizing Aging Mechanisms,” it identifies 

elastomer (i.e., rubber) degradation mechanisms as cracking, crazing, fatigue breakdown, 

abrasion, chemical attacks, and weathering. The GALL Report also notes that for rubber 

materials hardening and loss of strength of elastomers can be induced by elevated temperature 

(over about 95 °F [35 °C]), and additional aging factors such as exposure to ozone, oxidation, 

and radiation. Since the rubber water stops provide a flood barrier function and loss of sealing 

can result from a number of degradation mechanisms, the staff is uncertain why no AERMs 

have been identified for the rubber water stops exposed to air-indoor uncontrolled environment 
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and an AMP has not been identified (e.g., GALL Report item VII.F1.AP-102 notes elastomers in 

an air uncontrolled environment are subject to hardening and loss of strength due to 

degradation and identifies an AMP, and SRP-LR Table 3.5-1 item 72 identified loss of sealing 

due to deterioration of seals, gaskets, and moisture barriers [caulking, flashing, and other 

sealants] as an aging effect/mechanism that will be managed by the Structures Monitoring 

Program).

By letter dated June 27, 2012, the staff issued RAI 3.5.2.4-5 requesting that the applicant 

explain why no AERMs or an AMP has been identified for rubber water stops exposed to air 

indoor uncontrolled environment that provide an intended function of flood barrier.

In its response dated July 25, 2012, the applicant stated that the rubber water stops are located 

in the expansion joint between the turbine building, foundation basemat and adjoining 

structures, and the expansion joint between the turbine building foundation basemat and the 

turbine building foundation. The applicant also stated that the rubber water stops are partially 

embedded in the concrete and the portion exposed to the air-indoor uncontrolled environment is 

located within the expansion joint gap a minimum of 3 feet below the top surface of the 

6-foot-thick turbine foundation building basemat and the expansion joints containing the water 

stops are filled with an elastomeric material that is within scope of license renewal. The 

applicant further stated that the Structures Monitoring Program manages aging of the elastomer 

material within the seismic isolation joint, and although the maximum area temperature for the 

interior of the turbine building is 105 °F, the water stops are located in the lowest elevation of 

the building and are not exposed to temperatures above the GALL Report, Table IX.C, threshold 

for elastomers of 95 °F. In addition, the applicant stated that the water stop material is 

protected by the expansion joint configuration (i.e., surrounding concrete and expansion joint 

filler) and will not be exposed to an adverse environment (e.g., elevated temperature, ozone, 

oxidation, and radiation).

The staff finds the applicant’s response acceptable because the rubber water stops are 

protected from adverse environments by the surrounding concrete and expansion joint filler; 

aging of the expansion joint filler and surrounding concrete will be managed by the Structures 

Monitoring Program that performs periodic visual examinations by qualified personnel using 

criteria derived from industry codes and standards, including ACI 349.3R, ACI 318, 

ANSI/ASCE 11, and the American Institute of Steel Construction (AISC) specifications, as 

applicable; and the proposal is consistent with GALL Report recommendations for managing

aging of components as documented in item III.A6.TP-7 (SRP-LR Table 3.5.1 item 3.5.1-72). 

The staff’s concern described in RAI 3.5.2.4-5 is resolved.

On the basis of its review, the staff finds that the applicant has appropriately evaluated the AMR 

results of material, environment, AERM, and AMP combinations not evaluated in the 

GALL Report. The staff finds that the applicant has demonstrated that the effects of aging will 

be adequately managed so that the intended 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 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).
3-491

3.6 Aging Management of Electrical and Instrumentation and Controls System

This section of the SER documents the staff’s review of the applicant’s AMR results for the 

electrical and instrumentation and control (I&C) system components and component groups of:

• high-voltage insulators

• non-EQ insulated cables and connections

− cable connections (metallic parts)

− electrical cables and connections not subject to 10 CFR 50.49 EQ requirements

− electrical cables not subject to 10 CFR 50.49 EQ requirements used in 

instrumentation circuits

− electrical and instrumentation control penetration cables and connections not subject 

to 10 CFR 50.49 EQ requirements

− fuse holders (insulation material)

− non-EQ fuse holder (metallic portion)

− inaccessible power (400V to 35kV) cables (e.g., installed underground in conduit, 

duct bank or direct buried) not subject to 10 CFR 50.49 EQ requirements

− inaccessible power (115kV) cables (e.g., installed underground in conduit, duct bank 

or direct buried) not subject to 10 CFR 50.49 EQ requirements

• switchyard bus and connections

• transmission conductors and connections

3.6.1 Summary of Technical Information in the Application

LRA Section 3.6 provides AMR results for the electrical and I&C system components and 

component groups. LRA Table 3.6.1, “Summary of Aging Management Programs for the 

Electrical and I&C Components Evaluated in Chapter VI of NUREG-1801,” is a summary 

comparison of the applicant’s AMRs with those evaluated in the GALL Report for the electrical 

and I&C system components and component groups.

The applicant’s AMRs evaluated and incorporated applicable plant-specific and industry 

operating experience in the determination of AERMs. The plant-specific evaluation included 

condition reports and discussions with appropriate site personnel to identify AERMs. The 

applicant’s review of industry operating experience included a review of the GALL Report and 

operating experience issues identified since the GALL Report was issued.

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 system 

components within the scope of license renewal and subject to an AMR, will be adequately 

managed so that the intended function(s) will be maintained consistent with the CLB for the 

period of extended operation, as required by 10 CFR 54.21(a)(3).

The staff conducted an onsite audit of AMRs to ensure the applicant’s claim that certain AMRs 

were consistent with the GALL Report. The staff did not repeat its review of the matters 
3-492

described in the GALL Report; however, the staff did verify that the material presented in the 

LRA was applicable and that the applicant identified the appropriate GALL Report AMRs. The 

staff’s evaluations of the AMPs are documented in SER Section 3.0.3. Details of the staff’s 

audit evaluation are documented in SER Section 3.6.2.1.

In the onsite audit, the staff also selected AMRs consistent with the GALL Report and for which 

further evaluation is recommended. The staff confirmed that the applicant’s further evaluations 

were consistent with the SRP-LR Section 3.6.2.2 acceptance criteria. The staff’s audit 

evaluations are documented in SER Section 3.6.2.2.

The staff also conducted a technical review of the remaining AMRs not consistent with or not 

addressed in the GALL Report. The technical review evaluated whether all plausible aging 

effects have been identified and whether the aging effects listed were appropriate for the 

material-environment combinations specified. The staff’s evaluations are documented in SER 

Section 3.6.2.3.

For SSCs that the applicant claimed were not applicable or required no aging management, the 

staff reviewed the AMR items and the plant’s operating experience to verify the applicant’s 

claims.

Table 3.6-1 summarizes the staff’s evaluation of components, aging effects or mechanisms, and 

AMPs listed in LRA Section 3.6 and addressed in the GALL Report.

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

Report

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Electrical equipment 

subject to 

10 CFR 50.49 EQ 

requirements 

composed of various 

polymeric and 

metallic materials 

exposed to adverse 

localized 

environment caused 

by heat, radiation, 

oxygen, moisture, or 

voltage (3.6.1-1)

Various aging 

effects due to 

various 

mechanisms in 

accordance with 

10 CFR 50.49

EQ is TLAA to be 

evaluated for the 

period of extended 

operation. See the 

Standard Review Plan, 

Section 4.4, 

“Environmental 

Qualification (EQ) of 

Electrical Equipment,”

for acceptable 

methods for meeting 

the requirements of 

10 CFR 54.21(c)(1)(i) 

and (ii). See Chapter 

X.E1, “Environmental 

Qualification (EQ) of 

Electric Components,”

of this report for 

meeting the 

requirements of 

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

Yes TLAA Consistent with the 

GALL Report

(see SER 

Section 3.6.2.2.1)
3-493

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-2)

Loss of material 

due to 

mechanical 

wear caused by 

wind blowing on 

transmission 

conductors

A plant-specific AMP is 

to be evaluated

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.2)

High-voltage 

insulators composed 

of porcelain; 

malleable iron; 

aluminum; 

galvanized steel; 

cement exposed to 

air – outdoor 

(3.6.1-3)

Reduced 

insulation 

resistance due 

to presence of 

salt deposits or 

surface 

contamination

A plant-specific AMP is 

to be evaluated for 

plants located such 

that the potential exists 

for salt deposits or 

surface contamination 

(e.g., in the vicinity of 

salt water bodies or 

industrial pollution)

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.2)

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-4)

Loss of 

conductor 

strength due to 

corrosion

A plant-specific AMP is 

to be evaluated for 

ACSR

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.3)

Transmission 

connectors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-5)

Increased 

resistance of 

connection due 

to oxidation or 

loss of preload

A plant-specific AMP is 

to be evaluated

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.3)

Switchyard bus and 

connections 

composed of 

aluminum; copper; 

bronze; stainless 

steel; galvanized 

steel exposed to 

air – outdoor 

(3.6.1-6)

Loss of material 

due to 

wind-induced 

abrasion; 

Increased 

resistance of 

connection due 

to oxidation or 

loss of preload

A plant-specific AMP is 

to be evaluated

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.3)

Transmission 

conductors 

composed of 

aluminum; steel 

exposed to air –

outdoor (3.6.1-7)

Loss of material 

due to 

wind-induced 

abrasion

A plant-specific AMP is 

to be evaluated for 

ACAR and ACSR

Yes Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.2.3)
3-494

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Insulation material 

for electrical cables 

and connections 

(including terminal 

blocks, fuse holders, 

etc.) composed of 

various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-8)

Reduced 

insulation 

resistance due 

to thermal/

thermoxidative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion

Chapter XI.E1, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Non-EQ 

Insulated 

Cables and 

Connections

Consistent with the 

GALL Report

Insulation material 

for electrical cables 

and connections 

used in 

instrumentation 

circuits that are 

sensitive to 

reduction in 

conductor insulation 

resistance (IR) 

composed of 

Various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by heat, radiation, or 

moisture (3.6.1-9)

Reduced 

insulation 

resistance due 

to 

thermal/thermox

idative 

degradation of 

organics, 

radiolysis, and 

photolysis (UV 

sensitive 

materials only) 

of organics; 

radiationinduced 

oxidation; 

moisture 

intrusion

Chapter XI.E2, 

“Insulation Material for 

Electrical Cables and 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements Used in 

Instrumentation 

Circuits”

No Non-EQ 

Instrumentatio

n Circuits Test 

Review

Consistent with the 

GALL Report

Conductor insulation 

for inaccessible 

power cables greater 

than or equal to 400 

volts (e.g., installed 

in conduit or direct 

buried) composed of 

Various organic 

polymers (e.g., EPR, 

SR, EPDM, XLPE) 

exposed to adverse 

localized 

environment caused 

by significant 

moisture (3.6.1-10)

Reduced 

insulation 

resistance due 

to moisture

Chapter XI.E3, 

“Inaccessible Power 

Cables Not Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Non-EQ 

Inaccessible 

Power Cables 

(400 V to 

35 kV) and the 

115 kV

Inaccessible 

Transmission 

Cable

Consistent with the 

GALL Report

(see SER 

Section 3.6.2.3.1)
3-495

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Metal enclosed bus: 

enclosure 

assemblies 

composed of 

elastomers exposed 

to air – indoor, 

controlled or 

uncontrolled or air –

outdoor (3.6.1-11)

Surface 

cracking, 

crazing, 

scuffing, 

dimensional 

change 

(e.g., ”balloonin

g” and 

“necking”), 

shrinkage, 

discoloration, 

hardening and 

loss of strength 

due to 

elastomer 

degradation

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.M38, 

“Inspection of Internal 

Surfaces in 

Miscellaneous Piping 

and Ducting 

Components”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Metal enclosed bus: 

bus/connections 

composed of various 

metals used for 

electrical bus and 

connections 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-12)

Increased 

resistance of 

connection due 

to the loosening 

of bolts caused 

by thermal 

cycling and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Metal enclosed bus: 

insulation; insulators 

composed of 

porcelain; xenoy; 

thermo-plastic 

organic polymers 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-13)

Reduced 

insulation 

resistance due 

to 

thermal/thermox

idative 

degradation of 

organics/thermo

plastics, 

radiationinduced 

oxidation, 

moisture/debris 

intrusion, and 

ohmic heating

Chapter XI.E4, “Metal 

Enclosed Bus”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of steel 

exposed to air –

indoor, uncontrolled 

or air – outdoor 

(3.6.1-14)

Loss of material 

due to general, 

pitting, and 

crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)
3-496

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

galvanized steel; 

aluminum exposed 

to air – outdoor 

(3.6.1-15)

Loss of material 

due to pitting 

and crevice 

corrosion

Chapter XI.E4, “Metal 

Enclosed Bus,” or 

Chapter XI.S6, 

“Structures Monitoring”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections 

exposed to air –

indoor, uncontrolled 

(3.6.1-16)

Increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion, and 

oxidation (in an 

air, indoor 

controlled 

environment, 

increased 

resistance of 

connection due 

to chemical 

contamination, 

corrosion and 

oxidation do not 

apply); fatigue 

due to ohmic 

heating, thermal 

cycling, 

electrical 

transients

Chapter XI.E5, “Fuse 

Holders”

No Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Fuse holders (not 

part of active 

equipment): metallic 

clamps composed of 

various metals used 

for electrical 

connections 

exposed to air –

indoor, controlled or 

uncontrolled 

(3.6.1-17)

Increased 

resistance of 

connection due 

to fatigue 

caused by 

frequent 

manipulation or 

vibration

Chapter XI.E5, “Fuse 

Holders” No AMP is 

required for those 

applicants who can 

demonstrate these 

fuse holders are 

located in an 

environment that does 

not subject them to 

environmental aging 

mechanisms or fatigue 

caused by frequent 

manipulation or 

vibration

No Not applicable Not applicable to

GGNS (see SER 

Section 3.6.2.1.1)
3-497

Component Group

(SRP-LR Item No.)

Aging Effect/

Mechanism AMP in SRP-LR

Further 

Evaluatio

n in the 

GALL 

Report

AMP in LRA, 

Supplements, 

or 

Amendments

Staff Evaluation

Cable connections 

(metallic parts) 

composed of various 

metals used for 

electrical contacts 

exposed to air –

indoor, controlled or 

uncontrolled or air –

outdoor (3.6.1-18)

Increased 

resistance of 

connection due 

to thermal 

cycling, ohmic 

heating, 

electrical 

transients, 

vibration, 

chemical 

contamination, 

corrosion, and 

oxidation

Chapter XI.E6, 

“Electrical Cable 

Connections Not 

Subject to 

10 CFR 50.49 

Environmental 

Qualification 

Requirements”

No Non-EQ Cable 

Connections

Consistent with the 

GALL Report

Connector contacts 

for electrical 

connectors exposed 

to borated water 

leakage composed 

of various metals 

used for electrical 

contacts exposed to 

air with borated 

water leakage 

(3.6.1-19)

Increased 

resistance of 

connection due 

to corrosion of 

connector 

contact surfaces 

caused by 

intrusion of 

borated water

Chapter XI.M10, “Boric 

Acid Corrosion”

No Not applicable Not applicable to 

BWRs (see SER 

Section 3.6.2.1.1)

Transmission 

conductors 

composed of 

aluminum exposed 

to air – outdoor 

(3.6.1-20)

Loss of 

conductor 

strength due to 

corrosion

None - for Aluminum 

Conductor Aluminum 

Alloy Reinforced 

(ACAR)

None Not applicable Not applicable to 

GGNS (see SER 

Section 3.6.2.1.1)

Fuse holders (not 

part of active 

equipment): 

insulation material, 

metal enclosed bus: 

external surface of 

enclosure 

assemblies 

composed of 

galvanized steel, 

aluminum, exposed 

to air – indoor, 

controlled or 

uncontrolled

(3.6.1-21)

None None No NA Consistent with the 

GALL Report

The staff’s review of the electrical and I&C system component groups followed any one of 

several approaches. One approach, documented in SER Section 3.6.2.1, reviewed AMR 

results for components that the applicant indicated are consistent with the GALL Report and 

require no further evaluation. Another approach, documented in SER Section 3.6.2.2, reviewed 

AMR results for components that the applicant indicated are consistent with the GALL Report

and for which further evaluation is recommended. A third approach, documented in SER 

Section 3.6.2.3, reviewed AMR results for components that the applicant indicated are not 
3-498

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 system components is documented in 

SER Section 3.0.3.

3.6.2.1 AMR Results Consistent with the GALL Report

LRA Section 3.6.2.1 identifies the materials, environments, AERMs, and the following programs 

that manage aging effects for the electrical and I&C system components:

• Non-EQ Cable Connections

• Non-EQ Inaccessible Power Cables (400 V to 35 kV)

• Non-EQ Insulated Cables and Connections

• Non-EQ Instrumentation Circuits Test Review

LRA Table 3.6.2-1 summarizes AMRs for the electrical and I&C system components and 

indicate AMRs claimed to be consistent with the GALL Report.

The staff audited and reviewed the information in the LRA. The staff did not repeat its review of 

the matters described in the GALL Report; however, the staff did verify that the material 

presented in the LRA was applicable and that the applicant identified the appropriate 

GALL Report AMRs. The staff’s evaluation follows.

3.6.2.1.1 AMR Results Identified as Not Applicable

For LRA Table 3.6.1, items 3.6.1-11 through 3.6.1-15, the applicant claimed that the 

corresponding items in the GALL Report are not applicable. The staff reviewed the LRA and 

UFSAR and confirmed that the applicant’s LRA does not have any AMR results applicable for 

these items.

For LRA Table 3.6.1, items 3.6.1-16 and 3.6.1-17, the applicant stated that for fuse holder (not 

part of active equipment): metallic clamps exposed to air-indoor controlled, increased 

resistance of connection due to chemical contamination, corrosion, and oxidation; fatigue due to 

ohmic heating, thermal cycling, electrical transients and frequent manipulation or vibration are 

not applicable and no AMP is proposed. The applicant cited generic note I. The applicant also 

cited plant-specific note 601 that the fuse holders in the containment penetration panels 

(1BPZ1A, 1BPZ1B, 1BPZ2A, and 1BPZ2B) are subject to an AMR. The applicant stated that its 

evaluation of the fuses in the penetration protection cabinet fuse holder panels determined that 

the aging effects due to thermal fatigue in the form of high resistance caused by ohmic heating, 

thermal cycling, electrical transients, or mechanical fatigue caused by frequent manipulation 

(removal/replacement of the fuse), or vibration do not require aging management. GALL Report

item VI.A.LP-23 and -31, “Fuse Holders (Not Part of Active Equipment): Metallic Clamp,”

identifies the aging effect or mechanism as increased resistance of connection due to chemical 

contamination, corrosion, oxidation; fatigue due to ohmic heating, thermal cycling, electrical 

transients; and increased resistance of connection due to fatigue caused by frequent 

manipulation or vibration. The associated GALL Report AMP XI.E5, “Fuse Holders,” states that 

fuse holders within the scope of license renewal should be tested to provide an indication of the 

condition of the metallic clamps of fuse holders. The applicant did not provide technical 

justifications of why these fuse holders that are in the scope of license renewal do not require 

aging management. By letter dated June 22, 2012, the staff issued RAI 3.6.2.3-1 requesting the 

applicant to provide an evaluation that addresses each aging effect or mechanism identified in 

GALL Report, items VI.A.LP-23 and VI.A.LP-31. In response to the staff’s request, in a letter 
3-499

dated July 23, 2012, the applicant stated that LRA Table 3.6.2-1, note 601, summarizes the 

evaluation of potential aging effects and mechanisms for metallic clamps of fuse holders. The

evaluation of the aging effects and mechanisms identified in the GALL Report, item VI.A.LP-23 

and item VI.A.LP-31 is further explained as follows.

VI.A.LP-23, Increased Connection Resistance Due to Chemical Contamination, Corrosion, and 

Oxidation

The location and mounting details of the penetration protection cabinet fuse holder panels were 

determined by review of GGNS drawings and documentation, and confirmed by plant walkdown. 

The auxiliary building rooms in which they are located have no sources of chemical 

contamination, and the fuse holders are housed in a protective enclosure to preclude this aging 

mechanism even if chemical contamination were possible. Therefore, based on their installed 

location and design configuration, increased connection resistance due to chemical 

contamination, corrosion, and oxidation is not considered an aging effect requiring 

management.

VI.A.LP-23, Increased Connection Resistance Due to Fatigue Caused by Ohmic Heating, 

Thermal Cycling, and Electrical Transients

GGNS power circuits are sized based on power cable ampacity considering ohmic heating and 

short-circuit conditions. The cable sizing is based on ampacity values from Insulated Power 

Cable Engineers’ Association (IPCEA) P-46-426 “derating” factors for installation configuration, 

and the ability to carry 125 percent of full-load current. Ohmic heating is minimized by 

conservative cable sizing, which addresses rated temperature limitations. Therefore, ohmic 

heating of the fuse clamps is minimized. Without ohmic heating, thermal cycling on the metallic 

portion of the fuse clips is minimized. For electrical transients, GGNS electrical design ensures 

that stresses associated with electrical faults and transients are mitigated by the fast action of 

circuit protective devices at high currents. Mechanical stress due to electrical faults is not 

considered a credible contributor to the effects of aging since such abnormal conditions are 

rare. Therefore, increased connection resistance due to fatigue caused by ohmic heating, 

thermal cycling, and electrical transients is not an aging effect requiring management.

VI.A.LP-31, Increased Resistance of Connection Due to Fatigue Caused by Frequent 

Manipulation or Vibration

A review of GGNS operating practices was performed to determine if fuses are frequently 

pulled. Fuses in the penetration protection cabinet fuse holder panels are rarely pulled, and the 

few that have been pulled are not pulled on a periodic or frequent basis. The location and 

mounting details of the penetration protection cabinet fuse holder panels were determined by 

review of GGNS drawings and documentation, and confirmed by plant walkdown. The 

documentation and walkdown confirmed that there are no direct sources of vibration in proximity 

to the fuse holder panels. The fuse holder panels are floor mounted in the auxiliary building 

penetration rooms. Therefore, increased connection resistance due to fatigue caused by 

frequent manipulation or vibration is not an aging effect requiring management.

The staff finds the finds the applicant response acceptable because it provides adequate 

justification for why each aging effect and mechanism identified in GALL Report

items VI.A.LP-23 and VI.A.LP-31 are not applicable at GGNS. The staff finds that fatigue, 

mechanical stress, vibration, oxidation, and chemical contamination stressors are not applicable 

at GGNS. Fatigue is the aging effect for plants that manipulate fuses to deenergize circuits for 
3-500

plant testing. The fuses at GGNS are not routinely pulled or manipulated for plant testing. 

Therefore, fatigue and mechanical stresses due to testing are not an applicable aging effect. 

Cables are sized to 125 percent of full load current and ohmic heating is minimized by 

conservative cable sizing. Thermal cycling is minimized by the low ohmic heating. Therefore, 

the ohmic heating and thermal cycling are not significant stressors at GGNS. Stresses 

associated with mechanical stress due to electrical faults is not considered a credible aging 

stressor since such faults are infrequent and the fuse element design will interrupt the fault 

current in milliseconds. Forces associated with faults are mitigated by the fast action of fuse 

elements. Therefore, mechanical stress is not an applicable aging effect at GGNS. Vibration is 

an applicable aging stressor for fuse holders that are mounted on moving equipment such as 

motors, compressors, and pumps. GGNS fuses are not mounted on equipment subject to 

movement or vibration; they are mounted on concrete walls or support structures that do not 

vibrate. Therefore, vibration is not an applicable stressor at GGNS. Chemical contamination is 

a stress concentrator for fuse holders located near a chemical contamination source such as 

boron acid tanks. GGNS fuses are not exposed to chemical contamination or spills. During the 

staff audit, the staff walked down these fuses and noted that there is no potential source of 

chemical contamination in the areas near the fuse holders. Furthermore, fuse holders are 

enclosed in a protective panel that would provide protection against chemical attack. Therefore, 

chemical contamination is not an applicable aging effect at GGNS. The staff concern in

RAI 3.6.2.3-1 is resolved.

For LRA Table 3.6.1, item 3.6.1-19, the applicant claimed that the corresponding AMR items in 

the GALL Report are not applicable because the associated items are only applicable to PWRs. 

The staff reviewed the SRP-LR, confirmed these items only apply to PWRs, and finds that these 

items are not applicable to GGNS.

3.6.2.1.2 Conclusion

The staff evaluated the GALL Report AMR items that the applicant claimed are not applicable. 

On the basis of its review, the staff concludes that the AMR results that the applicant claimed 

are not applicable are not applicable to GGNS.

As discussed in SER Section 3.4.2.1, for those AMRs that the applicant claimed consistency 

with the GALL Report, the staff evaluated the applicant’s claim of consistency. The staff also 

reviewed information pertaining to the applicant’s consideration of recent operating experience 

and proposals for managing aging effects. On the basis of its review, the staff concludes that 

the AMR results, which the applicant claimed to be consistent with the GALL Report, are 

consistent.

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).

3.6.2.2 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 system components and provides information 

concerning how it will manage the following aging effects:
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• electrical equipment subject to EQ

• reduced insulation resistance due to presence of any salt deposits and surface 

contamination, and loss of material due to mechanical wear caused by wind blowing on 

transmission conductors

• loss of material due to wind-induced abrasion and fatigue, loss of conductor strength due 

to corrosion, and increased resistance of connection due to oxidation or loss of preload

• 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 3.6.2.2. The staff’s review of the applicant’s 

further evaluation follows.

3.6.2.2.1 Electrical Equipment Subject to Environmental Qualification

LRA Section 3.6.2.2.1 is associated with LRA Table 3.6.1 item 3.6.1-1. The applicant stated 

that EQ is a TLAA as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance 

with 10 CFR 54.21(c)(1). The applicant also stated that evaluation of this TLAA is addressed 

separately in LRA Section 4.4. Section 4.4 of the staff’s SE documents the review of the 

applicant’s evaluation of this TLAA and the EQ electrical component program.

3.6.2.2.2 Reduced Insulation Resistance Due to Presence of Any Salt Deposits and Surface 

Contamination, and Loss of Material Due to Mechanical Wear Caused by Wind 

Blowing on Transmission Conductors

LRA Section 3.6.2.2.2 is associated with LRA Table 3.6.1, items 3.6.1-2 and 3.6.1-3 and 

addresses reduced insulation resistance due to presence of salt deposits and surface 

contamination, and loss of material due to mechanical wear. The applicant stated that 

high-voltage insulators are subject to AMR if they are necessary for recovery of offsite power 

following a station blackout (SBO). Other high-voltage insulators are not subject to AMR since 

they do not perform a license renewal intended function. The applicant also stated that 

high-voltage insulators evaluated for GGNS license renewal are those used to support 

uninsulated, high-voltage electrical components such as transmission conductors and 

switchyard buses that are in the scope of license renewal.

The applicant stated that various airborne materials such as dust, salt, and industrial effluents 

can contaminate insulator surfaces. The buildup of surface contamination is gradual and in 

most areas washed away by rain. The glazed insulator surface aids this contamination removal. 

The applicant also stated that a large buildup of contamination could enable 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. GGNS is not located near the seacoast or near other sources of airborne particles. 

Therefore, reduced insulation resistance due to surface contamination is not an applicable aging 

effect for high-voltage insulators at GGNS.

Regarding loss of material due to mechanical wear, the applicant stated that mechanical wear is 

a potential aging effect for strain and suspension insulators subject to movement. Although this 
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aging effect is possible, industry experience has shown transmission conductors do not 

normally swing and when subjected to a substantial wind, movement will subside after a short 

period. The applicant also stated that wear has not been apparent during routine inspections 

and is not a credible aging effect. There are no AERMs for GGNS high-voltage insulators.

The staff reviewed LRA Section 3.6.2.2.2 against the criteria in SRP-LR Section 3.6.2.2.2, which 

states that reduced insulation resistance due to salt deposits and surface contamination may 

occur in high-voltage insulators. The GALL Report recommends further evaluation of 

plant-specific AMPs for plants at locations of potential salt deposits or surface contamination 

(e.g., in the vicinity of salt water bodies or industrial pollution). Loss of material due to 

mechanical wear caused by wind on transmission conductors may occur in high-voltage 

insulators. The GALL Report recommends further evaluation of a plant-specific AMP to ensure 

that these aging effects are adequately managed.

The applicant stated that GGNS is not located near the seacoast or near other sources of 

airborne particles. The applicant then concluded that reduced insulation resistance due to 

surface contamination is not an applicable aging effect for high-voltage insulators at GGNS. 

However, the applicant did not address the plant-specific operating experience at GGNS to 

support the applicant’s claim that contamination is not significant at GGNS. By letter dated 

June 22, 2012, the staff issued RAI 3.6.2.2.2-1 requesting the applicant to confirm that there 

has been no occurrence of insulator flashover due to surface contamination at GGNS. In 

response to the staff request, in a letter dated July 23, 2012, the applicant stated that before

LRA submittal, a review of GGNS operating experience for high-voltage insulators found no 

occurrence of insulator flashover. The applicant also stated that a subsequent review of up to 

June 30, 2012, also found no occurrence of insulator flashover for GGNS high-voltage 

insulators. The staff found the applicant response acceptable because the applicant addressed 

plant-specific operating experience and confirmed that there has been no occurrence of 

insulator flashover due to surface contamination. The staff concern in RAI 3.6.2.2.2-1 is 

resolved.

Since GGNS is not located in vicinity of salt water bodies or industrial pollution, surface 

contamination of high-voltage insulator is not a concern. In addition, rainfall and snow 

periodically wash away contamination; the glazed insulator surface also aids this contamination 

removal. The plant-specific operating experience at GGNS supports the applicant’s conclusion 

that contamination is not significant at GGNS because the applicant has indicated that there has 

been no occurrence of insulator flashover due to surface contamination.

The staff notes that EPRI 1013475 (License Renewal Handbook) states that mechanical wear in 

insulators is an aging effect for strain and suspension insulators in that they are subject to 

movement. Movement of insulators can be caused by wind blowing the supported transmission 

conductor, causing it to swing from side to side. If this swing is frequent enough, it could cause 

wear in the metal contact point of the insulator string and between an insulator and supporting 

hardware. Although this mechanism is possible, industry operating experience has shown that 

the transmission conductors do not normally swing and that even when they do, due to a 

substantial wind, they do not continue to swing for a long period of time once the wind has 

subsided. Transmission conductors typically are designed and installed not to swing 

significantly and cause wear due to wind-induced abrasion and fatigue. Furthermore, the 

applicant has not identified loss of material on high-voltage insulators due to mechanical wear 

during its routine inspection. Based on its review, the staff finds that mechanical wear aging 

effect of high-voltage insulators is not an aging effect requiring management at GGNS.
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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 items that apply to LRA Section 3.6.2.2.2, 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).

3.6.2.2.3 Loss of Material Due to Wind Induced Abrasion and Fatigue, Loss of Conductor 

Strength Due to Corrosion, and Increased Resistance of Connection Due to 

Oxidation or Loss of Preload

LRA Section 3.6.2.2.3 is associated with LRA Table 3.6.1, items 3.6.1-4, -5, -6, and 7 

addressing loss of material due to wind-induced abrasion and fatigue, loss of conductor strength 

due to corrosion, and increased resistance of connections due to oxidation or loss of preload of 

transmission conductors and connections, and switchyard bus and connections.

The applicant stated that wind loading can cause transmission conductor vibration, or sway. 

Wind loading that can cause a transmission line and insulators to vibrate is considered in the 

design and installation. Loss of material (wear) and fatigue that could be caused by 

transmission conductor vibration or sway are not applicable aging effects in that they would not 

cause a loss of intended function if left unmanaged for the period of extended operation. The 

applicant also stated that operation of active switchyard components is also a potential 

contributor to vibration and resulting wear. Switchyard bus is connected to active equipment by 

short sections of flexible conductors. The flexible conductors withstand the minor vibrations 

associated with the active switchyard components. The flexible conductors are part of the 

switchyard bus commodity group. Vibration is not applicable since flexible conductors 

connecting switchyard bus to active components eliminate the potential for vibration.

The applicant further stated a review of plant-specific operating experience did not identify any 

unique aging effects for transmission conductors. Therefore, loss of material due to wear of 

transmission conductors is not an aging effect requiring management at GGNS.

The applicant stated that transmission conductors are subject to AMR if they are necessary for 

recovery of offsite power following an SBO. At GGNS, transmission conductors from the GGNS

115 kV switchyard to the ESF transformer (ESF 12) and from the GGNS 115 kV switchyard to 

the Port Gibson substation support recovery from an SBO. Other transmission conductors are 

not subject to an AMR since they do not perform a license renewal intended function.

The applicant stated that tests performed by Ontario Hydro showed a 30 percent loss of 

composite conductor strength of an 80-year-old ACSR conductor due to corrosion. GGNS ESF 

12 transformer high-voltage side is connected to the 115 kV switchyard through overhead 

transmission lines. The 115 kV switchyard is connected to the Port Gibson substation by 

overhead transmission lines. These 115 kV overhead transmission conductors are 

336.4 thousand circular mils (MCM) 26/7 ACSR conductors. This specific conductor 

construction type was included in the Ontario Hydroelectric test, so the results of this test are 

representative of the GGNS 115 kV overhead transmission conductors. The 336.4 MCM 26/7 

ACSR transmission conductor tested in the Ontario Hydro test, as documented in the 

companion paper, “Aged ACSR Conductors, Part II - Prediction of Remaining Life,” bounds the 

GGNS transmission conductors.
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The applicant also stated that the National Electrical Safety Code (NESC) requires that tension 

on installed conductors be less than 60 percent of the ultimate conductor strength. The 

applicant stated that these requirements were reviewed for the specific transmission conductors 

included in the scope of license renewal. The applicant further stated that evaluation of the 

conductor type with the smallest ultimate strength margin (4/0 ACSR, 6/1) in the NESC 

illustrates the conservative nature of the design of transmission conductors. The 4/0 ACSR 

6/1 conductor has only one steel reinforcement conductor, so the impacts of corrosion on this 

one steel reinforcement conductor is more severe than a transmission conductor with multiple 

steel reinforcement conductors.

The applicant stated that the ultimate strength and the NESC required heavy load tension 

capability of 4/0 (212 MCM) ACSR 6/1 are 8,350 lbs and 2,761 lbs respectively. The actual 

margin for a 4/0 ACSR 6/1 conductor between the NESC heavy load and the ultimate strength 

is 5,589 lbs (i.e., there is a 67 percent of ultimate strength margin). The Ontario Hydro study 

showed a 30 percent loss of composite conductor strength in an 80-year-old conductor. In the 

case of the 4/0 ACSR 6/1 transmission conductors, a 30 percent loss of ultimate strength would 

mean that the 80-year ultimate strength (30 percent loss) of 4/0 (212 MCM) ACSR 6/1 would be 

5,845 lbs. Based on the NESC criteria, an 80-year-old 4/0 ACSR 6/1 conductor could have an 

installed tension of 3,507 lbs (60 percent of 5,845 lbs), which is a margin of 746 lbs, (i.e., there 

would be a 13 percent of ultimate strength margin for an 80-year-old cable). The applicant also 

stated that actual margin for an 80-year 4/0 ACSR 6/1 conductor between the NESC heavy load 

and the aged ultimate strength would be 3,084 lbs (i.e., there would still be a 53 percent margin 

to the aged ultimate strength). Therefore, there would still be a 53 percent ultimate strength 

margin based on the actual conductor strength after 80 years of service compared to the 

40 percent ultimate strength margin allowed by the NESC for a new cable. The applicant further 

stated that the 4/0 ACSR conductor type has the lowest initial design margin of transmission 

conductors included in the Ontario Hydro test, so this example bounds in-scope GGNS 

transmission conductors. This example illustrates with reasonable assurance that transmission 

conductors will have ample strength through the period of extended operation.

The applicant stated that a review of industry operating experience and NRC generic 

communications related to the aging of transmission conductors ensured that no additional 

aging effects exist beyond those previously identified. A review of plant-specific operating 

experience did not identify any aging effects for transmission conductors at GGNS.

The staff reviewed LRA Section 3.6.2.2.3 against the criteria in SRP-LR Section 3.6.2.2.3, which 

states that loss of material due to wind-induced abrasion and fatigue, loss of conductor strength 

due to corrosion, and increased resistance of connection due to oxidation or loss of preload 

could occur in transmission conductors and connections, and in switchyard bus and 

connections. The GALL Report recommends further evaluation of a plant-specific AMP to 

ensure that this aging effect is adequately managed.

The staff noted switchyard buses are connected to flexible conductors that do not swing and are 

supported by insulators and structural supports such as concrete footings and structural steel. 

Since there are no connections to moving or vibrating equipment, wind-induced abrasion and 

fatigue is not an applicable aging mechanism for switchyard bus and connections at GGNS.

The staff noted that wind borne particulates have not been shown to be a contributor to loss of 

material at GGNS and wind fatigue is addressed in 3.6.2.2.2. Therefore, the staff finds that 

wind-induced abrasion and fatigue is not a significant aging effect requiring management for 

transmission conductors and connections at GGNS.
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The staff noted that the design of switchyard bolted connections precludes torque relaxation. 

The use of stainless steel Belleville washers is the industry standard to preclude torque 

relaxation. GGNS design incorporates the use of stainless steel Belleville washers on bolted 

electrical connections to compensate for temperature changes, maintain the proper torque, and 

prevent loosening. This method of assembly is consistent with the good bolting practices 

recommended by industry guidelines (EPRI TR-104213, “Bolted Joint Maintenance and 

Application Guide”). Based on the review, the staff finds that loosening of the switchyard bolted 

connections is not an aging effect requiring management at GGNS.

The bolted connections and washers at GGNS are coated with an antioxidant compound 

(electrical joint compound) before tightening the connection to prevent the formation of oxides 

on the metal surface and to prevent moisture from entering the connection, thus reducing the 

chances of corrosion. The staff finds that increased resistance of connection due to oxidation or 

loss of preload are not significant AERMs for transmission conductor and switchyard bus 

connections at GGNS.

The Ontario Hydro study showed about 30 percent loss of conductor strength of an 80-year-old 

ACSR conductor due to corrosion. In addition, the National Electrical Safety Code (NESC) 

requires that tension on installed conductors be a maximum of 60 percent of the ultimate 

conductor strength. The NESC also sets the maximum tension a conductor must be designed 

to withstand under heavy load requirements, which includes consideration of 1⁄2 inch of radial ice 

and 4 lbs per square feet (psf) wind. Based on the Ontario Hydro study, a loss of conductor 

strength of 30 percent on ACSR conductors would mean that the conductor strength would be 

5,845 lbs (8,350 lbs x 0.7 = 5,845 lbs). The ratio between the heavy loading and the ultimate 

conductor strength would be approximately 53 percent (2,761 lbs/5,845 lbs). The NESC 

requires that tension on the installed conductor be a maximum of 60 percent of the ultimate 

conductor strength. The tension (heavy load) of a typical transmission conductor would not 

exceed the NESC maximum requirement of 60 percent of the ultimate conductor strength. The 

4/0 ACSR conductor type has the lowest initial design margin of transmission conductors as 

compared to the 336.4 kcmil, 30/7 ACSR conductors used in the test sample in the Ontario 

Hydro Study. The 4/0 ACSR 6/1 conductor has only one steel reinforcement conductor, so the 

impact of corrosion on this one steel reinforcement conductor is more severe than a 

transmission conductor with multiple steel reinforcement conductors. The staff determined that 

the example the applicant provided bounds the in-scope GGNS transmission conductors. With 

a 30 percent loss of conductor strength, there is still ample margin between the NESC 

requirements and the actual conductor strength. Furthermore, the applicant has confirmed that 

plant-specific operating experience did not identify any aging effects for transmission conductors 

at GGNS. Therefore, the staff finds that loss of conductor strength due to corrosion is not a 

significant aging effect requiring management at GGNS.

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 items that apply to LRA Section 3.6.2.2.3, 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).

3.6.2.2.4 Quality Assurance for Aging Management of Nonsafety-Related Components

SER Section 3.0.4 documents the staff’s evaluation of the applicant’s QA program.
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3.6.2.3 AMR Results Not Consistent with or Not Addressed in the GALL Report

In LRA Table 3.6.2-1, the staff reviewed additional details of the AMR results for material, 

environment, AERM, and AMP combinations not consistent with or not addressed in the 

GALL Report.

In LRA Table 3.6.2-1, the applicant indicated via notes F through J, that the combination of 

component type, material, environment, and AERM does not correspond to an 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 item component is not evaluated in 

the GALL Report. Note G indicates that the environment for the AMR item component and 

material is not evaluated in the GALL Report. Note H indicates that the aging effect for the AMR 

item component, material, and environment combination is not evaluated in the GALL Report. 

Note I indicates that the aging effect identified in the GALL Report for the item component, 

material, and environment combination is not applicable. Note J indicates that neither the 

component nor the material and environment combination for the item is evaluated in the 

GALL Report.

For component type, material, and environment combinations not evaluated in the 

GALL Report, the staff reviewed the applicant’s evaluation to determine whether the applicant 

has demonstrated that the effects of aging will be adequately managed so that the intended 

function(s) will be maintained consistent with the CLB for the period of extended operation. The 

staff’s evaluation is documented in the following sections.

3.6.2.3.1 Electrical and I&C Components - Summary of Aging Management Evaluation –

LRA Table 3.6.2-1

The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for the 

electrical and I&C components component groups.

115 kV Inaccessible Transmission Cables. In LRA Table 3.6.2-1, the applicant stated that 

conductor insulation for inaccessible power cables (115 kV) not subject to 10 CFR 50.49 

requirements exposed to significant moisture will be managed for reduced insulation resistance 

by 115 kV Inaccessible Transmission Cable AMP. The applicant cited generic note 602, which 

states the 115 kV Inaccessible Transmission Cable Program as a new plant-specific program; 

however, this program is based on the NUREG-1801, XI.E3 program.

The staff reviewed the associated items in the LRA and considered whether the aging effects 

the applicant proposed constitute all of the credible aging effects for this component, material, 

and environment description. The staff noted that the applicant addressed insulation resistance 

for this component, material, and environment combination in other AMR items in LRA 

Tables 3.6.2-1, conductor insulation for inaccessible power cables (400 V to 35 kV) not subject 

to 10 CFR 50.49 EQ requirements. Based on its review of GALL Report AMP XI.E3, which 

states that when a power cable is exposed to wet, or submerged, or other adverse 

environmental condition for which it was not designed, an aging effect of reduced insulation 

resistance may result, causing a decrease in the dielectric strength of the conductor insulation. 

The staff finds that the applicant has identified all credible aging effects for this component, 

material, and environment combination.

The staff’s evaluation of the applicant’s 115 kV Inaccessible Transmission Cable Program is 

documented in SER Section 3.0.3.2.1. The staff finds the applicant’s proposal to manage aging 
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using the 115 kV Inaccessible Transmission Cable Program acceptable because inspection for 

water collection will prevent inaccessible transmission cables from being exposed to significant 

moisture and testing will provide an indication of the condition of the conductor insulation.

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 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 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 license 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 safety evaluation report (SER) section provides the United States (US) Nuclear Regulatory 

Commission (NRC) staff’s (the staff) evaluation of the applicant’s basis for identifying those 

plant-specific or generic calculations and analyses that need to be identified as time-limited 

aging analyses (TLAAs) for the applicant’s license renewal application (LRA) and the list of 

TLAAs for the LRA. TLAAs are certain current licensing basis (CLB) calculations and analyses 

that involve time-limited assumptions defined by the current operating term. This SER section 

also provides the staff’s evaluation of the applicant’s basis for identifying those exemptions that 

need to be identified in the LRA pursuant to Title 10 of the Code of Federal Regulations

(10 CFR) 54.21(c)(2).

Pursuant to the requirements in 10 CFR 54.21(c)(1), an applicant for license renewal must list 

calculations and analyses in the CLB that conform to the definition of a TLAA in 10 CFR 54.3, 

which states that a licensee’s calculations and analyses are TLAAs if they meet all six of the 

following TLAA identification criteria:

(1) involve systems, structures, and component (SSCs) within the scope of license renewal,

as delineated in 10 CFR 54.4(a);

(2) consider the effects of aging;

(3) involve time-limited assumptions defined by the current operating term, for 

example, 40 years;

(4) were determined to be relevant by the licensee in making a safety determination;

(5) involve conclusions or provide the basis for conclusions related to the capability of the 

SSC to perform its intended functions, as delineated in 10 CFR 54.4(b); and

(6) are contained or incorporated by reference in the CLB.

For each TLAA, the applicant shall demonstrate:

(i) The analysis remains valid for the period of extended operation;

(ii) The analysis has 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.

In addition, 10 CFR 54.21(c)(2) requires applicants to list all plant-specific exemptions granted 

in accordance with the exemption approval criteria in 10 CFR 50.12 and that are in effect and 

are based on a TLAA. For any such exemptions, the applicant must provide an evaluation that 

justifies the continuation of these exemptions for the period of extended operation.

The staff’s guidance recommendations for reviewing LRA Chapter 4.1 sections are given in 

NUREG-1800, Revision 2, “Standard Review Plan for Review of License Renewal Applications 

for Nuclear Power Plants” (SRP-LR), Section 4.1.
4-2

4.1.1 Summary of Technical Information in the Application

4.1.1.1 Identification of TLAAs

LRA Section 4.1 states that the applicant reviewed and evaluated the analyses, and calculations 

in the CLB against the six criteria for TLAAs in 10 CFR 54.3. The LRA also states that the 

applicant reviewed the list of TLAAs in SRP-LR to see if they are applicable to and included as 

part of the applicant’s CLB.

The applicant stated that the process it used for its TLAA identification is consistent with the 

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

Requirements of 10 CFR Part 54—the License Renewal Rule.”

The applicant stated that it reviewed the following plant-specific or generic sources (documents 

or records): (a) updated final safety analysis report (UFSAR), (b) technical specifications (TS) 

and bases, (c) Technical Requirements Manual, (d) extended power uprate LAR, (e) BWRVIP 

documents referenced in the UFSAR or in docketed licensing correspondence, (f) industry 

topical reports (relevant documents referenced in the UFSAR or in docketed licensing 

correspondence), (g) fire protection documents, (h) Inservice Inspection Program documents, 

(i) NRC SERs, and (j) docketed licensing correspondence.

The applicant provides its list of TLAAs in LRA Table 4.1-1, “List of TLAAs.” In this table, the 

applicant indicates that the following analyses in the CLB meet the six criteria for TLAAs in 

10 CFR 54.3 and are TLAAs for the LRA:

• Reactor Pressure Vessel (RPV) Neutron Embrittlement Analyses in LRA Section 4.2

• Metal Fatigue Analyses in LRA Section 4.3

• Environmental Qualification (EQ) Analyses of Electrical Components in LRA Section 4.4

• Containment Liner Plate, Metal Containment, and Penetrations Fatigue Analysis in LRA 

Section 4.6

• Plant-specific TLAAs in LRA Section 4.7

The applicant also indicates in LRA Table 4.1-1 that “Concrete Containment Tendon Prestress 

Analysis” is not a TLAA, as described in LRA Section 4.5 (See SER Section 4.1.2.1.2).

The applicant provides its bases for accepting these TLAAs in accordance either with 

10 CFR 54.21(c)(1)(i), (ii), or (iii) in the applicable subsections of LRA Sections 4.2–4.4, 4.6,

and 4.7.

The applicant indicates in LRA Table 4.1-2 that the following generic TLAAs listed in Section 4.1 

of the SRP-LR Table 4.1-2 are TLAAs for the LRA:

• Reactor vessel neutron embrittlement (LRA Section 4.2)

• Metal fatigue (LRA Section 4.3)

• Environmental qualification of electrical equipment (LRA Section 4.4)

The applicant also indicates in LRA Table 4.1-2 that the following generic TLAAs listed in 

Section 4.1 of the SRP-LR Table 4.1-2 are not part of the CLB, and therefore they are not

included in the LRA:
4-3

• Concrete containment tendon prestress analysis

• Inservice local metal containment corrosion analyses

The applicant indicates in LRA Table 4.1-2 that the following potential plant-specific TLAAs 

listed in SRP-LR, Section 4.1, Table 4.1-3, are TLAAs for the LRA:

• Transient cycle count assumptions for the reactor vessel (RV) internals (RVI)

• Ductility reduction of fracture toughness for the RVI

• Fatigue analysis for the containment liner plate

• Containment penetration pressurization cycles

The applicant indicates in LRA Table 4.1-2 that the following potential plant-specific TLAAs 

listed in SRP-LR, Section 4.1, Table 4.1-3, are not part of the CLB, and therefore they are not 

included in the LRA:

• Intergranular separation in the heat-affected zone of RV low-alloy steel under austenitic 

stainless steel (SS) cladding analyses

• Low temperature overpressure protection analyses

• Fatigue analysis for the main steam supply lines to the turbine-driven auxiliary feedwater

(AFW) pumps

• Fatigue analysis of the reactor coolant pump (RCP) flywheel

• Fatigue analysis of the polar crane

• Flow-induced vibration endurance limit for the RVI

• Leak-before-break

• Metal corrosion allowance

• Inservice flaw growth analyses that demonstrate structure stability for 40 years

4.1.1.2 Identification of Regulatory Exemptions

LRA Section 4.1.2 states no exemptions were identified that will remain in effect for the period of 

extended operation and are based on a TLAA.

4.1.2 Staff Evaluation

4.1.2.1 Identification of TLAAs

The staff reviewed the applicant’s methodology for identifying the TLAAs and the TLAA results

for the LRA against the six criteria for TLAA identification in 10 CFR 54.3 and the generic list of 

TLAAs in SRP-LR Section 4.1, including those in SRP-LR Tables 4.1-2 and 4.1-3, as applicable 

to its CLB. The staff used the review procedures in SRP-LR Section 4.1.3 as the basis for its 

review.

4.1.2.1.1 Calculations and Analyses in the CLB Conforming to 10 CFR 54.3 TLAA Criteria

The staff confirmed that the applicant included its TLAAs for the RPV neutron embrittlement 

analyses in the applicable referenced subsections of LRA Section 4.2, which includes the 

TLAAs for the assessment of pressure-temperature (P-T) limits, upper-shelf energy (USE), RV 

circumferential weld inspection relief, RV axial weld failure probability, and RPV core reflood 
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thermal shock analysis. These analyses were included as TLAAs in the LRA because: (1) the 

analyses are mandated by applicable NRC requirements (e.g., 10 CFR Part 50, Appendix G, for

USE and P-T limit requirements, and 10 CFR Part 50, Appendix H, for RPV surveillance 

capsule neutron dosimetry and fracture toughness impact test analyses) or industryrecommended studies (e.g., the reflood analysis recommended by General Electric [GE]); and 

(2) the analyses conform to all six of the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the 

staff noted that the applicant’s identification of these TLAAs was in conformance with the staff 

recommendations in SRP-LR Sections 4.1 and 4.2, which provide the bases for identifying 

these types of neutron embrittlement analyses as TLAAs in accordance with the requirements in 

10 CFR 54.21(c)(1). Based on this review, the staff finds that the identification of these 

analyses as TLAAs is acceptable because it is in compliance with 10 CFR 54.21(c)(1). The 

staff evaluates the applicant’s basis for accepting these TLAAs in accordance with the 

applicable subsections of SER Section 4.2.

The staff confirmed that the applicant included its TLAAs on metal fatigue analyses in the 

applicable subsections of LRA Section 4.3, as previously referenced in the Summary of 

Technical Information above. These analyses were included as TLAAs in the LRA because: 

(1) the analyses are mandated by applicable design rules (e.g., those in Section III of the ASME 

Code or in the American National Standards Institute (ANSI) B31.1 design code) or the 

applicant implemented the analyses as part of its commitments to applicable NRC generic 

communications (e.g., the applicant conservatively treats environmentally assisted fatigue [EAF]

for limiting Class 1 locations as a TLAA in the LRA and addresses this analysis consistent with 

the resolution of Generic Safety Issue [GSI] No. 191) and (2) the analyses conform to all six of 

the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the staff noted that the applicant’s 

identification of these TLAAs was in conformance with the staff recommendations in SRP-LR 

Sections 4.1 and 4.3, which provide the bases for identifying these types of fatigue analyses as 

TLAAs in accordance with the requirements in 10 CFR 54.21(c)(1). Based on this review, the 

staff finds that the identification of these analyses as TLAAs is acceptable because it is in 

compliance with 10 CFR 54.21(c)(1). The staff evaluates the applicant’s basis for accepting 

these TLAAs in the applicable subsections of SER Section 4.3.

The staff confirmed that the applicant included its TLAA for environmental qualification (EQ) of 

electrical equipment in LRA Section 4.4. This analysis was included as a TLAA because: the 

analysis is mandated by the requirements in 10 CFR 50.49 and the analysis conforms to all six 

of the criteria for identifying TLAAs in 10 CFR 54.3. Thus, the staff confirmed that the 

applicant’s identification of the TLAA for EQ of electrical equipment was in conformance with the 

staff recommendations in SRP-LR Sections 4.1 and 4.4, which provide the bases for identifying 

EQ analyses for electrical components as TLAAs in accordance with 10 CFR 54.21(c)(1). 

Based on this review, the staff finds that the identification of the TLAA for EQ of electrical 

equipment is acceptable because it is in compliance with 10 CFR 54.21(c)(1). The staff 

evaluates the applicant’s basis for accepting the TLAA for EQ of electrical equipment in SER 

Section 4.4.

The staff confirmed that the applicant included its TLAAs for the containment liner plate, metal 

containment structures, and containment penetrations fatigue analyses in LRA Section 4.6. 

Cumulative usage factors (CUFs) calculated for the containment liner and quencher 

components are described in LRA Section 4.6.1 and listed in Table 4.6-1, and CUFs calculated 

for the containment penetrations are evaluated in LRA Section 4.6.2 and identified in LRA

Table 4.6-2. These analyses were included as TLAAs in the LRA because: (1) the analyses 

are mandated by the applicable fatigue calculation or fatigue waiver rules in Section III of the 

ASME Code or were performed as part of applicable design calculations and (2) the analyses 
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conform to the six criteria for TLAAs in 10 CFR 54.3. Thus, the staff noted that the applicant’s 

identification of these TLAAs was in conformance with the staff recommendations in SRP-LR 

Sections 4.1 and 4.6, which provide the staff’s bases for identifying containment structure 

analyses as TLAAs in accordance with 10 CFR 54.21(c)(1). Based on this review, the staff 

finds that the identification of these containment component TLAAs is acceptable because it is 

in compliance with 10 CFR 54.21(c)(1). The staff evaluates the applicant’s basis for accepting 

these TLAAs in SER Sections 4.6.1 and 4.6.2.

The staff confirmed that the applicant included the following plant-specific TLAAs for the LRA in 

LRA Section 4.7: (1) erosion of the MSL flow restrictors (LRA Section 4.7.1), (2) determination 

of intermediate high-energy line break (HELB) locations (LRA Section 4.7.2), and (3) fluence 

effects (ductility reduction) analyses for RVI components (LRA Section 4.7.3). The staff noted 

that the applicant’s identification of these TLAAs was consistent with the staff recommendations 

for identifying plant-specific TLAAS in SRP-LR Sections 4.1 and 4.7. Based on this review, the 

staff finds that the identification of these plant-specific TLAAs is acceptable because it is in 

compliance with 10 CFR 54.21(c)(1). The staff evaluates the applicant’s basis for accepting 

these plant-specific TLAAs in the applicable subsections of SER Section 4.7.

4.1.2.1.2 Evaluation of Applicant’s List of Calculations and Analyses in the CLB That Do Not 

Meet the Six Criteria for TLAAs in 10 CFR 54.3 and the Absence of Generic or 

Potentially Applicable Plant-Specific TLAAs Due to Absence in the CLB

Absence of a TLAA on Concrete Containment Tendon Prestress. In LRA Tables 4.1-1 

and 4.1-2, the applicant identified that the CLB does not include a concrete containment tendon 

prestress analysis. The applicant stated that its containment design does not include tendons.

SRP-LR Table 4.1-2 identifies the containment tendon prestress analysis as a generic type of 

TLAA that may be generically applicable to an applicant’s plant design. SRP-LR Section 4.5 

provides the staff’s recommended criteria for accepting these type of TLAAs in accordance with 

the TLAA acceptance requirements in 10 CFR 54.21(c)(1)(i), (ii), or (iii). The relevant SRP-LR 

recommendations are only applicable to concrete containment structures that use pre-stressed 

tendons as the containment structure reinforcement basis.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that the UFSAR Section 3.8 defines the containment as a 

concrete containment structure that is designed with three basis subsections: (1) a flat circular 

foundation mat, (2) a right circular containment cylinder, and (3) a hemispherical containment 

dome. The staff also noted that UFSAR Section 3.8 indicates that the containment mat, 

cylinder, and dome are constructed of cast-in-place, conventionally reinforced concrete, and 

that UFSAR Section 3.8.1 provides a full description of the reinforcement bases for the concrete 

containment structure. The staff confirmed, from its review of UFSAR Section 3.8.1, that the 

containment does not use prestressed tendons as the basis for reinforcing the containment mat, 

cylinder, or dome. Therefore, the staff concludes that the LRA does not need to include a 

concrete containment prestress TLAA because the staff has confirmed that: (a) the 

containment does not include prestressed tendons as the containment reinforcement basis and 

(b) the generic concrete containment prestress analysis in SRP-LR Table 4.1-2 is not applicable 

to the applicant’s CLB [Criterion 6 of 10 CFR 54.3(a)].

Absence of a TLAA on Inservice Local Metal Containment Corrosion. In LRA Table 4.1-2, the 

applicant identified that the CLB does not include any inservice local metal containment 

corrosion analyses for the containment structure. The applicant stated the containment is a GE 
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Mark III containment design and that the CLB does not include any corrosion analysis 

associated with this type of containment design. SRP-LR Table 4.1-2 identifies a local metal 

containment corrosion analysis as a generic type of TLAA that may be generically applicable to 

an applicant’s plant design.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff confirmed that UFSAR Section 3.8 indicates that the containment is a 

concrete containment design. The staff also confirmed that UFSAR Section 3.8 does not 

reference any localized metal corrosion analyses for the containment structure, other seismic 

Category 1 structures, or their subcomponents. Therefore, the staff concludes that the LRA 

does not need to include any localized metal containment corrosion TLAAs because the staff 

has confirmed that: (a) the applicant’s CLB does not include any metal corrosion analyses for 

the concrete containment structure, other seismic Category 1 structures, or their 

subcomponents and (b) the localized metal containment structure corrosion analysis reference 

in SRP-LR Table 4.1-2 is not applicable to the applicant’s CLB [Criterion 6 of 10 CFR 54.3(a)].

Absence of a TLAA on Intergranular Separation in the Heat-Affected Zone of Reactor Vessel 

Low-Alloy Steel Under Austenitic Stainless Steel Cladding. In LRA Table 4.1-2, the applicant 

identified that the CLB does not include any cycle-dependent analysis in evaluation of 

intergranular separations (underclad cracks or underclad cracking) in RPV cladding-to-forging 

welds.

SRP-LR Table 4.1-3 identifies that a plant-specific RPV underclad cracking analysis may qualify 

as a TLAA if such an analysis is included in the applicant's CLB. The relevant SRP-LR 

recommendations are only applicable to RPV SA-508, Class 2 forgings that were welded to the 

RPV cladding using a high heat weld input process that resulted in large-grained weld 

microstructures. The SRP-LR guidance does not apply if the CLB confirms that the design of 

the shell, head, or nozzle portions of the RPV does not include such forging components or if it 

can be demonstrated that the heat input for the welding practice used for the RPV-to-cladding 

welds was appropriately controlled during the welding process such that it would result in a finegrained deposited weld metal. NRC Regulatory Guide (RG) 1.43, “Control of Stainless Steel 

Weld Cladding of Low-Alloy Steel Components,” provides the staff’s recommended criteria for 

meeting these weld process heat input controls.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Section 5.3.1.2, identifies that the RPV is fabricated 

primarily from low alloy steel plates and forgings. The staff also noted that the UFSAR indicated 

that the low alloy steel RPV plates were ordered to SA 533, Grade B, Class 1 specifications and 

that the RPV forging components were fabricated to SA 508, Class 2 specifications. SER 

Section 3.1.2.2.5 documents the staff’s evaluation of the applicant’s response to request for 

additional information (RAI) 4.1-1. In its evaluation of the applicant’s response to RAI 4.1-1, the 

staff noted that UFSAR Section 5.3.1.6.45.3.1.4.1.2 identifies that the forging-to-cladding welds 

for all RPV low-alloy steel forging components were fabricated from materials and welding 

methods that conformed to the regulatory position in RG 1.43, “Control of Stainless Steel Weld 

Cladding of Low-Alloy Steel Components,” and resulted in fine-grain weld microstructures. 

Thus, the staff confirmed that the applicant used weld practices in the fabrication of the RPV-tocladding welds that are consistent with the regulatory position in Section C of RG 1.43. 

Therefore, the staff has determined that the applicant has implemented applicable design 

welding practices for precluding underclad cracking in the RPV as the basis for addressing 

potential underclad cracking in the RPV forging-to-cladding welds and that the design basis 

does not rely on any time dependent analysis to address this RPV cracking issue.Based on this 
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review, the staff concludes that the LRA does not need to include a TLAA on intergranular 

separation as described in SRP-LR Table 4.1-3 because the staff has confirmed that: (a) the 

forging-to-cladding welds for all SA-508, Class 2 low alloy steel forging components in the RPV 

were fabricated from materials and welding methods that resulted in fine-grain microstructures 

and (b) the applicant’s CLB does not contain or rely on any time-dependent analysis as the 

basis for addressing underclad cracking (i.e., intergranular separations) in the RPV’s 

forging-to-cladding welds.

Absence of a TLAA on Low Temperature Overpressure Protection. In LRA Table 4.1-2, the 

applicant identified that the CLB does not include a low-temperature overpressure protection 

(LTOP) analysis for the RPV and reactor coolant pressure boundary (RCPB). The applicant 

stated that this analysis is not applicable to boiling water reactor (BWR) designs.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific LTOP analysis that 

qualifies as a TLAA for the applicant’s LRA. The relevant SRP-LR recommendations are only 

applicable to the LTOP systems in pressurized water reactor (PWR) designs. The SRP-LR 

guidance is not applicable to BWR designs because they do not include LTOP systems.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Chapter 1 defines the reactor as a GE-designed 

BWR that is built to the GE BWR-6 model specifications and protected by a GE Mark III 

containment design. The staff also confirmed that the BWR-6 design does not include LTOP 

systems. Therefore, the staff concludes that the LRA does not need to include a plant-specific 

LTOP TLAA because the staff has confirmed that: (a) the BWR-6 reactor design does not 

include a LTOP system and (b) the TLAA referenced in SRP-LR Table 4.1-3 for LTOP systems 

is not applicable to the applicant’s CLB [Criterion 6 of 10 CFR 54.3(a)].

Absence of a TLAA on Fatigue Analysis for Main Steam Supply Lines to Auxiliary Feedwater 

Pumps. In LRA Table 4.1-2, the applicant identified that the CLB does not include a fatigue 

analysis for main steam lines that supply steam to steam-driven AFW pumps.

The applicant stated that its design does not include AFW pumps. SRP-LR Table 4.1-3 

identifies that the CLB may include a plant-specific metal fatigue analysis for AFW pump main 

steam supply lines that qualifies as a TLAA for the applicant’s LRA. The relevant SRP-LR 

recommendations are only applicable to PWRs with designs that include steam-driven AFW 

pumps. The SRP-LR guidance is not applicable to BWR designs because they are not 

designed with AFW pumps.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Chapter 1 defines the reactor as a GE-designed 

BWR that is built to the BWR-6 model specifications and protected by a GE Mark III 

containment design. The staff also confirmed that the BWR-6 design does not include any AFW 

systems or AFW pumps. Therefore, the staff concludes that the LRA does not need to include a 

plant-specific TLAA for steam-driven AFW pump steam supply lines because the staff has 

confirmed that: (a) the BWR-6 reactor design does not include AFW systems or AFW pumps 

and (b) the TLAA referenced in SRP-LR Table 4.1-3 for steam-driven AFW pump steam supply 

lines is not applicable to the applicant’s CLB [Criterion 6 of 10 CFR 54.3(a)].

Absence of a TLAA on Fatigue Analysis for Reactor Coolant Pump Flywheels. In LRA

Table 4.1-2, the applicant identified that the CLB does not include any cycle dependent flaw 
4-8

growth or flaw tolerance analysis for RCP flywheels. The applicant stated that it is a BWR and 

that the recirculation pumps in the RCPB recirculation loops are not designed with flywheels.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific cycle-dependent fatigue 

or flaw tolerance analysis for RCP flywheels that qualifies as a TLAA for the applicant’s LRA. 

The SRP-LR recommendations are only applicable to RCP flywheels in PWR designs. The 

relevant SRP-LR guidance is not applicable to BWR designs because the analogous pump 

components in BWR designs (i.e., the recirculation pumps) are not designed with flywheels.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Chapter 1 defines the reactor as a GE-designed 

BWR that is built to the BWR-6 model specifications and protected by a GE Mark III 

containment design. The staff also confirmed that the applicant’s BWR-6 design does not 

include AFW systems or AFW pumps. Therefore, the staff concludes that the LRA does not 

need to include a plant-specific TLAA for RCP flywheels because the staff has confirmed that: 

(1) the BWR-6 reactor design does not include RCP flywheels and (2) the TLAA referenced in 

SRP-LR Table 4.1-3 for RCP flywheels is not applicable to the applicant’s CLB [Criterion 6 of 

10 CFR 54.3(a)].

Absence of a TLAA on Fatigue Analysis of Polar Crane. In LRA Table 4.1-2, the applicant 

identified that the CLB does not include any analysis for the polar crane that would need to be 

identified as a TLAA in the LRA. The applicant stated that the relevant analysis of the polar 

crane is not based on time-dependent assumptions defined by the current operating term such 

as 40 years of the plant; therefore, it does not conform to the definition of a TLAA in 

10 CFR 54.3.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific cycle-dependent 

analysis for polar cranes that qualifies as a TLAA for the applicant’s LRA.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Chapter 9 identifies that the facility is designed with 

the following types of cranes: (a) a polar crane; (b) a containment hatchway crane; (c) a 

spent-fuel cask crane; and (d) a new fuel handling crane. The staff noted that UFSAR 

Chapter 9 analyzed these cranes based only on an analysis of the limiting load that could be 

supported by a crane lift without initiating the occurrence of an associated crane failure or load 

drop event. The staff did not find any time-dependent loading analyses for the cranes that might 

need to be identified as TLAAs for the LRA.

The staff noted that UFSAR Chapter 9 identifies that the polar crane was designed and 

analyzed to the Crane Manufacturers Association of America, Inc. (CMAA-70) design 

specification. The staff noted that the UFSAR did not specify which design specifications were 

used for the design and analysis of the containment hatchway crane, spent-fuel cask crane, or 

new fuel handling crane. By letter dated June 5, 2012, the staff issued RAI 4.1-2, which

requested the applicant to identify which design specifications were used for the design and 

analysis of the containment hatchway, spent-fuel cask, and new fuel handling cranes. The staff 

also asked the applicant to clarify whether the specific design specifications for the containment 

hatchway, spent-fuel cask, and new fuel handling cranes, and CMAA-70 specification for the 

polar crane, would have required the applicant to establish a limit on the number of times the 

cranes could be used to lift their limiting loads, and if so, why the time-dependent cycle analyses 

for the cranes would not need to be identified as TLAAs for the LRA, when assessed against the 

six criteria for identifying TLAAs in 10 CFR 54.3.
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In its response to RAI 4.1-2, by letter dated July 3, 2012, the applicant stated that the spent fuel 

cask and new fuel handling cranes were designed to meet applicable criteria of the CMAA-70, 

and the containment hatchway crane load-bearing parts were analyzed for all applicable loads 

in accordance with the requirements of the American Institute of Steel Construction (AISC) Steel 

Construction Manual, 7th Edition. The applicant also stated that the spent fuel cask crane, new 

fuel handling crane, and polar crane are designed for a minimum of 100,000 cycles in 

accordance with CMAA-70, and that the containment hatchway crane does not have an 

established limit on the number of times the crane could be used to lift a limiting load. The 

applicant further stated that the allowable cycles based on CMAA-70 allowable stress ranges 

are not time-limited and are well above the estimated number of cycles for the spent fuel cask 

crane, new fuel handling crane, and polar crane during 60 years of plant operation and, 

therefore, there are no TLAAs associated with crane cycles.

The staff reviewed the applicant’s response and noted that the spent fuel cask crane, new fuel 

handling cranes, and polar crane were designed for a minimum of 100,000 cycles in accordance 

with CMAA-70. The staff noted that the CMAA-70 allowable stress ranges are not time-limited. 

However, the staff also noted that the monitoring of loading cycles against the upper bound 

design limit for loading cycles is a time-dependent assessment defined by the life of the plant. 

Therefore, the staff did not have sufficient information to conclude that these assessments for 

these cranes do not need to be identified as TLAAs for the LRA because the analyses do 

include a time-dependency.

By letter dated September 7, 2012, the staff issued follow-up RAI 4.1-2a, in part (a) requesting, 

the applicant to provide justification on why the analysis of loading cycles for spent fuel cask 

cranes, new fuel handling cranes, and polar crane would not need to be identified as TLAAs for 

the LRA when compared to the six criteria for defining TLAAs in 10 CFR 54.3(a). In part (b) of 

this RAI, the staff asked the applicant to amend the LRA appropriately if it was determined that 

the analyses of loading cycles for the spent fuel cask cranes, new fuel handling cranes, and 

polar crane should have been identified as TLAAs, based on a comparison to the six criteria for 

identifying TLAAs in 10 CFR 54.3(a) and the TLAA identification requirements in 

10 CFR 54.21(c)(1), and to disposition the TLAAs accordingly in compliance with requirements 

in 10 CFR 54.21(c)(1)(i), (ii), or (iii).

The applicant responded to RAI 4.1-2a in a letter dated October 2, 2012. In its response, the 

applicant resolved the request raised in RAI 4.1-2a by amending the LRA to identify the 

analyses for the spent fuel cask crane, new fuel handling crane and polar crane as TLAAs for 

the LRA. Specifically, the applicant made the following changes to the LRA that the staff 

confirmed are in compliance with the requirements in 10 CFR Part 54 and also consistent with 

recommendations in the GALL Report and SRP-LR:

• With regard to compliance with the TLAA identification requirement in 

10 CFR 54.21(c)(1) and consistency with the recommendations for plant-specific TLAAs 

in SRP-LR Section 4.7, the staff confirmed that the applicant amended LRA Section 4.7 

to include TLAA Section 4.7.4, “Fatigue Analysis of Cranes,” which provides the 

applicant’s evaluation of the spent fuel cask crane, new fuel handling crane and polar 

crane analyses and discusses the applicant’s basis for acceptance the TLAA for these 

cranes in accordance with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(i).

• With regard to compliance with the UFSAR supplement inclusion requirements in 

10 CFR 54.21(c)(2), the staff confirmed that the applicant amended LRA Appendix A, 

“Updated Final Safety Analysis Report Supplement,” to include LRA Section A.2.5.4, 

“Fatigue Analysis of Cranes,” which provides the applicant’s UFSAR supplement 
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summary description on the TLAA for the fuel cask crane, new fuel handling crane, and 

polar crane.

• With regard to consistency with the recommendations in SRP-LR Section 4.1, the staff 

confirmed that the applicant amended LRA Table 4.1-1, “List of GGNS [Grand Gulf 

Nuclear Station] TLAAs and Resolution,” to include an item on “Fatigue Analysis of 

Cranes,” indicating acceptance of the TLAA and referring to the TLAA evaluation in LRA 

Section 4.7.4.

• With regard to consistency with the recommendations in SRP-LR Table 4.1-3, the staff 

confirmed that the applicant amended LRA Table 4.1-2, “Comparison of GGNS TLAA to 

NUREG-1800 TLAA,” to indicate that the “Fatigue Analysis of polar crane,” as listed in 

SRP-LR Table 4.1-2 is applicable to the GGNS CLB and to refer to the evaluation of the 

GGNS polar crane in LRA Section 4.7.4.

• With regard to consistency with the recommendations in SRP-LR Section 3.5.2.2, the 

staff confirmed that the applicant amended LRA Section 3.5.2.3, “Time Limited Aging 

Analyses,” to identify that the spent fuel cask crane, new fuel handling crane and polar 

crane analyses are within a scope of a TLAA in the LRA.

• With regard to consistency with the recommendations in aging management review 

(AMR) Item 1 in SRP-LR Table 3.3-1, the staff confirmed that the applicant amended 

AMR Item 3.3.1-1 in LRA Table 3.3.1 to identify that the analysis of fatigue for steel 

crane structural girders is a TLAA in the LRA.

• With regard to consistency with the recommendations in GALL Report Table VII.B, the 

staff confirmed that the applicant amended AMR Item 3.3.1-1 in LRA Table 3.5.2-1, 

“Containment Building,” to include a TLAA-based AMR item for steel crane structural 

girders that are exposed to an uncontrolled indoor air environment.

The staff finds that the applicant’s amended basis is acceptable because the staff has confirmed 

that: (a) the applicant amended the LRA to appropriately identify the analyses for the spent fuel 

cask crane, new fuel handling crane and polar crane as a TLAA in the LRA, (b) the applicant 

has made the appropriate changes to the LRA needed to be consistent with corresponding 

sections and tables in the GALL Report and SRP-LR, and (c) the changes made by the 

applicant are in compliance with the Commission’s TLAA identification requirements in 

10 CFR 54.21(c)(1) and Commission’s UFSAR supplement summary description requirements 

in 10 CFR 54.21(c)(2). The staff evaluation of the TLAA for the spent fuel cask crane, new fuel 

handling crane and polar crane is given in SER Section 4.7.4. The staff’s evaluation of the 

amendment of LRA Section 3.5.2.3 is given in SER Section 3.5.2.3. RAI 4.1-2a is resolved.

In relation to the applicant’s RAI 4.1-2 response for the containment hatchway crane, the staff 

noted that the crane rails were required to be designed in accordance with requirements for 

crane rail designs in Section 1 of the AISC standard and that the load-bearing parts of the 

cranes were required to be evaluated in accordance with the specifications in Section 5 of the 

AISC standard. This includes evaluation of the load-bearing parts for possible fatigue loading 

conditions per Chapter 5, Section 1.7 of the AISC standard and Section 1.7 of Appendix B of the 

AISC standard. Specifically, the staff noted that Table B1, “Number of Loading Cycles,” in 

Appendix B of the AISC standard would establish a loading condition for each of the crane 

load-bearing parts based on the following load cycle ranges: (a) 20,000–100,000 loading cycles 

for loading condition 1, (b) 100,000–500,000 loading cycles for loading condition 2, 

(c) 500,000-2,000,000 loading cycles for loading condition 3, and (d) over 2,000,000 loading 

cycles for loading condition 4. The staff noted that Tables B2 and B3 in Appendix B of the AISC 
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specification then use the loading condition category for each of the load-bearing parts to 

establish maximum allowable stresses for these components.

The staff also noted that UFSAR Section 9D.3.1 confirms that the load-bearing parts of the 

containment hatchway crane were designed and evaluated to the design specifications in the 

AISC Steel Construction Manual, 7th Edition, and the evaluation of the crane was used to 

perform structural modifications and “derating” of the containment hatchway crane. However, 

the staff noted that the UFSAR Section 9D.3.1 did not identify specifically what modifications 

were made to the design of this crane or which criteria in the AISC standard or other NRC 

requirements applicable to the crane were specifically derated per the crane analysis, or 

whether the specific analysis used for the “derating” purpose or purposes was based on a 

TLAA. Therefore, the staff did not have sufficient information to conclude that evaluation of the 

containment hatchway crane did not include any cycle dependent analyses that conformed to 

the definition of a TLAA in 10 CFR 54.3(a). The staff did not have sufficient information to 

determine whether the number of load cycles established for the hatchway crane in the design 

basis would have required the applicant to analyze the crane for fatigue loads based on the 

analysis basis established for fatigue loadings in Appendix B of the AISC standard; and, if so, 

why the counting of load cycles for the cranes against the limits set for the cranes would not be 

time-dependent as defined by the life of the plant. The staff also did not have sufficient 

information to determine whether the AISC standard subpart evaluation or evaluations used for 

the crane “derating” objectives was based on a TLAA.

Therefore, by letter dated September 7, 2012, the staff issued follow-up RAI 4.1-2b, requesting, 

in part (a) of the RAI, that the applicant to provide a basis on how the load-bearing parts for the 

containment hatchway crane were assessed for potential fatigue bearing loads, or else provide 

why the crane bearing would not have been required to be assessed for fatigue if fatigue 

analyses were not performed for the containment hatchway crane load-bearing parts as part of 

the design basis. In part (b) of this RAI, the staff asked the applicant to provide a basis on why 

such fatigue analyses would not need to be identified as TLAAs for the LRA if the CLB did 

include applicable fatigue analyses for the containment hatchway crane load-bearing parts. In 

part (c) of the RAI, the staff asked the applicant to identify all modifications of the containment 

hatchway crane that were made per the AISC standard evaluation of the crane. The staff also 

asked the applicant to identify the specific AISC standard subpart evaluation or evaluations 

used to “derate” this crane and to identify the specific AISC criteria or other NRC requirements 

that the evaluation or evaluations used to “derate” and to justify such a basis. The staff also 

asked the applicant to explain and justify why the specific AISC standard subpart evaluation or 

evaluations used for “derating” purpose would not need to be identified as a TLAA when 

compared to the six criteria for defining TLAAs in 10 CFR 54.3(a).

The applicant provided its response to RAI 4.1-2b in a letter dated October, 2, 2012. In its 

response, the applicant clarified that the containment hatchway crane is a non-safety related 

truck bed crane that contains a hydraulically operated boom that was purchased and mounted 

to a pedestal inside containment. The applicant stated that the analysis referred to in UFSAR 

Section 9D.3.1 is a supplemental analysis that was performed to demonstrate that the crane 

would not cause damage to safety-related equipment in the vicinity by failing during a postulated 

seismic event. The applicant stated that the supplemental AISC Standard analysis referred to in 

UFSAR Section 9D.3.1 was only performed to demonstrate that the containment hatchway 

would satisfy Seismic II over I structural requirements. The applicant stated that the “derating” 

of the containment hatchway crane referred to in UFSAR Section 9D.3.1 involved a decision by 

Entergy to set a maximum allowable load value for the crane to a value less than the maximum 

allowable load recommended for the crane by its vendor. The applicant also stated the 
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modifications of the containment hatchway crane referred to in the UFSAR were the addition of 

stiffeners at certain crane locations and the use of 1-inch diameter A490 bolts to attach the 

crane to its pedestal.

The applicant also clarified that the seismic analysis of the containment hatchway crane 

involved reconciliation against the following sections in the AISC Standard: (a) Section 1.5.1.2, 

“Shear”; (b) Section 1.5.13, “Compression”; (c) Section 1.5.1.4, “Bending”; (d) Section 1.9.1, 

“Unstiffened Elements Under Compression”; and (e) Section 1.9.2, “Stiffened Elements Under 

Compression.” The applicant clarified that the seismic analysis of the containment hatchway 

crane did not include any fatigue evaluation or fatigue analysis that was based on 

time-dependent assumptions.

The staff noted that the applicant’s response to RAI 4.1-2b clarifies what type of analyses were 

performed in the CLB in analysis of the containment hatchway crane and clarifies that the 

analysis of this crane was used solely to demonstrate that a failure of the crane during a 

postulated seismic event would not cause damage to safety-related equipment that would be 

required to be operable during such a seismic event or during a postulated design basis 

accident. The staff noted that the response RAI 4.1-2b confirms that the applicant’s CLB does 

not include a fatigue analysis for the containment hatchway crane, which otherwise would have 

been performed if the applicant had opted to analyze the containment hatchway crane to the 

fatigue analysis criteria in Appendix B of the AISC Standard. Based on the review, the staff 

finds that the applicant has provided an acceptable basis of demonstrating that the CLB does 

not include a fatigue TLAA for the containment hatchway crane because the staff has confirmed 

that the CLB did not evaluate the containment hatchway crane to the fatigue analysis criteria in 

Appendix B of the AISC Standard. RAI 4.1-2b is resolved.

Absence of a TLAA on Flow-Induced Vibration Endurance Limit for Reactor Vessel Internals. In 

LRA Table 4.1-2, the applicant identified that the CLB does not include any flow-induced 

vibration analysis for the RVI components that would need to be identified as a TLAA in the 

LRA. The applicant stated that the flow-induced vibration analyses for the RVI components are 

not based on time-dependent assumptions defined by the life of the plant and therefore do not 

conform to the definition of a TLAA in 10 CFR 54.3.

SRP-LR Table 4.1-3 identifies that the CLB may include plant-specific flow-induced vibration 

analyses for the RVI components that qualify as TLAAs for the applicant’s LRA.

The staff reviewed the information in the UFSAR for relevancy to the applicant’s “absence of a 

TLAA” basis. The staff noted that UFSAR Chapter 3.9.2.3 describes the flow-induced vibration 

analyses (dynamic modal analyses) that were performed on the RVI components and that 

served as the analysis reference points for evaluating the results of specific flow-induced 

vibration pre-operational and start-up tests performed on the RVI components before initial plant 

power operations. Specifically, the staff noted that the UFSAR identifies that the results of 

dynamic vibration analyses from other US nuclear plants (“sister plants”) are used as a 

bounding basis for evaluating the results of the dynamic preoperational and startup tests that 

were performed on the RVI components. The staff also noted that UFSAR Section 3A identifies 

that the applicant uses this type of basis for conforming to the NRC’s recommended position in 

RG 1.20, “Comprehensive Vibration Assessment Program for Reactor Internals during 

Preoperational and Initial Startup Testing.”

However, the staff noted that the UFSAR did not fully define which “sister plant” reports or 

analyses were being relied upon to baseline the results of the preoperational and startup tests 
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on the RVI components, or identify whether these sister plant reports or analyses included any 

analyses of time-dependent vibration parameters that would need to be identified as TLAAs for 

the LRA. Therefore, by letter dated June 5, 2012, the staff issued RAI 4.1-3, requesting 

additional information on the following issues related to these flow-induced vibration analyses: 

(a) identification of all “sister plant” vibration reports, calculations, or evaluations, and the 

analyses in these documents, which were being relied upon for conformance with the NRC’s 

recommended position in RG 1.20; and (b) justification on why the vibration analyses in the 

“sister plant” reports, calculations, or evaluations would not need to be identified as applicable 

TLAAs when compared to the six criteria for defining TLAAs.

The applicant responded to RAI 4.1-3, parts (a) and (b) by letter dated July 3, 2012. In its 

response, the applicant stated that UFSAR Section 3A discusses the comprehensive vibration 

assessment program for the reactor internals during preoperational and initial startup testing, 

which was developed consistent with the NRC’s recommended regulatory position in RG 1.20. 

The applicant also stated that UFSAR Section 15D.9 identifies that it is defined by the General 

Electric Company as a fully instrumented prototype BWR-6 251 plant in accordance with 

RG 1.20, and that three-phase vibration testing of the reactor internals was performed at the 

applicant’s site as described in UFSAR Section 3.9.2.4. The applicant stated that “sister plant”

flow-induced vibration assessments were not relied upon as part of the design basis. Based on 

this assessment, the applicant clarified that the CLB does not include any “sister plant” RVI 

flow-induced vibration analyses that need to be identified as TLAAs for the LRA.

The staff reviewed the UFSAR Section 15D for relevant information. Based on this review, the 

staff noted that the applicant’s response to RAI 4.1-3, parts (a) and (b) resolved the matter on 

whether the applicant’s RG 1.20 conformance basis for assessing RVI flow-induced vibrations 

was being done in comparison to RVI flow-induced vibration analyses for other BWR facilities 

(i.e., referred to “sister plants” in RAI 4.1-3) in the United States because the UFSAR confirms 

that the CLB does not include any “sister plant’ flow-induced vibration analyses that would need 

to be identified as TLAAs for the LRA. Therefore, the staff concern in RAI 4.1-3 is resolved.

However, the staff also noted that, in UFSAR Section 15D.8, the applicant does identify that GE 

performed a generic acoustic and flow-induced load analysis for the RVI components. The staff 

noted that, although this flow-induced vibration analysis does include a time dependency, the 

analysis assessed flow-induced vibrations of the internals only for the period associated with the 

initial operating cycle. Thus, the staff confirmed that, although the GE flow-induced vibration 

analysis is time-dependent, it is not based on (i.e., defined by) the life of the plant because the 

assessment only involves an assessment of vibrations over a single operating cycle and not 

through an assumed 40-year licensed life. Based on this review, the staff concludes that the 

applicant has provided a valid basis for concluding that the LRA does not need to identify any 

RVI flow-induced vibration TLAAs because the staff has confirmed that: (a) the GE 

flow-induced vibration analysis being relied upon in the applicant’s CLB is not a time-dependent 

analysis that is defined by the life of the plant, and (b) therefore, the analysis does not conform 

to Criterion 3 for defining TLAAs in 10 CFR 54.3(a).

Absence of a TLAA on Leak-Before-Break. In LRA Table 4.1-2, the applicant identified that its 

CLB review did not identify any time-dependent leak-before-break (LBB) analysis for the RCPB

piping. The applicant stated that its CLB does not credit LBB as a safety analysis for the RCPB.

SRP-LR Table 4.1-3 identifies that the CLB may include a plant-specific time-dependent LBB 

analysis for the RCPB that qualifies as a TLAA for the applicant’s LRA. The SRP-LR 

recommendations are only applicable to LBB analyses that were requested and approved by 
4-14

the staff to meet dynamic effect analysis relaxation requirements in 10 CFR Part 50, 

Appendix A, General Design Criterion (GDC) 4, “Dynamic Effects.”

The staff noted that the relevant SRP-LR guidance is not applicable to BWR designs because 

the staff has not approved any LBB analysis methodologies for analogous high-energy piping in 

BWR RCPB designs. The staff reviewed the UFSAR information and confirmed that the 

applicant’s design basis does not include or make reference to any LBB analysis requested and 

approved for relaxation from the dynamic effect analysis requirements in 10 CFR Part 50, 

Appendix A, GDC 4. Therefore, the staff concludes that the LRA does not need to include a 

plant-specific LBB TLAA because the staff has confirmed that: (1) the applicant’s design basis 

does not include an LBB analysis; and (2) the TLAA referenced in SRP-LR Table 4.1-3 for LBB 

analyses is not applicable to the CLB [Criterion 6 of 10 CFR 54.3(a)].

During its review, the staff noted that the applicant addresses its basis for complying with 

GDC 4 as part of the applicant’s HELB analysis criteria, which is addressed in UFSAR 

Section 3.6. The staff also noted that the applicant has included the design basis fatigue 

analyses for these HELB locations as TLAAs for the LRA and has discussed these HELB 

TLAAs in LRA Section 4.7.2. The staff’s evaluation of the applicant’s disposition of the HELB 

TLAA is documented in SER Section 4.7.2.

Absence of a TLAA on Metal Corrosion Allowance. In LRA Table 4.1-2, the applicant identified 

that the CLB does not include any time-dependent metal corrosion allowance evaluations for 

metallic components that would need to be identified as TLAAs for the LRA.

SRP-LR Table 4.1-3 identifies that the CLB may include plant-specific metal components 

corrosion allowance analyses that qualify as TLAAs for the applicant’s LRA.

The staff reviewed the UFSAR information for relevancy to the applicant’s “absence of a TLAA”

basis. The staff also noted that UFSAR Table 3.9-2g identifies that the calculation of the 

minimum wall thickness for nozzles on the main steam safety/relief valves included the 

establishment of a corrosion allowance of the components. The staff also noted that UFSAR 

Section 5.4.5 (UFSAR page 5.4-30) identifies that a corrosion allowance of 0.120-inches 

minimum was added to minimum wall thickness for the main steam isolation valves (MSIVs) to 

provide for 40 years of service, and that UFSAR Table 3.9-2h identifies that the calculation of 

the corrosion allowance for the MSIVs was performed in accordance with ASME Code 

Section III NB-3646 requirements. The staff also noted that UFSAR Section 5.2.3.2.3, states

that conservative corrosion allowances were included in the design of carbon steel and alloy 

steel reactor coolant system (RCS) components to protect them from general corrosion as a 

result of exposure to the reactor coolant environment. The staff noted that UFSAR 

Section 6.1.1.1.2 makes an equivalent type of statement for those carbon steel components in 

the emergency safety feature systems that are exposed to a treated water environment. The 

staff noted that the UFSAR did not indicate that the additional metal, which was included in the 

pipe design by these corrosion allowances, was included in the pipe design as a result of any 

time-dependent analysis. Instead, the staff confirmed that the applicant included the additional 

corrosion allowances based on conformance with applicable non-time dependent code 

provisions in the ASME Section III Code of record for the facility and not on any analysis that is 

required to be a TLAA for the facility.

Therefore, based on this assessment, the staff concludes that the applicant provided an 

acceptable basis for concluding that the CLB does not include any corrosion allowance TLAAs 
4-15

because the staff has confirmed that additional metal corrosion allowances that were included in 

the plant’s piping design were not based on any time-dependent analyses in the CLB.

Absence of a TLAA on Inservice Flaw Growth Analyses That Demonstrate Structure Stability for 

40 Years. In LRA Table 4.1-2, the applicant identified that its CLB does not include any 

time-dependent inservice flaw growth, flaw tolerance, or fracture mechanics evaluations for 

ASME Code Class components that demonstrate structural stability over a 40-year period.

SRP-LR Table 4.1-3 identifies that the CLB may include plant-specific (from inservice inspection 

(ISI) findings) fatigue flaw growth or time-dependent flaw tolerance analyses that qualify as 

TLAAs for the ASME Code Class components that are within the scope of an applicant’s LRA. 

SRP-LR Section 4.3.2.1.5 provides the staff’s recommended plant-specific criteria for accepting 

these types of TLAAs in accordance with the TLAA acceptance requirements in 

10 CFR 54.21(c)(1)(i), (ii), or (iii).

During the NRC aging management program (AMP) audit, held during the week of 

January 23, 2012, the staff confirmed that the CLB did not include any ISI-based flaw 

evaluations defined by a 40-year licensing period, with the exception of the applicant’s 

cycle-dependent fracture mechanics evaluation for the feedwater (FW) nozzles to the plant’s 

RV. The staff noted that the applicant used this analysis as part of its basis for managing 

cracking and for performing augmented ISI of the FW nozzles. The applicant credits its BWR 

Feedwater Nozzle Program (LRA AMP B.1.7) as the basis for managing cracking in these 

components. During the AMP audit, the staff confirmed that this AMP is based on and is 

consistent with the program element criteria in GALL Report AMP XI.M5, “BWR Feedwater 

Nozzles,” and with the augmented inspection recommendations in GE Report 

No. GENE-523-A71-0594, Revision 1, and in NUREG-0619.

The staff noted that GENE-523-A71-0594, Revision 1, included a generic flaw tolerance 

evaluation of BWR FW nozzles to support the augmented ISI method and interval that GE 

recommends for the BWR nozzle designs, including the FW nozzles. The staff also noted that 

the generic analysis did state that the analysis was based on a 40-year design life for the 

facility. Therefore, the staff determined that the applicant would need to provide additional 

justification on why the plant-specific analysis, as applied to the evaluation of the FW nozzles, 

would not need to be identified as a TLAA for LRA. Therefore, by letter dated June 5, 2012, the 

staff issued RAI 4.1-4, requesting, in part (a), that the applicant clarify how this plant-specific 

fracture mechanics evaluation compares to the six criteria for defining TLAAs in 10 CFR 54.3(a). 

In RAI 4.1-4, part (b), the staff asked the applicant to provide further justification on why the 

fracture mechanics evaluation would not need to be identified as a TLAA in the LRA, as 

required by 10 CFR 54.21(c)(1).

The applicant responded to RAI 4.1-4 by letter dated July 3, 2012. In its response to RAI 4.1-4, 

part (a), the applicant clarified that its plant-specific flaw tolerance analysis used to support the 

ISI interval for the FW nozzle in GENE-523-A71-0594, Revision 1, conformed to all six of the 

criteria for defining TLAAs in 10 CFR 54.3(a), except for Criterion 3. The applicant stated that 

this analysis did not conform to Criterion 3 in 10 CFR 54.3(a) because it does not include a time 

dependency and, therefore, is not a time-dependent analysis defined by the life of the plant. In 

its response to RAI 4.1-4, part (b), the applicant stated that the intent of the plant-specific 

fracture mechanics evaluation was to justify the inspection intervals in the GE generic 

evaluation. The applicant stated that the specific evaluation concluded that the results 

presented therein were valid for use in establishing future FW nozzle reinspection intervals 
4-16

based on the alternate requirements specified in the generic evaluation; therefore, the specific 

evaluation did not qualify the FW nozzles for a fixed term and is not a TLAA.

The staff noted that the applicant is using the frequency for performance of the alternative FW 

nozzle inspections to define the time period associated with the flaw tolerance analysis that is 

described and evaluated in the applicant’s plant-specific flaw tolerance analysis for the FW 

nozzle. In contrast, the staff noted that the inspection interval for the alternative FW nozzle

ultrasonic examinations is part of the safety basis for the nozzles because it is part of the basis 

for establishing acceptable alternative inservice requirements for the nozzle under the 

requirements of 10 CFR 50.55a. The ISI interval does not establish the time frame assumed for 

the flaw tolerance analysis in the GE report because it is actually part of the applicant’s safety 

basis decision, not the analysis basis supporting that decision. Thus, the staff concluded that 

the applicant should have identified the plant-specific flaw tolerance analysis for the FW nozzle 

as a TLAA in the LRA because it meets all six of the criteria for TLAAs in 10 CFR 54.3(a). This 

includes conformance with TLAA identification Criterion 3 in that the evaluation is based on 

time-dependent assumptions defined by the life of the plant.

By letter dated September 7, 2012, the staff issued follow-up RAI 4.1-4a, requesting, in part (a),

further justification on why the applicant had not identified the plant-specific flaw tolerance 

analysis for the FW nozzle as a TLAA in the LRA. The applicant provided its response to 

RAI 4.1-4a in a letter dated October, 2, 2012. In its response, the applicant stated that the flaw 

tolerance evaluation for the feedwater nozzle was performed to establish the adequacy of the 

periodic inspection interval. The applicant stated that the analysis evaluated a postulated flaw 

in the feedwater nozzle and demonstrated that, based on the transient loadings for the assumed 

flaw in the analysis, the feedwater nozzles would be acceptable for 19.5 years. The applicant 

clarified that the 19.5 years was an output of the analysis that was used to support the 

establishment of a 10-year inspection interval for the feedwater nozzle. The applicant used this

basis to make a conclusion that the analysis does not involve time-limited assumptions defined 

by the current operating term. The applicant further stated that the analysis was not performed 

for the purpose of qualifying the RPV feedwater nozzle to the expiration of the current operating 

term, and thus did not need to be identified as a TLAA.

The staff noted that it is the input to the flaw tolerance analysis that would establish whether the 

analysis is based on time-dependent assumptions defined by the current operating term for the 

facility. Thus, the staff noted that the applicant’s basis would be valid if the analysis used the 

number of design basis transients occurring over a 19.5-year period as the assumed inputs for 

the flaw growth (flaw tolerance) analysis. However, the staff noted that this basis would not be 

valid if the analysis used the number of transients occurring over a 40-year licensing basis 

period as the inputs for the flaw growth analysis. Thus, the staff needed additional information

regarding the input to the flaw tolerance analysis to verify whether the analysis was based on 

time-limited assumptions defined by the current operating period for the facility.

By letter dated November 5, 2012, the staff issued RAI 4.1-4b, the staff asked the applicant 

either to provide the plant-specific flaw tolerance analysis discussed in the response to 

RAI 4.1-4a or justify that the analysis did not involve the use of any time-limited assumptions 

defined by the current operating term as input.

The applicant responded to RAI 4.1-4b by letter dated November 29, 2012. In its response, the 

applicant clarified that the referenced, plant-specific flaw tolerance evaluation for the RV 

feedwater nozzles was based on an evaluation of applicable plant transient cycle occurrences 

over an approximately 5-year period from 1990 to 1995. The applicant stated that for each 
4-17

transient assumed in the analysis, the cycle count as of September 30, 1990, was subtracted 

from the cycle count as of April 15, 1995. The applicant explained that the results were divided 

by 4.5 years to obtain the occurrences of each transient per year over that time period and that 

the annual occurrence rates were used as input into the flaw tolerance evaluation to determine 

the number of years that it would take for a postulated flaw to grow to the critical flaw size. The 

applicant stated that the evaluation demonstrates that the flaw in the FW nozzle would be 

acceptable over a 19.5-year period.

The staff reviewed the response to RAI 4.1-4b and noted that the response clarifies how the 

assessment of design basis transients was performed as part of the flaw evaluation for the FW 

nozzle. The staff noted that the response demonstrates that the assessment of design 

transients in the flaw evaluation was based only on a 5-year time period and was not based on 

time-dependent assumptions defined by the current operating period. Instead, the analysis 

demonstrates that the 10-year interval for the FW nozzle is an acceptable frequency for 

inspections of the component. Therefore, the staff’s concerns described in RAIs 4.1-4, 4.1-4a, 

and 4.1-4b are resolved.

Thus, the staff concludes that the applicant has provided an acceptable basis for concluding 

that the flaw evaluation for the FW nozzle does not need to be identified a TLAA because 

(a) the staff has confirmed that flaw evaluation does not involve time-dependent assumptions 

defined by the current operating term, and (b) this demonstrates that the analysis does not 

conform to criterion No. 3 of the definition of TLAA, as stated in 10 CFR 54.3(a).

Potentially Applicable TLAAs in Response to BWRVIP Report Applicant Action Items. The staff 

noted that inclusion of LRA AMP B.1.11, “BWR Vessel Internals,” confirms that the applicant 

applies the Boiling Water Reactor Vessel and Internals Project (BWRVIP) inspection and flaw 

evaluation (I&FE) guideline reports as part of its basis for managing the aging effects applicable 

to the RVI components. Therefore, the staff noted that the NRC-issued SEs on the BWRVIP 

reports referenced in GALL Report AMP XI.M9, “BWR Vessel Internals,” and other BWRVIP 

I&FE guidelines referenced in the applicant’s LRA (specifically BWRVIP-18-A, BWRVIP-25, 

BWRVIP-26-A, BWRVIP-27-A, BWRVIP-38, BWRVIP-41, BWRVIP-42-A, BWRVIP-47-A, 

BWRVIP-48-A, BWRVIP-49-A, BWRVIP-74-A, and BWRVIP-76-A) include applicant action 

items (AAIs) that relate to the identification of TLAAs.

The staff verified that the applicant included its responses to the AAIs on these BWRVIP reports 

in Appendix C of the LRA. The staff’s evaluations of the applicant’s responses to these AAIs 

are given below.

AAIs that are Common to BWRVIP Report Nos. BWRVIP-18-A, BWRVIP-25, BWRVIP-26-A, 

BWRVIP-27-A, BWRVIP-38, BWRVIP-42-A, BWRVIP-47-A, BWRVIP-48-A, BWRVIP-49-A, 

BWRVIP-74, and BWRVIP-76

The staff verified that the applicant’s AAI response bases included the applicant’s response 

bases to the three AAIs that are common to all of these BWRVIP reports:

• AAI No. 1, which relates to the AMPs that are credited for aging management of the 

applicant’s RPV and RVI components, as required by 10 CFR 54.21(a)(3), and the need 

to commit to AMPs that incorporate and will implement the protocols in the BWRVIP 

I&FE guideline documents.
4-18

• AAI No. 2, which relates to the requirement in 10 CFR 54.21(d) and the generic need for 

inclusion of a final safety analysis report (FSAR) supplement for each AMP and TLAA 

that is credited for aging management of the applicant’s RPV and RVI components.

• AAI No. 3, which relates to the requirement in 10 CFR 54.22 and the generic need to 

identify any TS requirements that relate to aging management or evaluation of the 

applicant’s RPV or RVI components and would need to be amended in the LRA.

In its response to AAI No. 1, the applicant stated that the design of the GGNS has been verified 

to be bounded by the referenced BWRVIP reports. The applicant also stated that it commits to 

programs described as necessary in the BWRVIP reports to manage the effects of aging during 

the period of extended operation. The applicant further stated that the applicable commitments 

are administratively controlled in accordance with the requirements of the applicant’s 

10 CFR Part 50, Appendix B, quality assurance program and that any deviation from a BWRVIP 

report approved by the NRC will be reported to the NRC in accordance with the protocols of 

Technical Report BWRVIP-94.

The staff noted that the referenced BWRVIP reports have been incorporated by reference in the 

following AMPs for the LRA: (a) LRA AMP B.1.8, “BWR Penetrations,” which incorporates 

BWRVIP-27-A and BWRVIP-49-A; (b) LRA AMP B.1.10, “BWR Vessel ID Attachment Welds,” 

which incorporates BWRVIP-48-A; and (c) LRA AMP B.1.11, “BWR Vessel Internals,” which 

incorporates the remaining BWRVIP reports described in the following sections. The staff also 

verified that the applicant’s need to implement these programs and BWRVIP I&FE guidelines 

are already within the scope of plant-specific commitments in the CLB for implementing the 

Electric Power Research Institute (EPRI) BWRVIPs that have been issued and approved by the 

staff, and that the applicant is already implementing these BWRVIP protocols in accordance 

with its existing NEI 03-08 and BWRVIP-94 implementation commitments. The staff also noted 

that this basis is appropriately reflected in the applicant’s response to AAI No. 1. Based on this 

review, the staff finds that the applicant has appropriately resolved the request in AAI No. 1 

because the applicant has protocols in place to implement the applicable BWRVIP reports, and 

has implemented these BWRVIP protocols in accordance with the applicant’s “Existing” AMPs. 

The staff evaluations of these programs are provided in appropriate sections of this SER 

(e.g., SER Section 3.0.3.1.9 for the BWR Vessel ID Attachment Welds Program, SER 

Section 3.0.3.1.7 for the BWR Penetration Program, and SER Section 3.0.3.1.10 for the BWR

Vessel Internals Program). The request in AAI No. 1 is resolved.

In its response to AAI No. 2, the applicant stated that the UFSAR supplement is included as 

LRA Appendix A and includes a summary of the programs and activities specified as necessary 

for those BWRVIP programmatic activities. The staff verified that the applicant has 

appropriately included the applicable UFSAR supplement summary descriptions for those 

programmatic BWRVIP activities that are within the scope of the applicant’s BWRVIP-based 

AMPs and TLAAs in the following sections of the LRA: (a) Section A.1.8 for the BWR Vessel ID 

Attachment Welds Program; (b) Section A.1.10 for the BWR Penetrations Program; 

(c) Section A.1.1 for the BWR Vessel Internals Program; (d) Section A.2.2.1 for the metal 

fatigue TLAAs for RPV and RVI components; (e) Section A.2.1 for the RPV neutron 

embrittlement TLAAs; and (f) Section A.2.5.3 for the TLAA related to neutron fluence effects for 

the RVI components.

Based on this review, the staff finds that the applicant has resolved the request in AAI No. 2 

because the staff has confirmed that the applicant has provided the appropriate UFSAR 

supplements for the RPV and RVI-related AMPs and TLAAs in Appendix A of the LRA. The 

staff evaluations of these UFSAR supplements are provided in appropriate sections of this SER 
4-19

(e.g., SER Section 3.0.3.1.9 for the BWR Vessel ID Attachment Welds Program, SER 

Section 3.0.3.1.7 for the BWR Penetration Program, SER Section 3.0.3.1.10 for the BWR

Vessel Internals Program, SER Section 4.2 for the RPV neutron embrittlement TLAAs, SER 

Section 4.3 for the RPV and RVI metal fatigue TLAAs, and SER Section 4.7.3 for the TLAA 

related to neutron fluence effects for the RVI components). The request in AAI No. 2 is 

resolved.

In its response to AAI No. 3, the applicant stated that it did not identify any TS changes that 

would need to be identified for the LRA based on BWRVIP I&FE guidelines. The staff noted 

that the only potentially relevant TS requirements are those for the P-T limits TLAA. As 

described in SER Section 4.2.2, the staff evaluated and found acceptable the applicant’s intent 

to manage the P-T limits in accordance with 10 CFR 54.21(c)(1)(iii), including deferral of a 

submittal with updated P-T limit curves until such time as the applicant would be required to 

submit them in accordance with the requirements of 10 CFR Part 50, Appendix G, and its 

10 CFR 50.90 LAR process. The request in AAI No. 3 is resolved.

AAI No. 4 on BWRVIP-18-A (BWRVIP I&E Guidelines for Internal BWR Core Spray Lines)

The staff noted that AAI No. 4 for BWRVIP-18-A, states that BWR applicants for renewal should 

identify all TLAAs applicable to the design of its core spray (CS) internal components. In its 

response to this AAI, the applicant stated that the fatigue analysis for the internal portions of the 

CS line and CS sparger was the only analysis for these components that conformed to the 

definition of a TLAA. The staff confirmed that the applicant includes its fatigue analysis TLAA 

for these components in LRA Section 4.3.1.3 and includes the CUF value for these components 

in LRA Table 4.3-3. The staff also confirmed that the fatigue analysis for the internal portions of 

the CS line and sparger was the only analysis that conformed to the definition of a TLAA in 

10 CFR 54.3(a). Based on this review, the staff finds the applicant’s response to this AAI to be 

acceptable because it has confirmed that the applicant has included the applicable fatigue TLAA 

for the components in the LRA and that the design basis does not include any other analysis 

that needs to be identified as a TLAA for these components. The staff evaluates the applicant’s 

disposition for the metal fatigue TLAA for the internal portions of the CS line and the CS sparger 

in SER Section 4.3.1.3.2. AAI No. 4 on BWRVIP-18-A is resolved.

AAI No. 4 on BWRVIP-25 (BWRVIP I&E Guidelines for BWR Core Plates)

The staff noted that AAI No. 4 for BWRVIP-25, states that BWR applicants for license renewal 

should identify and evaluate whether the evaluation of stress relaxation of in-core plate rim 

holddown bolts should be identified as a TLAA for the components. In its response to this AAI, 

the applicant stated that the structural integrity of the core plate is ensured by the inclusion of 

wedges that hold the core plate in place and that the design does not rely on rim holddown bolts 

that are tensioned (preloaded) in place. Based on this design feature, the applicant stated that 

the design of the core plate does not include any analysis with regard to preloading of rim 

holddown bolts that would need to be identified as a TLAA in the LRA. The staff confirmed that 

UFSAR Section 4.5.2.1 states that the core plate design includes wedges for structural integrity. 

The staff confirmed that these wedges are relied upon as the basis for maintaining structural 

integrity of the core plate against lateral movement instead of reliance on core plate rim holddown bolts. Based on this review, the staff finds the applicant’s response to this AAI to be 

acceptable because it has confirmed that the structural integrity of the core plate does not rely 

on the tensioned rim holddown bolts and that the CLB does not include any analysis of 

preloaded core plate rim holddown bolts. AAI No. 4 on BWRVIP-25 is resolved.
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AAI No. 4 on BWRVIP-26-A (BWRVIP I&E Guidelines for BWR Top Guide Assemblies)

The staff noted that AAI No. 4 for BWRVIP-26-A, states that BWR applicants for license renewal 

should identify and evaluate the projected accumulated neutron fluence for BWR top guides that 

need to be identified as a TLAA for the assessment of irradiated-assisted stress-corrosion 

cracking (IASCC) in the components. In its response to this AAI, the applicant stated that the

60-year projected fluence value for the top guide exceeds the threshold for the initiation of 

IASCC-induced cracking in the top guide and its subcomponents. However, the applicant 

stated that methodology in BWRVIP-26-A does not include any analysis that would constitute a 

TLAA since the report was not used to make any safety determination or as justification for 

reducing the number of inspections that would be applied to these components. The applicant 

stated that since it has implemented the inspection requirements of BWRVIP-26-A and 

BWRVIP-183, its program will be adequate to manage the effects of aging on the top guide 

assembly for the period of extended operation. The staff confirmed that the referenced 

BWRVIP-26-A report does not rely on any generic TLAA for evaluating IASCC-induced cracking 

in the applicant’s top guide design or its subcomponents. The staff also confirmed that the CLB 

did not include any specific analysis for the top guide that conformed to the six criteria for 

TLAAs in 10 CFR 54.3(a) or that would need to be identified as a TLAA in accordance with 

10 CFR 54.21(c)(1). Instead, the staff noted that the applicant relies on inspections of the top 

guide that will be conducted using AMP B.1.11, “BWR Vessel Internals” Program, and the 

methodology of BWR-26-A as the basis for inspecting cracking in the tope guide and its 

subcomponents. The staff evaluates the applicant’s BWR Vessel Internals Program in SER 

Section 3.0.3.1.11. AAI No. 4 on BWRVIP-26-A is resolved.

AAI No. 4 on BWRVIP-27-A (BWRVIP I&E Guidelines for Standby Liquid Control Nozzles)

The staff noted that AAI No. 4 for BWRVIP-27-A, states that BWR applicants for license renewal 

referencing the BWRVIP-27-A report should identify and evaluate whether the CLB includes any 

projected fatigue CUF analyses that would need to be identified as potential TLAAs for their 

standby liquid control (SLC)/core ΔP line nozzles. In its response to this AAI, the applicant 

stated that the fatigue analysis of the SLC/core ΔP line for 60 years of operation is a potential 

TLAA in the LRA. However, the applicant stated that the NRC SE for BWRVIP-27 recognizes 

that this fatigue analysis is not required for all SLC/core ΔP configurations. The applicant stated 

that the CS system provides the flow path for injection of boron from the SLC system; therefore, 

the ΔP/SLC lines inside the RPV do not have a license renewal intended function and are not 

subject to an AMR. Thus, based on this assessment, the applicant stated that its CLB does not 

include any TLAAs associated with the inspection and evaluation guidelines in BWRVIP-27-A.

The staff noted that UFSAR drawing M-1086 identifies that the borated water flow path from the 

SLC system does not inject directly into the RPV using an SLC/core ΔP nozzle. Instead, the 

staff confirmed that the SLC system injects into the RCPB through a branch connection to the 

RCPB portion of the high-pressure core spray (HPCS) system. The staff confirmed that the 

UFSAR drawing indicates this SLC branch connection is located directly downstream of check 

valve F005 and upstream of block valve F036 in the HPCS system. The staff also confirmed 

that the applicant has included its TLAA for the fatigue analysis of the Class 1 portion of the 

SLC system in LRA Section 4.3.1.6 and CUF value for the limiting SLC piping component in 

LRA Table 4.3-5. Based on this confirmation, the staff finds the applicant’s response to AAI 

No. 4 acceptable because the staff has confirmed that: (1) the CLB does not include any 

fatigue analysis for a SLC/core ΔP RPV nozzle that would need to be identified as a TLAA in the 

LRA, and (2) the applicant has included its analogous fatigue usage value for the SLC system in 
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LRA Section 4.3.1.6 and the limiting CUF value for the SLC system in LRA Table 4.3-5. 

AAI No. 4 on BWRVIP-27-A is resolved.

AAI No. 4 on BWRVIP-42-A (I&E Guidelines for LPCI Coupling Components)

The staff noted that AAI No. 4 for BWRVIP-42-A, states that BWR applicants for license renewal 

referencing the BWRVIP-42 report for license renewal should identify and evaluate any potential 

TLAA issues that may affect the structural integrity of its RPV internal low-pressure coolant 

injection (LPCI) coupling components. In its response to this AAI, the applicant stated that the 

potential TLAA issues for LPCI components have been evaluated in LRA Section 4.3.1.3.

The staff noted that UFSAR drawing M-1087 confirms that, when called upon, the design 

provides emergency low-pressure system inventory into the RPV during a postulated design 

basis accident (DBA) event using a low-pressure core spray (LPCS) system. LPCS is the 

system that is analogous to the LPCI systems used to achieve identical emergency core cooling 

objectives for earlier GE Model 4 BWR designs. The staff confirmed that LRA Section 4.3.1.3 

includes a fatigue TLAA for the vessel head cooling spray nozzle and LRA Table 4.3-3 included 

the CUF value for this component. The staff also confirmed that the applicant included its 

fatigue analysis TLAA for portions of the LPCS system external to the RPV in LRA 

Section 4.3.1.6 and the limiting CUF for the LPCS piping in LRA Table 4.3-5. Thus, the staff 

noted that the LRA did include appropriate CUF values for portions of the LPCS system that are 

both internal and external to the RPV. Based on this review, the staff finds the applicant’s 

response to this AAI is acceptable because the staff has confirmed that the applicant has 

included an appropriate TLAA for the LPCS spray nozzle in LRA Section 4.3.1.3. The staff 

evaluates the applicant’s disposition for the metal fatigue TLAA for the LPCS spray nozzle in 

SER Section 4.3.1.3.2. AAI No. 4 on BWRVIP-42-A is resolved.

AAI No. 4 on BWRVIP-47-A (I&E Guidelines for BWR Lower Plenum Components)

The staff noted that AAI No. 4 for BWRVIP-47-A, states that BWR applicants referencing the 

BWRVIP-47-A report for license renewal should identify and evaluate any projected CUFs in the 

CLB for their lower plenum area components as potential TLAAs for the LRA. In its response to 

this AAI, the applicant stated that the potential TLAA issues for RPV internal lower plenum 

components have been evaluated and included in LRA Section 4.3.1.3.

The staff confirmed that the applicant assessed its metal fatigue TLAA for the RPV internal 

lower plenum area components in LRA Section 4.3.1.3 and noted that Table 4.3-3 in this LRA 

section includes appropriate CUF values for the following RPV internal lower plenum area 

components: (a) internal control rod drive (CRD) housings, (b) internal in-core housings and 

guide tubes, and (c) access hole covers. Based on this review, the staff finds the applicant’s 

response to this AAI is acceptable because the staff has confirmed that the applicant has 

included appropriate CUF values for these RPV internal lower plenum area components in LRA 

Section 4.3.1.3. The staff evaluates the applicant’s disposition for the metal fatigue TLAA for 

these lower plenum area components in SER Section 4.3.1.3.2. AAI No. 4 on BWRVIP-47-A 

is resolved.

AAIs on BWRVIP-74-A (Reactor Vessel Inspection and Flaw Evaluation Guidelines for License 

Renewal)

The staff noted that the NRC SE on the BWRVIP-74-A included the following TLAA-related 

AAIs:
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• AAI No. 8 on identification of appropriate metal fatigue TLAAs for the RPV components

• AAI No. 9 on identification of appropriate P-T limit analysis TLAAs for the RPV beltline 

components in the LRA

• AAI No. 10 on identification of appropriate USE analysis TLAAs for the RPV beltline 

components in the LRA

• AAI Nos. 11 and 12 on identification of appropriate TLAAs related to appropriate 

time-dependent probability of failure analyses for RPV axial and circumferential welds 

used to support ISI relief requests requested on relief from applicable RPV 

circumferential weld examination requirements

• AAI No. 13 on providing 60-year neutron fluence values for those TLAAs that have been 

included in the LRA for neutron irradiation embrittlement (i.e., P-T limit, USE, and the 

RPV axial and circumferential weld probability of failure analyses)

• AAI No. 14 on providing applicable time-dependent flaw tolerance or flaw growth 

analysis for ASME Code Class 1 RPV components

The staff confirmed that the applicant responded to these AAIs by referencing the appropriate 

subsections in LRA Section 4 that relate to the TLAA topics. The staff has evaluated the 

applicant’s bases for including the TLAAs referenced in its responses to AAI Nos. 8 through 13

in SER Section 4.1.2.1.1. The staff has evaluated the applicant’s basis for omitting identification 

of a fatigue flaw growth TLAA for the FW nozzle in SER Section 4.1.2.1.2. AAI Nos. 8 through 

14 on BWRVIP-74-A are resolved.

Impact of Extended Power Uprate License Amendment Request on TLAAs Identified for the 

LRA. The staff noted that LRA Section 1.2 indicates that the applicant submitted a 

10 CFR 50.90 LAR for approval of an extended power uprate (EPU). The EPU amendment was

subsequently issued on July 18, 2012. The licensed thermal power level increased to 

4408 MWt as a result of the EPU approval. The applicant stated that changes to the operating 

parameters because of the increase in power were considered during the LRA preparation. The 

applicant stated that a specific example of the impact that the EPU would have on the TLAAs for 

the LRA is the higher neutron fluence values that would result from the EPU. These neutron 

fluence values are used in the applicant’s evaluation of TLAAs on neutron irradiation 

embrittlement, as discussed and evaluated in LRA Section 4.2. The applicant also stated that 

any small changes in operating parameters as a result of the EPU would have little effect on 

aging effects requiring management.

The staff noted that 10 CFR Part 54 requires that all calculations and analyses that meet the six 

criteria in 10 CFR 54.3(a) to be identified as a TLAA in the LRA. One of these criteria is that the 

calculation or analysis must be contained or incorporated by reference in the CLB for it to be 

defined as a TLAA. Thus, the staff observed that the EPU might not be approved by the time 

the staff had completed its LRA review. Therefore, the staff noted that the TLAAs in the LRA 

that referenced post-EPU operating conditions and parameters might not be based on 

conservative assumptions because the EPU had not yet been approved for the applicant’s CLB. 

Therefore, by letter dated June 5, 2012, the staff issued RAI 4.1-6, asking the applicant to 

identify all the TLAAs discussed in the LRA Section 4 that have used post-EPU operating 

conditions and parameters in their calculations and analyses.

In its response dated July 3, 2012, the applicant stated that each of the following analyses in 

LRA Section 4 considered the post-EPU operating conditions and parameters: RV neutron 

embrittlement evaluations in LRA Section 4.2 include consideration of increased EPU fluence; 
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fatigue analysis results in LRA Section 4.3 include re-evaluations to reflect EPU operating 

conditions; EQ evaluations in LRA Section 4.4 included EPU conditions; the containment liner 

plate, metal containments and containment penetrations evaluations for LRA Section 4.6 

included considerations of EPU conditions; and each of the evaluations in LRA Section 4.7 for 

the erosion of the main steam line (MSL) flow restrictors, determination of intermediate HELB

locations, and fluence effects on the RVI included considerations of EPU operating conditions. 

The staff noted that the applicant received its EPU license amendment on July 18, 2012, and 

the post-EPU operating conditions described in the LRA became the applicant’s CLB.

The staff finds the applicant’s response to RAI 4.1-6 acceptable because it identified all the 

analyses discussed in the LRA Section 4 that have utilized post-EPU operating conditions and 

parameters. Furthermore, the issue described in RAI 4.1-6 is resolved because the post-EPU 

operating conditions described in the LRA became the applicant’s CLB with the approval of the 

EPU license amendment dated July 18, 2012. Thus, the calculations, evaluations, or analyses, 

identified in LRA Section 4, meet all six criteria in 10 CFR 54.3(a) in order for them to be defined 

as a TLAA.

4.1.2.2 Identification of Exemptions in the LRA

As required by 10 CFR 54.21(c)(2), the applicant must identify all exemptions granted under 

10 CFR 50.12 and in effect that are based on a TLAA, evaluate them, and justify their use 

during the period of extended operation. The LRA states that each active exemption was 

reviewed to determine whether it was based on a TLAA. The staff also reviewed the applicant’s 

CLB to see if the CLB included any exemptions granted in accordance with 10 CFR 50.12 and 

based on a TLAA. The staff’s review included the current operation license, the TS, and 

UFSAR for the facility. The staff’s review also included a search of the NRC’s main and legacy 

libraries in the NRC’s Agencywide Documents and Access Management System (ADAMS)

Document Control Library using the keyword “exemption.”

The staff noted that the P-T limits for the RV and RCPB were based on full compliance with the 

P-T limit generation requirements in 10 CFR Part 50, Appendix G, and Appendix G of the ASME 

Code Section XI. The staff also noted that the 32 effective full-power years (EFPYs) P-T limits 

were granted in the NRC’s SE associated with License Amendment No. 132, which was issued 

on August 27, 1997. Thus, the staff confirmed that the applicant’s generation of the 32 EFPY 

P-T limits for the facility was not based on any exemption from the requirements for generating 

P-T limits in 10 CFR Part 50, Appendix G, or in Appendix G of the ASME Code Section XI.

The staff also noted that Clause 2.D in the applicant’s Operating License, NPF-29 identifies that 

the applicant was granted a number of exemptions from the requirements in 10 CFR Part 50, 

Appendix A; 10 CFR Part 50, Appendix J, and 10 CFR Part 100. The operating license states

that the NRC found it acceptable to approve these exemptions based on compliance with one or 

more of the exemption acceptance criteria in 10 CFR 50.12. However, the staff noted that the 

operating license did not provide further discussion on the basis for these exemptions and 

whether approval of the exemptions was based all or in part on any analysis for the CLB that 

would need to be identified as a TLAA in the LRA. Therefore, by letter dated June 5, 2012, the 

staff issued RAI 4.1-5, requesting, in part (a), a summary of each of the exemptions that have 

been referenced in Clause 2.0 of Operating License, NPF-29, including the basis for requesting 

NRC approval of the exemption. In RAI 4.1-5, part (b), the staff asked the applicant to clarify 

whether the basis for requesting these exemptions, before their approvals, were based on 

analyses that would need to be identified as a TLAAs in accordance with 10 CFR 54.21(c)(1). 

In RAI 4.1-5, part (c), the staff asked the applicant to justify whether the exemptions referenced 
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in Clause 2.0 of Operating License, NPF-29, need to be identified as exemptions that are based 

on a TLAA and that need to be identified in accordance with 10 CFR 54.21(c)(2).

In a teleconference call held with the applicant on May 15, 2012, the staff provided clarification 

to the applicant that in its response to RAI 4.1-5, it needed to address the exemption that was 

granted from applicable 10 CFR Part 50, Appendix J, containment leak rate testing 

requirements. The staff clarified that the applicant did not need to provide an explanation for the 

exemption granted from GDC 17 in 10 CFR Part 50, Appendix A, GDC Criteria, because the 

license indicated that the exemption only applied until the plant startup out of the first refueling 

outage, for: (1) the emergency override of the test mode for the Division 3 diesel engine, (2) the 

second level of undervoltage protection for the Division 3 diesel engine, and (3) the generator 

ground over current trip function for the Division 1 and 2 diesel generators. Thus, the exemption 

from GDC 17 requirements, as mentioned in Operating License, NPF-29, is not applicable to the 

period of extended operation. The staff informed the applicant that it would not need to provide 

an explanation for the exemption granted from 10 CFR 100.11(a)(1) requirements because the 

operating license is clear that the exemption is only in regard to defining the activities that would 

need to be controlled in the plant exclusion areas, as defined in accordance with 

10 CFR 100.3(a) exclusion area provision, and that this exemption was not based on any TLAA 

analysis applicable to the LRA.

The applicant responded to RAI 4.1-5 by letter dated July 3, 2012, relative to the exemption 

granted from 10 CFR Part 50, Appendix J, containment leak rate testing requirements. In its 

response to RAI 4.1-5, part (a), the applicant stated that the exemption, which involves an 

exemption for containment airlock testing, was granted for the term of the operating license as 

described in Supplemental SER No. 7, Section 6.2.6.

The applicant stated that the exemption from the 10 CFR Part 50, Appendix J, testing 

requirements is because of a requirement in paragraph III.D.2(b)(ii) of 10 CFR Part 50, 

Appendix J, that the applicant deemed to be a hardship for the plant. In its response to

RAI 4.1-5, parts (b) and (c), the applicant clarified that the justification provided in support of this 

exemption did not rely on a time-limited analysis or assumption to support the exemption 

acceptance basis, and that based on this fact, the exemption does not need to be identified as 

an exemption that meets 10 CFR 54.21(c)(2) requirements.

Based on the explanation the applicant provided, the staff noted that the referenced exemption 

for the 10 CFR Part 50, Appendix J, containment leak rate testing requirements is only based on 

justification that an alternative containment leak rate test would provide an acceptable level of 

quality and safety in lieu of performing the full pressure test of the airlocks. The staff noted that 

the basis for the exemption does not rely upon any TLAA that has been included in the LRA. 

Thus, based on this review, the staff finds that the applicant has provided an acceptable basis 

that demonstrates that the exemption from 10 CFR Part 50, Appendix J, containment leak rate 

testing requirements in Operating License, NPF-29 do not need to be identified for the LRA in 

accordance with 10 CFR 54.21(c)(2) requirements because the exemption is not based on a 

TLAA. The staff concern in RAI 4.1-5 is resolved.

Based on this review, the staff concludes that the CLB does not include any exemptions that are 

based on a TLAA and that need to be identified for the LRA based on compliance with the 

requirement in 10 CFR 54.21(c)(2).
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4.1.3 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an accurate list of 

TLAAs, as required by 10 CFR 54.21(c)(1). The staff also concludes that the applicant has 

appropriately identified that it has no exemptions granted under the requirements in 

10 CFR 50.12 and that are based on a TLAA, as required by 10 CFR 54.21(c)(2).

4.2 Reactor Vessel Neutron Embrittlement

4.2.1 Reactor Vessel Fluence

4.2.1.1 Summary of Technical Information in the Application

LRA Section 4.2.1 describes the applicant’s analysis for RV high-energy neutron fluence (unit of 

n/cm2 with energies greater than 1 MeV), which involves a time-limited assumption defined by 

the operating term. Based on operating at an EPU power level beginning with Cycle 19, the 

predicted peak high-energy neutron fluence for 54 EFPY is 4.44x1018 n/cm2 (E > 1 MeV) at the 

vessel inner surface. The neutron fluence for the welds and shells of the RV beltline region was 

determined using the General Electric-Hitachi (GEH) method for neutron flux calculation 

documented in report NEDC-32983P-A and approved by the NRC. This method adheres to the 

guidance provided in RG 1.190, “Calculational and Dosimetry Methods for Determining 

Pressure Vessel Neutron Fluence.” Results of the fluence evaluation are shown in LRA 

Table 4.2-1.

In the LRA, the applicant did not disposition the fluence analysis for the RV in accordance with 

10 CFR 54.21(c)(1)(i), 54.21(c)(1)(ii), or 54.21(c)(1)(iii). The staff evaluated the applicant’s 

fluence analysis and TLAA disposition as described below.

4.2.1.2 Staff Evaluation

The staff reviewed the applicant’s fluence analysis for the RV consistent with SRP-LR 

Section 4.2, which indicates that the applicant identifies (a) the neutron fluence for the RV at the 

expiration of the license renewal period, (b) the staff-approved methodology used to determine 

the neutron fluence (or submits the methodology for staff review), and (c) whether the 

methodology follows the guidance in NRC RG 1.190.

LRA Section 4.2.1 addresses the applicant’s RV fluence calculations. LRA Section 4.2.1 states 

that the fluence is calculated based on a time-limited assumption defined by the operating term, 

which indicates that the RV neutron fluence analysis is a TLAA. In contrast, LRA Table 4.1-1, 

“List of GGNS TLAAs and Resolution,” does not identify the neutron fluence calculation as a 

TLAA. In addition, the LRA does not address the applicant’s TLAA disposition of the neutron 

fluence analysis in terms of the dispositions described in 10 CFR 54.21(c)(1)(i), (ii) or (iii).

By letter dated June 27, 2012, the staff issued RAI 4.2.1-1 requesting that the applicant clarify

why LRA Table 4.1-1 does not identify the neutron fluence calculation as a TLAA. The staff also 

requested, in Part (b), that, if the fluence calculation is identified as a TLAA, the applicant 

describe the TLAA disposition of the neutron fluence calculation in terms of the dispositions 

described in 10 CFR 54.21(c)(1)(i), (ii), or (iii). In addition, the staff requested, in Part (b), that 

the applicant revise LRA Section 4.2.1, Table 4.1-1, and Section A.2.1.1 (UFSAR supplement 

for RV fluence) to include a relevant TLAA disposition, consistent with the response.
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In its response dated July 25, 2012, the applicant stated in response to RAI 4.2.1-1, Part (a), 

that the neutron fluence calculation is not a TLAA since, as a stand-alone analysis, it does not 

meet the definition in 10 CFR 54.3(a). The applicant also stated that specifically, a neutron 

fluence calculation does not “consider the effects of aging,” which is the second element of the 

six-element definition of a TLAA in 10 CFR 54.3(a). In addition, the applicant stated, in 

response to RAI 4.2.1-1, Part (b), that, although the neutron fluence calculation does not meet 

the 10 CFR 54.3(a) definition of a TLAA, the calculation is projected to the end of the period of 

extended operation for use in demonstrating that neutron embrittlement analyses have been 

projected to the end of the period of extended operation. The applicant further stated that the 

validity of the neutron embrittlement TLAAs is based on a valid input of neutron fluence at the 

end of the period of extended operation.

In its review, the staff noted that, since the RV neutron fluence analysis considers the accrual of 

neutrons on the RV surface as a function of the reactor operating power level and operating 

time, the neutron fluence analysis considers the effects of aging (i.e., neutron embrittlement of 

the RV). The RV neutron fluence analysis with a time-limited assumption is also integral to the 

neutron embrittlement TLAAs for the RV (e.g., USE analysis and P-T limits analysis). 

Therefore, the staff noted that the RV neutron fluence analysis should be identified as a TLAA 

with an adequate TLAA disposition, as addressed in 10 CFR 54.21(c)(1)(i), (ii) or (iii). By letter 

dated September 14, 2012, the staff issued RAI 4.2.1-1a, Part (a), requesting that the applicant 

identify the RV neutron fluence analysis as a TLAA, based on the fact that the neutron fluence 

analysis considers the accrual of neutrons on the vessel surface as a function of the reactor 

operating power level and is integral to the neutron embrittlement TLAAs for the RV, or provide 

justification for why the analysis is not a TLAA. RAI 4.2.1-1a, Part (b), requested that the 

applicant describe its disposition of the neutron fluence TLAA and revise appropriate LRA 

sections as necessary.

The applicant responded to RAI 4.2.1-1a in its letter dated October 15, 2012. In its response, 

the applicant stated in response to RAI 4.2.1-1a, Part (a), that the effects of aging due to 

neutron fluence are considered in the neutron embrittlement TLAAs (e.g., USE analysis and P-T 

limits analysis). The applicant also stated that in response to RAI 4.2.1-1a, the RV neutron 

fluence analysis shall be treated as a TLAA. In addition, the applicant's response to 

RAI 4.2.1-1a, Part (b), dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(ii), which 

indicates that the neutron fluence TLAA has been projected to the end of the period of extended 

operation. In its response, the applicant also revised LRA Section 4.2.1, Table 4.1-1, and 

Section A.2.1.1 (UFSAR supplement) to appropriately reflect the TLAA disposition, consistent 

with its response. In its review, the staff finds this portion of the applicant’s response to 

RAI 4.2.1-1a acceptable, because the applicant identified the RV neutron fluence calculations 

as a TLAA with a relevant disposition and revised the LRA, consistent with its response to 

RAI 4.2.1-1a. Based on this review, the staff finds the issues related to RAIs 4.2.1-1 and 

4.2.1-1a resolved. The staff’s review related to the applicant’s TLAA is further described below.

LRA Section 4.2.1 addresses the peak neutron fluence values (energy greater than 1 MeV) for 

54 EFPYs based on planned EPU power level beginning with Cycle 19. The predicted peak 

neutron fluence value is 4.44x1018 n/cm2 at the vessel inner surface of the lower-intermediate 

shell and axial welds (i.e., Shell Plate 2 location). The LRA also states that the neutron fluence 

for the RV beltline region was determined using the GEH method for neutron flux calculation 

documented in report NEDC-32983P-A and approved by the NRC. The LRA further states that 

the GEH method adheres to the guidance provided in RG 1.190.
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During the AMP audit, held during the week of January 23, 2012, the staff noted that 

Reference 1, which is addressed below, describes the GEH method for the applicant’s fluence 

calculations. Reference 1 also refers to Reference 2, which describes another fluence 

calculation method (MPM method) that the applicant used:

• Reference 1: GEH, Project Task Report, 0000-0104-5984-RO, Revision 0, “Entergy 

Operations, Inc., Grand Gulf Nuclear Station Extended Power Uprate,” Task T0313, 

RPV Flux Evaluation, October 2009

• Reference 2: MPM-809633, “Grand Gulf Extended Power Uprate Neutron Transport 

Analysis,” August 2009

In addition, the GEH report referenced above indicates the following information:

• The total fluence values at different EFPYs were calculated by adding the corresponding 

post-EPU fluence to the pre-EPU fluence. The post-EPU fluence and total fluence 

values are calculated and reported in the GEH report, while the MPM-809633 report 

calculated the pre-EPU fluence.

• Section 3.4.2, “Observations,” of the GEH report indicates that the calculated post-EPU 

flux values for core shroud welds H1, V1, V2, V3, and V4 were found to be significantly 

lower than the pre-EPU flux values derived from MPM-809633. This section also states 

that, because the pre-EPU flux values were not calculated by GEH, the reason for this 

large difference at these locations is unknown.

Based on the information described above, the staff noted the following issues related to the 

applicant’s fluence analysis:

• LRA Sections 4.2.1 and A.2.1.1 (UFSAR supplement for RV fluence) do not identify the 

methodology described in MPM-809633 as one of the methods used to calculate the 

neutron fluence. In addition, it is not clear which fluence calculation methods are 

included in the CLB.

• The LRA does not provide information on the variance between the post-EPU flux values 

for shroud welds H1, V1, V2, V3, and V4 based on the GEH methodology and the 

pre-EPU flux values derived from MPM-809633. It is not clear as to why the post-EPU 

flux values, which are significantly lower than the pre-EPU flux values, are acceptable.

• The LRA does not provide information to confirm how the fluence calculation methods of 

the applicant comply with RG 1.190.

• The LRA does not describe the results of the measurement benchmarking of the fluence 

calculation methods with the plant-specific dosimetry data (e.g., the first-cycle or test 

capsule dosimetry data) as addressed in BWRVIP-86, Revision 1, Section 5.4, “Plan for 

Ongoing Vessel Dosimetry.” It is noted that the staff issued its SE for BWRVIP-86, 

Revision 1, by letter dated October 20, 2011.

By letter dated June 27, 2012, the staff issued RAI 4.2.1-2 requesting that the applicant:

• Part (a) - Justify why LRA Sections 4.2.1 and A.2.1.1 do not identify the methodology 

described in MPM-809633 as one of the methods that has been used to calculate and 

project the RV neutron fluence. Alternatively, revise LRA Sections 4.2.1 and A.2.1.1 to 

identify and include the MPM method in the LRA, as appropriate.
4-28

• Part (b) - As part of the response, clarify what methods for fluence calculations are 

included in the CLB. If the LRA does not identify all the fluence calculation methods that 

constitute the CLB, justify why the LRA does not identify all of them.

• Part (c) - Provide additional information on how the fluence calculation methods have 

been incorporated into the CLB (e.g., whether through 10 CFR 50.90 or 10 CFR 50.59 

process). As part of the response, provide information to demonstrate that such 

methods are consistent with RG 1.190.

• Part (d) - Provide the following information related to the flux and fluence calculations:

− Part (d.1) - Provide the pre-EPU (MPM method) and post-EPU (GEH method) flux 

values for core shroud welds H1, V1, V2, V3, and V4. If existent, describe any other 

location that involves the higher flux differences between the two calculation 

methods than these five core shroud welds and provide the associated flux values.

− Part (d.2) - Clarify why the post-EPU flux values (GEH method), which are 

significantly lower than the pre-EPU flux values (MPM method), are acceptable in 

terms of the adequacy of the fluence calculations and the compatibility between the 

fluence calculation methods.

− Part (d.3) - Provide the pre-EPU (MPM method) and post-EPU (GEH method) peak 

flux values for the inner surfaces of Shell Plates 1 and 2 at the cycle when the EPU 

is planned to start. If any significant difference exists between these flux values for 

either of the shell plates, justify why the significant difference is acceptable.

− Part (d.4) - If pre-EPU fluence values obtained using the MPM method were 

combined with post-EPU fluence values obtained using the GEH method to 

determine total, post-EPU and end-of-life-extended fluence values, please describe 

the treatment of uncertainty associated with this technique, and explain how it 

conforms to the guidance contained in RG 1.190. If the neutron fluence values were 

combined, and the uncertainty treatment is not believed to adhere to RG 1.190, 

please justify the acceptability of this approach.

• Part (e) - Provide additional information to confirm whether the fluence calculation 

methods have been benchmarked with the ongoing vessel dosimetry, consistent with 

Section 5.4 of BWRVIP-86, Revision 1. In addition, provide information to confirm 

whether the fluence calculations using the implemented methods are consistent with the 

vessel dosimetry data.

The applicant responded to RAI 4.2.1-2 in letter dated July 25, 2012. In its response to 

RAI 4.2.1-2, Part (a), the applicant stated that RV neutron fluence for EPU operating conditions, 

through the period of extended operation, is calculated in accordance with Licensing Topical 

Report, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux 

Evaluation,” NEDC-32983P-A, Revision 2, January 2006. The applicant also stated that 

pre-EPU fluence values were generated from the MPM Technologies, Inc. (MPM) analysis and 

the MPM analysis is consistent with the guidance contained in RG 1.190. The applicant further 

stated that the MPM method was approved by the NRC in its approval of a P-T limits LAR for 

the Nine Mile Point Unit 1 station (i.e., staff’s SE for “Nine Mile Point Nuclear Station, Unit 

No.1−Issuance of Amendment RE: Pressure-Temperature Limit Curves and Tables (TAC 

No. MB6687),” dated October 27, 2003). The applicant stated that this method is also 

described in UFSAR Section 4.3.2.8.
4-29

In its response to RAI 4.2.1-2, Part (b), the applicant also explained that the two fluence 

calculation methods included in the CLB are (1) the post-EPU GEH method which is reviewed 

and approved by the NRC in a SE (November 17, 2005) referenced in “General Electric 

Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation, NEDC-32983P-A, 

Rev. 2” (January 2006), and (2) the pre-EPU MPM method, as approved by the NRC and 

described in UFSAR Section 4.3.2.8. In addition, the applicant provided revisions to LRA 

Sections 4.2.1 and A.2.1.1 to identify and include the MPM method as a fluence calculation 

method, consistent with the applicant’s response.

In its response to RAI 4.2.1-2, Part (c), the applicant further addressed how the fluence 

calculation methods have been incorporated into the CLB. The applicant stated that the postEPU GEH fluence method was incorporated into the CLB through the 10 CFR 50.90 process 

during EPU license amendment approval and is consistent with RG 1.190, as described in 

NEDC-32983P-A, Revision 2. The applicant stated that the pre-EPU MPM fluence method was 

incorporated into the CLB through the 10 CFR 50.59 process and is also consistent with 

RG 1.190, as described in UFSAR Section 4.3.2.8.

In its response to RAI 4.2.1-2, Part (d.1), the applicant provided the pre-EPU and post-EPU flux 

values for the H1, V1, V2, V3, and V4 welds. The pre-EPU and post-EPU flux values for the H1 

weld are 1.04x1010 n/cm2

-s and 1.23x107 n/cm2-s, respectively. The staff noted that the 

pre EPU and post-EPU flux values for the H1 weld are in good agreement with the pre-EPU and 

post-EPU flux values for the other welds (V1 through V4), respectively. The neutron flux values 

for these welds indicate a common characteristic that the pre-EPU flux value is greater than the

post-EPU flux value by approximately three orders of magnitude. The staff’s evaluation of this 

item is further described below in conjunction with RAI 4.2.1-2a.

The applicant also provided the following information regarding the flux and fluence calculations.

• In its response to RAI 4.2.1-2, Part (d.1), the applicant further stated that welds H1, V1, 

V2, V3, and V4 are welds on the top guide that sits above the core shroud. None of the 

locations evaluated in the post-EPU GEH fluence evaluation except for H1, V1, V2, V3, 

and V4 were found to have flux values lower than pre-EPU flux values. The apparent 

discrepancy between the pre-EPU flux values and the post-EPU flux values has been 

entered into the applicant’s corrective action program (CAP).

• In its response to RAI 4.2.1-2, Part (d.2), the applicant stated that the pre-EPU values 

appear overly conservative, as they are associated with a location that is approximately 

45 inches above the top of the active fuel, where flux values are expected to be lower 

than values at the top of the active fuel. Even considering the apparently conservative 

flux values, the resulting fluence at this location is significantly less than the peak fluence 

on the core shroud welds.

• In its response to RAI 4.2.1-2, Part (d.3), the applicant stated that the pre-EPU (MPM 

method) peak flux for the RV inner surface is 1.71x109 n/cm2

-s. In comparison, the 

post-EPU (GEH method) peak flux for the RV inner surface is 2.90x109 n/cm2

-s. The 

ratio of post-EPU to pre-EPU peak RV inner diameter flux is 1.69. Some of the increase 

in flux level is due to the 15 percent thermal power increase from power uprate, and 

additional causes include higher power in peripheral bundles due to EPU operating 

conditions.

• In its response to RAI 4.2.1-2, Part (d.4), the applicant stated that the position in 

RG 1.190 recommends that flux uncertainties be determined to provide confidence in 

fluence calculations. Total uncertainty values for RV and RVI flux for both pre-EPU and 
4-30

post-EPU operating conditions are included in the respective fluence calculations. No 

specific guidance is provided in RG 1.190 regarding the combination of fluence results 

from multiple methods. Since both pre-EPU and post-EPU fluence values are the 

results of qualified methods (MPM and GEH methods), it is expected that the 

combination of these values is acceptable with respect to the uncertainty treatment 

specifications of RG 1.190.

In its response to RAI 4.2.1-2, Part (e), the applicant stated that, in accordance with paragraph 3 

of Section 5.4 of BWRVIP-86, Revision 1, the post-EPU fluence calculations were performed for 

the applicant’s RV using a methodology that was benchmarked against the RV dosimetry 

results from other BWRs, in accordance with the BWRVIP Integrated Surveillance Program 

(ISP).

In its review, the staff noted that the applicant explained that each of the fluence calculation 

methods (MPM and GEH methods) was approved by the NRC and the applicant incorporated 

each method into its current licensing basis through adequate processes. The staff also noted 

that measurement benchmarks were conducted on the MPM method and GEH method, as 

addressed in the NRC SEs dated October 27, 2003, and November 17, 2005, respectively. The 

staff found this portion of the applicant’s response acceptable, based on the applicant’s 

clarification.

However, the staff identified the following items that needed additional information. The staff 

noted that it was not clear whether the welds H1, V1, V2, V3, and V4 are core shroud welds in 

the top portion of the shroud cylindrical shells, as indicated in BWRVIP-02-A, or welds in the top 

guide as indicated in the applicant’s response. The staff also noted that it was not clear whether 

adequate corrective actions were taken for the fluence calculations on the welds H1, V1, V2, 

V3, and V4 so that the applicant’s corrective actions resolved the significant difference between 

the pre-EPU and post-EPU fast neutron flux values of these welds. The staff further noted that 

the 60-year fast neutron fluence (9.04x1018 n/cm2

) of the core spray spargers is less than the 

40-year fast neutron fluence (1.50x1021 n/cm2

) by approximately two orders of magnitude 

(applicant’s letter dated July 25, 2012, which addresses the response to RAI 4.7.3-1 regarding 

RVI). Given that the welds H1, V1, V2, V3, and V4 have post-EPU neutron flux significantly less 

than the pre-EPU neutron flux, the staff needed pre-EPU and post-EPU flux values for other RV

locations for additional comparisons.

In addition, the staff noted that RG 1.190, “Calculational and Dosimetry Methods for 

Determining Pressure Vessel Neutron Fluence,” Regulatory Position 1.4.1, provides guidance 

for analytic uncertainty analysis to support methodology qualification and uncertainty estimates 

(including combination of uncertainties). However, the applicant's response, addressing an 

expectation of acceptability, does not provide adequate information to determine how the new 

calculational method, which is based on adding the fluence values from the two different 

calculational methods together, adheres to the guidance contained in RG 1.190.

Therefore, the staff issued RAI 4.2.1-2a by letter dated September 14, 2012, requesting, in 

RAI 4.2.1-2a, Part (a), that the applicant clarify whether the welds H1, V1, V2, V3, and V4 are 

core shroud welds in the top portion of the shroud cylindrical shells. The staff requested in 

RAI 4.2.1-2a, Part (b), that the applicant clarify whether adequate corrective actions were taken 

for the fluence calculations on the welds H1, V1, V2, V3, and V4 to resolve the significant 

difference between the pre-EPU and post-EPU fast neutron flux values of these welds. The 

staff further requested in RAI 4.2.1-2a, Part (c), that the applicant resolve the issues that the 

60-year fast fluence of the core spray sparger, core shroud dome, and core shroud head stud 
4-31

components are less than their 40-year fast fluence, in order to confirm there is no concern 

related to the adequacy of RV fluence calculations. In addition, the staff requested in 

RAI 4.2.1-2a, Part (d), that the applicant provide the pre-EPU and post-EPU flux values for the 

RV locations listed in LRA Table 4.2-2 to confirm that the post-EPU neutron flux values of the 

RV plates, welds, and nozzles are greater than the pre-EPU neutron flux values. The staff 

requested in RAI 4.2.1-2a, Part (e), that the applicant provide its criteria in terms of the 

difference between the pre-EPU and post-EPU neutron flux values to initiate a corrective action 

for the RV and RVI neutron fluence analysis. The staff also requested in RAI 4.2.1-2a, Part (f), 

that the applicant demonstrate that the combined calculational uncertainty associated with both 

fluence methodologies remains within RG 1.190 guidance, or provide an alternative justification 

for the acceptability of this method that demonstrates that it satisfies the regulations discussed 

in the introduction section of RG 1.190.

The applicant responded to RAI 4.2.1-2a in its letter dated October 15, 2012. In its response to 

RAI 4.2.1-2a, Part (a), the applicant acknowledged that H1, V1, V2, V3, and V4 are unique 

identifiers of the welds at the top portion of the core shroud cylindrical shell, as shown in 

Figure 3-9 of BWRVIP-02-A. In its response to RAI 4.2.1-2a, Part (b), the applicant stated that 

the location of weld H1 is well above the top of the active fuel and V1 through V4 welds are 

physically located above the H1 weld. The applicant stated that, therefore, the fast flux drops 

off dramatically above the top of the active fuel and the MPM approach used a bounding flux at 

these high shroud locations. The applicant further stated that this conservative assumption 

provided acceptable results, since these are nonlimiting shroud locations. In addition, the 

applicant stated that, even with this conservative assumption, the H1 fluence remained below 

the inspection threshold of 5x1020 n/cm2 at 54 EFPY and this does not represent an error in the 

MPM evaluation or require any correction.

In its response to RAI 4.2.1-2a, Part (c), the applicant stated that errors were found in the 

40-year fluence values for the RVI orificed fuel support, CS sparger, core shroud dome, and 

core shroud head stud components reported in its response to RAI 4.7.3-1. The applicant 

further provided the corrections to the fluence values and clarified that, with the corrected 

values, the 60-year fluence values are greater than the 40-year fluence values for these 

components. As part of its response, the applicant explained that the correct 40-year and 

60-year fluence values for the core spray sparger are 5.73x1018 n/cm2 and 9.04x1018 n/cm2

, 

respectively. In comparison, the staff noted that the applicant’s previous letter dated 

July 25, 2012, provided an incorrect 40-year fluence value of 1.50x1021 n/cm2

.

In its response to RAI 4.2.1-2a, Part (d), the applicant provided and compared the pre-EPU and 

post-EPU peak neutron flux values at various RV locations, including the fast neutron peak flux 

values for RV beltline lower-intermediate shell and axial welds, N12 nozzles, circumferential 

weld AB, and lower shell/axial welds. The staff noted that the applicant’s comparisons 

confirmed that the post-EPU flux values are reasonably greater than the pre-EPU flux levels for 

the RV beltline locations.

In its response to RAI 4.2.1-2a, Part (e), the applicant stated that there are no predefined values 

for differences between pre-EPU and post-EPU neutron flux that are used as a threshold for 

entry into the CAP. The applicant further explained that the reason corrective action was 

initiated for the H1, V1, V2, V3, and V4 welds was that pre-EPU flux was higher than post-EPU 

flux only for these welds and the fluence values at these weld locations remain below the weld 

inspection threshold of 5x1020 n/cm2 even at 54 EFPY using the MPM method.
4-32

In its response to RAI 4.2.1-2a, Part (f), the applicant stated that it was not possible to prove the 

independence of all uncertainty terms used in the calculations of both fluence methods. In its 

response, the applicant used relative uncertainties for deriving the uncertainties for the 

fluence methods.

However, the staff identified concerns related to the applicant’s response as follows. 

Specifically, the staff noted that, in its response to RAI 4.2.1-2a, Part (b), the applicant stated 

that the MPM method used a bounding flux value for the core shroud welds that are located at 

the top of the core shroud shell. However, the staff noted that the applicant did not provide 

specific information to justify why the flux values obtained from the MPM method are boundingcase flux values for these core shroud weld locations.

As discussed above, the staff also noted that, in its response to RAI 4.2.1-2a, Part (f), the 

applicant used relative uncertainties for deriving the uncertainties for the fluence methods. The 

staff further noted that the total uncertainty is expressed as a “relative uncertainty” combination, 

which is, in actuality, a weighted average of the uncertainties associated with both methods. 

However, the staff noted that the applicant’s uncertainty analysis was not consistent with 

RG 1.190, and the errors associated with both fluence calculation methods are expected to 

propagate when the two fluence calculational methods are combined.

To address these concerns, the staff issued RAI 4.2.1-2b by letter dated November 20, 2012, 

requesting, in Part (a), that the applicant provide additional information to clarify why the flux 

values obtained from the MPM method are considered to represent bounding-case flux values 

for the core shroud weld locations. The staff also requested that the applicant clarify which 

locations are actually associated with the bounding-case flux values and why the bounding-case 

flux values were considered to include sufficient conservatisms for these RVI core shroud 

welds. In RAI 4.2.1-2b, Part (b), the staff requested that the applicant provide an analytic 

uncertainty analysis for the combined fluence values, consistent with the regulatory position in 

RG 1.190, or alternatively, the applicant provide RV neutron fluence values that were calculated 

using a single, NRC-approved method that has a valid and accepted analytic uncertainty 

analysis. This issue was identified as Open Item 4.2.1-1 in the SER with Open Items.

In its response dated January 18, 2013, the applicant addressed RAI 4.2.1-2b, Part (a) by 

stating that the variation of modeling between the two methods (i.e., GEH and MPM methods) 

resulted in significantly higher flux values for welds H1, V1, V2, V3, and V4 using the MPM 

method. The applicant also stated that possible contributing factors to the differing results 

include void fraction assumptions above the active fuel, upper-guide structure modeling, and 

water-column height in the area between the fuel and the shroud. The applicant further stated 

that, as the staff comments on BWRVIP-145-A indicate, there is significant difficulty in using the 

conventional discrete ordinates method in calculating fluence values for components away from 

the middle plane of the core.

In addition, the applicant stated that the shroud welds (H1, V1, V2, V3, and V4 welds) are the 

only welds in the vessel or shroud where pre-EPU neutron flux values were higher than 

post-EPU neutron flux values. The applicant stated that the most important top guide locations 

for considering the effects of fluence are areas at the lower elevations of the top guide, where 

the highest neutron flux and fluence occur near the center of the core. The applicant also 

indicated that the BWRVIP has determined that the top guide is susceptible to IASCC, since the 

fluence on the top guide exceeds the screening threshold of 5x1020 n/cm2 for the period of 

extended operation. The applicant further stated that both the MPM and GEH models indicate 

that the neutron fluence on the top guide exceeds the IASCC threshold and that the applicant 
4-33

follows the inspection and evaluation guidelines that are described in BWRVIP-26-A in order to 

manage IASCC for the top guide.

In its response to RAI 4.2.1-2b, Part (b), the applicant discussed the summation of pre-EPU and 

post-EPU peak fluence values from two different fluence methods and associated uncertainty 

calculations, as follows. The applicant indicated that it determined the 54-EFPY fluence by 

adding the MPM pre-EPU fluence for 22.99 EFPY and the GEH post-EPU fluence for the 

remaining 31.01 EFPY. The applicant also indicated that the neutron fluence values associated 

with the maximum uncertainties for the MPM pre-EPU and the GEH post-EPU calculational 

basis are as follows:

• MPM pre-EPU peak fluence with 16 percent uncertainty: 1.32x1018 ± 2.11x1017n/cm2

• GEH post-EPU peak fluence with 19 percent uncertainty: 3.12x1018 ± 5.92x1017 n/cm2

The applicant further stated that both uncertainty values are reported as relative (percentage) 

and that absolute uncertainty may be determined by combining an absolute calculated fluence

value with its associated relative uncertainty. The applicant indicated that the relative 

uncertainty of the combined total fluence is calculated by using the root-sum-of-squares 

(i.e., √((2.11x1017)

2

+(5.92x1017)

2

) = 6.29 x1017). The applicant also indicated that it determined 

the absolute uncertainty by dividing the root-sum-squares by the absolute total fluence value, 

such as, 6.29 x1017/(1.32x1018 + 3.12x1018) = 14.17 percent.

In its response, the applicant also stated that the independence of all uncertainty terms between 

the two fluence methods cannot be proven, as it is known that both fluence analyses involve a 

2D flux synthesis and discrete ordinates transport calculation using the same DORT code. The 

applicant further stated that, given that independence of all uncertainty terms cannot be proven, 

a conservative approach may be adopted and the provisional error propagation technique for 

uncertainties in sums of direct measurements may be used, where, in adding quantities, the 

uncertainties in those quantities are simply added as well. In addition, the applicant indicated 

that the maximum total uncertainty is calculated by this method as follows: 

(2.11x1017 + 5.92x1017)/(1.32x1018 + 3.12x1018) = 18.11 percent.

The applicant stated, as the staff indicated in the issue discussion of RAI 4.2.1-2b, the

uncertainty associated with adding the two fluence values together should be higher than either 

as a stand-alone calculation. However, the applicant stated that, since the total combined

fluence is also higher than the fluence from the individual stand-alone calculations, the relative 

uncertainty for the total of fluence is between the relative uncertainty of the individual

calculations.

The staff also noted that, since the method used to perform the MPM fluence calculations is not 

documented in an NRC-approved methodology, a detailed description of the calculative 

methods, and their qualification, as both pertain to GGNS, must be submitted for NRC staff 

review and approval for referencing in the LRA. This information will enable the staff to reach a 

determination regarding whether the MPM fluence calculations are adherent to RG 1.190, or are 

otherwise acceptable. Similarly, the staff has determined that the applicability of the GEH 

fluence methodology to GGNS should also be established. This effort may include 

plant-specific dosimetry comparisons, or establishing that the existing qualification contained in 

NEDC-32983P-A is adequate.

The staff also noted that the use of a combined method (using fluence from two separate 

methods) requires an additional analytic uncertainty analysis and an extensive amount of further 
4-34

validation and verification. Since the staff is not aware of any such combined method being 

approved in the past, such a proposal would require significant review to determine whether this 

approach could be found to comply acceptably with NRC guidance or not. For example, any 

codependent terms in the uncertainty associated with either method must be appropriately 

treated in the analysis, and any uncertainties associated with either method that could 

propagate must be evaluated. The staff further noted that the significant difference in neutron 

flux values associated with each method (limiting location flux values differ by approximately 

70 percent) warrants an additional evaluation of the causes, and GGNS would need to provide 

extensive justification.

In addition, the staff noted that the applicant’s response did not clearly address why the 

modeling variation between the MPM and GEH methods resulted in the MPM method yielding 

conservative bounding-case flux values for core shroud welds H1, V1, V2, V3, and V4.

By letter dated August 28, 2013, the staff issued RAI 4.2.1-2c requesting additional information 

to resolve the issues discussed above. In RAI 4.2.1-2c, the staff requested additional 

information, as follows:

• Part 1(a): Provide a detailed description of the MPM fluence calculations and their 

results, including the methods and data sets used to perform the calculations, the 

analytic representation of the reactor geometry, and the problem setup, execution, and 

post-processing.

• Part 1(b): Provide a description of the qualification of the MPM fluence calculational 

methods in sufficient detail to establish adherence to RG 1.190 as it applies to the 

BWR/6 design and GGNS, in particular, or sufficient details to demonstrate to the staff 

that the calculations are otherwise acceptable for use at GGNS.

• Part 1(c): Provide information to demonstrate that the GEH analytic method is suitably 

qualified for analysis of the GGNS RV.

• Part 1(d): Provide a detailed, analytic uncertainty analysis that accounts for any 

additional uncertainty or bias associated with adding fluence values together from these 

two methods (MPM and GEH methods), and benchmarking information to show that the 

results of the vessel fluence analyses remain valid when combined.

• Part 1(e): Provide information to establish that the difference between the two flux 

values calculated using the different methods is valid. For example, compare the two 

methods in calculational benchmarks; provide an estimate of the pre-EPU fluence using 

GEH calculational method; and provide an estimate of the post-EPU fluence using MPM 

calculational method)

• Part 2: Provide a description, including a technical basis, for each of the different 

calculational methods that are used to determine the fluence values of the RVI. For 

each of the RVI components, describe the fluence calculational method used for the 

component. In addition, explain why the use of different calculational methods is 

adequate to determine the fluence values of the RVI.

• Part 3: Justify the acceptability of using different methods to calculate related 

phenomena (e.g., neutron fluence) that all stem from the same source (e.g., the GGNS 

reactor core), for different surfaces (i.e., nozzles, beltline welds, vessel surface, and 

upper internals), as opposed to choosing one method to apply to all the surfaces.

• Part 4: Clarify why the modeling variation between the MPM and GEH methods results 

in conservative bounding-case flux values for the core shroud weld locations (H1, V1, 
4-35

V2, V3, and V4) using the MPM method. As part of the response, the applicant should 

clarify whether the MPM or GEH method approximates the region above the reactor core 

as water, without explicitly modeling the stainless steel top guide.

• Part 5(a)(i): If the method is NRC-approved insofar as it applies to vessel fluence

calculations, the applicant should provide the reference to the staff-accepted 

methodology.

• Part 5(a)(ii): If the method is not NRC-approved, the applicant provide the plant-specific 

calculations and documentation, and include sufficient information, to enable the NRC 

staff to determine whether the calculation adheres to RG 1.190, or other justification, as 

required to establish that the applicant’s fluence calculation is acceptable.

• Part 5(a)(iii): The applicant’s response regarding Part 5(a)(i) and 5(a)(ii) should be 

consistent with Regulatory Position 3, “Reporting,” for the specific documentation 

required to establish adherence to RG 1.190.

• Part 5(b): The applicant should confirm whether, and describe how, the remaining 

neutron fluence-related TLAAs are affected by this new fluence calculation.

The staff issued RAI 4.2.1-2c with the expectation that the applicant would either respond to the 

requests in Parts 1-3 of RAI 4.2.1-2c, or, alternatively, to the requests in Part 5(a) of the RAI, 

which would apply if the applicant is using the option to apply a single neutron fluence 

methodology for the TLAA basis. The applicant was also to provide its response to the requests 

in Parts 4 and 5(b) of the RAI.

In its letter dated September 23, 2013, the applicant responded to RAI 4.2.1-2c and indicated 

that it would respond to Part 5 of RAI 4.2.1-2c, in lieu of providing responses to parts1–3 of the 

RAI. The applicant further indicated that the supplemental response to part 5 of RAI 4.2.1-2c 

would be submitted within 7 to 9 months from the date of the letter providing the response to 

RAI 4.2.1-2c.

The applicant also responded to RAI 4.2.1-2c, Part 4, in the letter of September 23, 2013. In its 

response, the applicant stated that the MPM method specifically includes modeling of the 

stainless steel top guide using a mixture that includes Inconel or stainless steel in addition to 

Zircaloy, depending on the fuel type. The applicant also stated that, above the top guide, the 

steam exiting the reactor is also modeled to provide a conservative bounding-case flux value for 

the upper welds on the core shroud.

In comparison, the applicant stated that the GEH method also considers the stainless steel top 

guide. The applicant stated the difference between the methods is in GEH’s modeling of the 

area above the top guide. The applicant also stated that GEH originally modeled this area with 

steam and stainless steel that extended up to the H1 weld. The applicant further explained that 

an updated GEH evaluation without the stainless steel above the top guide resulted in higher 

flux values at the H1, V1, V2, V3, and V4 welds that are more consistent with those predicted by 

the MPM method when adjusted for the EPU power level.

In its review, the staff finds the applicant’s response to RAI 4.2.1-2c, Part 4, acceptable,

because (1) the applicant clarified that the difference in fluence values at the upper welds of the 

core shroud resulted from the difference in modeling for the area above the top guide between 

the MPM and GEH methods, and (2) the applicant confirmed that the updated GEH fluence 

values, based on the modeling without unnecessary stainless steel material above the top 
4-36

guide, are consistent with the MPM fluence values for these welds when adjusted for the EPU. 

The staff’s concern described in RAI 4.2.1-2c, Part 4, is resolved.

In its subsequent letter dated May 14, 2015, the applicant updated the status of the response to 

Part 5 of RAI 4.2.1-2c. The applicant indicated that GGNS submitted an LAR to the NRC staff 

to adopt the MPM method of calculating RV neutron fluence values as a single fluence method 

in accordance with RG 1.190. The applicant also indicated the LAR is documented in Entergy 

letter, GNRO-2014/00080, dated November 21, 2014. The applicant further indicated that NRC 

staff’s review of the LAR is in progress and that, once the MPM method is approved as a single

fluence methodology for CLB, it will submit information that was requested in Part 5 of 

RAI 4.2.1-2c.

By letter dated September 1, 2015, the applicant supplemented their response to RAI 4.2.1-2c, 

Part 5(a), stating that the MPM method of calculating RV neutron fluence at GGNS was NRC

approved on August 18, 2015, and that Amendment No. 204 to License No. NPF-29 was issued 

on August 18, 2015 (ADAMS Accession No. ML15229A218). The applicant also indicated that, 

because the fluence calculation method is approved by the NRC, it provided the reference 

(i.e., August 18, 2015, letter of the NRC) to the staff-approved MPM method in accordance with 

option (i) of RAI 4.2.1-2c part 5(a).

The staff noted that, on August 18, 2015, the staff issued a license amendment and safety 

evaluation (SE) approving the use of the MPM method as a single fluence calculational method 

that incorporated the method into the CLB of GGNS. The NRC SE verified that the method 

adheres to the recommended fluence methodology criteria in RG 1.190. As part of the 

verification, the SE confirmed that a dosimetry benchmark calculation for GGNS Cycle 1 was in 

excellent agreement with the dosimetry measurements.

In its review, the staff finds that the applicant’s response to RAI 4.2.1-2c, Part 5(a) is

acceptable, because (1) the applicant provided the relevant reference to the staff-approved 

single fluence method (i.e., MPM method) that was approved in the staff’s August 18, 2015, SE,

(2) the approved method, consistent with RG 1.190, was incorporated into the CLB by License 

Amendment No. 204, and (3) the additional actions of the applicant, which are specified in the 

staff’s August 18, 2015, SE, will ensure adequate qualification of the fluence method for the 

locations outside the original beltline region (e.g., comparison of fluence calculations with 

dosimetry measurements at core shroud locations above the active core region). The concern 

described in Part 5(a) of RAI 4.2.1-2c is resolved. The staff finds that this approved license 

amendment resolves the concerns described in RAI 4.2.1-2, Parts (a), (b), and (c).

By the letter dated July 29, 2015, the applicant also addressed its response to Part 5(b) of 

RAI 4.2.1-2c. In its response, the applicant provided revisions to the RV neutron embrittlement 

TLAAs described in LRA Section 4.2. These revisions are based on the revised 54-EFPY 

fluence values that were calculated by using the staff-approved MPM method. In its response, 

the applicant also revised the UFSAR supplement for the neutron embrittlement TLAAs to be 

consistent with the revisions to these TLAAs.

In its revision to LRA Section 4.2.1 for neutron fluence, the applicant explained that the RV

neutron fluence is calculated by using the staff-approved MPM method. The applicant also 

indicated that the projected peak RV fluence (E > 1 MeV) for 54 EFPY is revised from 4.44x1018

n/cm2 to 4.02x1018 n/cm2 (approximately 9.5 percent decrease). The applicant further indicated 

that the revised 54-EFPY fluence values extend the RV beltline region that is exposed to the 
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fluence level exceeding 1x1017 n/cm2. The applicant identified the following components as 

additional RV beltline components with neutron fluence exceeding 1x1017 n/cm2 for 54 EFPY:

• Upper intermediate shell (Shell Ring 3) and its associated axial welds and 

circumferential weld (Weld AC)

• N6 LPCI nozzles

The staff considered these additional beltline materials in its evaluation of the applicant’s 

disposition of TLAAs in the remaining subsections of SER Section 4.2.

Furthermore, the applicant revised LRA Section A.2.1.1 (UFSAR supplement) for the neutron 

fluence TLAA, consistent with the applicant’s response.

In its review, the staff finds that the applicant’s response to RAI 4.2.1-2c, Part 5(b) acceptable 

because (1) the applicant adequately revised LRA Section 4.2.1 to provide the projected RV

fluence for 54 EFPY as calculated by using the staff-approved fluence method, (2) the 

applicant’s revision to the LRA identifies additional beltline components that will have a 54 

EFPY neutron fluence exceeding 1x1017 n/cm2 based on the revised fluence projections, (3) the 

applicant adequately revised the UFSAR supplement for the RV neutron fluence TLAA, and 

(4) the applicant also provided revised neutron embrittlement TLAAs based on the revised 54-

EFPY fluence values. The staff’s evaluations of the other neutron embrittlement TLAAs are 

described in Sections 4.2.2 through 4.2.6 of this SER. The staff’s concern described in 

Part 5(b) of RAI 4.2.1-2c is resolved.

As discussed above, the staff finds that the applicant adequately evaluated the TLAA for the RV

neutron fluence because (1) the applicant adequately identified neutron fluence calculations as 

a neutron embrittlement TLAA, (2) the applicant incorporated the staff-approved fluence method 

into the CLB through the license amendment process, (3) the applicant performed 54-EFPY 

fluence calculations in accordance with the staff-approved method that is consistent with the 

guidance in RG 1.190, and (4) the applicant’s analysis provides neutron fluence projections to 

the end of the period of extended operation (54 EFPY). Open Item 4.2.1-1 is closed.

4.2.1.3 UFSAR Supplement

LRA Section A.2.1.1 provides the UFSAR supplement summarizing the fluence analysis for the 

RV. The staff reviewed LRA Section A.2.1.1 consistent with SRP-LR Section 4.2, which 

indicates that the applicant identifies (a) the neutron fluence at the expiration of the license 

renewal period, (b) the staff-approved methodology used to determine the neutron fluence (or 

submits the methodology for staff review), and (c) whether the methodology follows the 

guidance in RG 1.190.

As previously discussed, in its response dated July 25, 2012, to RAI 4.2.1-1, the applicant 

provided revisions to LRA Sections 4.2.1 and A.2.1.1 (UFSAR supplement) to identify both of 

the MPM and GEH fluence calculation methods as part of the CLB. As part of its response 

dated October 15, 2012, to RAI 4.2.1-1a, the applicant also identified the RV neutron fluence 

calculations as a TLAA and dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(ii). 

In addition, the applicant provided relevant revisions to the UFSAR supplement to include the 

MPM method and TLAA disposition in the UFSAR supplement.

As documented in Section 4.2.1.2 of this SER, the applicant revised LRA Section A.2.1.1 by 

letter dated July 29, 2015, in response to RAI 4.2.1-2c(5)(b), to clarify that the RV neutron 
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fluence analysis is performed by using the staff-approved MPM method. Based on the staff’s 

review of the UFSAR supplement, the staff finds that the applicant provided an adequate 

summary description of the neutron fluence analysis, as required by 10 CFR 54.21(d).

4.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the RV 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).

4.2.2 Pressure-Temperature Limits

4.2.2.1 Summary of Technical Information in the Application

LRA Section 4.2.2, as amended in the applicant’s letter of July 29, 2015, describes the 

applicant’s TLAA for calculating the pressure-temperature limits (P-T) limits that will be needed 

to safely operate the plant during normal and transient operating conditions (including heatups 

and cooldowns) and during pressure testing conditions for the plant. The current P-T limits of 

the applicant are located in a Pressure-Temperature Limits Report (PTLR) that was submitted to 

the NRC staff by letter dated September 8, 2010. The current P-T limits were approved up to 

35 EFPY as part of the recently approved EPU amendment (NRC letter dated July 18, 2012).

The Reactor Vessel Surveillance Program provides data to update the P-T limits. Prior to 

exceeding 35 EFPY, the applicant is required to develop new P-T limits for higher fluence 

values in accordance with the requirements in Administration Controls Section 5.6.6 of the 

plant’s TS (TS Section 5.6.6).

The applicant dispositioned the TLAA for P-T limits in accordance with 10 CFR 54(c)(1)(iii), that 

the effects of reduction in fracture toughness of the reactor vessel will be adequately managed 

by the Reactor Vessel Surveillance Program and the updates of P-T limits for the period of 

extended operation.

4.2.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the P-T limits and the corresponding disposition of

10 CFR 54.21(c)(1)(iii), consistent with SRP-LR Section 4.2.3.1.3.3, which states that updated 

P-T limits for the period of extended operation must be available prior to entering the period of 

extended operation. SRP-LR Section 4.2.3.1.3.3 also states that the 10 CFR 50.90 process for 

P-T limits located in the limiting condition of operations or the Administrative Controls Process 

for P-T limits that are administratively amended through a PTLR process can be considered 

adequate aging management programs within the scope of 10 CFR 54 21(c)(1)(iii), such that 

P-T limits will be maintained through the period of extended operation.

The staff noted that the applicant is using TS Section 5.6.6 (as approved in Facility License 

Amendment No. 191) and its approved PTLR process as the basis for accepting this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii). This TS section requires that any future updates of the 

P-T limits and the PTLR containing the P-T limits must be done in accordance with the methods 

of analysis in Proprietary General Electric-Hitachi Topical Report (TR) No. NEDC-33178P-A, 

Revision 1, “GE Hitachi Nuclear Energy Methodology for Development of Reactor Pressure 
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Vessel Temperature Curves” (June 2009). The staff noted that TS Section 5.6.6 also requires 

the applicant to provide the PTLR to the NRC upon issuance for each reactor vessel fluence 

period and for any revision or supplement of the PTLR.

The staff noted that the current PTLR and P-T limit curves are valid for operation up to 35 EFPY 

and were approved by the staff on July 18, 2012, in License Amendment No. 91 for the 

applicant’s EPU. Prior to the period of extended operation, the applicant will be required to 

update its P-T limit curves in accordance with the requirements in 10 CFR Part 50, Appendix G, 

and TS Section 5.6.6, including consideration of the additional materials identified with neutron 

fluence exceeding 1x1017 n/cm2 for 54 EFPY. The applicant will submit the PTLR containing the 

updated curves to the NRC for information. The staff noted that the applicant’s implementation 

of the approved methodology in TR NEDC-33178P-A, Revision 1, will ensure that the updated 

P-T limits will include appropriate safety margins on fracture and will incorporate the minimum 

temperature requirements that are specified in 10 CFR Part 50, Appendix G. The staff noted 

that the approved methodology will also ensure that the calculation of the P-T limits will consider 

the impact that increasing fluence induced by plant operations will have on the limiting adjusted 

reference temperature (ART) values used in the P-T limit calculations. The calculations of the 

P-T limits will incorporate plant-specific embrittlement information and surveillance data 

obtained from the applicant’s Reactor Vessel Surveillance Program (i.e., the BWRVIP ISP for 

the facility (see LRA Section B.1.38)).

Based on this review, the staff finds the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of reduction in fracture toughness due to neutron 

embrittlement of the reactor vessel will be adequately managed for the period of extended

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.2.2.1.3.3 because 

the applicant continues to update the P-T limits in accordance with 10 CFR Part 50, 

Appendix G, such that the P-T limits for the period of extended operation will be available prior 

to the period of extended operation in a consistent manner that the current P-T limits were 

approved up to 35 EFPY. The staff’s evaluation of the applicant’s Reactor Vessel Surveillance 

Program is given in Section 3.0.3.1.36 of this SER.

4.2.2.3 UFSAR Supplement

LRA Section A.2.1.2, as amended in the letter of July 29, 2015, provides the UFSAR 

supplement summarizing the applicant’s TLAA for P-T limits. The staff reviewed LRA 

Section A.2.1.2, consistent with SRP-LR Section 4.2.3.2, which states that the reviewer should 

verify that the applicant has provided information to be included in the UFSAR supplement that 

includes a summary description of the evaluation of the TLAA. The SRP-LR also states that 

Table 4.2-1 of the SRP-LR contains examples of acceptable UFSAR supplement information for 

this TLAA and the reviewer verifies that the applicant has provided a UFSAR supplement with 

information equivalent to that in SRP-LR Table 4.2-1.

The staff noted that the UFSAR supplement states that “the P-T limits will continue to be 

updated, as required by 10 CFR Part 50, Appendix G.” However, the requirements in 10 CFR 

Part 50, Appendix G, establish the minimum safety margin and minimum operating temperature 

requirements that must be factored into the calculations of P-T limits and that do not establish 

any criteria on when the updates of P-T limits must be performed in accordance with the CLB. 

Instead, the staff noted that the criteria for performing updates of the P-T limits are established 

in TS Section 5.6.6.
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By letter dated October 28, 2015, the staff issued RAI 4.2.2-1, in which the staff requested 

clarifications on this matter. Specifically, the staff asked the applicant to justify why UFSAR 

Supplement Section A.2.1.2 did not specify that updates of the P-T limits would be performed in 

accordance with the requirements stated in TS Section 5.6.6.

The applicant responded to RAI 4.2.2-1 in a letter dated November 23, 2015. In its response to 

RAI 4.2.2-1, the applicant amended UFSAR Supplement Section A.2.1.2 to indicate that the 

updates of the P-T limits will be performed in accordance with requirements for P-T limits in 

10 CFR Part 50, Appendix G, and in accordance with requirements in TS Section 5.6.6 for 

updating the P-T limits using the applicant’s PTLR process. The applicant also stated that the 

TLAA for the plant P-T limits is acceptable in accordance with 10 CFR 54.21(c)(1)(iii). The staff 

finds the amended version of UFSAR Supplement Section A.2.1.2 to be acceptable because: 

(a) the basis for updating the P-T limits using 10 CFR Part 50, Appendix G, and TS

Section 5.6.6 requirements is consistent with the CLB, and (b) the requirements and bases in 

the CLB for updating the P-T limits provide an acceptable basis for managing loss of fracture 

toughness due to neutron irradiation embrittlement in the ferritic shell, nozzle, and weld 

components of the reactor vessel during the period of extended operation. RAI 4.2.2-1 

is resolved.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.3.2 and is therefore acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA for P-T limits, as required by 10 CFR 54.21(d).

4.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of neutron irradiation 

embrittlement on the intended function of the reactor vessel will be adequately managed by the 

Reactor Vessel Surveillance Program in conjunction with the applicant’s updates of the P-T 

limits during 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).

4.2.3 Upper-Shelf Energy

The regulations in 10 CFR Part 50, Appendix G, provide the Commission’s requirements for 

minimum levels of reactor vessel Charpy USE. The rule requires the Charpy USE values of 

reactor vessel components made from ferritic steel materials to be greater than or equal to a 

minimum acceptable value of 50 ft-lb throughout the licensed life of the plant. Owners of plants 

that cannot demonstrate compliance with this acceptance criterion are allowed by the rule to 

submit a supplemental SE (i.e., equivalent margins analysis [EMA]) for NRC approval in order to 

demonstrate that lower values of Charpy USE will provide margins of safety against fracture 

equivalent to those specified and required in Appendix G of the ASME Boiler and Pressure 

Vessel Code, Section XI, Division 1 (ASME Section XI, Appendix G).

4.2.3.1 Summary of Technical Information in the Application

LRA Section 4.2.3, as amended in the applicant’s letter of July 29, 2015, describes the 

applicant’s TLAA for Charpy USE values for the period of extended operation (i.e., through 

54 EFPY of plant operations).
4-41

Charpy USE values for most of the applicant’s reactor vessel materials were determined in 

accordance with RG 1.99, Revision 2, Regulatory Position 1.2, which is applied in cases where 

reactor vessel surveillance data are not available. The exceptions are a plate material with Heat 

No. A1224-1 and a weld material with Heat No. 5P6214B (single and tandem), which are 

included in the BWRVIP ISP. These are the only materials that have credible surveillance data 

for the USE analysis such that Regulatory Position 2.2 of RG 1.99, Revision 2, was used to 

compute the USE values.

In the letter of July 29, 2015, the applicant provided updated USE calculations and values for 

the following types of components located in the beltline regions of the reactor: (a) shell plates 

in Shell Nos. 1, 2, and 3 of the reactor vessel, (b) axial weld components in Shell Nos. 1, 2, 

and 3 of the reactor vessel, (c) circumferential welds AB and AC used as the circumferential 

weld seams for the three reactor vessel beltline shell courses, (d) the N-6 nozzle forging and its 

nozzle-to-vessel weld, and (e) the N-12 nozzle materials and their nozzle to vessel welds. The 

applicant identified that the reactor vessel USE values were limited by the plate material that 

was made from the Heat C2779-1 in Shell Ring No. 3 of the reactor vessel. The applicant 

stated that, since it could not demonstrate that the USE value for this shell plate would remain 

above 50 ft-lb at the end of the period of extended operation, it performed an EMA for the 

component that covers 54 EFPY.

Based on this assessment, the applicant stated that the USE values (as presented in LRA 

Table 4.2-2) demonstrate that all beltline materials remain above the 50 ft-lb criterion in 10 CFR 

Part 50, Appendix G, or they have been demonstrated to have acceptable levels of USE 

through performance of an EMA. The applicant stated that the USE analyses (including the 

EMA for the plate made from Heat C2779-1) have been projected to the end of the period of 

extended operation and are acceptable in accordance with the criterion in 

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

4.2.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the USE values of the reactor vessel materials and 

the corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with SRP-LR 

Section 4.2.3.1.1.2, which states that the documented results of the revised USE analysis based 

on the projected neutron fluence at the end of the period of extended operation are reviewed for 

compliance with 10 CFR Part 50, Appendix G. In its review, the staff confirmed that the 

chemistry and initial USE values provided in LRA Section 4.2.2 are consistent with those 

provided in the recent LAR for a power uprate (approved by the staff on July 18, 2012); 

therefore, the technical information in LRA Section 4.2.2 is consistent with the applicant’s CLB. 

The staff also reviewed the USE values against the requirements of 10 CFR Part 50, 

Appendix G.

The regulations in 10 CFR Part 50, Appendix G, require the USE values of ferritic components 

in the beltline of the reactor vessel to be greater than or equal to 50 ft-lb in the irradiated 

condition throughout the licensed life of the plant. Owners of plants that cannot demonstrate 

compliance with this acceptance criterion are allowed to submit an EMA for NRC approval in 

order to demonstrate that lower values of Charpy USE will provide margins of safety against 

fracture equivalent to those specified and required in Appendix G of the ASME Boiler and 

Pressure Vessel Code, Section XI, Division 1 (ASME Section XI, Appendix G).
4-42

The predicted decrease in USE values due to neutron embrittlement during plant operation 

depends on the type of material (weld or base plate), the amount of copper in the material, and 

the predicted neutron fluence for the material, as described in RG 1.99, Revision 2.

RG 1.99, Revision 2, also addresses two acceptable approaches to project the USE values for 

ferritic steels. In accordance with RG 1.99, Revision 2, Regulatory Position 1.2, the applicant 

may use the curves of percent decrease in USE as a function of the material type, copper 

content, and neutron fluence, which are provided in RG 1.99, Revision 2 (in the absence of 

credible reactor vessel surveillance data). Alternatively, the applicant may determine the 

percent decrease in USE based on the reactor vessel surveillance data if credible surveillance 

data are available, in accordance with RG 1.99, Revision 2, Regulatory Position 2.2. In LRA 

Section 4.2.3, the applicant indicated that plate Heat No. A1224 and weld Heat No. 5P6214 are 

the only materials for which surveillance test data are available and the surveillance data were 

used to determine their USE values.

In its review, the staff confirmed that the applicant determined the USE values of the reactor 

vessel beltline materials, consistent with RG 1.99, Revision 2, with the exception of the following 

item that needed further clarification. It was not clear to the staff how the applicant determined 

the copper content of Shell Plate 1 Heat C2506-1, which had the lowest USE value (58.5 ft-lb) 

listed among the reactor vessel beltline materials. Note 2 of LRA Table 4.2-2 indicates that 

since information is not available for the actual measured copper content for this plate, the 

maximum allowable copper content was obtained from the vessel design specification 

(i.e., copper content of 0.12 percent).

In comparison, RG 1.99, Revision 2, specifically recommends that best estimate compositions 

of the materials be used, which are the mean values of measured composition data for a given 

material. If such best-estimate composition values are not available, upper limiting values given 

in the material specification are acceptable. Conservative estimates of the chemistry (mean 

plus one standard deviation) based on generic data may be used if justification is provided. 

However, the staff noted that RG 1.99, Revision 2, does not specifically address the use of the 

composition data described in a design specification to determine the level of neutron 

embrittlement for reactor vessel materials.

By letter dated June 27, 2012, the staff issued RAI 4.2.3-1 requesting, in Part (a), that the 

applicant provide the part of the design specification for Shell Plate 1 that describes the required 

copper content and the material specification that was in effect when the reactor vessel for 

GGNS was built. The staff also requested, in RAI 4.2.3-1, Part (b), that the applicant describe 

the documented basis for the copper content of Shell Plate 1 Heat C2506-1, such as available 

certified material test reports (CMTRs), quality control documents, and/or other data that might 

be used to justify the assumed copper content (i.e., copper content of 0.12 percent).

By letter dated July 26, 2012, the applicant responded to RAI 4.2.3-1, Part (a), and stated that 

the reference to the design specification in Note 2 of LRA Table 4.2-2 was in error, and the 

correct reference is the purchase specification. The applicant stated that a revision to Note 2 of 

LRA Table 4.2-2 was included in the RAI response to change “design specification” to 

“purchase specification.” As described in SER Section 4.2.1.2, the applicant provided a 

subsequent RAI response by letter dated July 29, 2015, in part to re-evaluate the neutron 

embrittlement TLAAs to account for the updated neutron fluence values. This response 

changed “purchase specification” back to “design specification” in this note, which became 

Note 8 in the amended LRA Table 4.2-2. By letter dated February 26, 2016, the applicant 

corrected Note 8 in LRA Table 4.2-2 to again reference the “purchase specification”. In 
4-43

addition, the applicant indicated that in order to justify the use of 0.12 percent copper for the 

USE calculations for Shell Plate 1 Heat C2506-1, all available BWR/6 fleet vessel CMTRs were 

reviewed. The applicant further stated that in the review, 28 data points were located, and it 

was found that mean plus two times the standard deviation results in 0.10 percent copper. The 

applicant stated that based on the reviewed data, it is shown that 0.12 percent copper is greater 

than the upper bound for all available BWR/6 copper content. The applicant's response to 

RAI 4.2.3-1, Part (b), cited the response to Part (a).

The staff reviewed the applicant’s response and finds the use of 0.12 percent copper for the 

USE evaluation for Shell Plate 1 acceptable because 0.12 percent is a statistically-based 

conservative estimate for the plate based on the staff’s review of the generic data. RAI 4.2.3-1, 

Parts (a) and (b) are resolved.

By letters dated July 29, 2015 and November 23, 2015, the applicant amended the LRA and 

updated the USE calculations to account for the new neutron fluence methodology and neutron 

fluence values (as projected to 54 EFPY) that were submitted for resolution of 

RAI 4.2.1-2c(5)(b).

The staff noted that the updated USE assessments apply to the following reactor vessel beltline 

components, which include the additional materials with neutron fluence exceeding 1x1017

n/cm2 for 54 EFPY: (a) shell plates in Shell Rings 1, 2, and 3 of the reactor vessel, (b) axial 

weld components in Shell Rings 1, 2, and 3 of the reactor vessel, (c) circumferential welds AB 

and AC used as the circumferential welds seams for the three reactor vessel beltline shell 

courses, (d) the N-6 nozzle forging and its nozzle-to-vessel weld, and (e) the N-12 nozzle 

materials and their nozzle to vessel welds. The staff also noted that the applicant performed the 

USE calculations issuing the method of analysis in Regulatory Position 2.1 of RG 1.99, 

Revision 2, and the method of analysis in Regulatory Position 2.2 of the RG, which incorporates 

applicable data from the BWRVIP ISP into the USE calculations for these reactor vessel plate, 

nozzle, and weld components.

The staff noted that the USE TLAA is limited by the USE calculation for the Shell Plate 3

component made from Heat C2779-1, which is the only RPV heat that does not meet the 50 ft-lb 

criterion in Appendix G to 10 CFR Part 50. The staff also noted that the applicant performed an 

EMA for this component because the applicant could not demonstrate that the USE value of the 

component would remain above 50 ft-lb through 54 EFPY of plant operations. However, the 

staff determined that the letter of July 29, 2015, did not include the EMA as an enclosure, or if 

previously approved by the staff, reference the plant records containing the EMA and the NRC 

SE issued in approval the EMA. Therefore, the staff could not tell whether the staff previously 

approved the referenced EMA. If the staff did not previously approve the EMA, the staff noted 

that it would need to be processed and reviewed for staff approval as part of the LRA review, 

since this is required by the regulations in 10 CFR Part 50, Appendix G.

By letter dated October 28, 2015, the staff issued RAI 4.2.3-2, Parts (1) and (2) to the applicant. 

In Part (1) of this RAI, the staff asked the applicant to clarify whether the EMA for the referenced 

RPV shell plate (as referenced in Note 10 of LRA Table 4.2-2) was submitted and approved by 

the staff. If the EMA was previously approved by the staff, the staff asked the applicant to 

identify the date of the staff’s SE (and if available, the ADAMS Accession No. or NRC microfiche 

Accession No. associated with the SE) that approved the EMA for incorporation into the 

licensing basis. Otherwise, if the EMA was not previously approved, the staff asked the 

applicant to provide its basis for why the EMA was not included in the letter of July 29, 2015, 

and submitted for staff approval, as required by 10 CFR Part 50, Appendix G. In RAI 4.2.3-2, 
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Part (2), the staff asked the applicant to identify the USE value that is associated with the RPV 

shell plate made from Heat C2779-1 at 54 EFPY.

The applicant responded to RAI 4.2.3-2, Parts (1) and (2), in a letter dated December 14, 2015. 

In its response to Part (1) of the RAI, the applicant clarified that the specific EMA that is being 

applied to the RPV shell plate made from Heat C2779-1 for the renewed licensing basis is the 

generic EMA for BWR 3 – 6 RPV plate components in EPRI BWRVIP Report No. 1008882, 

“BWRVIP-74-A: BWR Vessel and Internals Project: BWR Reactor Pressure Vessel Inspection 

and Flaw Evaluation Guidelines for License Renewal” (BWRVIP-74-A), dated June 2003. In its 

response to RAI 4.2.3-2, Part (2), the applicant clarified that the USE value for this plate 

component is projected to be 47 ft-lb at 54 EFPY.

In its response to RAI 4.2.3-2, the applicant also amended Note 10 of LRA Table 4.2-2 to state 

the following (as applied to the EMA for the RPV shell plate made from Heat C2779-1):

USE is projected to be reduced by 9.5% over the license period of 0 EFPY to 

54 EFPY. Considering the necessary adjustment resulting from the ... ISP 

results, the reduction remains at 9.5% resulting in a 54 EFPY USE of 47 ft-Ib. 

Therefore, EMA methods described in BWRVIP-74-A were applied. Since 

projected USE at 54 EFPY is greater than the minimum allowable USE of 35 ft-lb 

from BWRVIP-74-A, this material remains qualified.

The staff noticed that the applicant’s response to the RAI demonstrated compliance with these 

regulatory requirements by confirming or identifying that: (a) the USE analysis for the GGNS

RPV is limited by the USE analysis for the RPV shell plate made from Heat C2779-1, (b) the 

USE value for this RPV component at 54 EFPY (i.e., 47 ft-lb) is less than the 50 ft-lb 

requirement in 10 CFR Part 50, Appendix G, (c) the generic EMA for BWR RPV plate 

components in BWRVIP-74-A will be applied to the renewed licensing basis for the period of 

extended operation, and (d) the USE value of 47 ft-lb for the limiting RPV plate component at 

54 EFPY is acceptable because it is bounded by the lowest USE value (i.e., 35 ft-lb) approved 

for BWR RPV shell plate components in the BWRVIP-74-A EMA.

The staff performed an independent calculation of the USE value for this limiting shell plate in 

accordance with RG 1.99, Revision 2, and verified that the USE value for this component at

54 EFPY is projected to be 47 ft-lb. The staff verified that the generic EMA for BWR RPV shell 

plate components in the BWRVIP-74-A report was approved in an SE dated October 8, 2001 

(ADAMS Accession No. ML012920549), and that the NRC’s SE approved USE values for BWR 

RPV shell plate components as low as 35 ft-lb. Therefore, the staff confirmed that the applicant 

has projected the USE analysis for limiting RPV beltline plate components to the end of the 

period of extended operation and has adequately demonstrated that the USE value will remain 

above the lowest EMA-approved USE value for BWR RPV plate components stated in the 

BWRVIP-74-A report. The staff also verified that the applicant has adequately projected the 

USE values for the remaining RPV beltline components in accordance with 

10 CFR 54.21(c)(1)(ii) and has demonstrated that the USE values will be in excess of 50 ft-lb at 

the end of the period of extended operation, as required in accordance with 10 CFR Part 50, 

Appendix G. RAI 4.2.3-2, Parts (1) and (2), are resolved.

Based on its review, the staff finds the applicant has demonstrated, pursuant to

10 CFR 54.21(c)(1)(ii), that the USE analyses for the reactor vessel beltline materials have been 

projected to the end of the period of extended operation. Additionally, it meets the acceptance 

criteria in SRP-LR Section 4.2.2.1.1.2 because the applicant projected the USE values to the 
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end of the period of extended operation in accordance with RG 1.99, Revision 2, and it has 

adequately demonstrated that they will either: (a) meet the 50 ft-lb USE requirement stated 

10 CFR Part 50, Appendix G, or (b) for the EMA that applies to the limiting RPV beltline plate 

component, the USE value for the component at 54 EFPY will be above the 35 ft-lb USE value 

approved in BWRVIP-74-A for BWR RPV shell plate components.

4.2.3.3 UFSAR Supplement

LRA Section A.2.1.3 provides the UFSAR supplement summarizing the TLAA of the USE for

reactor vessel beltline materials. By letter dated July 29, 2015, the applicant amended the 

UFSAR supplement for this TLAA to indicate that the USE analyses for the reactor vessel 

beltline components have been projected to 54 EFPY and are acceptable because they either 

have been demonstrated to be above the 50 ft-lb acceptance criterion requirement stated in 

10 CFR Part 50, Appendix G, or through performance of an applicable EMA, which is applicable 

to the reactor vessel plate component made from Heat C2779-1. The staff reviewed amended 

LRA Section A.2.1.3, consistent with SRP-LR Section 4.2.3.2, which states that the reviewer 

should verify that the applicant has provided information to be included in the UFSAR

supplement that includes a summary description of the evaluation of the TLAA. The SRP-LR 

also states that Table 4.2-1 of the SRP-LR contains examples of acceptable UFSAR

supplement information for this TLAA and the reviewer verifies that the applicant has provided a 

UFSAR supplement with information equivalent to that in SRP-LR Table 4.2-1.

The staff finds the amended UFSAR supplement to be acceptable because it adequately 

summarizes how the USE TLAA has been evaluated to be in compliance with the requirements 

for USE in 10 CFR Part 50, Appendix G.

Based on its review of the amended UFSAR supplement, the staff finds that it meets the

acceptance criteria in SRP-LR Section 4.2.3.2 and is therefore acceptable. Additionally, the staff 

determines that the applicant provided an adequate summary description of its actions to 

address the TLAA evaluation of the USE of the reactor vessel materials, as required by

10 CFR 54.21(d).

4.2.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses for the USE of the reactor 

vessel materials have 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 Reactor Vessel Circumferential Weld Inspection Relief

4.2.4.1 Summary of Technical Information in the Application

LRA Section 4.2.4 summarizes the TLAA for inspection relief for the RV circumferential welds. 

The RV was fabricated by Chicago Bridge and Iron (CB&I). ASME Code Section XI, 

Table IWB-2500-1, Examination Category B-A requires periodic volumetric examinations of the 

RV circumferential welds. As addressed in an NRC letter dated April 11, 2001, the applicant 

was granted inspection relief for the circumferential welds for the remaining period of the current 

operating license (32 EFPY). The basis of the staff’s approval for the inspection relief request 

was that the conditional probability of failure (CPF) for the applicant’s circumferential welds are 
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bounded by staff-accepted CPF values for RV circumferential welds through the end of the 

current license period. These staff-accepted CPF values are described in the staff’s SE

(July 28, 1998) regarding BWRVIP-05, “BWR Vessel and Internals Project, BWR Reactor 

Pressure Vessel Shell Weld Inspection Recommendations.” The staff’s approval for the 

inspection relief request was also based on the guidance in Generic Letter (GL) 98-05, which 

addresses the acceptance criteria for inspection relief for the circumferential welds, consistent 

with the staff’s SE for BWRVIP-05.

LRA Section 4.2.4 provides the mean ART of the applicant’s limiting circumferential welds, 

which is defined as “Initial RTNDT + ∆RTNDT.” The mean ART of the applicant’s welds was 

compared with the limiting-case mean ART for the CB&I RV circumferential welds that the staff 

determined for 64 EFPY in its SE for BWRVIP-05. The mean ART (-8 °F) of the applicant’s 

circumferential welds at the end of the period of extended operation (54 EFPY) is significantly 

less than the staff-determined mean ART value (70.6 °F) for the limiting-case circumferential 

welds (64 EFPY). Since the ART value of the applicant’s circumferential welds is bounded by 

the staff’s assessment, the applicant concluded that the CPF for the applicant’s circumferential 

welds remains below the limiting-case CPF.

In addition, the applicant stated that the procedures and training to minimize the potential for RV

cold over-pressurization have been implemented. The applicant stated that it will request relief 

from the requirement to perform volumetric examinations of the RV circumferential welds, in 

accordance with 10 CFR 50.55a. The applicant initially dispositioned this TLAA in the LRA in 

accordance with 10 CFR 54.21(c)(1)(ii), that the analysis for the RV circumferential weld 

inspection relief has been projected to the end of the period of extended operation.

4.2.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the RV circumferential weld inspection relief and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii) consistent with SRP-LR Section 4.2.3.1.4, 

which states that the staff verifies that the applicant has identified that, should the inspection 

relief be desired for the period of extended operation, an application will be made under 

10 CFR 50.55a(a)(3) prior to entering the period of extended operation.

In its review, the staff has verified all of the input parameters (copper and nickel content, 

unirradiated RTNDT, neutron fluence) used for the probability of failure calculation listed in LRA 

Table 4.2-3, including the additional material with neutron fluence exceeding 1x1017 n/cm2 for 

54 EFPY. The staff noted that the applicant’s TLAA has been projected to the end of the period 

of extended operation to support the relief from the ASME Code Section XI inservice inspection 

of circumferential welds. The applicant’s alternative to the weld inspection is based on the 

staff’s SE (July 28, 1998) regarding the BWRVIP-05 report. The staff’s SE indicates that BWR 

applicants may request relief from inservice inspection requirements of 10 CFR 50.55a(g) for 

volumetric examination of RV circumferential welds by demonstrating the following items: at the 

expiration of their license, the circumferential welds satisfy the limiting CPF for circumferential 

welds specified in the staff’s evaluation, and that the applicant has implemented operator 

training and established procedures to limit the frequency of cold over-pressure events.

The first acceptance criterion for the inspection relief is addressed in LRA Table 4.2-3 where the 

applicant confirmed that the mean ART value (-8 °F) of the applicant’s limiting circumferential 

welds for the period of extended operation is less than the 64-EFPY ART value (70.6 °F) that 

the staff determined for the limiting-case circumferential weld of the CB&I RV. The staff found 

that the applicant’s CPF analysis is acceptable because the mean ART values of RV
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circumferential welds govern the CPF values for the welds and that the applicant‘s analysis 

confirmed that the mean ART value of the applicant’s circumferential welds is significantly less 

than the staff-determined mean ART value of the limiting-case circumferential welds for CB&I 

RVs. Hence, the CPF value for GGNS would be lower than the staff accepted generic 

CB&I value.

For the second acceptance criterion for the inspection relief, LRA Section 4.2.4 indicates that 

the applicant has implemented the procedures and training to minimize the potential for RV cold 

over-pressure events. In its review, the staff found that the continued implementation of 

operator training and establishment of procedures to limit the frequency of cold overpressure 

events meets the second acceptance criterion described in the staff’s SE for BWRVIP-05.

However, the staff identified an issue with the applicant’s disposition of this TLAA. SRP-LR 

Section 4.2.3.1.4 states that if the applicant indicates that relief from circumferential weld 

examination will be made under 10 CFR 50.55a(a)(3), the applicant will manage this TLAA in 

accordance with 10 CFR 54.21(c)(1)(iii). In contrast, the applicant dispositioned this TLAA in 

accordance with 10 CFR 54.21(c)(1)(ii), inconsistent with the SRP-LR. By letter dated 

October 17, 2012, the staff issued RAI 4.2.4-1, requesting the applicant explain why the TLAA 

for the circumferential weld inspection relief is dispositioned in accordance with 

10 CFR 54.21(c)(1)(ii) or revise the TLAA disposition to be in accordance with 

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

In its response dated November 15, 2012, applicant amended its disposition of the TLAA to 

10 CFR 54.21(c)(iii). In accordance with 10 CFR 54.21(c)(iii), the licensee affirmed that the 

effects of aging from neutron irradiation embrittlement of the RV circumferential welds will be 

adequately managed for the period of extended operation. The staff’s concern described in 

RAI 4.2.4-1 is resolved.

As previously discussed, the applicant’s September 1, 2015, response to RAI 4.2.1-2c, Part 5(a) 

confirmed that the staff approved the applicant’s LAR to incorporate a single fluence method 

(MPM method) into the CLB. By its letter dated July 29, 2015 (response to RAI 4.2.1-2c, 

Part 5(b)), the applicant also revised LRA Section 4.2.4 to update the RV circumferential weld 

inspection relief analysis based on the updated fluence projections for 54 EFPY.

In its updated analysis, the applicant identified that circumferential weld AC is a new limiting 

circumferential weld in place of weld AB. The applicant also confirmed that the updated mean 

ART value (20 °F) of the new limiting weld is less than the 64-EFPY ART value (70.6 °F) that 

the staff determined for the limiting-case circumferential weld of the CB&I RV. In its review, the 

staff finds the updated analysis acceptable because the updated mean ART of the applicant’s 

limiting circumferential weld is bounded by the staff’s SE regarding the BWRVIP-05 report. The 

concern described in RAI 4.2.1-2c, Part 5(b) regarding the circumferential weld inspection relief 

analysis is resolved.

The staff finds the applicant’s conclusion for this TLAA acceptable because the applicant’s 

evaluation in LRA Section 4.2.4 confirms that the CPF values for the applicant’s RV

circumferential welds at 54 EFPY is bounded by the staff-accepted CPF values that are 

described in the SE (July 28, 1998) for BWRVIP-05. The applicant indicated that it will request 

relief from the requirement to perform volumetric examinations of the RPV circumferential 

welds, in accordance with 10 CFR 50.55a.
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4.2.4.3 UFSAR Supplement

LRA Section A.2.1.4, as amended by letter dated November 15, 2012, provides the UFSAR 

supplement summarizing the TLAA for relief from RV circumferential weld examination. The 

staff reviewed LRA Section A.2.1.4, consistent with SRP-LR Section 4.2.3.2, which states that 

the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of the TLAA.

The applicant dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(iii), consistent 

with the SRP-LR that indicates that if the applicant will ask for relief from circumferential weld 

examination under 10 CFR 50.55a(a)(3), the applicant will manage this TLAA in accordance 

with 10 CFR 54.21(c)(1)(iii).

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.2.3.2. Additionally, the staff finds that the applicant provided an adequate 

summary description of its actions to address the TLAA for the relief from the RV circumferential 

weld inspection, as required by 10 CFR 54.21(d).

4.2.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the RV circumferential weld will be 

adequately managed 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).

4.2.5 Reactor Vessel Axial Weld Failure Probability

4.2.5.1 Summary of Technical Information in the Application

LRA Section 4.2.5 describes the applicant’s TLAA for the RV axial weld failure probability for the

period of extended operation. The staff’s SE (October 18, 2001) for BWRVIP-74, “BWR Vessel 

and Internals Project, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation 

Guidelines,” evaluates the failure frequency of BWR RV axial welds. The staff’s SE for 

BWRVIP-74 also indicates that a mean ART of 114 °F closely matches a failure frequency 

threshold of 5.0x10-6 per reactor-year that determines the acceptability of the RV failure 

frequency for the first 40 years of reactor operation. In addition, the staff’s SE regarding 

BWRVIP-74 indicates that an acceptable method for performing this analysis is to demonstrate 

that the mean ART for the limiting axial beltline weld at the end of the period of extended 

operation is less than the values specified in Table 1 of the staff’s SE for BWRVIP-74.

The mean ART for the applicant’s limiting axial weld at 54 EFPY is projected to be -19 °F, which 

is significantly less than the acceptable mean ART value (114 °F) described in the staff’s SE for 

BWRVIP-74. Therefore, the RV failure probability due to the failure of the applicant’s limiting 

axial weld is well below the acceptable limit of 5.0x10-6 per reactor-year. The applicant 

dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(ii), that the neutron 

embrittlement of the RV axial welds has been projected to the end of the period of 

extended operation.
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4.2.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the RV axial weld failure probability and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii) consistent with SRP-LR Section 4.2.3.1.5. 

The SRP-LR states that the applicant should provide (a) a comparison of the neutron fluence, 

initial RTNDT, chemistry factor, ∆RTNDT, and mean RTNDT (i.e., mean ART) of the limiting axial 

weld at the end of the license renewal period to the reference case in the BWRVIP and staff 

analyses; and (b) an estimate of conditional failure probability of the RV at the end of the license 

renewal term based on the comparison of the mean RTNDT for the limiting axial welds and the 

reference case. The SRP-LR also states that the staff should ensure that the applicant’s plant 

is bounded by the BWRVIP-05 analysis, or that the applicant has committed to a program to 

monitor axial weld embrittlement.

In its review, the staff has verified all of the input parameters (copper and nickel content, 

unirradiated RTNDT, neutron fluence) used for the probability of failure calculation listed in LRA 

Table 4.2-4, including those for the additional materials with neutron fluence exceeding 1x1017

n/cm2 for 54 EFPY. The staff noted that LRA Table 4.2-4 lists the mean ART (-19 °F) of the 

applicant’s limiting axial weld for 54 EFPY to be compared with the acceptable mean ART value 

(114 °F), which is specified in the staff’s SE for BWRVIP-74 and closely matches the acceptable 

failure frequency limit of 5.0x10-6 per reactor-year. The staff finds that the applicant’s analysis is 

acceptable because the applicant confirmed that the mean ART of its liming axial weld is less 

than the acceptable mean ART value (114 °F) specified in the staff’s SE for BWRVIP-74, 

indicating that the applicant’s limiting case is bounded by the acceptable analysis in 

BWRVIP-74, consistent with the review procedures in the SRP-LR.

As previously discussed, the applicant’s September 1, 2015, response to RAI 4.2.1-2c, Part 5(a) 

confirmed that the staff approved the applicant’s LAR to incorporate a single fluence method 

(MPM method) into the CLB. By its letter dated July 29, 2015 (response to RAI 4.2.1-2c, 

Part 5(b)), the applicant also revised LRA Section 4.2.5 to update the RV axial weld failure 

probability analysis based on the updated fluence projections for 54 EFPY.

In its updated analysis, the applicant confirmed that the updated mean ART (-20 °F) of the 

applicant’s limiting axial weld (Heat Number 5P6214B/0331 Tandem) for 54 EFPY is slightly 

lower than the previously determined mean ART (-19 °F) due to the reduction in peak fluence 

from 4.44x1018 to 4.02x1018 (energy greater than 1 MeV). In its review, the staff finds the 

updated analysis acceptable because the updated mean ART of the applicant’s limiting axial 

weld is bounded by the acceptable mean ART value (114 °F), which is specified in the staff’s SE 

for BWRVIP-74. In addition, the staff confirmed that the use of the credible chemistry factor 

from the integrated surveillance program would increase the mean ART value of the limiting 

axial weld by 12 °F but would not change the conclusion of this evaluation. The concern 

described in RAI 4.2.1-2c, Part 5(b) regarding the axial weld failure probability analysis is 

resolved.

Based on its review, the staff finds that the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(ii), that the analysis for the neutron embrittlement of the RV axial welds has 

been projected to the end of the period of extended operation and confirmed that the level of the 

neutron embrittlement of the axial welds is bounded by the bounding-case neutron 

embrittlement analysis that is addressed in the staff’s SE for BWRVIP-74. Therefore, the 

applicant’s TLAA meets the acceptance criteria in SRP-LR Section 4.2.2.1.5 by confirming that 

the failure frequency of the RV for 54 EFPY due to the failure of axial welds is less than the 

failure frequency limit (5.0x10-6 per reactor-year) specified in the SRP-LR.
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4.2.5.3 UFSAR Supplement

LRA Section A.2.1.5 provides the UFSAR supplement summarizing the TLAA for the RV axial 

weld failure probability. The staff reviewed LRA Section A.2.1.5 consistent with SRP-LR 

Section 4.2.3.2, which states that the reviewer should verify that the applicant has provided 

information to be included in the UFSAR supplement that includes a summary description of the 

evaluation of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that it meets the acceptance 

criteria in SRP-LR Section 4.2.3.2 and is therefore acceptable. Additionally, the staff finds that 

the applicant provided an adequate summary description of its actions to address the TLAA for 

the RV axial weld failure probability.

4.2.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for the RV axial weld failure 

frequency 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).

4.2.6 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis

4.2.6.1 Summary of Technical Information in the Application

LRA Section 4.2.6 contains the applicant’s TLAA for the RV core reflood thermal shock. 

Generic Electric Report NEDO-10029 addresses a RV core reflood thermal shock analysis and 

the analysis is relevant for the applicant for 40 years of the current license term as referenced in 

UFSAR, Section 5.3. In addition, the applicant cited a more recent analysis, which provides an

evaluation of the core reflood thermal shock during loss-of-coolant accident (LOCA) event for a 

BWR-6 RV design: “Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel 

Following a Postulated Loss of Coolant Accident,” Fifth International Conference on Structural 

Mechanics on Reactor Technology, Berlin, Germany, August 1979, by S. Ranganath.

The more recent analysis indicates that when the peak stress intensity occurs at approximately 

300 seconds after the LOCA, the temperature inside the vessel wall is approximately 400°F. 

The maximum ART value calculated for the applicant’s RV beltline material is 53°F. Using the 

equation for fracture toughness (KIC) presented in ASME Code, Section XI, Appendix A, and the 

applicant’s maximum ART value for 54 EFPY, the applicant’s limiting vessel material reaches 

USE at approximately 158°F. The 400°F temperature predicted for the thermal shock event at 

the time of peak stress intensity remains well above the 158°F value, at which the material 

would transition to the upper shelf. The analysis indicated that if the material was exhibiting 

upper-shelf behavior during the peak stress event, the vessel would be adequately protected. 

Therefore, the recent analysis projected the TLAA through the period of extended operation.

The applicant dispositioned this TLAA in accordance with 10 CFR 54.21(c)(1)(ii), that the RV

core reflood thermal shock analysis has been projected to the end of the period of the extended 

operation.
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4.2.6.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the RV core reflood thermal shock and the 

corresponding disposition of 10 CFR 54.21(c)(1)(ii), consistent with the review procedures in 

SRP-LR Section 4.7.3.1.2. The SRP-LR states that the staff reviews the revised analyses to 

verify that their period of evaluation is extended, such that they are valid for the period of 

extended operation (e.g., 60 years).

In its review, the staff noted that the LRA includes only a brief evaluation based on ART values 

and temperatures to demonstrate that the Ranganath analysis is bounding for the GGNS RV

core reflood thermal shock analysis. The staff also noted that the LRA did not provide sufficient 

information for the staff to confirm the applicant’s claim in the LRA. In addition, the staff 

requested clarification as to why the LRA does not identify the following items as a TLAA: 

(1) reflood thermal shock analysis of the RV core shroud and (2) growth of the core shroud 

stress-corrosion cracking (SCC) indication.

By letter dated June 5, 2012, the staff issued RAI 4.2.6-1 requesting that the applicant provide 

the following information and calculations to confirm that the applicant’s RV materials are 

bounded by the analysis in the Ranganath paper as referenced in the LRA: (a.1) additional 

supporting information and calculations, including the projected fracture toughness values of the 

RV materials in comparison to the acceptable RV fracture toughness values for the postulated 

event, (a.2) confirmation as to whether the applicant's bounding-case analysis in LRA 

Section 4.2.6 includes all the relevant RV materials, the fast fluence values of which are 

projected to exceed 1x1017 n/cm2 during the period of extended operation, not omitting any 

newly identified limiting material or extended beltline material (e.g., not omitting the relevant 

materials addressed in LRA Table 4.2-2), and (a.3) justification for why the applicant’s RV is 

sufficiently similar to the RV analyzed in the paper for comparison.

In its response dated July 3, 2012, the applicant stated that the fracture toughness values are 

temperature dependent for any given material, and as shown in LRA Section 4.2.6, the plantspecific temperature at 1/4T depth into the vessel wall was determined to be 400°F at 

300 seconds (with the peak stress) into the thermal shock event. The applicant also indicated 

that using the highest ART (53°F) for 54 EFPY, the RV materials are projected to have a 

fracture toughness (KIC) of 200 ksi√in at approximately 158°F based on the fracture toughness 

equation in ASME Code Section XI, Appendix A. The applicant further indicated that since this 

temperature (158°F for 200 ksi√in) is significantly lower than 400°F, it is assured that the 

fracture toughness of the beltline materials remains at sufficiently high levels during the reflood 

thermal shock event. In addition, the applicant indicated that Figure 5 of the Ranganath paper 

demonstrates that at 300 seconds into the thermal shock event and 1/4T depth into the vessel 

wall, the maximum applied stress intensity factor (103 ksi√in) occurs and the maximum stress 

intensity factor during the thermal shock event is less than 200 ksi√in (i.e., the fracture 

toughness of the RV at 158°F based on the highest ART for 54 EFPY). The applicant stated 

that therefore, there is sufficient margin to prevent fracture due to reflood thermal shock.

The applicant addressed the request regarding the consideration of all the relevant RV materials 

and the bounding-case analysis as follows. The applicant stated that the maximum ART value

(53°F) provided in LRA Section 4.2.6 is for the limiting material considering all relevant materials 

evaluated in LRA Table 4.2.2. The applicant also stated that this includes all materials that are 

exposed to fast fluence values in excess of 1x1017 n/cm2

. The applicant further stated that the 

input parameters to the applicant’s analysis for this TLAA, such as vessel size and vessel 
4-52

thickness are similar to the input parameters considered in the Ranganath evaluation while the 

neutron fluence for the GGNS RV is less than the fluence used in the Ranganath evaluation.

In addition, the applicant stated that there is no reflood thermal shock analysis of the RV core 

shroud. The applicant stated that the reflood thermal shock analysis addressed in LRA 

Section 4.2.6 and the subsequent Ranganath evaluation applies to the RV, and potential effects 

on the SCC indication have not been evaluated for a reflood thermal shock event since no 

reflood thermal shock analysis exists for the applicant’s RV core shroud.

Regarding the consideration of potential crack growth due to SCC, the applicant stated in its 

response that the indication found in the shroud circumferential weld was evaluated following 

discovery in 2005. The applicant indicated that the evaluation determined an acceptable 

inspection frequency and did not qualify the affected weld for service to the end of the 40-year 

operating term. The applicant stated that the flaw was found to be acceptable for service until 

the next inspection and, therefore, the crack growth does not meet the 10 CFR 54.3 definition of 

a TLAA. The applicant stated that potential SCC crack growth in the core shroud is monitored 

by the ISI Program described in LRA Section B.1.23.

In its review, the staff found the applicant’s response acceptable because (a) the fracture 

toughness of the limiting RV material projected for 54 EFPY is adequate at 400°F such that the 

limiting-case fracture toughness of the RV is significantly greater than the maximum applied 

stress intensity factor (103 ksi√in) at the 1/4T location during the core reflood event, (b) the

analysis includes all the relevant materials of the RV, and (c) the applicant clarified that no 

reflood thermal shock analysis exists for the applicant’s RV core shroud such that a reflood 

thermal shock analysis is not a TLAA for the applicant’s core shroud. The staff’s concern 

described in RAI 4.2.6-1 is resolved.

As previously discussed, the applicant’s September 1, 2015, response to RAI 4.2.1-2c, Part 5(a) 

confirmed that the staff approved the applicant’s LAR to incorporate a single fluence method 

(MPM method) into the CLB. By its letter dated July 29, 2015 (response to RAI 4.2.1-2c, 

Part 5(b)), the applicant also revised LRA Section 4.2.6 to update the RV core reflood thermal 

shock analysis based on the updated fluence projections for 54 EFPY.

In its updated analysis, the applicant confirmed that the updated maximum ART value 

calculated for the applicant’s RV beltline material is 51 °F, which is slightly less than the 

previously determined maximum ART value (53 °F). In its review, the staff finds the updated 

analysis acceptable because the updated maximum ART value, which is less than the 

previously determined one, does not affect the applicant’s previous conclusion and staff’s 

acceptance basis regarding the RV core reflood thermal shock analysis. The concern described 

in RAI 4.2.1-2c, Part 5(b) regarding the RV core reflood thermal shock analysis is resolved.

The staff finds that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the RV core reflood thermal shock has been projected to the end of the period of 

extended operation. The LRA, and applicant’s response to RAI 4.2.6-1, confirm that the fracture 

toughness of the limiting RV material at 54 EFPY is greater than the maximum applied stress 

intensity factor analyzed in the bound-case analysis for the RV core reflood shock. Therefore, 

the staff finds the applicant’s TLAA is adequate for the period of extended operation.
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4.2.6.3 UFSAR Supplement

LRA Section A.2.1.6, as amended by the July 29, 2015 letter, provides the UFSAR supplement 

summarizing the applicant’s TLAA for the RV core reflood thermal shock analysis. The staff 

reviewed LRA Section A.2.1.6, consistent with SRP-LR Section 4.2.3.2, which states that the 

reviewer should verify that the applicant has provided information to be included in the UFSAR 

supplement that includes a summary description of the evaluation of the TLAA. Based on its 

review of the UFSAR supplement, the staff concludes that the information in the UFSAR 

supplement is an adequate summary description of the program, as required by 

10 CFR 54.21(d).

4.2.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for RV core reflood thermal 

shock has been projected to the end of the period of extended operation. The staff also 

concludes that the UFSAR contains an appropriate summary description of the TLAA 

evaluation, as required by 10 CFR 54.21(d).

4.3 Metal Fatigue

4.3.1 Class 1 Fatigue

LRA Section 4.3.1 describes the applicant’s Class 1 fatigue analyses. The LRA states that 

Class 1 components and systems that have fatigue analyses include the RV, the RVI, and 

Class 1 piping. These analyses were performed for the design of Class 1 components in 

accordance with their design requirements. The LRA also states that design cyclic loadings and 

thermal conditions for Class 1 components are defined by the applicable design specifications 

for each component, and the original design specifications provided the initial set of transients 

used in the design of the components. The Fatigue Monitoring Program tracks and evaluates 

transient cycles and requires corrective actions if limits are approached and ensures that the 

number of occurrences of each transient cycle that the plant experiences remain within the 

allowable numbers of cycles.

LRA Table 4.3-1 provides the numbers of cycles accrued to date and the projected number of 

accrued cycles expected at the end of 60 years of operation. The LRA states that the projected 

values through the period of extended operation were based on the rate of occurrence for the 

previous 10 years.

Staff Evaluation

The staff reviewed the applicant’s projected and analyzed transient cycles in LRA Table 4.3-1 

associated with its Class 1 fatigue analyses. The staff reviewed the list of transients used in the 

existing CUF analyses for the current operating term and the associated number of occurrences 

to assess the expected margin to the design cycle limits at the end of the period of extended 

operation. The staff also reviewed the relevant design basis information and CLB information 

(including applicable cycle-counting requirements in the TS).

The staff notes that the applicant will manage all of the Class 1 fatigue TLAAs using the Fatigue 

Monitoring Program, such that the projected transient cycle values provided in LRA Table 4.3-1 
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are for information purposes only, since the AMP will ensure that appropriate corrective actions 

are taken to ensure that counts for individual transients do not exceed their limits.

The staff reviewed LRA Section 4.3.1 and noted that the applicant did not explain why the 

operational data from 1985 to 1999 were not taken into account for the 60-year projections. In 

addition, the applicant did not justify why the data between 1999 and 2010 used in the 60-year 

projections were conservative. By letter dated May 24, 2012, the staff issued RAI 4.3-1,

requesting the applicant to justify why the operational data between initial plant operation in 

1985 to 1999 was not considered and to justify why using the data between 1999 and 2010 is a 

conservative approach to project to 60 years of plant operation.

In its response dated June 21, 2012, the applicant stated that plant operating data from the 

10.4-year period on which LRA Table 4.3-1 is based is considered a more accurate 

representation of future transient cycle occurrence rate than data extending back to initial plant 

startup. The applicant explained that startup testing and initial equipment operation caused a 

high frequency of occurrences during 1985 to 1999 and incorporating lessons learned from 

operating experience has resulted in improved plant performance and a consequently lower rate 

of transient occurrence. In addition, the applicant stated the use of data from 1999 and 2010 is 

a conservative approach for projections to 60 years of plant operation since the plant was on 

18-month operating cycles during this time but will be operating on a 24-month fuel cycle in the 

future. The staff noted longer operating times between refueling cycles equates to fewer

occurrences of normal and test transients. The applicant stated that the projections were not 

used to reduce cycles assumed for any analysis, including the EAF screening, does not replace 

the original transient cycle limits, and is not used to satisfy 10 CFR 54.21(c)(1)(ii). Furthermore, 

actions will be taken based on actual accrued cycles regardless of projected values.

The staff finds it reasonable that the operating data early in plant life were not used in the 

60-year projections because the recent operating data is an accurate representation of how the 

applicant operates its plant based on lessons learned and operating experience. However, 

regardless of the projections the applicant provided in the LRA, the applicant’s Fatigue 

Monitoring Program is tracking the number of cycle occurrences or calculating cumulative 

fatigue usage to ensure that corrective actions are taken before a design cycle limit or the 

design limit on fatigue usage is exceeded. The staff noted that these projections provide an 

early indication of whether design cycle limits may be exceeded and that the Fatigue Monitoring 

Program provides for management of fatigue.

The staff finds the applicant’s response to RAI 4.3-1 acceptable because the applicant 

explained why early operating data for transients were not included, explained that these cycle 

projections were not used to provide validation or update fatigue analyses, and stated that the 

Fatigue Monitoring Program will ensure that corrective actions are taken before a design cycle 

limit or design limit of fatigue usage is exceeded during the period of extended operation. The 

staff’s concern described in RAI 4.3-1 is resolved.

LRA Table 4.3-1 states that the “Design Hydro” transient originally was designed to 40 cycles of 

pressurization with a pressure of 1,250 psig. In addition, since the test was performed at less 

than 1,050 psig, the number of allowable cycles has been recalculated as 50 cycles. However, 

the staff noted that the UFSAR still indicates that the allowable number of cycles for this 

transient is 40 cycles. The applicant did not explain how the number of allowable cycles for the 

“Design Hydro” transient was recalculated to 50 cycles, what limits are being used in the 

Fatigue Monitoring Program, and why the information between the LRA and the UFSAR is not 

consistent. By letter dated May 24, 2012, the staff issued RAI 4.3-2 requesting the applicant to 
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clarify the discrepancy in information associated with the “Design Hydro” transient in the LRA 

and UFSAR and to clarify the limit that the Fatigue Monitoring Program will be managing. In 

addition, the applicant was requested to identify all other transients in which the number of 

allowable cycles in the LRA is not consistent with the CLB (e.g., TS and UFSAR) and to justify 

any differences.

In its response dated June 21, 2012, the applicant stated that the “Design Hydro” transient is 

specified as having a maximum pressure of 1,250 psig for design purposes. However, an 

actual “Design Hydro” transient reaches a peak pressure of only 1,025 psig. The applicant 

further stated that by conservatively assuming 1,050 psig for every occurrence of this transient,

the less severe nature of the actual transient resulted in an increase in the allowed number of 

cycles while ensuring the design basis usage for the worst case location would remain the 

same. The staff finds it reasonable that a decrease in pressure for a transient results in a lower 

value of stress that the component experiences. Consistent with the trend of the ASME Code 

design fatigue curves, a lower value of stress results in an increase in the number of allowable 

cycles. The applicant also explained that UFSAR Table 3.9-35 contains a footnote indicating 

that the cycles listed are the (original) design transient limits and that the current fatigue 

operating cycle information is located in a site-specific mechanical standard; thus, no UFSAR 

change is necessary.

The applicant stated that LRA Table 4.3-1 lists the analyzed numbers of cycles. Further, a 

comparison of this table to the UFSAR and TS revealed that the LRA values are equivalent to 

the values in the UFSAR and TS except for the “Design Hydro” transient and the single safety 

relief valve (SRV) actuation and shutdown transients. The staff noted that the LRA values for 

the single SRV actuation and shutdown transients are less than the design cycle limits specified 

in the UFSAR. The staff finds this acceptable and conservative because the Fatigue Monitoring 

Program is monitoring these two transients to a lower cycle limit than the design cycle limits 

specified in the UFSAR, which ensures that the design limit for these two transients will not be 

exceeded.

The staff finds the applicant’s response to RAI 4.3-2 acceptable because the applicant 

(1) clarified how the cycle limit on the “Design Hydro” transient was increased, (2) confirmed 

that its UFSAR already provides a reference to this updated cycle limit, and (3) confirmed that 

there are no other differences in cycle limits between the LRA and the UFSAR, except as 

justified above. The staff’s concern described in RAI 4.3-2 is resolved.

The staff noted in LRA Table 4.3-1 that the “Loss of Feedpumps” transient may exceed its 

design cycle limit of 10 during the period of extended operation. The applicant did not explain 

how exceeding the design cycle limit for this transient during the period of extended operation 

will impact fatigue TLAAs and why exceeding the design limit for this transient would affect only 

the RV FW nozzle. By letter dated May 24, 2012, the staff issued RAI 4.3-3 requesting the 

applicant to identify all components that included the “Loss of Feedpumps” transient in its 

fatigue analysis and discuss how exceeding the design cycle limit for this transient will affect 

these fatigue TLAAs. In addition, the staff requested the applicant to justify how the Fatigue 

Monitoring Program will ensure that fatigue usage remains within the allowable limit given that 

one of the design transients used in the fatigue analysis is expected to exceed the design 

limit during the period of extended operation if stress-based fatigue is not used as the 

monitoring method.

In its response dated June 21, 2012, the applicant stated that the loss of FW pumps transient is 

a part of the design basis for its plant and, therefore, was included for all Class 1 components 
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that have an associated fatigue analysis. Based on the design basis fatigue analyses, the 

cycle-based fatigue monitoring method was chosen assuming that design basis transient 

severity will produce the design basis fatigue usage if the design basis number of cycles occurs. 

The staff noted that this method also accounts for more or fewer occurrences of a particular 

transient by calculating the cumulative fatigue usage incurred based on the number of transients 

that actually occur regardless of the number of occurrences assumed in the design analyses.

The applicant clarified that for the period of extended operation, stress-based fatigue monitoring 

is planned only for the FW nozzles; however, if a cycle-based fatigue monitoring location 

approaches its allowable usage, then stress-based fatigue monitoring would be an option. The 

applicant explained that its program will automatically account for the incremental fatigue usage 

for each “Loss of Feedpumps” transient, even if the design basis number of transients is 

exceeded. The staff’s review of the applicant’s Fatigue Monitoring Program and more 

specifically cycle-based fatigue monitoring and stress-based fatigue monitoring is documented 

in SER Section 3.0.3.1.18.

The staff finds the applicant’s response to RAI 4.3-3 acceptable because the applicant clarified 

that all Class 1 components that have an associated fatigue analysis are affected by the loss of 

feedpumps transient. The applicant also justified that, by using cycle-based fatigue monitoring,

it can periodically calculate cumulative fatigue usage, which is based on design severity and 

design fatigue usage contribution per transient occurrence, to ensure the design limit on fatigue 

usage is not exceeded even if a design cycle limit is exceeded. Further, the applicant’s Fatigue 

Monitoring Program includes an option to use stress-based fatigue monitoring, which provides 

more detailed monitoring to manage accumulated fatigue usage. The staff’s concern described 

in RAI 4.3-3 is resolved.

LRA Table 4.3-1 indicates that the 60-year projections for several transients are expected to 

exceed their associated design allowable limit during the period of extended operation. LRA 

Section 4.3.1 discusses subsequent projections that will refine the estimate of the numbers of 

cycles expected through 60 years of operation. However, the applicant did not identify the 

locations or fatigue analyses that will be affected by these design transients and it is not clear to 

the staff how often the applicant will perform these subsequent cycle projections. By letter 

dated May 24, 2012, the staff issued RAI 4.3-4 requesting the applicant to identify the locations 

that will be affected by transients that have 60-year projected cycles that exceed their 

associated design cycle limit during the period of extended operation; to clarify how often these 

subsequent cycle projections will be performed; and whether they are part of the Fatigue 

Monitoring Program.

In its response dated June 21, 2012, the applicant clarified that the term “locations” in LRA 

Section 4.3.1 that was referenced in the staff’s RAI was meant to refer to transients and not to 

plant locations. The applicant revised LRA Section 4.3.1 to provide this clarification between 

the terms “locations” and “transients.” The applicant also clarified that when an allowable value 

for cycles is approached, the Fatigue Monitoring Program will initiate corrective action that will 

require identifying the plant locations affected by the specific transient. The staff finds the 

applicant’s revisions to LRA Section 4.3.1 acceptable because it clarified that the applicant’s 

program is managing the transients used as assumptions into the fatigue analyses and that 

corrective actions will include identification of the specific plant locations that may be affected if 

an allowable cycle limit is approached.

The applicant stated that the projections to 60 years are included as part of the periodic update 

completed by the Fatigue Monitoring Program once every two operating fuel cycles. The 
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projections in these periodic updates are not necessary to adequately manage the effects of 

metal fatigue during the period of extended operation and are considered as inputs to optimize 

resource utilization when planning future activities for the program. These projections are used 

for information only. The applicant stated that the Fatigue Monitoring Program will ensure that

fatigue usage remains within allowable limits, independent of the 60-year projections. The staff 

finds it acceptable that the applicant uses these periodic refinements for the 60-year projections 

as information for the purposes of resource utilization and planning future activities because the 

Fatigue Monitoring Program periodically ensures that the allowable cycle limit and allowable 

design limit on fatigue usage is not exceeded based on the actual occurrence of transient 

cycles. The staff’s review of the Fatigue Monitoring Program and its ability to manage metal 

fatigue during the period of extended operation is documented in SER Section 3.0.3.1.18.

The staff finds the applicant’s response to RAI 4.3-4 acceptable because the applicant revised 

LRA Section 4.3.1 to clarify the terms “locations” and “transients,” the applicant explained how it 

will use subsequent cycle projections as information for resource utilization and planning future 

activities, and the Fatigue Monitoring Program periodically ensures corrective actions are taken 

before an allowable cycle limit or design limit on fatigue usage is exceeded during the period of 

extended operation. The staff’s concern described in RAI 4.3-4 is resolved.

UFSAR Table 3.9-1 indicates that there are 400 design cycles for the “control rod pattern 

change” transient and UFSAR Table 3.9-35 indicates that there are 80 step-change cycles for 

the “loss of feedwater heaters” transient. The staff noted that these transients were not included 

in LRA Table 4.3-1; therefore, it is not clear whether they have been used as inputs into the 

TLAAs discussed in LRA Section 4.3. By letter dated May 24, 2012, the staff issued RAI 4.3-6 

requesting the applicant to identify the TLAAs in LRA Section 4 that used these transients as an 

input and confirm that these transients were monitored since initial plant startup. In addition, 

based on disposition of these identified TLAAs, the applicant was requested to clarify whether 

these transients are currently included in the Fatigue Monitoring Program or to provide the 

accumulated number and projected number of occurrences for each transient in LRA

Tables 4.3-1.

In its response dated June 21, 2012, the applicant stated each of the Class 1 metal fatigue 

TLAA evaluated in LRA Section 4.3 used the “loss of feedwater heaters” transient as an input. 

The applicant explained that the 80 step-change cycles for the “loss of feedwater heaters”

transient result from the summation of two transients that have been monitored since plant 

startup. These two transients are the turbine bypass (10 cycles) and partial FW heater bypass 

(70 cycles). The applicant confirmed that the Fatigue Monitoring Program tracks the turbine 

bypass and partial FW heater bypass transients. It stated that the “control rod pattern change”

transient was considered for the fatigue analyses of the FW nozzle and piping system and has a 

small effect on pressure and temperature. This transient has not been tracked since its effect 

on fatigue usage was determined to be insignificant. The staff’s evaluation associated with the 

Fatigue Monitoring Program not monitoring the “control rod pattern change” transient is 

documented in SER Section 3.0.3.1.18, in which the staff found this transient does not need to 

be monitored. The applicant confirmed that none of the Class 1 metal fatigue TLAAs in LRA 

Section 4.3 are evaluated in accordance with 10 CFR 54.21(c)(1)(i) or 54.21(c)(1)(ii). Instead, 

the staff noted they were all evaluated in accordance with 10 CFR 54.21(c)(1)(iii).

The staff finds the applicant’s response to RAI 4.3-6 acceptable because it clarified that the 

“loss of feedwater heaters” transient is the combination of the turbine bypass (10 cycles) and 

partial FW heater bypass (70 cycles) transients; the applicant confirmed that these transients 

have been monitored since plant startup and are included in the applicant’s Fatigue Monitoring 
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Program for the period of extended operation, which will ensure corrective actions are taken if a 

cycle limit is approached. In its response, the applicant also justified not monitoring the “control 

rod pattern change” transient. The staff’s concern described in RAI 4.3-6 is resolved.

The staff’s review of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.1.18. The staff determined that the program includes three monitoring methods 

(cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring) that are 

capable of managing metal fatigue and environmentally-assisted fatigue (EAF) during the period 

of extended operation. The staff also determined that the use of these three monitoring 

methods is conservative and progressively provides a more refined monitoring approach to 

manage metal fatigue and EAF to ensure that the applicable allowable design limits are not 

exceeded. The staff determined that these characteristics of the applicant’s Fatigue Monitoring 

Program are consistent with GALL Report AMP X.M1.

UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing Class 1 metal fatigue. The 

staff reviewed LRA Section A.2.2.1 consistent with SRP-LR Section 4.3.3.2, which states that 

the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the TLAA.

Based on its UFSAR supplement review, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address Class 1 fatigue 

analyses, as required by 10 CFR 54.21(d). Additional details of the staff’s evaluation for specific 

Class 1 fatigue analyses are documented below.

Conclusion

On the basis of its review, the staff concludes that the applicant provided an adequate 

description and acceptable basis for monitoring design transients and cycles and managing 

cumulative fatigue usage with its Fatigue Monitoring Program. The program ensures that 

corrective actions are taken before exceeding the design limit during the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an appropriate 

summary description of the monitoring bases of transients and design cycles, as required by 

10 CFR 54.21(d).

4.3.1.1 Reactor Vessel

4.3.1.1.1 Summary of Technical Information in the Application

LRA Section 4.3.1.1 describes the applicant’s TLAA for metal fatigue of the RV components. 

The LRA states that UFSAR Section 5.3.3.3 describes the RPV as being fabricated in 

accordance with ASME Code Section III, Class 1 requirements. In addition, the RPV fatigue 

analyses were performed in accordance with the ASME Boiler and Pressure Vessel Code, 

Section III, its interpretations, and applicable requirements for Class A vessels as defined 

therein, as of the order date of December 1972. LRA Table 4.3-2 provides a list of the 40-year 

design CUFs for critical RV locations.
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The applicant dispositioned the metal fatigue TLAA for RV components in accordance with 

10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of aging due to fatigue on the RV will be 

adequately managed for the period of extended operation.

4.3.1.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of the RV components and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.3.3.1.1.3, 

which states that the reviewer should verify that the applicant has identified the appropriate 

program as described and evaluated in the GALL Report and included an assessment of the 

TLAA information against relevant design basis and CLB information.

The staff reviewed LRA Table 4.3-2 and noted that the CUF values for the RV components are 

less than 1.0. The staff noted that, while these CUF values are less than the design limit of 1.0, 

the applicant has proposed managing fatigue of these components with its Fatigue Monitoring 

Program to ensure that fatigue is managed and the design limits are not exceeded during the 

period of extended operation. The staff’s review of the applicant’s Fatigue Monitoring Program 

is documented in SER Section 3.0.3.1.18. The staff determined that this program includes three 

monitoring methods (cycle counting, cycle-based fatigue monitoring, and stress-based fatigue 

monitoring) that are capable of managing metal fatigue and EAF during the period of extended 

operation. The staff also determined that the use of these three monitoring methods is 

conservative and progressively provides a more refined monitoring approach to manage metal 

fatigue and EAF to ensure that the applicable allowable design limits are not exceeded. The 

staff determined that these characteristics of the applicant’s Fatigue Monitoring Program are 

consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the RV

components analyzed in accordance with ASME Code Section III will be adequately managed 

by the Fatigue Monitoring Program for the period of extended operation. Additionally, it meets 

the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its 

Fatigue Monitoring Program, which the staff determined in SER Section 3.0.3.1.18 is consistent 

with GALL Report AMP X.M1, to manage metal fatigue to ensure that the allowable design limits 

on fatigue usage are not exceeded during the period of extended operation; otherwise, the 

applicant will take corrective actions in accordance with its program.

4.3.1.1.3 UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing metal fatigue for the RV. 

The staff reviewed LRA Section A.2.2.1 consistent with SRP-LR Section 4.3.3.2, which states

that the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address RV fatigue 

analyses, as required by 10 CFR 54.21(d).
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4.3.1.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with the requirements of 10 CFR 54.21(c)(1)(iii), that the effects of 

fatigue for the RV will be adequately managed by the Fatigue Monitoring Program for the period 

of extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.3.1.2 Reactor Vessel Feedwater Nozzle

4.3.1.2.1 Summary of Technical Information in the Application

LRA Section 4.3.1.2 describes the applicant’s TLAA for metal fatigue of the RV FW nozzle. The 

LRA states that, as described in UFSAR Section 5.3.3.1.4.5.1, the FW nozzle design includes 

features to eliminate thermal fatigue concerns identified in previous BWR FW nozzle designs. 

This included a second piston ring and triple thermal sleeves being incorporated into the design 

of the nozzle. The LRA also states that the analysis of the FW nozzle determined the fatigue 

usage from potential rapid cycling behind the thermal sleeves that is added to the fatigue usage 

based on monitored plant transients.

The applicant dispositioned the metal fatigue TLAA for the RV FW nozzle in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue for these nozzles will be 

adequately managed for the period of extended operation.

4.3.1.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of the RV FW nozzles and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.3.3.1.1.3, 

which states that the reviewer should verify that the applicant has identified the appropriate 

program, as described and evaluated in the GALL Report, and included an assessment of the 

TLAA information against relevant design basis and CLB information.

The staff noted that LRA Section A.2.2.1 states that the applicant implemented a plant 

modification before plant operation to eliminate concerns identified in previous BWR designs for 

the FW nozzle. Furthermore, the analysis for this modification included fatigue from potential 

rapid cycling behind the thermal sleeves; therefore, the FW nozzle analysis contains a 

location-specific rapid cycling fatigue usage that is added to the cycle-based fatigue usage. The 

LRA also states that the FW nozzle will be re-evaluated for EAF and will consider the effects of 

potential rapid cycling as necessary.

However, the staff noted that the LRA did not explain how the potential rapid cycling will be 

considered in the reanalysis and under what condition it is considered “necessary.” In addition, 

LRA Section A.2.2.1 did not provide an adequate summary description of the activities for 

managing the effects of rapid cycling for the RV FW nozzle. By letter dated May 24, 2012, the 

staff issued RAI 4.3-10 requesting the applicant to provide additional information related to the 

incorporation of rapid cycling in the reanalysis of the FW nozzle and to revise LRA 

Section A.2.2.1 to provide an adequate summary description related to aging management of 

rapid cycling.

In its response dated June 21, 2012, the applicant stated that the reanalysis of the FW nozzle 

for consideration of the effects on fatigue of the reactor water environment EAF will consider the 
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effects of rapid cycling based on thermal duty maps (i.e., flow rates and time spent at different 

FW and vessel temperatures). The applicant stated that plant operational data will be used in 

the analysis to account for actual historical operation and the effects of rapid cycling on the FW

nozzle will be considered for any operating condition in which there is FW flow. In addition, the 

applicant revised LRA Section A.2.2.1 to provide a summary description of how it intends to 

manage rapid cycling and include it into the reanalysis for the FW nozzle.

The staff noted that the phenomena of rapid cycling of the FW nozzle is the result of small 

thermal amplitude and high frequency temperature changes caused by the mixing of hotter 

reactor coolant with colder incoming FW at the nozzle annulus that impinges on the FW nozzle 

wall, causing thermal cycling of the metal surface. Based on the circumstances that rapid 

cycling occurs at the FW nozzle and the applicant’s resolution to GL 81-11 that addressed 

potential cracking at FW nozzle, the staff finds it appropriate that the applicant will consider 

rapid cycling based on actual historical operational data of reactor coolant and incoming FW

temperatures to determine the accrued fatigue usage in the EAF reanalysis. In addition, the 

staff finds it appropriate that rapid cycling will be considered in the EAF reanalysis for any 

transient with operating condition in which there is FW flow to determine the contribution to 

fatigue usage from the mixing of hotter reactor coolant with colder incoming FW.

The staff finds the applicant’s response to RAI 4.3-10 acceptable because (a) the applicant is 

considering transients (e.g., rapid cycling of the FW nozzle) that cause cyclic strains that are 

significant contributors to the fatigue usage consistent with GALL Report AMP X.M1, (b) the 

applicant’s method for incorporating rapid cycle of the FW nozzle is appropriate, as described 

above, and (c) the applicant revised LRA Section A.2.2.1 to provide an adequate summary 

description for aging management of rapid cycling for the FW nozzle. The staff’s concern 

described in RAI 4.3-10 is resolved.

The staff’s review of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.1.18. The staff determined that the program includes three monitoring methods 

(cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring) that are 

capable of managing metal fatigue and EAF during the period of extended operation. The staff 

also determined that the use of these three monitoring methods is conservative and 

progressively provides a more refined monitoring approach to manage metal fatigue and EAF to 

ensure that the applicable allowable design limits are not exceeded. The staff determined that 

these characteristics of the applicant’s Fatigue Monitoring Program are consistent with GALL

Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the reactor FW

nozzles analyzed in accordance with ASME Code Section III will be adequately managed by the 

Fatigue Monitoring Program for the period of extended operation. Additionally, it meets the 

acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue 

Monitoring Program, which the staff determined in SER Section 3.0.3.1.18 is consistent with 

GALL Report AMP X.M1, to manage metal fatigue to ensure that the allowable design limits on 

fatigue usage are not exceeded during the period of extended operation; otherwise, the 

applicant will take corrective actions in accordance with its program.

4.3.1.2.3 UFSAR Supplement

LRA Section A.2.2.1, as amended by letter dated June 21, 2012, provides the UFSAR 

supplement summarizing metal fatigue for the reactor FW nozzle. The staff reviewed LRA 
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Section A.2.2.1 consistent with SRP-LR Section 4.3.3.2, which states that the reviewer should 

verify that the applicant has provided information to be included in the UFSAR supplement that 

includes a summary description of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address reactor FW

nozzle fatigue analyses, as required by 10 CFR 54.21(d).

4.3.1.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, in accordance with the requirements of 10 CFR 54.21(c)(1)(iii), that the effects of 

fatigue for the reactor FW nozzles will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. The staff also concludes that the UFSAR 

supplement contains an adequate summary description of the evaluated TLAAs, as required by 

10 CFR 54.21(d).

4.3.1.3 Reactor Pressure Vessel Internals

4.3.1.3.1 Summary of Technical Information in the Application

LRA Section 4.3.1.3 describes the applicant’s TLAA for metal fatigue of RPV internals. The 

LRA states that the RPV internals consist of the core support structure and non-core support 

structure components. Furthermore, the core support structure components are ASME Code 

components; however, the ASME Code requirements do not apply to the non-core support 

structure components, but the methods of the ASME Code were used in their design. The LRA 

also states that the original analyses for the core support structure used the 1974 edition with 

addenda up to and including the Summer 1976 Addenda.

The applicant dispositioned the metal fatigue TLAA for RPV internals in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue for the RPV internals will be 

adequately managed for the period of extended operation.

4.3.1.3.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of the RPV internals and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.3.3.1.1.3, 

which states that the reviewer should verify that the applicant has identified the appropriate 

program as described and evaluated in the GALL Report and included an assessment of the 

TLAA information against relevant design basis and CLB information.

LRA Section 4.3.1.3 did not identify the transients that were used for the RPV internals; 

therefore, the staff cannot verify the adequacy of the disposition of the fatigue TLAA for the RPV 

internals in accordance with 10 CFR 54.21(c)(1)(iii). By letter dated May 24, 2012, the staff 

issued RAI 4.3-7 requesting the applicant to identify the transients and associated design cycles 

used for the RVI fatigue analyses and confirm that these transients are included in the Fatigue 

Monitoring Program.

In its response dated June 21, 2012, the applicant confirmed that the transients and associated 

design cycles used in the fatigue analysis of the RVI are the same as those used in the fatigue 
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analysis of the RCS pressure boundary components. Furthermore, these transients and 

associated design cycles are listed in LRA Table 4.3-1 and are included in the Fatigue 

Monitoring Program. The staff noted that the applicant’s Fatigue Monitoring Program monitors 

the transients listed in LRA Table 4.3-1, which are used as inputs into the fatigue analyses of 

the RCS pressure boundary components and RPV internals, to ensure that corrective actions 

are taken before a design cycle limit or the design limit on fatigue usage is exceeded.

The staff finds the applicant’s response to RAI 4.3-7 acceptable because it confirmed that the 

transients used as inputs in the fatigue analyses of the RPV internals are already listed in 

LRA 4.3-1 and are monitored by the Fatigue Monitoring Program. The staff’s concern described 

in RAI 4.3-7 is resolved.

The staff reviewed LRA Table 4.3-3 and noted that the CUF values for the RPV internals are 

less than 1.0. The staff noted that, while these CUF values are less than the design limit of 1.0, 

the applicant has proposed managing fatigue of these components with its Fatigue Monitoring 

Program to ensure that fatigue is managed and the design limits are not exceeded during the 

period of extended operation. The staff’s review of the applicant’s Fatigue Monitoring Program 

is documented in SER Section 3.0.3.1.18. The staff determined that the program includes three 

monitoring methods (cycle counting, cycle-based fatigue monitoring, and stress-based fatigue 

monitoring) capable of managing metal fatigue and EAF during the period of extended 

operation. The staff also determined that the use of these three monitoring methods is 

conservative and progressively provides a more refined monitoring approach to manage metal 

fatigue and EAF to ensure that the applicable allowable design limits are not exceeded. The 

staff determined that these characteristics of the applicant’s Fatigue Monitoring Program are 

consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the RPV internals 

analyzed for metal fatigue will be adequately managed by the Fatigue Monitoring Program for 

the period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.1.3 because the applicant is crediting its Fatigue Monitoring Program, which the 

staff determined in SER Section 3.0.3.1.18 is consistent with GALL Report AMP X.M1, to 

manage metal fatigue to ensure that the allowable design limits on fatigue usage are not 

exceeded during the period of extended operation; otherwise, the applicant will take corrective 

actions in accordance with its program.

4.3.1.3.3 UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing metal fatigue for the RPV

internals. The staff reviewed LRA Section A.2.2.1 consistent SRP-LR Section 4.3.3.2, which 

states that the reviewer should verify that the applicant has provided information to be included 

in the UFSAR supplement that includes a summary description of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address RPV internal

fatigue analyses, as required by 10 CFR 54.21(d).
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4.3.1.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue for the RPV 

internals will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.3.1.4 Reactor Recirculation Pumps

4.3.1.4.1 Summary of Technical Information in the Application

LRA Section 4.3.1.4 describes the applicant’s TLAA for metal fatigue of the reactor recirculation 

pumps. The LRA states that UFSAR Section 3.9.1.2.1.4 describes the Byron-Jackson 

recirculation pump fatigue analysis. This analysis for the reactor recirculation pump casing 

considered the RCS fatigue transients specified by GE, justified exempting portions of the 

casing from analysis and determined that the remaining locations met 1974 ASME Code 

Section III fatigue requirements.

The applicant dispositioned the metal fatigue TLAA for the reactor recirculation pumps in 

accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue for reactor 

recirculation pumps will be adequately managed for the period of extended operation.

4.3.1.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of the reactor recirculation pumps and 

the corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR 

Section 4.3.3.1.1.3, which states that the reviewer should verify that the applicant has identified 

the appropriate program as described and evaluated in the GALL Report and included an 

assessment of the TLAA information against relevant design basis and CLB information.

LRA Section 4.3.1.4 states that the fatigue analysis for the Byron-Jackson reactor recirculation 

pump casing considered the transients specified by GE and this analysis justified exempting 

portions of the case from analysis. In addition, it also determined that the remaining locations 

met 1974 ASME Code Section III fatigue requirements. The staff noted that LRA 

Section 4.3.1.4 and UFSAR Section 3.9.1.2.1.4 did not provide information about the locations 

of the pump casing that were exempt from a fatigue analysis and the locations that met 1974 

ASME Code Section III fatigue requirements. In addition, the applicant did not explain how the 

locations were determined to be exempt and whether the Fatigue Monitoring Program ensures 

that the assumptions associated with this determination will continue to remain valid during the 

period of extended operation.

By letter dated May 24, 2012, the staff issued RAI 4.3-11 requesting the applicant to provide 

additional information about the locations and the provision that permitted the fatigue 

requirement exemptions for the Byron-Jackson reactor recirculation pump casing. In addition, 

the applicant was requested to justify whether or not this exemption for a fatigue analysis needs 

to be identified as a TLAA and to explain how the exemptions will remain valid during the period 

of extended operation. The staff also requested information for the locations that met 1974 

ASME Code Section III fatigue requirements and the locations in the pump cover that were later 

reanalyzed because of modifications to install shaft sleeves and modify the seal water 

heat exchanger.
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In its response dated June 21, 2012, the applicant confirmed that the pump casing was exempt 

from fatigue analysis per ASME Code Section III NB-3222.4(d) and the only component in the 

pump cover assembly requiring analysis was the seal water heat exchanger. The staff noted 

that an analysis for cyclic service is not required if the six criteria specified in ASME Code 

Section III NB-3222.4(d) are met, which include conditions associated with atmospheric to 

service pressure cycle, normal service pressure fluctuation, temperature differences during 

startup and shutdown cycles and normal service, temperature difference in DM weld, and 

mechanical loads. The applicant stated that since this determination considered the assumed 

number of transients specified by GE, this evaluation for a fatigue analysis exemption is treated 

as a TLAA. By tracking cycles associated with the exemption against the allowable numbers of 

cycles with the Fatigue Monitoring Program, the applicant stated this will ensure that this 

exemption will remain valid during the period of extended operation.

The staff noted the transients specified by GE that were used in this exemption and the RCS

are the same and are monitored by the applicant’s Fatigue Monitoring Program; therefore, the 

staff finds it acceptable that the applicant is using this program to ensure that this exemption 

remains valid during the period of extended operation. In addition, the staff finds the applicant’s 

approach to manage this exemption acceptable because the applicant provided an 

enhancement to its Fatigue Monitoring Program to ensure the validity of this exemption analysis 

during the period of extended operation. The staff’s review of the Fatigue Monitoring Program is 

documented in SER Section 3.0.3.1.18.

The applicant stated that the seal water heat exchanger on the pump cover in its original 

configuration was analyzed in 1980 using the 1974 ASME Code Section III fatigue 

requirements. The staff noted that, following modifications to install shaft sleeves and to modify 

the seal water heat exchanger, the CUF also was determined to be less than 1.0.

The staff finds the applicant’s response to RAI 4.3-11 acceptable because it identified the 

components of the reactor recirculation pump that were subject to the exemption and to a 

fatigue analysis. Further, the applicant enhanced its Fatigue Monitoring Program to ensure that 

corrective actions are taken if the validity of the fatigue exemption is challenged during the 

period of extended operation, and the applicant’s Fatigue Monitoring Program is managing 

those transients that are contributors to the CUF value for the shaft sleeves and modified seal 

water heat exchanger on the pump cover. The staff’s concern described in RAI 4.3-11 

is resolved.

The staff’s review of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.1.18. The staff determined that the program includes three monitoring methods 

(cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring) that are 

capable of managing metal fatigue and EAF during the period of extended operation. The staff 

also determined that the use of these three monitoring methods is conservative and 

progressively provides a more refined monitoring approach to manage metal fatigue and EAF to 

ensure that the applicable allowable design limits are not exceeded. The staff determined that 

these characteristics of the applicant’s Fatigue Monitoring Program are consistent with GALL

Report AMP X.M1.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of fatigue on the intended functions of the reactor recirculation pumps will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation. Additionally, 

it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because the applicant is crediting 

its Fatigue Monitoring Program, which the staff determined in SER Section 3.0.3.1.18 is 
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consistent with GALL Report AMP X.M1, to manage metal fatigue to ensure that the allowable 

design limits on fatigue usage are not exceeded during the period of extended operation; 

otherwise, the applicant will take corrective actions in accordance with its program.

4.3.1.4.3 UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing metal fatigue for the reactor 

recirculation pumps. The staff reviewed LRA Section A.2.2.1 consistent with SRP-LR 

Section 4.3.3.2, which states that the reviewer should verify that the applicant has provided 

information to be included in the UFSAR supplement that includes a summary description of the 

TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address reactor 

recirculation pump fatigue analyses, as required by 10 CFR 54.21(d).

4.3.1.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue for the reactor 

recirculation pumps will be adequately managed by the Fatigue Monitoring Program for the 

period of extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.3.1.5 Control Rod Drives

4.3.1.5.1 Summary of Technical Information in the Application

LRA Section 4.3.1.5 describes the applicant’s TLAA for metal fatigue of the CRDs. The LRA 

states that the Class 1 portions of the CRDs were analyzed for fatigue and that the CUF values 

are low and the tracking of cycles under the Fatigue Monitoring Program ensures the fatigue on 

these components remains acceptable. LRA Table 4.3-4 provides the CUF values for the 

Class 1 CRD components.

The applicant dispositioned the metal fatigue TLAA for the CRDs in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue for these components will be 

adequately managed for the period of extended operation.

4.3.1.5.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of the CRDs and the corresponding 

disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.3.3.1.1.3, which states

that the reviewer should verify that the applicant has identified the appropriate program as 

described and evaluated in the GALL Report and included an assessment of the TLAA 

information against relevant design basis and CLB information.

The staff reviewed LRA Table 4.3-4 and noted that the CUF values for the CRD components 

are significantly less than 1.0, with the highest being 0.2 for the lower piston tube threads. The 

staff noted that while these CUF values are low such that the design limit of 1.0 should not be 

exceeded, the applicant has proposed managing fatigue of these components with its Fatigue 
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Monitoring Program to ensure that fatigue is managed and the design limits are not exceeded 

during the period of extended operation. The staff’s review of the applicant’s Fatigue Monitoring 

Program is documented in SER Section 3.0.3.1.18. The staff determined that the program 

includes three monitoring methods (cycle counting, cycle-based fatigue monitoring, and 

stress-based fatigue monitoring) that are capable of managing metal fatigue and EAF during the 

period of extended operation. The staff also determined that the use of these three monitoring 

methods is conservative and progressively provides a more refined monitoring approach to 

manage metal fatigue and EAF to ensure that the applicable allowable design limits are not 

exceeded. The staff determined that these characteristics of the applicant’s Fatigue Monitoring 

Program are consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the CRD

components will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 

because the applicant is crediting its Fatigue Monitoring Program, which the staff determined in 

SER Section 3.0.3.1.18 is consistent with GALL Report AMP X.M1, to manage metal fatigue to 

ensure that the allowable design limits on fatigue usage are not exceeded during the period of 

extended operation; otherwise, the applicant will take corrective actions in accordance with its 

program.

4.3.1.5.3 UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing metal fatigue for the reactor 

CRDs. The staff reviewed LRA Section A.2.2.1 consistent with SRP-LR Section 4.3.3.2, which 

states that the reviewer should verify that the applicant has provided information to be included 

in the UFSAR supplement that includes a summary description of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address reactor CRD

fatigue analyses, as required by 10 CFR 54.21(d).

4.3.1.5.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue for the CRD

components will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

adequate summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).

4.3.1.6 Class 1 Piping

4.3.1.6.1 Summary of Technical Information in the Application

LRA Section 4.3.1.6 describes the applicant’s TLAA for metal fatigue of the Class 1 piping. The 

LRA states that the components of the RCPB whose failure could cause a loss of reactor 

coolant at a rate in excess of the normal makeup system capability are ASME Code Section III 

Class 1 components. The LRA provided a table of Class 1 systems and the associated piping 

and instrumentation diagram for the LRA. The LRA also states that its ASME Code Class 1 

piping specifications identified that the piping must be analyzed for the cycles identified on GE
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transient cycle drawings and a detailed fatigue analysis was generated to analyze multiple 

locations on each system within the ASME Class 1 boundary. LRA Table 4.3-5 provides the 

highest CUF value identified in the analyses for each system containing Class 1 piping and is 

from the analysis of record, which does not include the effects of reactor water environment 

EAF, which is evaluated in LRA Section 4.3.3. The Fatigue Monitoring Program will monitor the 

cycles actually incurred to ensure that action is taken if the actual cycles approach their 

analyzed numbers.

The applicant dispositioned the metal fatigue TLAA for Class 1 piping in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue for these components will be 

adequately managed for the period of extended operation.

4.3.1.6.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for metal fatigue of Class 1 piping and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.3.3.1.1.3, 

which states that the reviewer should verify that the applicant has identified the appropriate 

program as described and evaluated in the GALL Report and included an assessment of the 

TLAA information against relevant design basis and CLB information.

The staff noted that LRA Table 4.3-5 provides a CUF value of 0.4138 for the FW piping; 

however, LRA Table 4.3-6 provides a CUF value of 0.2228 for the FW piping. It is not clear to 

the staff why there is a discrepancy between the CUF values for the FW piping in the LRA 

tables and why the EAF evaluation used the lower CUF value of 0.2228, instead of 0.4138. The 

staff noted that if the environmental fatigue life correction factor (Fen) value provided in LRA

Table 4.3-6 was used with the CUF value of 0.4138, the CUFen exceeds the ASME Code limit 

of 1.0. In addition, it is not clear to the staff why the CUF value for the LPCS RV nozzle, HPCS 

RV nozzle, and RV nozzle-RHR are all the same. By letter dated May 24, 2012, the staff issued

RAI 4.3-12 requesting the applicant to clarify these discrepancies for the FW piping and the 

LPCS RV nozzle, HPCS RV nozzle, and RV nozzle-RHR.

In its response dated June 21, 2012, the applicant clarified that the correct FW piping CUF 

value was determined to be 0.2228 and that LRA Table 4.3-5 has been revised with the correct 

value. With the revision to the LRA, the staff noted that the CUF values for the FW piping in 

LRA Tables 4.3-5 and 4.3-6 are consistent and the use of this CUF value in the EAF evaluation 

for the FW piping is appropriate. Based on the applicant’s response, the staff noted that the 

CUF values for the LPCS RV nozzle, HPCS RV nozzle, and RV nozzle-RHR were evaluated by 

a common analysis during its original design; thus, the staff finds it reasonable that these 

nozzles would have the same CUF value of 0.564. The staff noted that this approach of using a 

bounding analysis to be representative of several components (e.g., the LPCS RV nozzle, 

HPCS RV nozzle, and RV nozzle-RHR) is typical during the original design of the plant because 

of the similarities of the components (e.g., material, stress and loading, effects from thermal and 

pressures transients).

The staff finds the applicant’s response to RAI 4.3-12 acceptable because the applicant 

confirmed that the correct CUF value for the FW piping was used in the EAF evaluation and the 

applicant explained that the CUF values for the LPCS and HPCS RV nozzle and RV

nozzle-RHR were evaluated by one analysis and thus share the same CUF value. The staff’s

concern described in RAI 4.3-12 is resolved.
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The staff reviewed LRA Table 4.3-5 and noted that the CUF values for the Class 1 system 

components are less than 1.0. The staff noted that while these CUF values are less than the 

design limit of 1.0, the applicant has proposed managing fatigue of these components with its 

Fatigue Monitoring Program to ensure that fatigue is managed and the design limits are not 

exceeded during the period of extended operation. The staff’s review of the applicant’s Fatigue 

Monitoring Program is documented in SER Section 3.0.3.1.18. The staff determined that the 

program includes three monitoring methods (cycle counting, cycle-based fatigue monitoring,

and stress-based fatigue monitoring) that are capable of managing metal fatigue and EAF

during the period of extended operation. The staff also determined that the use of these three 

monitoring methods is conservative and progressively provides a more refined monitoring 

approach to manage metal fatigue and EAF to ensure that the applicable allowable design limits 

are not exceeded. The staff determined that these characteristics of the applicant’s Fatigue 

Monitoring Program are consistent with GALL Report AMP X.M1.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of fatigue on the intended functions of the Class 1 piping analyzed for metal fatigue will 

be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation. Additionally, it meets the acceptance criteria in SRP-LR Section 4.3.2.1.1.3 because 

the applicant is crediting its Fatigue Monitoring Program, which the staff determined in SER 

Section 3.0.3.1.18 is consistent with GALL Report AMP X.M1, to manage metal fatigue to 

ensure that the allowable design limits on fatigue usage are not exceeded during the period of 

extended operation; otherwise, the applicant will take corrective actions in accordance with its 

program.

4.3.1.6.3 UFSAR Supplement

LRA Section A.2.2.1 provides the UFSAR supplement summarizing metal fatigue for Class 1 

piping. The staff reviewed LRA Section A.2.2.1 consistent with SRP-LR Section 4.3.3.2, which 

states that the reviewer should verify that the applicant has provided information to be included 

in the UFSAR supplement that includes a summary description of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address reactor Class 1 

piping fatigue analyses, as required by 10 CFR 54.21(d).

4.3.1.6.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue for Class 1 piping 

will be adequately managed by the Fatigue Monitoring Program for the period of extended 

operation. The staff also concludes that the UFSAR supplement contains an adequate 

summary description of the evaluated TLAAs, as required by 10 CFR 54.21(d).
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4.3.2 Non-Class 1 Fatigue

4.3.2.1 Non-Class 1 Fatigue – Piping and In-Line Components

4.3.2.1.1 Summary of Technical Information in the Application

LRA Section 4.3.2.1.describes the applicant’s non-Class 1 piping and in-line component fatigue 

analyses. The LRA states that the impact of thermal cycles on non-Class 1 components is 

addressed in the calculation of the allowable stress range. The design of ASME Code 

Section III Class 2 and 3 or ANSI B31.1 piping systems incorporates a stress range reduction 

factor for piping design for thermal stresses. 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. 

For many plant systems, significant temperature cycles are coincident with plant heatups and 

cooldowns. In addition, there are other plant systems with transients that occur independently 

of plant heatups and cooldowns.

The applicant dispositioned the metal fatigue TLAA for non-Class 1 piping and in-line 

components in accordance with 10 CFR 54.21(c)(1)(i), that the non-Class 1 piping stress 

calculations remain valid for the period of extended operation.

4.3.2.1.2 Staff Evaluation

The staff reviewed the applicant’s metal fatigue TLAA for non-Class 1 piping and in-line 

components and the corresponding disposition of 10 CFR 54.21(c)(1)(i) consistent with SRP-LR 

Section 4.3.3.1.2.1, which states that relevant information in the TLAA, operating plant transient 

history, design basis, and CLB is reviewed to verify that the maximum allowable stress range 

values for the existing fatigue analysis remain valid for the period of extended operation and the 

allowable limit for full thermal range transients will not be exceeded during the period of 

extended operation.

The applicant stated that for many plant systems, significant temperature cycles are coincident 

with plant heatups and cooldowns. The staff noted that these same plant systems can also 

experience significant temperature cycles coincident with the design transients of the plant, 

which are listed in LRA Table 4.3-1. The staff noted that the total number of transients that 

occurred until May 26, 2012, for the design transient set was significantly less than the 

7,000-cycle limit. The staff also noted that the total number of transients expected to occur 

through 60 years of operation for the design transient set is still significantly less than the 

7,000-cycle limit. In both instances, the staff finds that there is significant margin between the 

total number of transients and the 7,000-cycle limit; therefore, the staff finds that there is margin 

to account for unanticipated cycles for the design limits while maintaining the 7,000-cycle limit 

for these non-Class 1 piping and in-line components. The applicant stated that the control rod 

drive system experiences temperature changes during a plant trip. The staff noted that the 

design transients listed in LRA Table 4.3-1 that would be associated with plant trips is 

significantly less than the 7,000-cycle limit, with margin to account for unanticipated plant trips 

through the period of extended operation.

For other systems with transients that occur independent of plant heatups and cooldowns, the 

applicant stated that the emergency diesel generators and fire pump diesel engine are tested 

periodically (approximately monthly), which will not result in the total number of cycles 

exceeding 7,000. The staff noted that the estimated usage of the emergency diesel generators 
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and fire pump diesel engine, which are not normally in service, through 60 years of operation is 

based on periodic surveillance testing and in response to infrequent abnormal operating 

conditions of the system. The staff noted that since these events occur infrequently, it is 

conservative to assume that the emergency diesel generators and fire pump diesel engine run 

no more than five times per year in response to these abnormal operating conditions of the 

system. The staff noted that the number of cycles through the period of extended operation for 

the emergency diesel generators and fire pump diesel engine is expected to be no more than 

15 percent of the 7,000 allowable cycles; therefore, the staff finds that there is a significant 

margin to account for unanticipated cycles for these components through the period of extended 

operation.

For the water sampling system, the applicant stated that it primarily samples using a continuous 

flow stream that is not isolated between samples. The staff noted that since samples are taken 

from a continuous flow stream that is not isolated between samples, it does not cause a thermal 

cycle for each sample taken. The applicant stated that special samples may be drawn 

infrequently through isolated lines. The staff noted that these samples would result in a thermal 

cycle because they are taken through isolated lines rather than a continuous flow stream. Since 

samples are not normally taken in such a way that would cause a thermal cycle and special 

samples, which cause a thermal cycle, are infrequently taken, the staff finds it reasonable that 

the 7,000-cycle limit will not be exceeded during the period of extended operation.

The staff finds the applicant has demonstrated, in accordance with the requirements of

10 CFR 54.21(c)(1)(i), that the TLAAs for fatigue of non-Class 1 piping and in-line components, 

remain valid for the period of extended operation. Additionally, the applicant meets the 

acceptance criteria in SRP-LR Section 4.3.2.1.2.1 because the expected total number of full 

thermal range transients over the period of extended operation for non-Class 1 piping and 

in-line components does not exceed the 7,000-cycle limit, with significant margin to account for 

unanticipated cycling.

4.3.2.1.3 UFSAR Supplement

LRA Section A.2.2.2, as amended by letter dated February 29, 2012, provides the UFSAR 

supplement summarizing the TLAA for fatigue of non-Class 1 piping and in-line components. 

The staff reviewed LRA Section A.2.2.2 consistent with SRP-LR Section 4.3.3.2, which states

that the reviewer should verify that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of the TLAA.

Based on its review of the UFSAR supplement, the staff finds that the supplement meets the 

acceptance criteria in SRP-LR Section 4.3.2.2. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the TLAA of 

non-Class 1 piping and in-line components, as required by 10 CFR 54.21(d).

4.3.2.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, as required by 10 CFR 54.21(c)(1)(i), that the fatigue analyses of non-Class 1 

piping and in-line components remain valid for the period of extended operation. The staff also 

concludes that the UFSAR supplement contains an adequate summary description of the 

evaluated TLAAs, as required by 10 CFR 54.21(d).
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4.3.2.2 Non-Class 1 Fatigue – Non-Piping Components

4.3.2.2.1 Summary of Technical Information in the Application

LRA Section 4.3.2.2.describes the applicant’s non-Class 1 non-piping component fatigue 

analyses. The LRA states that non-Class 1 components other than piping system components 

require fatigue analyses if they were built to a section of the code such as ASME Section III, 

NC-3200 or ASME Code Section VIII, Division 2. The applicant’s review of the non-Class 1 

components other than piping identified non-Class 1 fatigue analysis applicable to 

expansion joints.

The applicant dispositioned the metal fatigue TLAA for non-Class 1 non-piping components in 

accordance with 10 CFR 54.21(c)(1)(i), that the non-Class 1 non-piping component stress 

calculations remain valid for the period of extended operation.

4.3.2.2.2 Staff Evaluation

The staff reviewed the applicant’s metal fatigue TLAA for non-Class 1 non-piping components 

and the corresponding disposition of 10 CFR 54.21(c)(1)(i) consistent with SRP-LR 

Section 4.3.3.1.2.1, which states that relevant information in the TLAA, operating plant transient 

history, design basis, and CLB is reviewed to verify that the maximum allowable stress range 

values for the existing fatigue analysis remain valid for the period of extended operation and that 

the allowable limit for full thermal range transients will not be exceeded during the period of 

extended operation.

LRA Section 4.3.2.2 states a review of the non-Class 1 non-piping components identified fatigue 

analysis applicable to expansion joints. In addition, an evaluation of these analyses determined 

the number of cycles were adequate for 60 years of operation. However, the staff noted that the 

LRA did not identify the cycles or transients that these expansion joints were analyzed for and 

information regarding the number of occurrences for these cycles through the period of 

extended operation to support the disposition in accordance with 10 CFR 54.21(c)(1)(i). By 

letter dated May 24, 2012, the staff issued RAI 4.3-5 requesting the applicant to identify the 

cycles or transients that were considered as an input to the fatigue analyses of the expansion 

joints. In addition, the applicant was requested to justify the evaluation, referenced in LRA 

Section 4.3.2.2, which was performed for these expansion joint analyses that determined the 

number of cycles were adequate for 60 years of operation.

In its response dated June 21, 2012, the applicant stated that the cycles identified in the 

expansion joint design specifications varied by the location and use of the expansion joint as 

well as the level of complexity of the design specification. Furthermore, for simplicity, some 

locations specified a large number of thermal or dynamic cycles at the maximum joint expansion 

expected under any conditions. The applicant clarified that these components are not within the 

RCPB so there is no TS or UFSAR requirement to track the associated transients. Therefore, 

accumulated numbers of cycles are available only for cycles that also must be tracked for 

Class 1 components, such as SRV lifts and earthquakes (information regarding these transients 

are in LRA Table 4.3-1).

The applicant also stated that the allowable numbers of cycles for the other transients are well 

beyond reasonably postulated numbers of the transients, making it unnecessary to monitor 

these transients. The applicant explained that the design specifications identified a 

conservative number of cycles at a given amount of expansion so that simplified analyses could 
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be performed and the typical analysis shows the expansion joint is qualified for many more 

cycles than was specified with these simplified bounding assumptions. The applicant reiterated 

that it completed a review of these analyses to verify the expansion joints are adequate for 

60 years.

However, the applicant did not provide the number of cycles that the design specifications 

identified for non-Class 1 expansion joints and the expected number of cycles through the 

period of extended operation; therefore, the staff was not able to verify the adequacy of the 

disposition of the TLAA in accordance with 10 CFR 54.21(c)(1)(i). By letter dated 

August 7, 2012, the staff issued follow-up RAI 4.3-5a requesting information for the number of 

cycles that the design specifications identified for non-Class 1 expansion joints and the 

expected number of cycles through the period of extended operation. In addition, the applicant 

was asked to describe the details of the review that was completed for these expansion joint 

fatigue analyses to verify that the components are adequate for 60 years of operation and to 

justify that this review and evaluation demonstrate the disposition in accordance with 

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

In its response dated September 4, 2012, the applicant provided a table listing its non-Class 1 

expansion joints. For several of these expansion joints, the applicant provided the usage factor 

associated with the design cycles and the applicant explained that, based on the usage factor,

these expansion joints are acceptable for many more cycles than specified. Furthermore, for

other expansion joints without usage factors, the applicant provided the number of cycles for 

which the specific expansion joint was designed or qualified. As part of the evaluation, the 

applicant stated that the expansion joints without usage factors were qualified to a number of 

cycles that is greater than the design cycles; therefore, the expansion joints are acceptable for 

many more cycles than specified.

The staff noted that although the expansion joints may have a low usage factor when compared 

to the design limit of 1.0, the low usage factor by itself does not support the disposition that the 

analysis remains valid for the period of extended operation. Similarly, the staff noted a 

component being “qualified” for many more cycles compared to the design cycles does not 

support the disposition that the analysis, which is based on the number of design cycles, 

remains valid for the period of extended operation (i.e., 10 CFR 54.21(c)(1)(i)). Furthermore, 

the applicant also did not provide AMR results in the LRA for these expansion joints subject to 

metal fatigue.

By letter dated October 3, 2012, the staff issued Follow-up RAI 4.3-5b requesting the applicant 

provide adequate justification for the disposition of 10 CFR 54.21(c)(1)(i), by demonstrating that 

the design number of cycles used in the original analysis will not be exceeded during the period 

of extended operation or, revise the TLAA disposition with adequate justification. The applicant 

was also requested to provide the AMR results for all non-Class 1 expansion joints in 

accordance with 10 CFR 54.21(a)(1).

In its response dated October 22, 2012, the applicant revised the TLAA disposition of certain

expansion joints that have CUF values for their fatigue design. The applicant has multiplied its 

40-year design CUF values by 1.5 to obtain the 60-year projected CUF values and concluded 

that the 60-year CUF values would not exceed the design limit of 1.0 and, therefore, 

dispositioned the TLAA in accordance with 10 CFR 54.21(c)(1)(ii). The staff’s review of the 

applicant’s dispositions for the TLAAs associated with these non-Class 1 expansion joints with 

CUF values are discussed later. However, the applicant did not revise the UFSAR supplement 

in LRA Section A.2.2.2 indicating that, for these expansion joints, the metal fatigue TLAA has 
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been projected to the end of the period of extended operation in accordance with

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

The applicant did not demonstrate that the design number of cycles used in the original analysis 

of the expansion joints in the standby liquid control (at tank outlet and pump inlets), high 

pressure core spray (diesel exhaust), and compressed air (air accumulators) will not be 

exceeded during the period of extended operation.

By letter dated November 30, 2012, the staff issued RAI 4.3-5c requesting the applicant provide, 

for expansion joints discussed above, adequate justification for the disposition of 

10 CFR 54.21(c)(1)(i), by demonstrating that the number of cycles used in the design analysis 

will not be exceeded during the period of extended operation. The applicant was also requested 

to revise UFSAR supplement in LRA Section A.2.2.2 indicating that certain metal fatigue TLAAs 

for expansion joints have been projected to the end of the period of extended operation in 

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

In its response dated December 18, 2012, the applicant revised LRA Section A.2.2.2. In 

addition, the applicant clarified that the analysis for the standby liquid control system (at tank 

outlet and pump inlets) expansion joints did not use the design value of cycles (1,000). Instead, 

the analysis used the magnitude of movement (0.125 inch) as an input and determined that 

400,000 cycles are allowed for this component. Therefore, even if the original number of cycles 

in the design specification for this component (1,000) is multiplied by the ratio of 60 years to 

40 years (1.5), the result does not exceed the acceptable qualified value of 400,000 cycles 

determined in the analysis for the component. The staff noted that the analysis qualified the 

component for 400,000 cycles, as opposed to the 1,000 cycles, as previously characterized by 

the applicant. Similarly, the applicant clarified that the analysis for the high pressure core spray 

diesel exhaust expansion joints determined that 4000 cycles are allowed for this component. 

Therefore, even if the original number of cycles in the design specification for this component 

(1,200) is multiplied by the ratio of 1.5, the result does not exceed the acceptable qualified value 

of 4,000 cycles. The applicant also clarified that the analysis for the expansion joints of the 

compressed air accumulators determined that 10,000 cycles are allowed for this component. 

Therefore, even if the original number of cycles expected in the design specification for this 

component (700) is multiplied by the ratio of 1.5, the result does not exceed the acceptable 

qualified value of 10,000 cycles.

The staff finds the use of the 1.5 factor for projecting future transient occurrence for these 3 sets 

of expansion joints described above to be reasonable because the resulting estimated 60-year 

occurrence provides a gauge of the margin available prior to the qualified limit being reached. 

In any event, the number of expected cycles through the period of extended operation is 

expected to be no more than 45 percent of the qualified cycles; therefore, there is a sufficient 

amount of margin to account for unanticipated cycles for these expansion joints.

Based on its review, the staff finds the applicant’s response to RAI 4.3-5c acceptable because 

the applicant justified that the cycles experienced by these expansion joints will not exceed the 

qualified number of cycles established in the design analysis during the period of extended 

operation. Furthermore, the staff also finds the applicant’s response acceptable because LRA 

Section A.2.2.2 was revised to accurately summarize and provide the details of how the metal 

fatigue TLAA for non-Class 1 expansion joints with usage factors have been projected to the 

end of the period of extended operation in accordance with 10 CFR 54.21(d). The staff’s 

concerns described in RAIs 4.3-5, 4.3-5a, 4.3-5b, and 4.3-5c are resolved.
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The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(i), that the 

fatigue analyses for expansion joints without usage factors remain valid for the period of 

extended operation. Additionally, the applicant meets the acceptance criteria in SRP-LR 

Section 4.3.2.1.2.1 because the projected total numbers of cycle over the period of extended 

operation for these expansion joints do not exceed the original design limit, with margin to 

account for unanticipated cycling of these components.

The staff reviewed LRA Section 4.3.2.2, as amended by letter dated December 18, 2012, and 

the TLAA for non-Class 1 expansion joints with CUF values to verify that in accordance with 

10 CFR 54.21(c)(1)(ii), the analyses have been projected to the end of the period of extended 

operation.

In its response dated October 22, 2012, the applicant multiplied its 40-year design CUF values 

by 1.5 to obtain the 60-year projected values and concluded that the 60-year CUF values would 

not exceed the design limit of 1.0. The staff noted that the highest 60-year CUF among this set 

of expansion joints is 0.15, which is significantly below the design limit of 1.0. The staff finds 

that 1.5 projection basis provides a reasonable scale to project the 40-year design CUF to 

60 years, and the resulting estimated 60-year CUF provides a gauge of the margin available 

before the design limit of 1.0 is reached.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

fatigue analyses for certain expansion joints with CUF values have been projected to the end of 

the period of extended operation. Additionally, it meets the acceptance criteria of SRP-LR 

Section 4.3.2.1.1.2 because the applicant has demonstrated that the recalculated CUF values 

through 60 years of operation are less than the design limit of 1.0 with margin to account for 

additional fatigue usage.

4.3.2.2.3 UFSAR Supplement

LRA Section A.2.2.2, as amended by letter dated December 18, 2012, provides the UFSAR 

supplement summarizing the TLAA for non-Class 1 non-piping components. The staff reviewed 

LRA Section A.2.2.2 consistent with SRP-LR Section 4.3.3.2, which states that the reviewer 

verifies that the applicant has provided information to be included in the UFSAR supplement 

that includes a summary description of the evaluation of the metal fatigue TLAA.

Based on its review of the UFSAR supplement, as amended by letter dated 

December 18, 2012, the staff finds it meets the acceptance criteria in SRP-LR Section 4.3.2.2, 

and is therefore acceptable. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address non-Class 1 non-piping components, as 

required by 10 CFR 54.21(d).

4.3.2.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses for non-Class 1 

expansion joints without usage factors remain valid for the period of extended operation. The 

staff also concludes that the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), 

that the analyses for non-Class 1 expansion joints with CUF values have 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).
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4.3.3 Effects of Reactor Water Environment on Fatigue Life

4.3.3.1 Summary of Technical Information in the Application

LRA Section 4.3.3.describes the applicant’s evaluation to address the effects of reactor water 

environment on fatigue life. The LRA describes an evaluation for the six locations using 

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

Power Plant Components,” issued February 1995, which addresses the application of 

environmental correction factors to fatigue analyses. Specifically, NUREG/CR-6260, 

Section 5.6, identified certain component locations to be the most sensitive to environmental 

effects for newer vintage GE plants, which are directly relevant to the applicant. The LRA also 

states that additional locations were evaluated beyond the six locations identified in 

NUREG/CR-6260; specifically, the highest usage factor was evaluated in the piping in the FW, 

reactor recirculation, RHR, LPCS, and HPCS systems.

The LRA states that the applicant will review design basis ASME Code Class 1 component 

fatigue evaluations to ensure the GGNS locations evaluated for the effects of the reactor coolant 

environment on fatigue include the most limiting components within the RCPB. The LRA 

provides a list of formulae that will be used to address the environmental effects on fatigue for 

these critical components for carbon and low-alloy steel, austenitic stainless steel, and nickel 

alloy materials. Furthermore, if an acceptable CUF cannot be calculated, the applicant stated it 

will repair or replace the affected locations before exceeding an environmentally adjusted CUF 

of 1.0.

The applicant dispositioned the analyses to address the effects of reactor water environment on 

fatigue life in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of EAF on the intended 

functions of the analyzed components will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation.

4.3.3.2 Staff Evaluation

The staff noted that the applicant addressed the effects of EAF consistent with the guidance in 

the SRP-LR and the staff’s recommendations for resolving Generic Safety Issue No. 190 

(GSI-190), “Fatigue Evaluation of Metal Components for 60-Year Plant Life,” issued

December 1999. The staff also noted that, consistent with Commission Order No. CLI-10-17, 

dated July 8, 2010, the evaluations associated with EAF do not fall within the definition of TLAA 

in 10 CFR 54.3(a) because these evaluations are not in the CLB of GGNS. Nevertheless, the 

applicant has credited its Fatigue Monitoring Program to manage the effects of EAF; therefore, 

the staff reviewed LRA Section 4.3.3 and the evaluations for EAF to verify, in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of EAF will be adequately managed for the period of 

extended operation.

The staff reviewed the applicant’s analyses to address the effects of reactor water environment 

on fatigue life and the corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with 

SRP-LR Section 4.3.3.1.3, which provides guidance for the reviewer to verify that the applicant 

has addressed EAF as part of an AMP formulated in support of license renewal. In addition, the 

SRP-LR provides guidance for verifying that the critical components evaluated for EAF include a 

sample of high fatigue usage locations and have applied Fen values which are calculated with 

the recommended sets of formulae in NUREG/CR-5704,”Effects of LWR Coolant Environments 

on Fatigue Design Curves of Austenitic Stainless Steel,” issued April 1999; NUREG/CR-6583, 

“Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy 
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Steels,” issued February 1998; and NUREG/CR-6909, “Effect of LWR Coolant Environments on 

the Fatigue Life of Reactor Materials – Final Report,” issued February 2007.

The staff noted that LRA Section A.2.2.3 indicates that, before the period of extended operation, 

the applicant will update the fatigue usage calculation using refined fatigue analyses to 

determine valid CUFs less than 1.0 when accounting for the effects of reactor coolant 

environment. In addition, LRA Table 4.3-7 indicates that the applicant has not calculated the 

environmentally-adjusted CUF for nickel-based alloy components and that there are many 

locations with EAF CUFs greater than 1.0. However, the staff noted that neither the LRA nor its 

UFSAR supplement provide a sufficient description of how CUF values will be refined and Fen

factors will be calculated. Without a description of how the Fatigue Monitoring Program will be 

permitted to refine the CUF and calculate the Fen factors, the staff is unsure as to how the 

program will manage the effects of reactor coolant environment on metal fatigue during the 

period of extended operation. By letter dated May 24, 2012, the staff issued RAI 4.3-8 

requesting the applicant to provide and justify the methods that will be used to refine the CUF 

and Fen values and to revise LRA Section A.2.2.3 to provide this description, as necessary.

In its response dated June 21, 2012, the applicant provided an explanation of the conservatism 

in the original design basis fatigue calculations that are meant to simplify the analyses, such as 

combining all transients together and considering them all to be as severe as the worst transient 

for a particular location. The applicant stated that to account for EAF, design basis fatigue 

analyses may be revised to reduce the conservatism to meet the criterion on CUF of 1.0. Such 

techniques include the consideration of actual severity of historical transients to reduce 

assumed cyclic loads from being as severe as the assumed design basis transients. In 

addition, the applicant stated that conservatism also may be reduced for specific locations by 

considering 60-year projected cycles if they are less than the design basis numbers of cycles. 

Furthermore, a detailed NB-3200 calculation may be performed if the reduction in conservatism 

in the design basis fatigue analyses is not possible.

The staff finds the techniques that the applicant described to reduce conservatism in the fatigue 

analyses are appropriate because they consider the actual circumstances of transients, such as 

transient severity, number of cycles, and treating transients separately, rather than using worsecase scenarios or design basis assumptions. The staff noted that these techniques are 

commonly used because they are effective and yield successful results; but the staff noted that 

they are not the only possible techniques to refine CUF values. In addition, the staff finds it 

appropriate that calculations may be performed in accordance with ASME Code, Section III, 

Subsection NB because 10 CFR 50.55a approves its use for the design of RCPB components.

The applicant stated that the specific approach to refining the analysis will vary from calculation 

to calculation and that speculating on the specific approaches in the UFSAR supplement would 

be inappropriate. Since the use of any combination of techniques to refine a fatigue analysis 

will vary depending on the circumstances of each calculation, the staff agrees that it is not 

appropriate to provide the specifics in the UFSAR supplement. The applicant stated that LRA 

Section A.2.2.3 indicates that CUFs will be determined using an NRC-approved version of the 

ASME Code or NRC-approved alternative. In addition, LRA Section A.2.2.3 was revised in the 

applicant’s response to state “[e]nvironmental effects on fatigue for these critical components 

will be evaluated using one of the following sets of formulae in accordance with the guidance in 

NUREG-1801, Revision 2, Section X.M1.”

The staff finds it acceptable that the UFSAR supplement indicates the use of an NRC-approved 

version of the ASME Code or NRC-approved alternative to calculate CUFs because 
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10 CFR 50.55a identified the versions of the ASME Code that have been approved for use; 

specifically, 10 CFR 50.55a(b) provides approved versions of ASME Code, Section III to 

perform CUF-related calculations. The staff also finds it acceptable that the UFSAR supplement

indicates the use of the formulae in the staff’s guidance document, NUREG-1801, Revision 2, 

Section X.M1, to determine the Fen factor to address EAF.

The staff finds the applicant’s response to RAI 4.3-8 acceptable because (1) the determination 

of CUF will be performed in accordance with a version of the ASME Code, as approved for use 

in 10 CFR 50.55a, or a staff-approved alternative; (2) the determination of the Fen factor will be 

performed consistent with formulae in the GALL Report; and (3) this information is captured in 

the applicant’s UFSAR supplement to provide a summary description of activities for managing

EAF. The staff’s concern described in RAI 4.3-8 is resolved.

LRA Section 4.3.3 provides a description of operating times of the plant with normal water 

chemistry (NWC) and hydrogen water chemistry (HWC). It also states that EAF analyses 

included an evaluation of the water chemistry history using a time-weighting methodology to 

determine the “cumulative environment” for the components when determining the dissolved 

oxygen.

The staff noted that the use of a time-weighted percentage for NWC and HWC to evaluate EAF

is based on the assumption that transients occurred linearly from the time of initial plant 

operation. However, based on information the staff noted during its audit and from LRA

Table 4.3-1, this may not always be the case. It is possible that the use of a time-weight 

percentage for HWC/NWC in the formulation of Fen values may underestimate the 

environmentally-adjusted CUFs. The applicant did not explain why the use of a time-weighted

percentage for NWC/HWC is acceptable when evaluating EAF, and LRA Section A.2.2.3 did not 

provide an adequate description on the treatment of NWC and HWC in the current and future 

EAF CUF analyses. By letter dated May 24, 2012, the staff issued RAI 4.3-9, requesting the 

applicant to justify that the use of a time-weighted percentage for HWC/NWC operation to 

calculate Fen values is appropriate or conservative, instead of incorporating available information 

for transient occurrences during NWC/HWC operation for the calculations that support LRA 

Section 4.3.3 and the EAF CUF calculations that will be performed in the future. The applicant 

was also requested to revise LRA Section A.2.2.3 to provide a description of the methodology to 

address NWC/HWC operation for the future analyses to determine valid EAF CUF values, 

as necessary.

In is response dated June 21, 2012, the applicant stated that the enhancement for the Fatigue 

Monitoring Program will be performed using industry-accepted techniques for consideration of 

the effects of the reactor water, including techniques for incorporating the impact of dissolved 

oxygen concentration into the calculation of the Fen factor.

The applicant clarified that the discussion related to dissolved oxygen concentrations in 

LRA 4.3.3 and the information in LRA Table 4.3-6 will not be used to review the effects of EAF 

or to accept any location as a bounding location. The applicant also revised LRA 

Section A.2.2.3 to include the following, “[i]ndustry-accepted techniques will be used for 

consideration of the effects on fatigue of the reactor water environment (environmentally 

assisted fatigue – EAF), including techniques for incorporating the impact of dissolved oxygen 

concentration into the calculation of fatigue environmental correction factors.”

The staff noted that it is possible these industry-accepted techniques may not or will not be 

approved for use by the staff. Furthermore, the staff noted that the concern identified in
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RAI 4.3-9 specifically addressed the use of a time-weighted percentage for HWC/NWC in the 

formulation of Fen values and that this use may underestimate the environmentally-adjusted 

CUFs. The applicant has not explained how the use of unspecified industry-accepted 

techniques will resolve this potential non-conservatism. By letter dated August 7, 2012, the staff 

issued follow-up RAI 4.3-9a requesting the applicant to revise LRA Section A.2.2.3 to indicate 

that future calculation of Fen values will incorporate available transient cycle occurrence data 

during operating times in NWC and HWC instead of using a time-weighted percentage for NWC 

and HWC operation.

In its response dated September 4, 2012, the applicant revised its UFSAR supplement in LRA 

Section A.2.2.3 indicating that future calculations of Fen values will incorporate available 

transient cycle occurrence data during operating times in NWC and HWC. The staff noted that 

the applicant’s methodology will eliminate the under-estimation of the environmentally-adjusted 

CUFs due to a time-weight percentage for HWC/NWC in the Fen values formulation. The staff 

noted that by updating the UFSAR supplement, the applicant provided an adequate description 

on the treatment of NWC and HWC in future EAF CUF analyses.

The staff finds the applicant’s response to RAI 4.3-9a acceptable because (a) future calculations 

of EAF CUF will incorporate available information for transient occurrences during NWC/HWC 

operation, and (b) this information is captured in the applicant UFSAR supplement to provide a 

summary description of activities for managing environmentally-assisted fatigue. The staff’s 

concerns described in RAIs 4.3-9 and 4.3-9a are resolved.

The applicant assessed the effects of reactor water environment on fatigue life in LRA 

Section 4.3.3 by applying the Fen factors to the CUF values and the resulting CUFen values are 

greater than 1.0 in many cases. The staff noted that the UFSAR supplement in LRA 

Section A.2.2.3 indicates that, prior to the period of extended operation, the applicant will update 

the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 

1.0 when accounting for the effects of reactor water environment. The applicant also 

dispositioned the evaluations to address the effects of reactor water environment on fatigue life

in accordance with 10 CFR 54.21(c)(1)(iii) to demonstrate that the effects of environmentallyassisted fatigue on the intended functions of the analyzed components will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation.

The staff also noted that, consistent with Commission Order No. CLI-10-17, the regulations 

contain no requirement that an applicant complete an EAF analysis prior to the issuance of a 

renewed license. Therefore, the staff finds it reasonable that the applicant will update the 

fatigue usage calculation using refined fatigue analyses to determine valid CUFs less than 1.0 

when accounting for the effects of reactor water environment prior to the period of extended 

operation because this information is captured in the applicant’s UFSAR supplement to provide 

a summary description of activities for managing EAF.

The staff’s review of the applicant’s Fatigue Monitoring Program is documented in SER 

Section 3.0.3.1.18. The staff determined that the AMP includes three monitoring methods 

(cycle counting, cycle-based fatigue monitoring and stress-based fatigue monitoring) that are 

capable of managing metal fatigue and EAF during the period of extended operation. The staff 

also determined that the use of these three monitoring methods progressively provides a more 

refined monitoring approach to manage metal fatigue and EAF to ensure that the applicable 

allowable design limits are not exceeded. The staff determined that these characteristics of the 

applicant’s Fatigue Monitoring Program are consistent with GALL Report AMP X.M1.
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The staff finds the applicant has demonstrated pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of EAF on the intended functions will be adequately managed by the Fatigue Monitoring 

Program for the period of extended operation. Additionally, it meets the acceptance criteria in 

SRP-LR Section 4.3.2.1.3 because the applicant is crediting its Fatigue Monitoring Program, 

which the staff determined in SER Section 3.0.3.1.18 is consistent with GALL Report 

AMP X.M1, to manage EAF to ensure that the allowable design limits on fatigue usage are not 

exceeded during the period of extended operation; otherwise, the applicant will take corrective 

actions in accordance with its program.

4.3.3.3 UFSAR Supplement

LRA Section A.2.2.3, as amended by letters dated June 21, 2012, and September 4, 2012,

provides the UFSAR supplement summarizing the evaluations for the effects of reactor water 

environment on fatigue life. The staff reviewed LRA Section A.2.2.3 consistent with SRP-LR 

Section 4.3.3.2, which states that the reviewer should verify that the applicant has provided

information to be included in the UFSAR supplement that includes a summary description of the 

evaluations.

Based on its review of the UFSAR supplement, as amended by letters dated June 21 and 

September 4, 2012, the staff finds that the supplement meets the acceptance criteria in SRP-LR 

Section 4.3.2.2. Additionally, the staff determines that the applicant provided an adequate 

summary description of its actions to evaluate the effects of reactor water environment on 

fatigue life, as required by 10 CFR 54.21(d).

4.3.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of reactor water environment 

on fatigue life will be adequately managed by the Fatigue Monitoring Program for the period of 

extended operation. The staff also concludes that the UFSAR supplement contains an 

appropriate summary description of the EAF evaluations, as required by 10 CFR 54.21(d).

4.4 Environmental Qualification of Electric Equipment

The 10 CFR 50.49 Environmental Qualification (EQ) program is a TLAA for the purposes of 

license renewal. The TLAA of the EQ electrical components includes all long-lived, passive, 

and active electrical and instrumentation and controls (I&C) components that are important to 

safety and located in a harsh environment. The harsh environments of the plant are those 

areas subject to environmental effects by LOCAs or HELBs. EQ equipment comprises 

safety-related and Q-list equipment, nonsafety-related equipment, the failure of which could 

prevent satisfactory accomplishment of any safety-related function, and necessary 

post-accident monitoring equipment.

As required by 10 CFR 54.21(c)(1), the applicant must provide a list of EQ TLAAs in the LRA. 

The applicant shall demonstrate that for each type of EQ equipment, one of the following is true: 

(1) the analyses remain valid for the period of extended operation, (2) the analyses have been 

projected to the end of the period of extended operation, or (3) the effects of aging on the 

intended function(s) will be adequately managed for the period of extended operation.
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4.4.1 Summary of Technical Information in the Application

LRA Section 4.4 describes the applicant’s TLAA for the evaluation of environmentally qualified 

electrical equipment for the period of extended operation. The applicant stated the EQ Program

manages component thermal, radiation, and cyclical aging, as applicable, through the use of 

aging evaluations based on 10 CFR 50.49(f) qualification methods.

The applicant dispositioned the TLAA for the electric equipment in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, and cyclical aging on the intended 

functions will be adequately managed by the Environmental Qualification (EQ) of Electric 

Components Program for the period of extended operation.

4.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the electric equipment consistent with SRP-LR 

Section 4.4.2.1, which states that, in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), an applicant must demonstrate that the effects of aging on the intended 

function(s) will be adequately managed for the period of extended operation. The EQ

requirements established by 10 CFR Part 50, Appendix A, Criterion 4, and 10 CFR 50.49 

specifically require each applicant to establish a program to qualify electrical equipment so that 

such equipment, in its end of life condition, will meet its performance specifications during and 

following DBAs.

The staff reviewed LRA Sections 4.4 and B.1.17, plant basis documents, additional information 

provided to the staff, and interviewed plant personnel to verify whether the applicant provided 

adequate information to meet the requirements of 10 CFR 54.21(c)(1). For electrical 

equipment, 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 for the period of extended 

operation. Per the GALL Report, plant EQ Programs that implement the requirements of 

10 CFR 50.49 are considered acceptable AMPs in accordance with 10 CFR 54.21(c)(1)(iii). 

GALL Report AMP X.E1, “Environmental Qualification (EQ) of Electric Components,” provides a 

way to meet the requirements of 10 CFR 54.21(c)(1)(iii). The staff reviewed the applicant’s EQ 

Program to determine whether it will ensure 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 pursuant to 10 CFR 50.49. The staff 

conducted an audit of the information provided in LRA Sections 4.4 and B.1.17 and the program 

basis documents. LRA Section B.1.17 discusses the component reanalysis attributes, including 

analytical models, data collection and reduction methods, underlying assumptions, acceptance 

criteria, and corrective actions. The staff’s review of the applicant’s EQ of Electrical 

Components is documented in SER Section 3.0.3.1.16. On the basis of its audit, the staff finds 

that the EQ Program, which the applicant claimed to be consistent with GALL Report

AMP X.E1, “Environment Qualification (EQ) of Electric Components,” is consistent with the 

GALL Report; therefore, the staff concludes that the applicant’s Environmental Qualification 

(EQ) of Electric Components Program will be implemented per the requirements of 

10 CFR 54.21(c)(1)(iii).
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The staff finds the applicant has demonstrated pursuant to10 CFR 54.21(c)(1)(iii), that the 

effects of thermal, radiation, and cyclical aging on the intended functions of the electric 

equipment will be adequately managed for the period of extended operation.

Additionally, it meets the acceptance criteria in SRP-LR Section 4.4.2.1 because the applicant’s 

EQ of Electric Components 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 of Electric Components Program provides assurance that the aging 

effects will be managed and that components within the scope of the EQ of Electric 

Components Program will continue to perform their intended functions for the period of 

extended operation.

4.4.3 UFSAR Supplement

LRA Section A.1.17 provides the UFSAR supplement summarizing the Environmental 

Qualification (EQ) of Electric Equipment TLAA. The staff reviewed LRA Section A.1.17 

consistent with SRP-LR Section 4.4.1.3, which states that the detailed information on the 

evaluation of TLAAs is contained in the renewal application. A summary description of the 

evaluation of TLAAs for the period of extended operation is contained in the applicant’s UFSAR

supplement.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.4.1.3. Additionally, the staff determines that the applicant provided an 

adequate summary description of its actions to address the Environmental Qualification (EQ) of 

Electric Equipment TLAA for the period of extended operation, as required by 10 CFR 54.21(d).

4.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of thermal, radiation, and 

cyclical aging on the intended functions of the electric equipment will be adequately managed 

by the Environmental Qualification (EQ) of Electric Components Program 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).

4.5 Concrete Containment Tendon Prestress Analyses

4.5.1 Summary of Technical Information in the Application

LRA Section 3.5.2.2.1.4, “Loss of Prestress due to Relaxation, Shrinkage, Creep, and Elevated

Temperature,” states that the GGNS containment structure is constructed of reinforced concrete 

with no prestressed tendons associated with its design. Therefore, loss of prestress due to 

relaxation, shrinkage, creep, and elevated temperature do not apply. Accordingly, the applicant 

dispositioned the Concrete Containment Tendon Prestress TLAA assigned by NUREG-1800 

Section 4.5, by stating in LRA Section 4.5, “Concrete Containment Tendon Prestress,” that the 

section is not applicable.

4.5.2 Staff Evaluation

The staff reviewed relevant containment design information in the UFSAR to evaluate the 

validity of the applicant’s basis. The staff reviewed the description provided in Table 1.3-4, 
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“Comparison of Containment Design Characteristic,” of the UFSAR, which attests that the 

containment is a “[r]einforced concrete cylindrical structure (not prestressed) with hemispherical 

head; steel lined.” Based on this review, the staff has confirmed that the design of the 

containment structure is not reinforced with 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 the containment building 

has no prestressed tendons.

4.5.4 Conclusion

On the basis of its review, as discussed above, the staff concludes this TLAA is not required.

4.6 Containment Liner Plate, Metal Containments, and Penetrations Fatigue 

Analyses

4.6.1 Containment Liner Plate, Metal Containments

4.6.1.1 Summary of Technical Information in the Application

LRA Section 4.6.1 describes the applicant’s TLAA for the containment liner plate and metal 

containments fatigue analysis. The LRA states that the containment is a BWR Mark III. The 

applicant stated that, as described in UFSAR Section 3.8.1.3, the containment was designed in 

accordance with the loads defined in GE Topical Report NEDO 11314-08 (GESSAR 

Appendix 3B) and that additional loads defined in GE 22A4365 and later defined by GE 

22A7000, Revision 2, were considered for the final design verification of the containment.

The LRA states that the quenchers were designed for a conservatively high value of 

18,000 cycles and the usage factors were calculated to be much less than 1.0: usage factors 

for the quencher arm, arm-to-shell juncture, support arm, support arm weld, and stiffening ring 

were 0.018. The calculated fatigue usage factor at the support arm to shell connection was 

0.23. The LRA states that the SRV actuations are tracked and will be maintained below the 

value used in the fatigue evaluation.

The LRA states that the suppression pool and cylinder wall liner plate fatigue analysis was 

performed using Subsections NE and NB of the ASME Code Section III, 1971 Edition with 

Summer 1973 Addenda. The calculated fatigue usage was less than 0.02 with a total number 

of 19,362 cycles, including heatups and cooldowns, seismic cycles, and SRV actuations.

The applicant dispositioned the TLAA for the containment liner plate and metal containment 

components in accordance with 10 CFR 54.21(c)(1)(iii), that the effects of aging due to fatigue 

on the primary containment will be adequately managed by the Fatigue Monitoring Program for 

the period of extended operation.

4.6.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the containment liner plate and metal containment 

components and the corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with 

SRP-LR Section 4.6.3.1.1.3, which states that the applicant’s proposed AMP to ensure that the 
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effects of aging on the intended functions are adequately managed for the period of extended 

operation is reviewed. If the program will replace the component before its CUF exceeds 1, the 

review verifies that the CUF for the replacement will remain less than or equal to 1 during the 

period of extended operation.

The staff reviewed UFSAR Appendix 6A, Section 3BA.7, which states that the GGNS quencher 

rests in bearing on the containment basemat. The quencher component includes the stiffening 

ring subcomponent shown on UFSAR Appendix 6A, Figure A-2. A large cylindrical support arm 

extends from the quencher to the drywell wall, which takes moments and lateral and vertical-up 

forces. Vertical-down forces are taken by the support arm and the basemat. The staff 

confirmed in UFSAR Appendix 6A, Section 3BA.7, that the quenchers were designed to 18,000 

fatigue cycles and that for all quencher components, the fatigue usage factors calculated were 

significantly lower than 1.

The staff reviewed UFSAR Section 3.8.1.3 and confirmed that the initial design of the GGNS

Mark III containment was in accordance with the loads defined in GE Topical Report NEDO 

11314-08 (GESSAR Appendix 3B), and that additional loads initially defined in GE 22A4365, 

Interim Containment Loads Report, Revision 2, and later defined in GE 22A7000, Revision 2 

(GESSAR II, Appendix 3B), were considered in the final design verification of the containment. 

The staff reviewed UFSAR Section 3.8.1.1.2 and noted that the concrete containment is lined 

completely with a welded steel liner plate to form a leak-tight barrier that minimizes radioactive 

leakage to the environment. The staff reviewed UFSAR Section 3.8.1.4.2 and noted that the 

liner plate was designed in accordance with Bechtel Corporation Topical Reports BC-TOP-1 

and BC-TOP-5A. The UFSAR states that the GGNS [containment] liner plate is backed by 

concrete and does not classify as a pressure boundary, and is therefore not designed in 

accordance with ASME Code Section III, Division I. The staff did not find a fatigue analysis for 

the containment liner and agrees that it does not need to be analyzed for fatigue because it is 

integral with the concrete that backs it. Further, it is not credited as a pressure boundary. The 

suppression pool liner plate is fabricated out of stainless steel and was designed to be affected 

by periodic negative pressure loading due to the SRV discharge. The staff noted that, for this 

reason a fatigue evaluation of the suppression pool liner was performed using Subsections NE 

and NB of the ASME Code, Division I, Section III, 1971 Edition with Summer of 1973 Addenda. 

The LRA states that it calculated a CUF value of less than 0.02 with a total number of cycles of 

19,362, including the transient cycles associated with heatups and cooldowns, seismic cycles, 

and SRV actuations. Furthermore, the heatups and cooldowns, seismic cycles, and SRV 

actuations are tracked against limits that are well below the total cycle value used in the liner 

fatigue evaluation.

SRP-LR Section 4.6.2.1.1.3 states that an acceptable method for meeting the requirements of 

10 CFR 54.21(c)(1)(iii) is that an AMP provided by the applicant shall demonstrate that the 

effects of aging on the component’s intended functions will be adequately managed during the 

period of extended operation. The staff noted that the applicant is monitoring transient cycles 

with the Fatigue Monitoring Program. The applicant’s Fatigue Monitoring Program tracks SRV 

actuations for fatigue of the quenchers and will ensure that SRV actuations are maintained 

below the value used in the fatigue analysis. The Fatigue Monitoring Program also tracks 

heatups, cooldowns, seismic cycles, and SRV actuations for fatigue of the suppression pool and 

cylinder wall liner plate.

The staff finds the applicant has demonstrated in accordance with the requirements of

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions of the containment 

liner plate and metal containment components will be adequately managed for the period of 
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extended operation. Additionally, the TLAA disposition meets the acceptance criteria in 

SRP-LR Section 4.6.2.1.1.3 because the applicant’s Fatigue Monitoring Program will monitor 

transient cycles and take action before any of the transients meets its analyzed number of 

occurrences.

4.6.1.3 UFSAR Supplement

LRA Section A.2.4 provides the UFSAR supplement summarizing the containment liner plate 

and metal containments TLAA. The staff reviewed LRA Section A.2.4 consistent with SRP-LR 

Section 4.6.3.2, which states that the reviewer verifies that the applicant has provided 

information to be included in the UFSAR supplement that includes a summary description of the 

evaluation of containment liner plate and metal containments fatigue TLAA.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address containment 

liner and metal containment components, as required by 10 CFR 54.21(d).

4.6.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended 

functions of the containment liner plate and metal containments will be adequately managed by 

the Fatigue Monitoring Program 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).

4.6.2 Containment Penetrations

4.6.2.1 Summary of Technical Information in the Application

LRA Section 4.6.2 describes the applicant’s TLAAs for the containment penetrations. The LRA 

states that ASME Class 1 piping that has guard pipes with flued heads for containment 

penetration welded to the piping has individual analyses for fatigue at each penetration. The 

LRA states that Class 1 fatigue analyses for the following flued head penetrations: Main Steam, 

Main FW, RHR, RCIC, Main Steam Drain, multiple RHR/LPCI penetrations, HPCS, LPCS, and 

RWCU. The calculated usage factors are shown in LRA Table 4.6-2.

The LRA cites UFSAR Figure 3.6A-33 in stating that the guard pipe assemblies use bellows. 

The applicant also cites UFSAR Figure 9.1-15 and Section 9.1.4.2.3.11 in stating that the fuel 

transfer tube also uses bellows. The applicant stated that calculations were identified for the 

bellows that analyzed a large number of cycles of flexure due to normal operation and 

earthquakes. Those calculations are considered TLAAs. In both the cases of the guard pipe 

bellows and the fuel transfer tube bellows, the applicant stated that the number of analyzed 

cycles is significantly higher than the total number of cycles projected for the period of 

extended operation.

The applicant dispositioned the TLAAs for the containment penetrations in accordance with 

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended functions will be adequately 

managed by the Fatigue Monitoring Program for the period of extended operation.
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4.6.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the containment penetrations, and the 

corresponding disposition of 10 CFR 54.21(c)(1)(iii) consistent with SRP-LR Section 4.6.3.1.1.3, 

which states that the applicant’s proposed AMP to ensure that the effects of aging on the 

intended functions are adequately managed for the period of extended operation is reviewed. If 

the program will replace the component before its CUF exceeds 1, the review verifies that the 

CUF for the replacement will remain less than or equal to 1 during the period of extended 

operation.

The staff reviewed the UFSAR and found no additional systems with piping penetrations that 

included a flued head and individual fatigue analysis. The staff also noted from LRA

Table 4.6-2, which identified the result of each analysis and grouped the analyses into what the 

applicant stated were “simplified bounding load cases,” that each penetration analyzed to a CUF

of less than one. The staff also reviewed LRA Table 4.3-1 and UFSAR Section 3.9.1.1 for 

documentation of analyzed transients and noted that the current and projected transient cycles 

for 60 years of operation are less than the design cycle limits.

For the bellows on the containment penetration guard pipes and fuel transfer tube, the staff 

noted that the applicant stated it analyzed a large number of cycles of flexure due to normal 

operation and earthquakes. The staff also noted the applicant’s statement that the number of 

analyzed cycles is significantly higher than the total number of cycles projected for the period of 

extended operation and that the applicant will use the Fatigue Monitoring Program to manage 

the aging effects. However, the staff noted that the LRA does not provide additional information 

regarding the calculations performed for the fatigue analysis, such as the number of analyzed 

cycles or the included transients. Therefore, the staff identified that it needed further information 

to confirm that the evaluation for the fatigue analysis remains valid for the period of extended 

operation. By letter dated June 27, 2102, the staff issued RAI 4.6.2-1 requesting that the 

applicant identify the number of cycles that the bellows for the guard pipes and fuel transfer 

tubes were designed for and explain how that number was developed. The staff also requested 

that the applicant identify which transients were included in the original evaluation and which 

ones will be monitored under the Fatigue Monitoring Program.

By letter dated July 25, 2012, the applicant responded to RAI 4.6-2, stating that the design 

specification for the penetration bellows indicates specific values of movement for normal 

conditions and for accident conditions. The applicant stated that the main steam secondary 

containment penetration bellows at the turbine building to auxiliary building interface has the 

lowest number of allowable cycles for penetration bellows, with an allowable value of 

10,000 cycles of movement. The applicant also stated that the number of times the main steam 

lines are heated up (as part of plant startup) plus the total number of earthquake cycles will 

remain well below the allowable 10,000 cycles through the period of extended operation. The 

applicant further stated that the other penetration bellows are qualified for many more 

movement cycles (up to 100,000 or 1,000,000) and that these allowable cycles are significantly 

higher than the total number of piping thermal movements, pressurization cycles, and seismic 

movement cycles expected for the period of extended operation.

The staff finds the applicant’s response acceptable because the applicant has identified the 

most limiting analysis for this component type and all other penetration bellows are qualified for 

many more cycles. In addition, SRP-LR Section 4.6.2.1.1.3 states that an acceptable method 

for meeting the requirements of 10 CFR 54.21(c)(1)(iii) is that an AMP provided by the applicant 

shall demonstrate that the effects of aging on the component’s intended functions will be 
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adequately managed for the period of extended operation. The staff noted that the applicant is 

monitoring transient cycles affecting the penetration and fuel transfer tube bellows, including 

piping thermal movements, pressurization cycles, and seismic movement cycles, using the 

Fatigue Monitoring Program. The staff’s concerns described in RAI 4.6-2 are resolved.

The staff finds the applicant has demonstrated, pursuant to 10 CFR 54.21(c)(1)(iii), that the 

effects of fatigue on the intended functions of the containment penetrations will be adequately 

managed for the period of extended operation. Additionally, the applicant’s demonstration 

meets the acceptance criteria in SRP-LR Section 4.6.2.1.1.3 because the applicant’s Fatigue 

Monitoring Program will monitor transient cycles and take action before any of the transients 

meets its analyzed numbers.

4.6.2.3 UFSAR Supplement

LRA Section A.2.4 provides the UFSAR supplement summarizing the containment penetrations 

TLAA. The staff reviewed LRA Section A.2.4 consistent with SRP-LR Section 4.6.3.2, which 

states that the reviewer verifies that the applicant has provided information to be included in the 

UFSAR supplement that includes a summary description of the evaluation of containment 

penetrations fatigue TLAA.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.6.2.2, and is, therefore, acceptable. Additionally, the staff determines that 

the applicant provided an adequate summary description of its actions to address the 

containment penetrations TLAA, as required by 10 CFR 54.21(d).

4.6.2.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the intended 

functions of the containment penetrations will be adequately managed by the Fatigue Monitoring 

Program 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 Other Plant-Specific TLAAs

LRA Section 4.7, as amended by letter dated October 2, 2012, summarizes the evaluation of 

the following plant-specific TLAAs:

• Erosion of the MSL Flow Restrictors

• Determination of Intermediate High-Energy Line Break Locations

• Fluence Effects for the Reactor Vessel Internals

• Fatigue Analysis of Cranes

4.7.1 Erosion of the MSL Flow Restrictors

4.7.1.1 Summary of Technical Information in the Application

LRA Section 4.7.1 describes the applicant’s TLAA for the erosion of the main steam line flow 

restrictors. The LRA refers to UFSAR Section 5.4.4.4, which indicates that very slow erosion of 
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the flow restrictors occurs with time, and that even with erosion rates as high as 0.004 inch per 

year, the increase in choked flow would be no more than 5 percent after 40 years of operation.

The LRA states that the evaluation of erosion-corrosion rate for the main steam flow elements 

considered the specific material present in the GGNS flow restrictors and determined that the 

expected rate, when operating at the velocities that would be present following EPU, would be 

much less than the conservative value in the UFSAR. The LRA also states that, using the 

expected rate, the total erosion after 60 years would remain less than the conservative total 

erosion value identified in the UFSAR for 40 years.

The applicant dispositioned the TLAA for the erosion of the main steam line flow restrictor in 

accordance with 10 CFR 54.21(c)(1)(ii) that the analysis has been projected to the end of the 

period of extended operation.

4.7.1.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the erosion of the main steam line flow restrictors 

and the corresponding disposition that the analysis has been projected to the end of the period 

of extended operation consistent with SRP-LR Section 4.7.3.1.2, which states that the results of 

the revised analyses are confirmed to ensure that they are valid for the period of extended 

operation.

The staff noted that the LRA did not contain information regarding the revised analyses to 

demonstrate that the choked flow will remain less than the 170 percent of normal flow or less 

than 6.91x106 pounds per hour at 1,025 psig upstream pressure in the event of a main steam 

line break, as stated in UFSAR Section 5.4.4. In addition, it was unclear to the staff to what 

value the LRA was referring in the statement “total erosion value identified in the UFSAR for 

40 years,” since a total erosion value was not given. By letter dated June 5, 2012, the staff 

issued RAI 4.7.1-1 requesting the applicant to provide the results of the projected analyses 

demonstrating that the intended functions of these components are maintained in accordance 

with the CLB, and to include the bases for concluding that the expected erosion rate would be 

much less than the value in the UFSAR.

In its response dated July 3, 2012, the applicant stated that the erosion rate of 0.004 inch per 

year stated in UFSAR Section 5.4.4.4 was highly conservative, and that information from a later 

evaluation shows that the expected flow restrictor erosion would be less than the 0.160 inch 

derived from the 0.004 inch per year for 40 years of operation. In addition, the applicant 

provided several attributes to explain the reduction in the erosion-corrosion rate from the 

0.004 inch per year given in the UFSAR, including that materials with minimal chromium content 

are resistant to erosion-corrosion damage. However, the applicant did not provide any specific 

details regarding the revised analysis. In its review of the response, the staff noted that 

although the flow restrictors are constructed from stainless steel, the chromium content in 

stainless steel does not prevent loss of material due to erosion in all situations. The applicant’s 

response did not provide sufficient information for the staff to complete its review of this issue. 

In order to resolve this concern, by letter dated September 7, 2012, the staff issued

RAI 4.7.1-1a requesting the applicant to provide the evaluation discussed in its earlier response.

In its response dated October 2, 2012, the applicant provided NEDC-33668P, Revision 1, dated 

August 2011, “Grand Gulf Station Plant Life Extension Support Main Steam Line Flow 

Restrictors Material Review and Effect on Offsite Dose from Steam Release Due to ErosionCorrosion.” The staff reviewed Section 3, “Evaluation,” regarding the erosion-corrosion rate and 
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the impact to offsite dose due to increase in steam release. Based on review of Section 3 of 

this report, the staff verified that the expected erosion-corrosion rate of the main steam line flow 

restrictors is less than the rate assumed in UFSAR Section 5.4.4.4 and that the consequent 

increase in offsite dose is less than the 5 percent increase stated in UFSAR Section 5.4.4.4. 

The staff’s concerns described in RAIs 4.7.1-1 and 4.7.1-1a are resolved.

The staff finds that the applicant demonstrated, pursuant to 10 CFR 54.21(c)(1)(ii), that the 

analysis for the main steam line flow restrictor erosion has been projected to the end of the 

period of extended operation. Additionally, it meets the acceptance criteria in SRP-LR 

Section 4.7.3.1.2 because the revised report reevaluated the overly conservative assumptions 

in the original analysis to show that the TLAA acceptance criteria continue to be satisfied for the 

period of extended operation.

During its review of LRA Table 3.1.2-3, “Reactor Coolant Pressure Boundary,” the staff noted 

that it includes cast austenitic stainless steel flow elements, which appear to be the main steam 

line flow restrictors. The table indicates that these components are being managed by the 

Water Chemistry – BWR Program, for cracking through item 3.4.1-11, and for loss of material 

through item 3.1.1-79. However, the staff noted that item 3.1.1-79 does not apply to loss of 

material due to erosion, and that Table 3.1.2-3 did not include a separate AMR item for the 

TLAA associated with erosion of the flow restrictors. In order to address this concern, by letter 

dated September 7, 2012, the staff issued RAI 4.7.1-2 requesting that the applicant provide an 

AMR item for the main steam line flow restrictors in LRA Table 3.1.2-3 that credits the TLAA for 

managing loss of material due to erosion. In its response dated October 2, 2012, the applicant 

revised LRA Table 3.1.2-3 by adding an AMR item for loss of material due to erosion of the flow 

element to indicate that it is being managed through a TLAA. The staff finds this response 

acceptable because the LRA now provides the aging management method used by GGNS to 

demonstrate that the effects of aging will be adequately managed for the main steam line flow 

restrictors. The staff’s concern described in RAI 4.7.1-2 is resolved.

4.7.1.3 UFSAR Supplement

LRA Section A.2.5.1 provides the UFSAR supplement summarizing the erosion of the main 

steam line flow restrictors. The staff reviewed the LRA Section A.2.5.1 consistent with SRP-LR 

Section 4.7.3.2, which states that the information to be included in the UFSAR supplement 

includes a summary description of the evaluation of each TLAA.

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.3.2, and is therefore acceptable. Additionally, the staff determines that the 

applicant provided an adequate summary description of its actions to address the main steam 

line flow restrictor erosion analysis, as required by 10 CFR 54.21(d).

4.7.1.4 Conclusion

On the basis of its review, the staff concludes that the applicant provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analysis for the main steam flow 

restrictor erosion 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).
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4.7.2 Determination of Intermediate High-Energy Line Break Locations

4.7.2.1 Summary of Technical Information in the Application

LRA Section 4.7.2 describes the TLAA associated with the determination of intermediate HELB 

locations. The LRA states that the determination of HELB locations in UFSAR Section 3.6A.2 

relied on an evaluation of piping systems that had been analyzed in accordance with CUF 

analyses. The applicant stated that, as long as the other stress criteria in the UFSAR section

were met, pipe break would not need to be postulated for high-energy pipe location as long as 

the CUF value for the components was confirmed to be less than a value of 0.1. The applicant 

stated that, since these CUF calculations are based on design transients defined by the initial 

40-year life of the plant, the CUF calculations are TLAAs for the LRA.

The LRA states that the Fatigue Monitoring Program will identify if the number of cycles for the 

high-energy piping systems are approaching their analyzed number of cycles. If the cycle limit 

on any transient will be exceeded, the design calculations for that system will be reviewed to 

determine if additional locations in that system need to be evaluated as potential HELB 

locations or if reanalysis would be required. As part of the periodic updates that consider actual 

plant transients, the program will ensure that the CUF values for piping locations where breaks 

were not postulated will not exceed a CUF value criterion of 0.1. Furthermore, if other locations 

are determined to require consideration as postulated pipe break locations, appropriate 

corrective actions will be taken to address the new break locations.

The applicant stated that the CUF evaluations for HELB locations are acceptable in accordance 

with the TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii), that the Fatigue Monitoring 

Program will be used to adequately manage the associated effects of aging on these locations

for the period of extended operation.

4.7.2.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for HELB analyses and the corresponding disposition of 

10 CFR 54.21(c)(1)(iii), consistent with SRP-LR Section 4.3.2.1.1.3, which provide the NRC’s 

recommended “acceptance criteria” for accepting CUF-based TLAAs in accordance with the 

TLAA acceptance criterion in 10 CFR 54.21(c)(1)(iii). SRP-LR Section 4.3.3.1.1.3 states that 

the applicant may reference GALL Report AMP X.M1 to accept the TLAA in accordance with 

10 CFR 54.21(c)(1)(iii), and the reviewer should verify that the applicant’s program contains the 

same program elements that were evaluated and relied upon in approving the corresponding 

generic program in the GALL Report. The staff evaluated the applicant’s disposition against 

relevant information in applicable subsections and tables of UFSAR Chapter 3 and the criteria in 

10 CFR Part 50, Appendix A, GDC 4, “Dynamic Effects.” GDC 4 requires that the design of 

nuclear power plants be sufficient to protect safety-related components, structures, or 

equipment against dynamic effects, including missiles, pipe whips, and discharge of fluids that 

may result from equipment failures or events and conditions outside of the nuclear power plant.

The staff determined that UFSAR Section 3.6 provides the basis for meeting GDC 4. This 

UFSAR section provides the design basis for identifying those plant piping components that 

need to be identified as high-energy pipe break locations for the applicant’s design basis, such 

that the components would need to be restrained or supported in accordance with the 

component restraint basis defined in UFSAR Section 3.6A.2.3. UFSAR Section 3.6A.2.1 

defines high-energy systems as systems or portions of the systems in which the maximum 

system operating temperature exceeds 200 oF or the maximum system operating pressure 
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exceeds 275 psig during normal plant conditions. This UFSAR section also establishes the 

criteria that a given location would need to be identified as a HELB location.

UFSAR Table 3.6A-14 identifies the plant systems that are HELB systems. The following 

UFSAR tables identify the component locations for the systems listed in UFSAR Table 3.6A-14 

that are currently HELB component locations for the analysis:

• Table 3.6A-18 for break locations in the Class 1 portions of the main steam system

• Table 3.6A-19 for break locations in the Class 1 portions of the FW system (including 

Class 1 residual heat removal [RHR] and reactor water clean-up [RWCU] injection piping 

to the FW system)

• Table 3.6A-20 for reactor recirculation and RHR suction piping

• Table 3.6A-21 for steam piping to the reactor core isolation cooling (RCIC) system 

turbine

• Table 3.6A-23 for RWCU piping

• Table 3.6A-24 for low-pressure core spray (LPCS) piping

• Table 3.6A-25 for high-pressure core spray (HPCS) piping

• Table 3.6A-26 for low-pressure coolant injection (LPCI) piping

These UFSAR tables identify the intermediate high-energy Class 1 component locations listed 

as HELB locations that were added to the list based on having CUF values in excess of 0.1. 

The design transients for the ASME Code Class 1 systems in the HELB analyses are defined in 

the following sections or tables of the UFSAR: (a) main steam system components in UFSAR 

Section 3.9.1.1.1.5, (b) recirculation system transients in UFSAR Section 3.9.1.1.1.6, and 

(c) remaining Class 1 piping components in UFSAR Table 3.9-1.

The staff noted that LRA Section 4.7.2 did not identify the high-energy piping systems in UFSAR

Table 3.6A-14 that were within the scope of the TLAA and the Fatigue Monitoring Program’s 

cycle counting activities. By letter dated May 24, 2012, the staff issued RAI 4.7.2-1 requesting 

the applicant provide this clarification.

In its response dated June 21, 2012, the applicant stated that:

(a) The HELB TLAAs apply to all piping that utilized the criteria of CUF <0.1 to eliminate 

consideration of a postulated break, which includes much of the piping described in

Table 3.6A-14. However, this table does not provide the details necessary to precisely 

identify the piping that is included in these descriptions of high-energy lines. The 

detailed description of the postulated pipe break locations is provided in the text, tables,

and figures of UFSAR Section 3.6 and the details on the break locations postulated for 

connected systems are provided in UFSAR Section 3.C, including a description of the 

3-inch and smaller high-energy lines.

(b) A review of the HELB evaluations and the associated analyses of CUFs will be 

performed as an enhancement to the Fatigue Monitoring Program, which will identify the 

specific Class 1 systems and components within the scope of the Fatigue Monitoring 

Program’s cycle counting activities. The applicant stated that it will use the results of this 

review to ensure that the necessary transient cycles are tracked and the appropriate 

fatigue usage is monitored for the Class 1 systems and components for which HELB 

TLAAs apply. This enhancement to the program will adequately manage the effects of 
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metal fatigue on all the high-energy piping in UFSAR Table 3.6A-14 that have used the 

criteria of CUF <0.1 in HELB evaluations.

The staff noted that the applicant has already included an enhancement to its Fatigue 

Monitoring Program to perform a review of its CUF calculations to identify the specific 

high-energy Class 1 components that would need to be included within scope of the cycle 

counting activities. In addition, these cycle counting activities will be performed consistent with 

the design transients and cycle limits assumed in the CUF calculations for these components 

that determined a CUF less than 0.1. The staff confirmed that the applicant has included this 

enhancement to the Fatigue Monitoring Program in Commitment No. 10 and in LRA 

Section A.1.19.

The staff noted that using the Fatigue Monitoring Program for the HELB TLAA is relevant for 

those intermediate high-energy Class 1 component locations with CUF values that are less than 

or equal to a value of 0.1. For these locations, the staff finds that the Fatigue Monitoring 

Program is acceptable to disposition the HELB TLAA in accordance with 10 CFR 54.21(c)(1)(iii) 

because the implementation of the program will assess whether the accumulation of design 

basis transients will result in CUF values that are in excess of a value of design limit of 0.1. If 

the cumulative fatigue usage approaches this design limit the applicant will take action to amend 

its design basis to identify the affected ASME Code Class 1 components as additional HELB 

locations. The staff noted that actions may include the need to modify the design of the 

components to include pipe whip restraints or refinement of the fatigue analysis to demonstrate 

that the CUF value for the affected components still meets the design limit of 0.1.

Additionally, the Fatigue Monitoring Program for the HELB TLAA meets the acceptance criteria 

in SRP-LR Section 4.3.2.1.1.3 because: (a) the staff has confirmed that the applicant’s Fatigue 

Monitoring Program (LRA AMP B.1.19) is an acceptable means for managing the effects of 

cumulative fatigue damage on the results of the HELB analyses, (b) it serves as an acceptable 

basis for determining whether additional Class 1 components need to be added as HELB 

locations based on the results of any updated CUF analyses performed on the components 

under the AMP, and (c) it demonstrates conformance with the acceptance criteria in SRP-LR 

Section 4.3.2.1.1.3 on when Fatigue Monitoring Programs can be used to accept CUF-based 

TLAAs in accordance with the acceptance criterion in 10 CFR 54.21(c)(1)(iii). RAI 4.7.2-1 

is resolved.

The staff evaluates the ability of the Fatigue Monitoring Program to manage the impacts of 

fatigue-related aging effects on the GGNS ASME Code Class 1 components (including those 

that are within the scope of the HELB TLAA) in SER Section 3.0.3.1.18.

4.7.2.3 UFSAR Supplement

The applicant provided a UFSAR supplement summary description of its HELB TLAA in LRA 

Section A.2.5.2. The staff reviewed the UFSAR supplement summary description consistent 

with SRP-LR 4.7.3.2, which states that the reviewer should verify that the applicant has 

provided information in its UFSAR supplement that includes a summary description of the 

evaluation of the TLAA and describes how the TLAA has been dispositioned for the period of 

extended operation.

The staff noted that the applicant’s UFSAR supplement summary description for the HELB 

TLAA provided an accurate and sufficient discussion of the HELB TLAA based on the HELB 

design basis in UFSAR Section 3.6A.2 and the design transients for the high-energy Class 1 
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systems within the scope of the HELB analyses, which are defined in UFSAR Section 3.9. The 

staff also noted that the UFSAR supplement summary description for the HELB TLAA provided 

an acceptable summary of the applicant’s basis for accepting the HELB TLAA in accordance 

with the criterion in 10 CFR 54.21(c)(1)(iii) and for using the Fatigue Monitoring Program to 

manage the fatigue-related effects of aging that are applicable to the intermediate, high-energy 

ASME Code Class 1 systems and components within the scope of HELB TLAA. Thus, the staff 

found that the applicant had included an acceptable UFSAR supplement summary description 

because, consistent with the criterion in SRP-LR Section 4.7.3.2, it had provided an adequate 

description of the TLAA consistent with the GGNS design basis and the basis for accepting the 

TLAA in accordance with 10 CFR 54.21(c)(1)(iii). Based on its review of the UFSAR 

supplement consistent with the guidance of SRP-LR Section 4.7.3.2, the staff concludes that the 

summary description of the applicant’s actions to address the HELB TLAA is adequate.

4.7.2.4 Conclusion

On the basis of its review, the staff concludes that, the applicant has demonstrated, pursuant to 

10 CFR 54.21(c)(1)(iii), that the effects of fatigue on the HELB locations will be adequately 

managed for the period of extended operation. The staff also concludes that the UFSAR

supplement contains an appropriate summary description of the HELB TLAA evaluation, as 

required by 10 CFR 54.21(d).

4.7.3 Fluence Effects for the Reactor Vessel Internals

4.7.3.1 Summary of Technical Information in the Application

LRA Section 4.7.3 describes the applicant’s TLAA for fluence effects for the RVI components. 

The LRA states that a design specification for the RVI components includes requirements 

beyond ASME Code design requirements for austenitic stainless steel base metal components 

exposed to greater than 1x1021 n/cm2 (greater than 1 MeV) or weld metal greater than 

5x1020 n/cm2 (greater than 1 MeV). The applicant analyzed the fluence of the RVI components 

included in the design specification at EPU operating conditions for 60 years of plant life 

(54 EFPY) and determined the location-specific fluence levels. Specifically, the LRA states that 

those RVI components that are defined as RVI core support structure components were 

evaluated against the irradiation criteria in the design specification. The LRA states that the 

results of the evaluation show that the RVI core support structure components meet the design 

specification at EPU operating conditions for 54 EFPY. The applicant dispositioned the TLAA 

for fluence effects for the RVI components in accordance with 10 CFR 54.21(c)(1)(ii), that the 

analysis has been projected to the end of the period of extended operation.

4.7.3.2 Staff Evaluation

The staff reviewed the applicant’s analysis to address the effects of fluence on strain values and 

clamping loads for certain RVI components, and the corresponding disposition that the analysis 

has been projected to the end of the period of extended operation, consistent with SRP-LR 

Section 4.7.3.1.2. The SRP-LR states that the results of the revised analysis should be 

reviewed to verify that their period of evaluation is extended, such that they are valid for the 

period of extended operation. The SRP-LR also states that the applicant may recalculate the 

analysis using a 60-year period to show that the acceptance criteria continue to be satisfied for 

the period of extended operation. In addition, the SRP-LR states that the applicant shall provide 

a sufficient description of the analysis and document the results of the reanalysis to show that it 

is satisfactory for the 60-year period.
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The staff determined that LRA Section 4.7.3 does not provide a sufficient description of the 

analysis and, therefore, the staff could not evaluate the adequacy of the TLAA. By letter dated 

June 27, 2012, the staff issued RAI 4.7.3-1 requesting the applicant to clarify the scope of the 

analysis by justifying why only the RVI core support structure components were evaluated 

against the irradiation criteria in the design specification. The staff also requested that the 

applicant (a) identify the 40-year fluence levels of the RVI components, (b) identify and justify 

the projected 60-year fluence levels for these components, and (c) identify the design 

requirements from the design specification and the ASME Code.

The applicant responded to RAI 4.7.3-1 by letter dated July 25, 2012. Regarding the staff’s 

request to justify why only the RVI core support structure components were evaluated, the 

applicant explained that the provision to evaluate the fluence effects on these components is 

from a vendor design specification. The applicant also stated that non-core-support-structure 

bolting components were also evaluated as part of the TLAA. The applicant provided a table in 

the response identifying the specific components included in the analysis. The staff reviewed 

the response and determined that it adequately clarifies the scope of the TLAA because it 

specifically identifies each of the RVI components that are addressed in the analysis.

As part of the response to RAI 4.7.3-1, the applicant also provided the 40- and 60-year fluence 

values for each RVI component within the scope of the analysis. However, for several 

components, the applicant later determined that the fluence values were incorrect and 

submitted corrected values for these components by letters dated September 4, 2012, and 

October 15, 2012. The staff reviewed this information and determined that it adequately 

responds to the staff’s request to provide the 40-year fluence levels and the projected 60-year 

fluence levels.

As another part of its response to RAI 4.7.3-1, the applicant stated that the 60-year fluence 

levels were calculated in accordance with the NRC-approved fluence methodology in topical 

report NEDC-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast 

Neutron Flux Evaluations,” Revision 2 (GE methodology). The staff reviewed this justification 

with the applicant’s July 25, 2012, response to RAI 4.2.1-2, which states that the GE 

methodology was incorporated into the CLB during EPU license amendment approval. SRP-LR 

Section 4.7.3.1.2 states that the applicable analysis technique can be the one that is in effect in 

the CLB at the time when the LRA is filed. However, it was not clear to the staff whether the 

applicant’s analysis technique (i.e., use of the GE methodology) was consistent with the CLB 

when the LRA was filed because the EPU license amendment was approved after the applicant 

submitted the LRA. Nevertheless, the applicant used the GE methodology to calculate both the 

pre-EPU fluence and post-EPU fluence values for the RVI components in the TLAA through the 

period of extended operation. Therefore, by letter dated November 20, 2012, the staff issued 

RAI 4.7.3-1a, Part b, requesting that the applicant justify use of the GE methodology for 

calculating the pre-EPU fluence for the RVI components.

In addition, as part of the response to RAI 4.7.3-1 regarding identification of the applicable 

design requirements from the design specification and the ASME Code, the applicant stated 

that the core shroud was built to the stress criteria of ASME Code Section III, “Rules for 

Construction of Nuclear Facility Components,” Subsection NG, “Core Support Structures,” but 

clarified that the ASME Code Section III does not have specific requirements for evaluating the 

irradiation effects on RVI. The applicant explained that the impact of an increased fast fluence 

exposure on the integrity of the components is an increase in the yield and tensile strengths of 

the materials used to fabricate the components. The applicant therefore concluded that an 

increased fluence exposure on the components has no impact on the stress qualification. The 
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applicant also explained that fast fluence can cause stress relaxation in those RVI components 

that are used in fastened mechanical connections, such as bolted RVI assemblies. The 

applicant stated that the effects of stress relaxation were therefore evaluated for those RVI coresupport-structure and non-core-support-structure bolting components that were within the scope 

of the TLAA. The staff reviewed the response and determined that, although it clarifies that the 

applicable design requirements are not from the ASME Code, it does not provide the requested 

fluence-based design requirements for the components. Therefore, the staff noted that the 

applicant did not sufficiently demonstrate that the results of the re-analysis would be satisfactory 

for 60 years of plant operation. In RAI 4.7.3-1a, Part a., the staff again requested the applicant 

to provide the applicable design requirements for each RVI component that was included and 

analyzed in the TLAA and to show that these requirements are met as a result of the re-analysis 

of fluence effects through the proposed 60 years of plant operation.

The applicant responded to RAI 4.7.3-1a, Part a., by letter dated January 18, 2013. In its 

response, the applicant explained that the applicable design requirements establish maximum 

strain levels for non-fastened RVI base metal components, maximum stress levels for RVI weld 

components, and minimum preload requirements (clamping load requirements) for RVI 

threaded fasteners (bolting). The applicant also stated that the stress levels for RVI weld 

components are not impacted by neutron fluence. For the other RVI base metal component 

types, the applicant stated that the design requirements of the components would not receive 

any special considerations in the ASME Code as long as the projected neutron fluence values 

for the components at 54 EFPY are projected to remain lower than thresholds for inducing the 

applicable aging effects in the components (i.e., changes in dimension due to strain or 

component elongation for RVI non-fastened base metal components and loss of preload due to 

stress relaxation in RVI bolting).

The applicant identified that the applicable fluence threshold is defined as 1x1021 nvt (E > 1.0 

MeV) for RVI base metal components made from stainless steel materials. The applicant also 

provided and defined the applicable ASME Code design requirements for calculating the 

allowable strains in these non-fastened RVI base metal components or the allowable stresses 

for RVI weld components. For RVI threaded fasteners (i.e., bolting), the applicant stated that 

the applied preloads (i.e., clamping loads) for the bolts would need to exceed the minimum 

preloads in the Code requirements needed for structural integrity of the fastened assemblies.

The applicant also provided a proprietary table (Enclosure 1 in ADAMS Accession 

No. ML13022A475) that provided the calculated strains and allowable strains for the RVI base 

metal components and the applied clamping and clamping allowables for RVI bolting 

components. For components whose projected neutron fluence (at 54 EFPY) was projected to 

exceed the applicable fluence threshold, the staff reviewed the proprietary table to verify that: 

(a) the operational strains for non-fastened RVI base metal components were within the 

maximum allowable strain criteria for the components, and (b) the applied preloads for RVI 

bolting components were greater than the minimum required preload needed for structural 

integrity of the fastened RVI assemblies. For RVI non-fastened base-metal components, the 

staff verified that the calculated strains for the components were lower than the limiting 

maximum allowable strain values for the components, as calculated using the applicable ASME 

strain equation given in the RAI response. Similarly for RVI bolting components, the staff 

verified that the preloads applied to the components were greater than the minimum required 

preloads needed for structural integrity of the bolted assemblies.

Based on its review and as described above, the staff finds the applicant’s response to 

RAI 4.7.3-1a, Part a, acceptable.
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By letter dated December 18, 2012, the staff issued RAI 4.7.3-1a, Part b, requesting that the 

applicant justify use of the GEH method for calculating fluence values for the reactor vessel 

internals (RVIs). Subsequently, the staff noted that the license amendment dated 

August 18, 2015 approved use of the MPM single fluence method, which became the GGNS 

CLB methodology for fluence evaluation, as described in SER Section 4.2.1.2. This license 

amendment is based on the staff’s acceptance of the MPM fluence method which adheres to 

RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron 

Fluence,” for the RPV as documented in Section 4.2.1 of this safety evaluation report. In its 

review, the staff confirmed that specific fluence method modeling options important for RVI 

fluence calculations were appropriate and consistent with the relevant guidance in RG 1.190. 

Specifically, the staff confirmed the appropriateness of the following: (1) spatial mesh resolution 

in the axial direction, (2) angular quadrature order with supporting sensitivity studies, (3) 

anisotropic scattering treatment with respect to scattering cross-sections, (4) specification of a 

high resolution three-dimensional neutron source, specifically in the axial direction, (5) detailed 

three-dimensional water density distribution modeled in the core region, and (6) modeling of 

material regions between the active fuel region and the model boundaries. The staff also 

confirmed that fluence method uncertainties associated with RVIs were appropriately 

determined.

The staff finds the fluence calculations for the RVIs acceptable because (1) the applicant used 

appropriate modeling options for RVI fluence calculations using the MPM method which is 

consistent with RG 1.190; and (2) fluence method uncertainties associated with RVIs were 

appropriately determined. The staff’s concern described in RAI 4.2.1-2c, Part 5(b) and RAI 

4.7.3-1a, Part b regarding RVI fluence calculations is resolved.

In its response dated July 29, 2015 to RAI 4.2.1-2c, Part 5(b), the applicant also addressed 

whether the updated RVI fluence values calculated using the staff-approved MPM method affect 

the TLAA regarding the fluence effects on RVIs. The applicant stated that no change to LRA 

Section 4.7.3 is necessary because the RVIs with the updated 54-EFPY fluence values, 

calculated using the MPM fluence method, continue to meet the design specification. By letter 

dated April 4, 2016, the applicant also provided an updated proprietary table that describes the 

calculated strains and maximum allowable strains for RVI components and the applied clamping 

loads and load allowable clamping for RVI bolting components. The staff noted that the 

calculated strains and clamping loads met the acceptance criteria in accordance with the design 

specification.

Therefore, based on this review, the staff finds that the applicant has appropriately 

demonstrated that this TLAA is acceptable in accordance with 10 CFR 54.21(c)(1)(ii) because: 

(a) the applicant has adequately explained how the evaluation of neutron fluence factors into the 

design calculations for RVI components at the facility, (b) the applicant has demonstrated that 

the neutron fluence projection basis for the RVI components is based on use of an acceptable 

neutron fluence methodology, and (c) the staff has verified that the applicant has appropriately 

projected the neutron fluence to the end of the period of extended operation (i.e., to 54 EFPY) 

and has demonstrated that the applicable strains or preload levels will meet the applicable 

design requirements for these parameters. RAI 4.7.3-1a, Parts a and b, are resolved and Open 

Item 4.2.1-1, as related to this TLAA, is closed.

4.7.3.3 UFSAR Supplement

LRA Section A.2.5.3 provides the UFSAR supplement summarizing the TLAA for fluence effects 

for the RVI. The staff reviewed LRA Section A.2.5.3 consistent with SRP-LR Section 4.7.3.2, 
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which states that the following is to be confirmed: (a) that the applicant has provided 

information to be included in the UFSAR supplement that includes a summary description of the 

evaluation of each TLAA, and (b) that each such summary description is appropriate such that 

later changes can be controlled by 10 CFR 50.59. The SRP-LR also states that the description 

should contain information that the TLAA has been dispositioned for the period of extended 

operation. The staff verified that the UFSAR supplement summary description provides an 

adequate summary of the fluence effects for reactor vessel internals analysis and the basis for 

accepting this TLAA in accordance with the requirement in 10 CFR 54.21(c)(1)(ii).

Based on its review of the UFSAR supplement, the staff finds it meets the acceptance criteria in 

SRP-LR Section 4.7.3.2. Additionally, the staff determines that the applicant provided an 

adequate summary description of the Fluence Effects for Reactor Vessel Internals Analysis and 

the applicant’s basis for projecting this TLAA to the end of the period of extended operation, as 

required by 10 CFR 54.21(d).

4.7.3.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the Fluence Effects for Reactor Vessel 

Internals Analysis has been projected to the end of the period of extended operation. The staff 

also concludes that the FSAR 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

As added by letter dated October 2, 2012, in response to RAI 4.1-2a, LRA Section 4.7.4.1 

describes the applicant’s TLAA for the fatigue analysis of cranes. The applicant stated that the 

cranes designed to CMAA-70, have cycles specified as part of their design analysis. The 

applicant determined that the spent fuel cask crane, new fuel handling crane, and polar crane 

include CMAA-70 in their design specifications, and that the number of load cycles a crane is 

qualified for under CMAA-70 is 100,000 cycles. The applicant also stated that the expected 

number of lifts is well below the value specified in CMAA-70. The applicant further stated that 

cranes that were designed to CMAA-70 were evaluated as TLAAs.

The applicant dispositioned the TLAA for the spent fuel cask crane, new fuel handling crane, 

and polar crane in accordance with 10 CFR 54.21(c)(1)(i), that the analysis remains valid for the 

period of extended operation.

4.7.4.2 Staff Evaluation

The staff reviewed the applicant’s TLAA for the spent fuel cask crane, new fuel handling crane, 

and polar crane, and the corresponding disposition of 10 CFR 54.21(c)(1)(i) consistent with 

SRP-LR Section 4.7.3.1.1, which states that the existing analyses should be shown to be 

bounding even during the period of extended operation.

Spent Fuel Cask Crane. The staff reviewed UFSAR Section 9.1.4, “Fuel Handling System,” and 

noted that the primary purpose of the spent fuel cask crane is to facilitate onsite handling of the 

fuel cask. The spent fuel cask crane is a 150-ton capacity crane designed to handle a fuel 

shipping cask or dry fuel storage transfer cask weighing approximately 125 tons. The staff also 
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reviewed the table in LRA Section 4.7.4.1, as amended by letter dated October 2, 2012, and 

noted that the applicant has estimated 250 lifts per operating cycle, and an estimated 

37 operating cycles through the period of extended operation. The applicant’s total estimated 

number of lifts through the period of extended operation is 9,250, which is significantly less than 

the 100,000 permissible cycles for which the crane was designed and, therefore, is acceptable.

New Fuel Handling Crane. The staff reviewed UFSAR Section 9.1.4, “Fuel Handling System,” 

and noted that the new fuel bridge crane is a 5-ton capacity crane which handles new fuel from 

the time it arrives in the fuel handling area until it is placed in the fuel preparation machine. The 

staff also reviewed the table in LRA Section 4.7.4.1, as amended by letter dated 

October 2, 2012, and noted that the applicant has estimated 720 lifts per operating cycle, and 

an estimated 37 operating cycles through the period of extended operation. The applicant’s 

total estimated number of lifts through the period of extended operation is 26,640, which is 

significantly less than the 100,000 permissible cycles for which the crane was designed and, 

therefore, is acceptable.

Polar Crane. The staff reviewed UFSAR Section 9.1.4, “Fuel Handling System,” and noted that 

the polar crane is designed as seismic Category I equipment. The main hoisting equipment is 

designed for a 125-ton capacity, and the auxiliary hoist is designed for a 35-ton capacity. 

UFSAR Section 9.1.4.2.2.1 states that the containment polar crane is used to move all of the 

major components (RV head, shroud head and separator, and dryer assembly), as required by 

operations. The staff also reviewed the table in LRA Section 4.7.4.1, as amended by letter 

dated October 2, 2012, and noted that the applicant has estimated 200 lifts per operating cycle, 

and an estimated 37 operating cycles through the period of extended operation. The applicant’s 

total estimated number of lifts through the period of extended operation is 7,400, which is 

significantly less than the 100,000 permissible cycles for which the crane was designed and,

therefore, is acceptable.

Based on its review, the staff finds the applicant has demonstrated pursuant to 

10 CFR 54.21(c)(1)(i), that the analyses for the spent fuel cask crane, new fuel handling crane, 

and polar crane remain valid for the period of extended operation.

4.7.4.3 UFSAR Supplement

LRA Section A.2.5.4, as amended by letter dated October 2, 2012, provides the UFSAR 

supplement summarizing the fatigue analysis of cranes. The staff reviewed LRA 

Section A.2.5.4 consistent with SRP-LR Section 4.7.3.2, which states that the applicant has 

provided information to be included in the UFSAR supplement that includes a summary

description of the evaluation of each TLAA. SRP-LR Section 4.7.3.2 also states that each 

summary description is reviewed to verify that it is appropriate, such that later changes can be 

controlled by 10 CFR 50.59 and that the description should contain information that the TLAAs 

have been dispositioned for the period of extended operation.

Based on its review of the UFSAR supplement, as amended by letter dated October 2, 2012, 

the staff finds it meets the acceptance criteria in SRP-LR Section 4.7.3.2, and is therefore 

acceptable. Additionally, the staff determines that the applicant provided an adequate summary 

description of its actions to address the fatigue analyses of the spent fuel cask crane, new fuel 

handling crane, and polar crane, as required by 10 CFR 54.21(d).
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4.7.4.4 Conclusion

On the basis of its review, the staff concludes that the applicant has provided an acceptable 

demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the fatigue analyses for the spent fuel 

cask crane, new fuel handling crane, and polar crane 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).

4.8 Conclusion for TLAAs

The staff reviewed the information in LRA Section 4, “Time-Limited Aging Analyses.” On the 

basis of its review, the staff concludes that the applicant has provided a sufficient list of TLAAs, 

as defined in 10 CFR 54.3, and the applicant has demonstrated that: (1) the TLAAs will remain 

valid for the period of extended operation, as required by 10 CFR 54.21(c)(1)(i), (2) the TLAAs 

have been projected to the end of the period of extended operation, as required by 

10 CFR 54.21(c)(1)(ii), or (3) the effects of aging on 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.

With regard to these matters, the staff concludes that there is reasonable assurance that the 

activities authorized by the renewed license will continue to be conducted in accordance with 

the CLB, and that any changes made to the CLB, in order to comply with 10 CFR 54.29(a), are 

in accordance with the Atomic Energy Act of 1954, as amended, and NRC regulations.

5-1

SECTION 5

REVIEW BY THE ADVISORY COMMITTEE ON REACTOR 

SAFEGUARDS

In accordance with Title 10, Part 54, “Requirements for Renewal of Operating Licenses for 

Nuclear Power Plants,” of the Code of Federal Regulations, the Advisory Committee on Reactor 

Safeguards (ACRS) will review the license renewal application (LRA) for Grand Gulf Nuclear 

Station, Unit 1 (GGNS). The ACRS Subcommittee on Plant License Renewal continued its 

detailed review of the LRA after this safety evaluation report (SER) was issued. Entergy 

Operations, Inc. (Entergy or the applicant) and the staff of the United States (US) Nuclear 

Regulatory Commission (NRC) (the staff) meet with the Subcommittee in May 2016, and will 

meet with the full Committee to discuss issues associated with the review of the LRA.

During the 637th meeting of the ACRS held October 6, 2016, the ACRS completed its review of 

the GGNS LRA and the staff’s SER. The ACRS documented its findings in a letter to the 

Commission dated October 14, 2016. A copy of this letter is provided in this section. 
5-2
5-3
5-4
5-5
5-6
6-1

SECTION 6

CONCLUSION

The staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff) reviewed 

the license renewal application (LRA) for Grand Gulf Nuclear Station, Unit 1 (GGNS), in 

accordance with NRC regulations and NUREG-1800, Revision 2, “Standard Review Plan for 

Review of License Renewal Applications for Nuclear Power Plants,” dated December 2010. 

Title 10 of the Code of Federal Regulations (10 CFR) 54.29 sets the standards for issuance of a 

renewed license.

On the basis of its review of the LRA, the staff determines that the requirements of 

10 CFR 54.29(a) have been met.

The staff noted that any requirements of 10 CFR Part 51, Subpart A, will be documented in a 

draft supplement to NUREG-1437, “Generic Environmental Impact Statement for License 

Renewal of Nuclear Plants (GEIS).”

A-1

APPENDIX A

GRAND GULF NUCLEAR STATION, UNIT 1, LICENSE RENEWAL 

COMMITMENTS

During the review of the Grand Gulf Nuclear Station, Unit 1 (GGNS) license renewal application 

(LRA) by the staff of the United States (US) Nuclear Regulatory Commission (NRC) (the staff), 

Entergy Operations, Inc., (Entergy or the applicant) made commitments related to aging 

management programs (AMPs) to manage aging effects for structures and components. The 

following table lists these commitments along with the implementation schedules and sources 

for each commitment.
A-2

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

1 Implement the 115 kilovolt (KV) Inaccessible Transmission Cable Program for 

Grand Gulf Nuclear Station (GGNS) as described in License Renewal Application 

(LRA) Section B.1.1

B.1.1 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

2 Implement the Aboveground Metallic Tanks Program for GGNS as described in 

LRA Section B.1.2

B.1.2 Prior to 

May 1, 2024,

or the end of the 

last refueling outa

prior to 

November 1, 202

whichever is later

3 Enhance the Bolting Integrity Program for GGNS to clarify the prohibition on use 

of lubricants containing MoS2 for bolting, and to specify that proper gasket 

compression will be visually verified following assembly.

Enhance the Bolting Integrity Program to include consideration of the guidance 

applicable for pressure boundary bolting in Regulatory Guide (NUREG) 1339, 

Electric Power Research Institute (EPRI) NP-5769, and EPRI TR-104213.

Enhance the Bolting Integrity Program to include volumetric examination per 

American Society of Mechanical Engineers (ASME) Code Section IX, Table IWB2500-1, Examination Category B-G-1, for high-strength closure bolting regardless 

of code classification.

B.1.3 Prior to May 1, 20

4 Enhance the Boraflex Monitoring Program for GGNS to perform periodic

surveillances of the boraflex neutron absorbing material in the spent fuel pool and 

upper containment pool at least once every 5 years using Boron-10 Areal Density 

Gage for Evaluating Racks (BADGER) testing.

RACKLIFE analysis will continue to be performed each cycle. This analysis will 

include a comparison of the RACKLIFE predicted silica to the plant measured 

silica. This comparison will determine if adjustments to the RACKLIFE loss 

coefficient are merited. The analysis will include projections to the next planned 

RACKLIFE analysis date to ensure current Region I storage locations will not 

need to be reclassified as Region II storage locations in the analysis interval.

B.1.4 Prior to May 1, 20
A-3

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

5 Implement the Buried Piping and Tanks Inspection Program for GGNS as 

described in LRA Section B.1.5. Soil testing will be performed at two locations 

near the stainless steel condensate storage system piping that is subject to aging 

management review. Measured parameters will include soil resistivity, bacteria, 

pH, moisture, chlorides and redox potential. If the soil is determined to be 

corrosive then the number of inspections will be increased from one to two prior to 

and during the period of extended operation.

B.1.5 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

6 Enhance the Boiling Water Reactor (BWR) Vessel Internals Program for GGNS as 

follows.

Evaluate the susceptibility to neutron or thermal embrittlement for reactor vessel

internal components composed of CASS, X-750 alloy, precipitation-hardened (PH) 

martensitic stainless steel (e.g., 15-5 and 17-4 PH steel), and martensitic stainless 

steel (e.g., 403, 410 and 431 steel). This evaluation will include a plant-specific 

identification of the reactor vessel internals components made of these materials.

Inspect portions of the susceptible components determined to be limiting from the 

standpoint of thermal aging susceptibility, neutron fluence, and cracking susceptibility 

(i.e., applied stress, operating temperature, and environmental conditions). The 

inspections will use an inspection technique capable of detecting the critical flaw size 

with adequate margin. The critical flaw size will be determined based on the service 

loading condition and service-degraded material properties. The initial inspection will 

be performed either prior to or within 5 years after entering the period of extended 

operation. If cracking is detected after the initial inspection, the frequency of 

reinspection will be justified based on fracture toughness properties appropriate for the 

condition of the component. The sample size for the initial inspection of susceptible 

components will be 100 percent of the accessible component population, excluding 

components that may be in compression during normal operations.

B.1.11 Prior to May 1, 20
A-4

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

7 Enhance the Compressed Air Monitoring Program for GGNS to apply a 

consideration of the guidance of ASME OM-S/G-1998, Part 17; ANSI/ISAS7.0.01-1996; EPRI NP-7079; and EPRI TR-108147 to the limits specified for air 

system contaminants.

Enhance the Compressed Air Monitoring Program to include periodic and 

opportunistic inspections of accessible internal surfaces of piping, compressors, 

dryers, aftercoolers, and filters to apply consideration of the guidance of ASME 

OM-S/G-1998, Part 17 for inspection frequency and inspection methods of these 

components in the following compressed air systems.

• Automatic Depressurization System (ADS) air

• Division 1 Diesel Generator Starting Air (D1DGSA)

• Division 2 Diesel Generator Starting Air (D2DGSA)

• Division 3 Diesel Generator Starting Air (D3DGSA), also known as the HPCS 

Diesel Generator

• Instrument Air (IA)

B.1.12 Prior to May 1, 20

8 Enhance the Diesel Fuel Monitoring Program to include a 10-year periodic 

cleaning and internal inspection of the fire water pump diesel fuel oil tanks, the 

diesel fuel oil day tanks for Divisions I, II, III, and the diesel fuel oil drip tanks for 

Divisions I, II. These cleanings and internal inspections will be performed at least 

once during the 10-year period prior to the period of extended operation and at 

succeeding 10-year intervals. If visual inspection is not possible, a volumetric 

inspection will be performed.

Enhance the Diesel Fuel Monitoring Program to include a volumetric examination 

of affected areas of the diesel fuel tanks if evidence of degradation is observed 

during visual inspection. The scope of this enhancement includes the diesel fuel 

oil day tanks (Divisions I, II, III), the diesel fuel oil storage tanks (Divisions I, II, III), 

the diesel fuel oil drip tanks (Divisions I, II), and the diesel fire pump fuel oil 

storage tanks, and is applicable to the inspections performed during the 10-year 

period prior to the period of extended operation and at succeeding 10-year 

intervals.

B.1.16 Prior to 

May 1, 2014, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-5

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

9 Enhance the External Surfaces Monitoring Program to include instructions for 

monitoring of the aging effects for flexible polymeric components through manual 

or physical manipulation of the material, including a sample size for manipulation 

of at least 10 percent of available surface area.

Enhance the External Surfaces Monitoring Program as follows.

Underground components within the scope of this program will be clearly 

identified in program documents.

Instructions will be provided for inspecting all underground components within the 

scope of this program during each 5-year period, beginning 10 years prior to 

entering the period of extended operation.

Revise External Surfaces Monitoring Program procedures to specify the following 

for insulated components.

a. Periodic representative inspections will be conducted during each 

10-year period during the period of extended operation.

b. For a representative sample of insulated indoor components 

exposed to condensation (because the component is operated 

below the dew point), insulation will be removed for visual 

inspection of the component surface. Inspections will include a 

minimum of 20 percent of the inscope piping length for each 

material type (e.g., steel, stainless steel, copper alloy, aluminum), 

or for components with a configuration which does not conform to 

a 1-ft axial length determination (e.g., valve, accumulator), 

20 percent of the surface area. Alternatively, insulation will be 

removed and a minimum of 25 inspections will be performed that 

can be a combination of 1-ft axial length sections and individual 

components for each material type.

c. Inspection locations will be selected based on the likelihood of 

corrosion under insulation (CUI). For example, CUI is more likely 

for components experiencing alternate wetting and drying in 

environments where trace contaminants could be present and for 

components that operate for longer periods of time below the dew 

point. Subsequent inspections can be limited to an examination 

of the exterior surface of the insulation for indications of damage 

to the jacketing or protective outer layer of the insulation, if the 

following conditions are verified in the initial inspection.

B.1.18 Prior to 

May 1, 2014, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-6

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

9

(cont.)

d. No loss of material due to general, pitting, or crevice corrosion 

beyond that which could have been present during initial 

construction, and

e. No evidence of cracking. If the external visual inspections of the 

insulation reveal damage to the exterior surface of the insulation 

or there is evidence of water intrusion through the insulation 

(e.g., water seepage through insulation seams/joints), periodic 

inspections under the insulation will continue as described above. 

Removal of tightly adhering insulation that is impermeable to 

moisture is not required unless there is evidence of damage to the 

moisture barrier. Tightly adhering insulation is considered a 

separate population from the remainder of insulation installed on 

in-scope components. The entire population of in-scope 

accessible piping component surfaces that have tightly adhering 

insulation will be visually inspected for damage to the moisture 

barrier at the same frequency as inspections of other types of 

insulation. These inspections will not be credited toward the 

inspection quantities for other types of insulation.

10 Enhance the Fatigue Monitoring Program to monitor and track all critical thermal 

and pressure transients for all components that have been identified to have a 

fatigue Time Limited Aging Analysis (TLAA).

Enhance the Fatigue Monitoring Program to perform a review of the GGNS 

high-energy line break analyses and the corresponding tracking of associated 

cumulative usage factors to ensure the GGNS program adequately manages 

fatigue usage for these locations.

Fatigue usage calculations that consider the effects of the reactor water 

environment will be developed for a set of sample reactor coolant system 

components. This sample set will include the locations identified in NUREG/CR6260 and additional plant-specific component locations in the reactor coolant 

pressure boundary if they are found to be more limiting than those considered in 

NUREG/CR-6260. Fen factors will be determined using the formulae sets listed in 

Section 4.3.3. If necessary following this analysis, revised cycle limits will be 

incorporated into the Fatigue Monitoring Program documentation.

B.1.19 Prior to 

November 1, 202
A-7

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

10 (cont.) Enhance the Fatigue Monitoring Program to provide updates of the fatigue usage 

calculations on an as needed basis if an allowable cycle limit is approached, or in 

a case where a transient definition has been changed, unanticipated new thermal 

events are discovered, or the geometry of components have been modified. The 

program revision will include providing for the consideration of the recirculation 

pump fatigue analysis exemption validity if cycles that were input into the 

exemption evaluation exceed their limits.

11 Enhance the Fire Protection Program to require visual inspections of the 

Halon/CO2 fire suppression system at least once every fuel cycle to examine for 

signs of corrosion.

Enhance the Fire Protection Program to require visual inspections of fire damper 

framing at least once every fuel cycle to check for signs of degradation.

Enhance the Fire Protection Program to require visual inspection of concrete 

curbs, manways, hatches, manhole covers, hatch covers, and roof slabs at least 

once every fuel cycle to confirm that aging effects are not occurring.

Enhance the Fire Protection Program to require an external visual inspection of 

the CO2 tank at least once every fuel cycle to examine for signs of corrosion.

B.1.20 Prior to May 1, 20

12 The Fire Water System Program will be enhanced as follows.

Revise Fire Water System Program procedures to ensure sprinkler heads are 

tested or replaced in accordance with NFPA 25 (2011 Edition), Section 5.3.1.

Revise Fire Water System program procedures to specify replacing any sprinkler 

that shows signs of leakage or corrosion.

Revise Fire Water System Program procedures to perform a flow blockage 

evaluation if during main drain testing, the flowing pressure drops more than 

10 percent from the flowing pressure observed during the original acceptance test 

or other previously performed tests at the same location.

Revise Fire Water System Program procedures to ensure there is no flow 

blockage by visually inspecting the charcoal filter deluge fire water distribution 

piping when the charcoal is replaced.

B.1.21 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-8

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

12 (cont.) Revise Fire Water System Program procedures to perform air flow testing to 

ensure there are no obstructions downstream of the deluge valves for control 

room fresh air, auxiliary building standby gas, containment cooling system, and 

containment vent charcoal filter units each refueling cycle.

Revise Fire Water System Program procedures to include periodic internal 

inspections and documentation of any excessive accumulation of corrosion 

products appreciable localized corrosion (e.g., pitting) beyond a normal oxide 

layer in the corrective action program and that follow-up volumetric wall thickness 

examination will be performed as part of the corrective action.

Revise Fire Water System Program procedures to require internal inspections at 

the end of one fire main and the end of one branch line on two of the wet pipe 

systems in the auxiliary building, two of the wet pipe systems in the control 

building, and one wet pipe system in the fire pump house every 5 years. During 

each 5-year internal inspection period, inspect different wet pipe sprinklers such 

that internal inspections are performed on all of the wet pipe sprinkler systems in 

the auxiliary and control buildings every 15 years and in the fire pump house 

every 10 years. In the event internal obstructions are identified in a building wet 

pipe system, expand the number of inspections to include all of the wet pipe 

sprinkler systems in that building.

Revise Fire Water System Program procedures to periodically open a flushing 

connection at the end of a main and remove a component such as a sprinkler 

toward the end of one branch line for piping associated with preaction, and dry 

pipe systems to perform a visual inspection in accordance with NFPA 25 (2011 

Edition) Section 14.2.1.

Revise Fire Water System Program procedures to inspect the normally dry fire 

suppression piping and piping components with a 10 CFR 54.4(a)(3) intended 

function that may be wetted to ensure that the piping does not collect water. In 

the event areas are identified that collect water, perform the following augmented 

tests and inspections to ensure that flow blockage have not occurred.

1. In each 5-year interval beginning with the 5-year period before the period of 

extended operation, perform either (a) a flow test or flush sufficient to detect 

potential flow blockage, or (b) visual inspections on 100 percent of the 

internal surface of piping segments that allow water to collect. 
A-9

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

12 (cont.) In each 5-year interval during the period of extended operation, perform 

volumetric wall thickness inspections on 20 percent of the length of piping 

segments that allow water to collect. Data points are obtained to the extent that 

potential degraded conditions can be identified (e.g., general corrosion, 

microbiologically-influenced corrosion). The 20 percent of piping inspected in 

each 5-year interval should be in different locations than piping inspected in 

previous intervals.

If the results of a 100 percent interval visual inspection are acceptable and the 

segment is not subsequently wetted, no further augmented tests or inspections 

are necessary.

a. Revise Fire Water System Program procedures to include inspecting 

sprinklers in the overhead from the floor for signs of corrosion.

b. Revise Fire Water System Program procedure to include periodic 

inspection of hose reels for degradation.

c. Revise Fire Water System Program procedures to replace sprinklers that 

the tested sprinkler represents, if the tested sprinkler fails to meet the test 

acceptance criteria.

d. Revise Fire Water System Program procedures to ensure the hydrant 

valve is opened fully and ensure the hydrant flows for not less than 

1 minute during flow testing.

e. Revise Fire Water System Program procedures for inspecting the interior 

of the fire water tanks to include the following.

1. A review of at least two previous coating inspection results is 

performed prior to conducting a coating inspection.

2. The coating inspection report will include a list of locations identified 

with coating degradation including, where possible, photographs

indexed to inspection location, and a prioritization of the repair 

areas into areas that must be repaired before returning the system 

to service and areas where coating repair can be postponed to a 

subsequent inspection or repair opportunity.
A-10

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

12 (cont.) f. Revise Fire Water System Program procedures for inspecting the interior 

of the fire water tanks at the frequency specified by NFPA 25 

Section 9.2.6 to include the following.

1. Testing for possible voids beneath the tank.

2. Inspection of the vortex breaker.

3. Coating inspections and documentation, and review of inspection 

results are performed by qualified personnel.

i. Individuals performing coating inspections are certified to 

ANSI N45.2.6, “Qualifications of Inspection, Examination, and 

Testing Personnel for Nuclear Power Plants.”

ii. A nuclear coatings specialist qualified in accordance with 

ASTM D7108-05, “Standard Guide for Establishing Qualifications 

for a Nuclear Coatings Specialist,” will evaluate inspection 

findings and prepare post-inspection reports.

g. Revise Fire Water System Program procedures to determine the extent 

of coating defects on the interior of the fire water tanks by using one or 

more of the following methods when conditions such as cracking, 

peeling, blistering, delamination, rust, or flaking are identified during 

visual examination.

1. Adhesion testing endorsed by Regulatory Guide (RG) 1.54.

2. Dry film thickness measurements at random locations to determine 

overall coating thickness as specified in NFPA 25 (2011 Edition) 

Section 9.2.7 Item (2).

3. Nondestructive ultrasonic readings to evaluate the wall thickness 

where there is evidence of pitting or corrosion as specified in 

NFPA 25 (2011 Edition) Section 9.2.7 Item (3).

4. Spot wet-sponge tests to detect pinholes, cracks, or other 

compromises in the coating as specified in NFPA 25 (2011 Edition) 

Section 9.2.7 Item (4).

5. Test the tank bottom for metal loss or rust on the underside by use 

of ultrasonic testing where there is evidence of pitting or corrosion as 

specified in NFPA 25 (2011 Edition) Section 9.2.7 Item (5).
A-11

12 (cont.) h. Revise Fire Water System Program procedures to determine the extent 

of coating defects on the interior of the fire water tanks by using one or 

more of the following methods when conditions such as cracking, 

peeling, blistering, delamination, rust, or flaking are identified during 

visual examination in accordance with NFPA 25 (2011 Edition), 

Section 9.2.6.4.

1. Lightly tapping and scraping the coating to determine the coating 

integrity.

2. Dry film thickness measurements at random locations to determine 

overall thickness of the coating.

3. Wet-sponge testing or dry film testing to identify holidays in the 

coating.

4. Adhesion testing in accordance with ASTM D3359, ASTM D4541, or 

equivalent testing endorsed by RG 1.54 at a minimum of three 

locations.

5. Ultrasonic testing where there is evidence of pitting or corrosion to 

determine if the tank thickness meets the minimum thickness 

criteria.

i. Revise the Fire Water System Program procedures to ensure a fire water 

tank is not returned to service after identifying interior coating blistering, 

delamination, or peeling unless there are only a few small intact blisters 

surrounded by coating bonded to the substrate as determined by a 

qualified coating inspector, or the following actions are performed.

1. Any blistering in excess of a few small intact blisters, or blistering not 

completely surrounded by coating bonded to the substrate is 

removed.

2. Any delaminated or peeled coating is removed.

3. The exposed underlying coating is verified to be securely bonded to 

the substrate as determined by an adhesion test endorsed by 

RG 1.54 at a minimum of three locations.

4. The outermost coating is feathered and the remaining outermost 

coating is determined to be securely bonded to the coating below via 

an adhesion test endorsed by RG 1.54 at a minimum of three 

locations adjacent to the defective area.

12 (cont.) 5. Ultrasonic testing is performed where there is evidence of pitting or 

corrosion to ensure the tank meets minimum wall thickness 

requirements.
A-12

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

6. An evaluation is performed to ensure downstream flow blockage is 

not a concern.

7. A follow-up inspection is scheduled to be performed within 2 years 

and every 2 years after that until the coating is repaired, replaced, or 

removed.

j. Revise the Fire Water System Program procedures to include the 

following acceptance criteria for loss of coating integrity.

1. Indications of peeling and delamination are not acceptable.

2. Blisters are evaluated by a coating specialist qualified in accordance 

with an ASTM International standard endorsed in RG 1.54, including 

staff limitations associated with the use of a particular standard. 

Blisters should be limited to a few intact small blisters that are 

completely surrounded by sound coating/lining bonded to the 

substrate. Blister size and frequency should not be increasing 

between inspections (e.g., reference ASTM D714-02, “Standard Test 

Method for Evaluating Degree of Blistering of Paints”).

3. Indications such as cracking, flaking, and rusting are to be evaluated 

by a coatings specialist qualified in accordance with an ASTM 

International standard endorsed in RG 1.54, including staff 

limitations associated with the use of a particular standard.

4. Minor cracking and spalling of cementitious coatings/linings is 

acceptable provided there is no evidence that the coating/lining is 

debonding from the base material.

5. As applicable, wall thickness measurements, projected to the next 

inspection, meet design minimum wall requirements.

6. Adhesion testing results, when conducted, meet or exceed the 

degree of adhesion recommended in plant specific design 

requirements specific to the coating/lining and substrate.
A-13

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

12 (cont.) k. Revise Fire Water System Program procedures to include a visual 

inspection of a representative number of locations on the interior surface 

of below-grade fire protection piping at a frequency of at least once every 

10 years during the period of extended operation. A representative 

number is 20 percent of the population (defined as locations having the 

same material, environment, and aging effect combination) with a 

maximum of 25 locations.

l. Revise Fire Water System Program procedures to inspect the strainers 

upstream of the deluge valves every 3 years.

m. Revise Fire Water System Program procedures for flow testing, main 

drain testing, or internal inspection to specify an acceptance criterion of 

no debris observed (i.e., no corrosion products that are sufficient to 

obstruct flow or cause downstream components to become clogged.)

n. Revise Fire Water System Program procedures to require an obstruction 

evaluation if any signs of abnormal corrosion or blockage are identified 

during flow testing, main drain testing, or internal inspection. Any signs 

of corrosion or blockage should be removed, its source determined and 

corrected, and the condition entered into the corrective action program. 

Where corrosion or blockage is found, the obstruction evaluation should 

consider system valves, risers, cross mains and branch lines, and the 

performance of a complete flushing program by qualified personnel.

o. Revise Fire Water System Program procedures to require an obstruction 

evaluation in the event there is frequent false tripping of the dry pipe fire 

suppression system associated with the auxiliary building railroad 

access.

13 Enhance the Flow-Accelerated Corrosion Program to revise program 

documentation to specify that downstream components are monitored closely to 

mitigate any increased wear when susceptible upstream components are replaced 

with resistant materials, such as high Cr material.

B.1.22 Prior to May 1, 20
A-14

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

14 Enhance the Inservice Inspection – IWF Program to address inspections of 

accessible sliding surfaces.

Enhance the Inservice Inspection – IWF Program to clarify that parameters 

monitored or inspected will include corrosion; deformation; misalignment of 

supports; missing, detached, or loosened support items; improper clearances of 

guides and stops; and improper hot or cold settings of spring supports and 

constant load supports. Accessible areas of sliding surfaces will be monitored for 

debris, dirt, or indications of excessive loss of material due to wear that could 

prevent or restrict sliding as intended in the design basis of the support. Structural 

bolts will be monitored for corrosion and loss of integrity of bolted connections due 

to self-loosening and material conditions that can affect structural integrity. Highstrength structural bolting (actual measured yield strength greater than or equal to 

150 ksi or 1,034 MPa in sizes greater than 1 inch nominal diameter) susceptible to 

stress corrosion cracking (SCC) will be monitored for SCC. When a component 

support is found with minor age-related degradation, but still is evaluated as 

“acceptable for continued service” as defined in IWF-3400, the program owner 

may choose to repair the degraded component and substitute a randomly 

selected component that is more representative of the general population for it in 

subsequent inspections.

Enhance the Inservice Inspection – IWF Program to clarify that detection of aging 

effects will include:

a. Monitoring structural bolting (American Society for Testing Materials 

(ASTM) A-325, ASTM F1852, and ASTM A490 bolts) and anchor bolts for 

loss of material, loose or missing nuts, loss of preload and cracking of 

concrete around the anchor bolts.

b. Volumetric examination comparable to that of ASME Code Section XI, 

Table IW8-2500-1, Examination Category 8-G-1 for high-strength structural 

bolting to detect cracking in addition to the VT-3 examination. This 

volumetric examination may be waived with adequate plant-specific 

justification.

B.1.24 Prior to May 1, 20
A-15

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

14

(cont.)

c. Identification of all component supports that contain high-strength bolting 

(actual measured yield greater than or equal to 150 ksi) in sizes greater 

than 1 inch nominal diameter. The extent of examination for support types 

that contain high-strength bolting will be as specified in ASME Code Section 

XI, Table IWF-2500-1. GGNS will examine high-strength structural bolting 

on the frequency specified in ASME Code Section XI, Table IWF-2500-1.

Enhance the Inservice Inspection – IWF Program acceptance criteria to include 

the following as unacceptable conditions.

a. Loss of material due to corrosion or wear, which reduces the load 

bearing capacity of the component support;

b. Debris, dirt, or excessive wear that could prevent or restrict sliding of the 

sliding surfaces as intended in the design basis of the support; and

c. Cracked or sheared bolts, including high-strength bolts, and anchors.

Enhance the Inservice Inspection – IWF Program preventive action to include the 

following.

Incorporate into plant procedures recommendations delineated in NUREG-1339, 

and Electric Power Research Institute (EPRI) NP-5769 and TR-1 04213 for highstrength structural bolting. These recommendations should address proper 

selection of bolting material, proper installation torque or tension, and the use of 

appropriate lubricants and sealants.

15 Enhance the Inspection of Overhead Heavy Load and Light Load Handling 

Systems Program to include monitoring of rails in the rail system for the aging 

effect “wear,” and structural connections/bolting for loose or missing bolts, nuts, 

pins, or rivets. Additionally, the program will be clarified to include visual 

inspection of structural components and structural bolts for loss of material due to 

various mechanisms and structural bolting for loss of preload due to selfloosening.

Enhance the Inspection of Overhead Heavy Load and Light Load Handling 

Systems Program acceptance criteria to state that any significant loss of material 

for structural components and structural bolts, and significant wear of rails in the 

rail system, is evaluated according to ASME B30.2 or other applicable industry 

standard in the ASME B30 series.

B.1.25 Prior to May 1, 20
A-16

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

16 Implement the Internal Surfaces in Miscellaneous Piping and Ducting 

Components Program as described in LRA Section B.1.26.

B.1.26 Prior to May 1, 20

17 Enhance the Masonry Wall Program to clarify that parameters monitored or 

inspected will include monitoring gaps between the supports and masonry walls 

that could potentially affect wall qualification.

Enhance the Masonry Wall Program to clarify that detection of aging effects 

require masonry walls to be inspected every 5 years unless technical justification 

is provided to extend the inspection to a period not to exceed 10 years.

B.1.27 Prior to May 1, 20

18 Implement the Non-EO Cable Connections Program as described in LRA Section 

B.1.28

B.1.28 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

19 Enhance the Non-Environmentally Qualified (Non-EQ) Inaccessible Power Cables 

(400V to 35kV) Program to include low-voltage (400V to 2kV) power cables.

Enhance the Non-EQ Inaccessible Power Cables (400V to 35kV) Program to 

include condition-based inspections of manholes not automatically dewatered by a 

sump pump being performed following periods of heavy rain or potentially high 

water table conditions, as indicated by river level.

Enhance the Non-EQ Inaccessible Power Cables (400V to 35kV) Program to 

clarify that the inspections will include direct observation that cables are not 

wetted or submerged, that cables/splices and cable support structures are intact, 

and that dewatering/drainage systems (i.e., sump pumps) and associated alarms 

if applicable operate properly.

B.1.29 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-17

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

20 Implement the Non-EQ Instrumentation Circuits Test Review Program as 

described in LRA Section B.1.30.

B.1.30 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

21 Implement the Non-EQ Insulated Cables and Connections Program as described 

in LRA Section B.1.31.

B.1.31 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

22 Enhance the Oil Analysis Program to provide a formalized analysis technique for 

particulate counting.

Enhance the Oil Analysis Program to include piping and components within the 

main generator system (N41) with an internal environment of lube oil.

B.1.32 Prior to May 1, 20

23 Implement the One-Time Inspection Program as described in LRA Section B.1.33. B.1.33 Within the 10 yea

prior to 

November 1, 202

24 Implement the One-Time Inspection - Small Bore Piping Program as described in 

LRA Section B.1.34.

B.1.34 Within the 6 years 

prior to 

November 1, 202

25 Enhance the Periodic Surveillance and Preventive Maintenance Program to revise 

program guidance documents as necessary to include all activities as described in 

LRA Section B.1.35.

B.1.35 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-18

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

26 Enhance the Protective Coating Program to include parameters monitored or 

inspected by the program per the guidance provided in ASTM 05163-08.

Enhance the Protective Coating Monitoring and Maintenance Program to provide 

for inspection of coatings near sumps or screens associated with the Emergency 

Core Cooling System.

Enhance the Protective Coating Program to include acceptance criteria per ASTM 

05163-08.

B.1.36 Prior to May 1, 20

27 Ensure that the additional requirements of the ISP(E) specified in BWRVIP-86, 

Revision 1, including the conditions of the final NRC safety evaluation for 

BWRVIP-116 incorporated in BWRVIP-86, Revision 1, will be addressed before 

the period of extended operation.

Ensure that new fluence projections through the period of extended operation and 

the latest vessel beltline ART Tables are provided to the BWRVIP prior to the 

period of extended operation.

B.1.38 Prior to May 1, 20

28 Enhance the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plant Program to clarify that detection of aging effects will monitor 

accessible structures on a frequency not to exceed 5 years consistent with the 

frequency for implementing the requirements of RG 1.127.

Enhance the RG 1.127, Inspection of Water-Control Structures Associated with 

Nuclear Power Plant Program to perform periodic sampling, testing, and analysis 

of ground water chemistry for pH, chlorides, and sulfates on a frequency of at 

least every 5 years.

Enhance the RG 1.127, Inspection of Water-Control Structures Associated With 

Nuclear Power Plant Program acceptance criteria to include quantitative 

acceptance criteria for evaluation and acceptance based on the guidance 

provided in ACI 349.3R.

B.1.39 Prior to May 1, 20

29 Implement the Selective Leaching Program as described in LRA Section B.1.40. B.1.40 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later
A-19

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

30 Enhance the Structures Monitoring Program to clarify that the scope includes the 

following:

a. In-scope structures and structural components.

• Containment Building (GGN 2)

• Control House - Switchyard

• Culvert No.1 and drainage channel

• Manholes and Ductbanks

• Radioactive Waste Building Pipe Tunnel

• Auxiliary Building (GGN2)

• Turbine Building (GGN2)

b. In-scope structural components

• Anchor bolts

• Anchorage / embedments

• Base plates

• Basin debris screen and grating

• Battery racks

• Beams, columns, floor slabs and interior walls

• Cable tray and cable tray supports

• Component and piping supports

• Conduit and conduit supports

• Containment sump liner and penetrations

• Containment sump structures

• Control room ceiling support system

• Cooling tower drift eliminators

• Cooling tower fill

• CST/RWST retaining basin (wall)

• Diesel fuel tank access tunnel slab

• Drainage channel

• Drywell electrical penetration sleeves

• Drywell equipment hatch

• Drywell floor slab (concrete)

• Drywell head

• Drywell head access manway

• Drywell liner plate

• Drywell mechanical penetration sleeves

• Drywell personnel access lock

B.1.42 Prior to May 1, 20
A-20

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

30

(cont.)

• Drywell wall (concrete)

• Ductbanks

• Electrical and instrument panels and enclosures

• Equipment pads/foundations

• Exterior walls

• Fan stack grating

• Fire proofing

• Flood curbs

• Flood retention materials (spare parts)

• Flood, pressure and specialty doors

• Floor slab

• Foundations

• HVAC duct supports

• Instrument line supports

• Instrument racks, frames and tubing trays

• Interior walls

• Main steam pipe tunnel

• Manholes

• Manways, hatches, manhole covers, and hatch

covers

• Metal siding

• Missile shields

• Monorails

• Penetration sealant (flood, radiation)

• Penetration sleeves (mechanical/electrical not

penetrating primary containment boundary)

• Pipe whip restraints

• Pressure relief panels

• Reactor pedestal

• Reactor shield wall (steel portion)

• Roof decking

• Roof hatches

• Roof membrane

• Roof slabs

• RPV pedestal sump liner and penetrations

• Seals and gaskets (doors, manways and

hatches)

• Seismic isolation joint
A-21

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

30

(cont.)

• Stairway, handrail, platform, grating, decking,

and ladders

• Structural bolting

• Structural steel, beams columns, and plates

• Sumps and sump liners

• Support members: welds; bolted connections;

support anchorages to building structure

• Support pedestals

• Transmission towers (see Note 1)

• Upper containment pool floor and walls

• Vents and louvers

• Weir wall liner plate

Note 1: The inspections of these structures may be performed by the 

transmission personnel. However, the results of the inspections will be provided 

to the GGNS Structures Monitoring Program owner for review.

c. Clarify the term “significant degradation” to include “that could lead to loss of 

structural integrity.”

d. Include guidance to perform periodic sampling, testing, and analysis of 

ground water chemistry for pH, chlorides, and sulfates on a frequency of at 

least every 5 years.

Enhance the Structures Monitoring Program to clarify that parameters monitored 

or inspected include:

a. inspection for missing nuts for structural connections.

b. monitoring sliding/bearing surfaces such as Lubrite plates for loss of material 

due to wear or corrosion, debris, or dirt. The program will be enhanced to 

include monitoring elastomeric vibration isolators and structural sealants for 

cracking, loss of material, and hardening.

c. Include periodically inspecting the leak chase system associated with the 

upper containment pool and spent fuel pool to ensure the tell-tales are free of 

significant blockage. The inspection will also inspect concrete surfaces for 

degradation where leakage has been observed, in accordance with this 

Program.
A-22

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

30

(cont.)

Enhance the Structures Monitoring Program to clarify that detection of aging 

effects will:

a. Include augmented inspections of vibration isolators by feel or touch to 

detect hardening if the vibration isolation function is suspect.

b. Require inspections every 5 years for structures and structural components 

within the scope of license renewal.

c. Require direct visual examinations when access is sufficient for the eye to 

be within 24 inches of the surface to be examined and at an angle of not 

less than 300 to the surface. Mirrors may be used to improve the angle of 

vision and accessibility in constricted areas.

d. Specify that remote visual examination may be substituted for direct 

examination. For all remote visual examinations, optical aids such as 

telescopes, borescopes, fiber optics, cameras, or other suitable instruments 

may be used provided such systems have a resolution capability at least 

equivalent to that attainable by direct visual examination.

e. Include instructions to augment the visual examinations of roof membranes, 

and seals and gaskets (doors, manways, and hatches) with physical 

manipulation of at least 10 percent of available surface area.

Enhance the Structures Monitoring Program acceptance criteria by prescribing 

acceptance criteria based on information provided in industry codes, standards, 

and guidelines including NEI 96-03, ACI 201.1R-92, ANSI/ASCE 11-99 and 

ACI 349.3R-96. Industry and plant-specific operating experience will also be 

considered in the development of the acceptance criteria.
A-23

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

31 Enhance the Water Chemistry Control – Closed Treated Water Program to 

provide a corrosion inhibitor for the engine jacket water on the engine-driven fire 

water pump diesel in accordance with industry guidelines and vendor 

recommendations.

Enhance the Water Chemistry Control – Closed Treated Water Program to 

provide periodic flushing of the engine jacket water and cleaning of heat 

exchanger tubes for the engine-driven fire water pump diesel in accordance with 

industry guidelines and vendor recommendations.

Enhance the Water Chemistry Control – Closed Treated Water Program to 

provide testing of the engine jacket water for the engine-driven fire water pump 

diesels at least annually.

Enhance the Water Chemistry Control – Closed Treated Water Program to revise 

the water GNRO chemistry procedure for closed treated water systems to align 

the water chemistry control parameter limits with those of EPRI 1007820.

Enhance the Water Chemistry Control – Closed Treated Water Program to 

conduct inspections whenever a boundary is opened for the following systems.

• Drywell chilled water (DCW - system P72)

• Plant chilled water (PCW - system P71)

• Diesel generator cooling water subsystem for Division I and II standby diesel 

generators

• Diesel engine jacket water for engine-driven fire water pump

• Diesel generator cooling water subsystem for Division III (HPCS) diesel 

generator

• Turbine building cooling water (TBCW - system P43)

• Component cooling water (CCW - system P42)

B.1.44 Prior to May 1, 20
A-24

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

31

(cont.)

These inspections will be conducted in accordance with applicable ASME Code 

requirements, industry standards, and other plant-specific inspection and 

personnel qualification procedures that are capable of detecting corrosion or 

cracking.

Enhance the Water Chemistry Control – Closed Treated Water Program to inspect 

a representative sample of piping and components at a frequency of once every 

10 years for the following systems.

• Drywell chilled water (DCW - P72)

• Plant chilled water (PCW - P71)

• Diesel generator cooling water subsystem for Division I and II standby diesel 

generators

• Diesel engine jacket water for engine-driven fire water pump

• Diesel generator cooling water subsystem for Division III (HPCS) diesel 

generator

• Turbine building cooling water (TBCW - P43)

• Component cooling water (CCW - P42)

Components inspected will be those with the highest likelihood of corrosion or 

cracking. A representative sample is 20% of the population (defined as 

components having the same material, environment, and aging effect 

combination) with a maximum of 25 components. The inspection methods will be 

in accordance with applicable ASME Code requirements, industry standards, or 

other plant-specific inspection and personnel qualification procedures that ensure 

the capability of detecting corrosion or cracking.

32 Enhance the BWR CRD Return Line Nozzle Program to include inspection of the 

CRD return line nozzle inconel end cap to carbon steel safe end dissimilar metal 

weld once prior to the period of extended operation and every 10 years thereafter.

B.1.6 Prior to 

May 1, 2024, or th

end of the last

refueling outage

prior to 

November 1, 202

whichever is later

33 Enhance the BWR Penetrations Program to include that site procedures which 

implement the guidelines of BWRVIP-47-A will be clarified to indicate that the 

guidelines of BWRVIP-47-A apply without exceptions.

B.1.8 Prior to May 1, 20
A-25

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

34 Deleted. 

35 The Service Water Integrity Program will be enhanced as follows.

During the 10-year period prior to the period of extended operation, visual 

inspections will be performed of coated internal surfaces of standby service water 

system components. Subsequent coating inspections will be performed based on 

inspection results as follows.

i. If no peeling, delamination, blisters, or rusting are observed, and any 

cracking and flaking has been found acceptable, subsequent inspections 

will be performed at least once every 6 years. If the coating is inspected on 

one train and no indications are found, and, if the redundant train has the 

same coating and turbulent flow is not present, then the redundant train 

need not be inspected during that inspection interval.

ii. If the inspection results do not meet (i) and a coating specialist has

determined that no remediation is required, then subsequent inspections 

will be conducted on an every other refueling outage interval.

iii. If the inspection results do not meet (i) and a coating specialist determines

remediation is required, then the coated components can only be returned 

to service if the following actions are performed: (1) any blistering in 

excess of a few small intact blisters, or blisters not completely surrounded 

by coating bonded to the substrate is removed, (2) any delaminated or 

peeled coating is removed, (3) the exposed underlying coating is verified to 

be securely bonded to the substrate at a minimum of three locations as

determined by adhesion testing endorsed by RG 1.54 adjacent to the 

defective area, (4) the outer most coating is feathered and the remaining 

outermost coating is determined to be securely bonded to the coating 

below via adhesion testing endorsed by RG 1.54, (5) ultrasonic testing is 

performed to ensure the component meets the minimum wall thickness 

requirements, and (6) an evaluation is performed to ensure blockage 

downstream is not a concern, (7) a follow-up inspection is performed within

2 years and every 2 years until the coating is repaired, replaced, or

removed.

B.1.41 Within the 10 yea

prior to 

November 1, 202
A-26

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

35 (cont.) Revise Service Water Integrity Program documents to include inspections for loss 

of material due to erosion.

Revise Service Water Integrity Program documents to include visual inspections 

for loss of coating integrity during the 10-year period prior to the period of 

extended operation. Include provisions to specify subsequent coating inspections 

based on inspection results as follows.

i. If no peeling, delamination, blisters, or rusting are observed, and any 

cracking and flaking has been found acceptable, subsequent inspections 

will be performed at least once every 6 years. If the coating is inspected on 

one train and no indications are found, and the redundant train has the 

same coating and turbulent flow is not present, then the redundant train 

need not be inspected during that inspection interval.

ii. If the inspection results do not meet (i) and a coating specialist has

determined that no remediation is required, then subsequent inspections 

will be conducted on an every other refueling outage interval.

iii. If the inspection results do not meet (i) and a coating specialist determines

remediation is required, then the coated components can only be returned 

to service if the following actions are performed: (1) any blistering in 

excess of a few small intact blisters, or blisters not completely surrounded 

by coating bonded to the substrate is removed, (2) any delaminated or 

peeled coating is removed, (3) the exposed underlying coating is verified to 

be securely bonded to the substrate at a minimum of three locations as

determined by adhesion testing endorsed by RG 1.54 adjacent to the 

defective area, (4) the outer most coating is feathered and the remaining 

outermost coating is determined to be securely bonded to the coating 

below via adhesion testing endorsed by RG 1.54, (5) ultrasonic testing is 

performed to ensure the component meets the minimum wall thickness 

requirements, (6) an evaluation is performed within 2 years and every 

2 years until the coating is repaired, replaced, or removed.

Revise Service Water Integrity Program procedures for inspecting the interior of

coated components to include one or more of the following methods to determine 

the condition of the coating and the condition of the component under the 

degraded coating when conditions such as cracking, peeling, blisters, 

delamination, rust, or flaking are identified during the visual examination.

B.1.41 Prior to May 1, 20
A-27

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

35 (cont.) 1. Lightly tapping and scraping the coating to determine the coating 

integrity.

2. Wet-sponge testing or dry film testing to identify holidays in the coating.

3. Adhesion testing in accordance with ASTM D3359, ASTM D4541, or 

equivalent testing endorsed by RG 1.54 at a minimum of three locations 

adjacent to the defective area.

4. Ultrasonic testing to determine if the component’s wall thickness meets 

the minimum thickness criteria.

Revise Service Water Integrity Program documents to visually inspect 50 percent 

of coated internal surfaces of piping or a minimum of 73 locations of 360 degrees 

of linear foot for each combination of type of coating, material the coating is 

protecting, and environment. Inspection locations will be based on coating 

degradation susceptibility, operating experience, vendor recommendation, and 

safety significance.

Inspect all accessible coated internal surfaces of tanks.

Revise Service Water Integrity Program documents to include the following 

coating integrity acceptance criteria: (1) peeling and delamination are not 

acceptable, (2) cracking is not acceptable if accompanied by delamination or loss 

of adhesion, and (3) blisters are limited to a few small intact blisters that are 

completely surrounded by sound coating bonded to the surface.

Revise Service Water Integrity Program documents to include the following 

coating integrity corrective actions: In the event peeling, delamination, cracking, 

or loss of adhesion is identified, follow-up evaluations including adhesion testing 

endorsed by RG 1.54 will be performed. In the event the base metal is exposed 

and the visual inspection identifies corrosion, this inspection finding will be entered 

into the corrective action program, and an evaluation will confirm the component 

remains acceptable for continued service. As necessary, a volumetric 

examination will be performed to ensure there is sufficient wall thickness so that 

the component remains capable of performing its intended function. If repair or 

replacement of the coating is postponed, the evaluation will consider the minimum 

wall thickness requirements and the rate of corrosion and confirm the component 

remains acceptable for continued service until the next inspection or repair 

opportunity, which will be within 2 years.
A-28

APPENDIX A: GRAND GULF LICENSE RENEWAL COMMITMENTS

Item

No. Commitment

FSAR

Supplement 

Section/

LRA Section

Enhancement o

Implementatio

Schedule 

35 (cont.) Revise Service Water Integrity Program documents to specify a review of at least 

the two previous coating inspection results prior to conducting a coating 

inspection.

Revise Service Water Integrity Program procedures to ensure coating inspections 

are performed by individuals certified to ANSI N45.2.6, “Qualifications of 

Inspection, Examination, and Testing Personnel for Nuclear Power Plants.”

Revise Service Water Integrity Program procedures to ensure that a nuclear 

coatings specialist qualified in accordance with ASTM D7108-05, “Standard Guide 

for Establishing Qualifications for a Nuclear Coatings Specialist,” will evaluate 

inspection findings and prepare post-inspection reports.

Revise Service Water Integrity Program documents to state that coating 

inspection reports will include lists of locations identified with coating deterioration 

including, where possible, photographs indexed to inspection location, and a 

prioritization of the repair areas into areas that must be repaired before returning 

the system to service and areas where coating repair can be postponed to the 

next inspection or repair opportunity, which will be within 2 years.

Revise Service Water Integrity Program procedures to ensure degraded 

coating/lining will be evaluated for potential flow blockage downstream prior to 

returning a coated component to service. Any coating that is found degraded and 

returned to service prior to repair or replacement will be evaluated by a coating 

specialist qualified in accordance with ASTM International standards endorsed by 

RG 1.54. The evaluation considers the effect of the coating/lining failure on the 

component’s intended function, problems identified during prior inspections, repair 

methods used during prior repairs, and known service history of the original 

coating.

36 Revise program documentation to specify that components subject to wallthinning mechanisms other than FAC, which are replaced with alternate materials 

(e.g. replacing a carbon steel pipe with stainless steel) shall continue to be 

periodically monitored at a frequency commensurate with their post-replacement 

wear rate and operating time.

B.1.22 Prior to May 1, 2024 
B-1

APPENDIX B

CHRONOLOGY

This appendix lists chronologically the routine licensing correspondence between the staff of the 

United States (US) Nuclear Regulatory Commission (NRC) (the staff) and Entergy Operations, 

Inc., (Entergy or the applicant). This appendix also lists other correspondence on the staff’s 

review of the Grand Gulf Nuclear Station, Unit 1 (GGNS) license renewal application (LRA) 

(under Docket No. 50-416).

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

October 28, 2011 ML11308A052 Letter from Entergy to NRC, Submitting Grand Gulf, Unit 1, 

License Renewal Application

October 28, 2011 ML11308A101 Grand Gulf, Unit 1, License Renewal Application

November 9, 2011 ML11293A013 Letter from NRC to Entergy, Receipt and Availability of the License 

Renewal Application for the Grand Gulf Nuclear Station, Unit 1

November 9, 2011 ML11293A014 Federal Register Notice, Notice of Receipt and Availability of the 

License Renewal Application for the Grand Gulf Nuclear Station, 

Unit 1

December 16, 2011 ML11335A340 Letter from NRC to Entergy, Determination of Acceptability and 

Sufficiency for Docketing, Proposed Review Schedule, and 

Opportunity for a Hearing Regarding the Application from Entergy 

Operations, Inc. for Renewal of the Operating License for Gulf 

Nuclear Station, Unit 1

December 16, 2011 ML11335A341 Federal Register Notice, Notice of Opportunity for Hearing 

Regarding Renewal of Facility Operating License No. NPF-29 for 

an Additional 20 year Period, Inc. Grand Gulf Nuclear Station, 

Unit 1 (Docket No. 50-416)

January 4, 2012 ML11350A053 Letter from NRC to Entergy, Plan for the Scoping and Screening 

Regulatory Audit Regarding the Grand Gulf Nuclear Station, 

Unit 1, License Renewal Application Review

January 6, 2012 ML11362A433 Meeting Notice, Forthcoming Meeting to Discuss the License 

Renewal Process and Environmental Scoping for Grand Gulf 

Nuclear Station, Unit 1, License Renewal Application

January 18, 2012 ML12009A105 Letter from NRC to Entergy, Plan for the Aging Management 

Program Regulatory Audit Regarding the Grand Gulf Nuclear 

Station, Unit 1, License Renewal Application Review

April 3, 2012 ML12067A235 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 4, 2012 ML12068A233 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 11, 2012 ML12080A191 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 12, 2012 ML12074A008 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application
B-2

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

April 16, 2012 ML12076A014 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 17, 2012 ML12076A009 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 18, 2012 ML12087A001 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 25, 2012 ML12094A009 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 26, 2012 ML12101A360 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

April 30, 2012 ML12104A219 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 1, 2012 ML12123A077 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 3, 2012 ML12109A213 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 3, 2012 ML12124A255 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 9, 2012 ML12115A276 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 9, 2012 ML12115A090 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 9, 2012 ML12130A417 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 9, 2012 ML12130A419 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 14, 2012 ML12117A383 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 14, 2012 ML12136A063 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 15, 2012 ML12118A539 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 15, 2012 ML12137A265 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application
B-3

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

May 18, 2012 ML12153A367 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 24, 2012 ML12123A704 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 24, 2012 ML12125A373 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 25, 2012 ML12150A174 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 25, 2012 ML12150A182 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 25, 2012 ML12150A180 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

May 29, 2012 ML12139A055 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

May 30, 2012 ML12152A098 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 5, 2012 ML12137A296 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 5, 2012 ML12158A142 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 6, 2012 ML12159A213 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 8, 2012 ML12137A290 Letter from NRC to Entergy, Aging Management Programs Audit 

Report Regarding The Grand Gulf Nuclear Station, Unit 1

June 11, 2012 ML12164A430 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 11, 2012 ML12164A432 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 15, 2012 ML12151A265 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 20, 2012 ML12165A387 Letter from NRC to Entergy, Scoping and Screening Methodology 

Audit Report Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application 

June 20, 2012 ML12151A368 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application
B-4

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

June 21, 2012 ML12174A026 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 22, 2012 ML12152A345 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 22, 2012 ML12152A393 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 22, 2012 ML12177A128 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 22, 2012 ML12177A130 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

June 27, 2012 ML12164A174 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 27, 2012 ML12164A726 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

June 27, 2012 ML12157A056 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 3, 2012 ML12187A119 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 12, 2012 ML12198A018 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 17, 2012 ML12179A137 Memoranda, Summary of Telephone Conference Call Held on 

March 19, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to Grand Gulf Nuclear Station, Unit 1, License Renewal 

Application

July 17, 2012 ML12180A541 Memoranda, Summary of Telephone Conference Call Held on 

March 14, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 17, 2012 ML12188A706 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 19, 2012 ML12202A055 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 23, 2012 ML12188A516 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 23, 2012 ML12206A059 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application
B-5

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

July 23, 2012 ML12206A058 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 25, 2012 ML12208A039 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 25, 2012 ML12208A166 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 26, 2012 ML12208A359 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

July 27, 2012 ML12200A138 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 27, 2012 ML12201B476 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 31, 2012 ML12180A467 Memoranda, Summary of Telephone Conference Call Held on 

April 3, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

July 31, 2012 ML12191A187 Memoranda, Summary of Telephone Conference Call Held on 

April 13, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 1, 2012 ML12191A026 Memoranda, Summary of Telephone Conference Call Held on 

April 25, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 7, 2012 ML12208A267 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 13, 2012 ML12227A291 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

August 15, 2012 ML12201B504 Memoranda, Summary of Telephone Conference Call Held on 

May 23, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 15, 2012 ML12220A337 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 15, 2012 ML12229A582 Letter from Entergy to NRC, Grand Gulf, Unit 1, License Renewal 

Application 2012 Annual Update.

August 15, 2012 ML12229A579 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

August 15, 2012 ML12193A071 Memoranda, Summary of Telephone Conference Call Held on 

May 15, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application
B-6

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

August 15, 2012 ML12202A214 Memoranda, Summary of Telephone Conference Call Held on 

May 30, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 21, 2012 ML12230A310 Letter from NRC to Entergy, Correction to Requests for Additional 

Information for the Review of the Grand Gulf Nuclear Station, 

Unit 1, License Renewal Application

August 21, 2012 ML12235A229 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

August 23, 2012 ML12240A229 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

August 28, 2012 ML12193A046 Memoranda, Summary of Telephone Conference Call Held on 

May 2, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 28, 2012 ML12201B545 Memoranda, Summary of Telephone Conference Call Held on 

June 5, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

August 28, 2012 ML12209A148 Memoranda, Summary of Telephone Conference Call Held on 

June 8, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 4, 2012 ML12249A300 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

September 5, 2012 ML12234A671 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 7, 2012 ML12230A247 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 7, 2012 ML12242A545 Revision of Schedule for the Conduct of a Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7493)

September 10, 2012 ML12214A572 Memoranda, Summary of Telephone Conference Call Held on 

July 11, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 12, 2012 ML12235A304 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 13, 2012 ML12257A353 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

September 14, 2012 ML12248A158 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application
B-7

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

September 14, 2012 ML12214A548 Memoranda, Summary of Telephone Conference Call Held on 

July 18, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 14, 2012 ML12237A295 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

September 24, 2012 ML12268A365 Inspection Report, Grand Gulf Nuclear Station, Unit 1, License 

Renewal Inspection

October 2, 2012 ML12277A188 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 2, 2012 ML12277A079 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 3, 2012 ML12270A249 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

October 9, 2012 ML12284A032 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 15, 2012 ML12290A108 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 15, 2012 ML12290A110 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 17, 2012 ML12278A036 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

October 19, 2012 ML12286A024 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

October 22, 2012 ML12297A204 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

October 31, 2012 ML12250A105 Memoranda, Summary of Telephone Conference Call Held on 

August 15, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

October 31, 2012 ML12264A387 Memoranda, Summary of Telephone Conference Call Held on 

August 21, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

November 5, 2012 ML12296A194 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

November 9, 2012 ML12271A252 Memoranda, Summary of Telephone Conference Call Held on 

August 22, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application
B-8

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

November 9, 2012 ML12264A392 Memoranda, Summary of Telephone Conference Call Held on 

September 4, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

November 15, 2012 ML123210175 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

November 15, 2012 ML12264A649 Memoranda, Summary of Telephone Conference Call Held on 

August 29, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

November 19, 2012 ML12325A173 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

November 20, 2012 ML12312A453 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

November 29, 2012 ML12339A011 Letter from Entergy to NRC, Response to Requests for Additional 

Information Regarding the Grand Gulf Nuclear Station, Unit 1, 

License Renewal Application

November 30, 2012 ML12333A218 Letter from NRC to Entergy, Requests for Additional Information 

for the Review of the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

December 18, 2012 ML12354A467 Grand Gulf Nuclear Station, Unit 1, Response to Requests for 

Additional Information (RAI) Set 42, dated November 20, 2012.

December 18, 2012 ML12354A465 Grand Gulf Nuclear Station, Unit 1, Response to Requests for 

Additional Information (RAI) Set 43, dated November 30, 2012.

January 3, 2013 ML12271A471 Memoranda, Summary of Telephone Conference Call Held on 

September 7, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

January 3, 2013 ML12334A347 Memoranda, Summary of Telephone Conference Call Held on 

September 28, 2012, Between NRC and Entergy, Concerning 

RAIs Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

January 3, 2013 ML12334A586 Memoranda, Summary of Telephone Conference Call Held on 

October 9, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

January 11, 2013 ML12335A172 Memoranda, Summary of Telephone Conference Call Held on 

October 15, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

January 14, 2013 ML12338A650 Memoranda, Summary of Telephone Conference Call Held on 

October 26, 2012, Between NRC and Entergy, Concerning RAIs 

Pertaining to the Grand Gulf Nuclear Station, Unit 1, License 

Renewal Application

January 18, 2013 ML13022A474 Grand Gulf Nuclear Station, Unit 1 - Response to Requests for 

Additional Information (RAI) 4.2.1-2b and 4.7.3-1a

January 31, 2013 ML13016A044 Grand Gulf SER with Open Items Transmittal Letter

January 31, 2013 ML13032A194 Safety Evaluation Report With Open Items Related to the License 

Renewal of Grand Gulf Nuclear Station, Unit 1
B-9

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

February 26, 2013 ML13002A430 Revision of Schedule for the Conduct of a Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7385)

March 12, 2013 ML13058A120 Request for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC No. 

ME7493) – Set 47

March 12, 2013 ML13045A917 RAI for the Review of the Grand Gulf Nuclear Station License 

Renewal Application (TAC No. ME7493)

April 2, 2013 ML13093A328 Comments on Safety Evaluation Report Related to the License 

Renewal of Grand Gulf Nuclear Station, dated January 31, 2013

April 3, 2013 ML13064A058 Summary of Telephone Conference Call Held on 

February 19, 2013, Between the NRC and Entergy Operations, 

Inc., Concerning Requests for Additional Information Pertaining to 

the Grand Gulf Nuclear Station, License Renewal Application 

(TAC. No. ME7493)

August 8, 2013 ML13221A272 Follow-up Actions from Teleconference Held on August 1, 2013, 

Related to Pre-Decisional Enforcement Conference Between the 

NRC and Grand Gulf on Tuesday July 16, 2013

April 15, 2013 ML13107A015 Grand Gulf Nuclear Station, Unit 1 - Response to Requests for 

Additional Information (RAI) Set 44, dated March 12, 2013

May 23, 2013 ML13120A176 Revision of Schedule for the Conduct of Review of the Grand Gulf 

Nuclear Station, License Renewal Application and Project 

Manager Change (TAC No. ME7493)

August 28, 2013 ML13227A394 Request for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7493) – Set 47

September 12, 2013 ML13238A234 Requests for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC No. 

ME7493) – Set 49

September 23, 2013 ML13266A368 Grand Gulf Nuclear Station, Unit 1 - Response to Requests for 

Additional Information (RAI) Set 47, dated August 28,2013

October 17, 2013 ML13291A126 Entergy, Reply to Notice of Violation; EA-13-058

October 25, 2013 ML13302A598 Grand Gulf Nuclear Station, Unit 1, License Renewal Application 

2013 Annual Update 

November 21, 2013 ML13263A225 Requests for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC No. 

ME7493) – Set 48

December 20, 2013 ML13358A041 Grand Gulf Nuclear Station, Unit 1 - Response to Request for 

Additional Information (RAI) Set 48 dated November 21, 2013

January 2, 2014 ML13318A805 Request for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7493) – Set 50

April 15, 2014 ML14050A079 Regarding the Response to Request for Additional Information, 

Set 47, for the Grand Gulf Nuclear Station, License Renewal 

Application (TAC No. ME7493)

May 13, 2014 ML14133A364 Grand Gulf Nuclear Station, Unit 1 - Response to Request for 

Additional Information (RAI) dated January 2, 2014

July 10, 2014 ML14184B183 Summary of Telephone Conference Call Held on June 18, 2014, 

Between the NRC and Entergy Operations, Inc., Concerning Draft 

RAI 3.0.5-1E (Operating Experience Follow-Up) for the Grand 

Gulf, Unit 1, License Renewal Application (TAC No. ME7493)
B-10

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

September 11, 2014 ML14238A620 Request for Additional Information for the Review of the Grand 

Gulf Nuclear Station License Renewal Application, Set 51 (TAC 

No. ME7493)

October 27, 2014 ML14301A102 Letter from Entergy to NRC, Grand Gulf, Unit 1, License Renewal 

Application 2014 Annual Update.

November 6, 2014 ML14311A694 Grand Gulf Nuclear Station, Unit 1- Response to Request for 

Additional Information (RAI) Set 51 dated September 11, 2014

February 19, 2015 ML14258A145 August 21, 2014, Summary of Telephone Conference Call Held 

Between the NRC and Entergy Operations, Inc., Concerning RAI 

Set 51 For The Grand Gulf, Unit 1, License Renewal Application 

(TAC No. ME7493)

March 30, 2015 ML15089A524 Grand Gulf Nuclear Station, Unit 1 - Follow-up response to NRC 

Letter, “Updated Fluence Methodology License Amendment 

Request Unacceptable With Opportunity To Supplement,” dated 

February 18, 2015, to provide Independent Benchmarking of the 

3D Fluence Calculation Method as documented in Letter 

GNRO-2015/00011, also dated February 18, 2015 

April 6, 2015 ML15085A493 Request for Additional Information for the Review of the Grand 

Gulf Nuclear Stations License Renewal Application, Set 52 (TAC 

No. 7493)

April 20, 2015 ML15092A250 March 19. 2015, Record of Conference Call for GGNS License 

Renewal – RAI Set 52.

April 22, 2015 ML15107A079 Project Manager Change for the License Renewal of Grand Gulf 

Nuclear Station, Unit 1 (TAC No. ME7493)

May 20, 2015 ML15141A178 Grand Gulf Nuclear Station, Unit 1 - Response to Request for 

Additional Information (RAI) Set 52, dated April 6, 2015

July 29, 2015 ML15212A747 Grand Gulf Nuclear Station, Unit 1 - Response to License Renewal 

Amendment Request for Additional Information Set 47, 

Question 4.2.1-2c (5) (b)

August 19, 2015 ML15231A307 Grand Gulf Nuclear Station, Unit 1 - Responses to Request for 

Additional Information (RAI) Set 52, RAls 3.0.31-FWS-2a and 

3.0.3-2b, dated June 18, 2015

September 1, 2015 ML15245A295 Grand Gulf Nuclear Station, Unit 1 - Response to License Renewal 

Application (LRA) Request for Additional Information (RAI) Set 47, 

Question 4.2.1-2c (5) (a) i

October 14, 2015 ML15215A041 Summary of Telephone Conference Call held on June 18, 2015, 

between the NRC and Entergy Operations, Inc., Concerning 

Request for Additional Information Responses, Pertaining to the 

Grand Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7493)

October 28, 2015 ML15286A108 Requests for Additional Information for the Review of the Grand 

Gulf Nuclear Station, License Renewal Application (TAC 

No. ME7493)-Set 53

November 23, 2015 ML15327A181 Responses to Request for Additional Information (RAI) Set 53, 

dated October 28, 2015

December 10, 2015 ML15344A283 Letter from Entergy to NRC, Grand Gulf, Unit 1, License Renewal 

Application 2015 Annual Update.

December 14, 2015 ML15348A402 Amended Response to Request for Additional Information (RAI) 

4.2.3-2, dated October 28, 2015, Grand Gulf Nuclear Station, 

Unit 1

January 12, 2016 ML15355A034 December 28, 2015, Summary of Teleconference for GGNS Set 

53 RAI Responses.
B-11

APPENDIX B: CHRONOLOGY

Date

ADAMS Accession 

No. Subject

February 3, 2016 ML16012A391 Schedule Revision For the Review of the Grand Gulf Nuclear 

Station, License Renewal Application (TAC No. ME7493)

February 26, 2016 ML16057A670 Grand Gulf, Unit 1 - Supplemental Correction Response to License 

Renewal Amendment Request for Additional Information Set 47.

March 31, 2016 ML16067A240 Advisory Committee on Reactor Safeguards Review of the Grand 

Gulf Nuclear Station, Unit 1, License Renewal Application -

Transmittal of Final Safety Evaluation Report.

April 4, 2016 ML16064A183 Final Safety Evaluation Report Related to the License Renewal of

Grand Gulf Nuclear Station, Unit 1

April 4, 2016 ML16095A118 GNRO-2016/00018 - Grand Gulf Nuclear Station License Renewal 

Documents to Support Review of Application for Renewal of 

license: Report Number MPM-814779, Revision 3, Neutron 

Transport Analysis for Grand Gulf Nuclear Station and Engineering 

Report GGNS-NE-15-00003.

June 6, 2016 ML16158A487 Grand Gulf, Unit 1 - Comments Regarding License Renewal 

Safety Evaluation Report ML16090A252 Dated April 4, 2016.

July 28, 2016 ML16210A526 Regional Administrator’s Letter to William Dean Regarding the 

Grand Gulf Nuclear Station License Renewal Application.

September 23, 2016 ML16267A400 Clarification of Grand Gulf Nuclear Station Containment Leak Rate 

Program Description Grand Gulf Nuclear Station, Unit 1 Docket 

No. 50-416

October 3, 2016 ML16277A573 Additional Clarification of the Grand Gulf Nuclear Station 

Containment Leak Rate Program Description Grand Gulf Nuclear 

Station, Unit 1 Docket No. 50-416

October 3, 2016 ML16279A517 Advisory Committee on Reactor Safeguards Review of the Grand 

Gulf Nuclear Station, Unit 1, License Renewal Application –

Transmittal Of Updated Containment Leak Rate Aging 

Management Program Review (TAC No. ME7493)

October 12, 2016 ML16280A285 Summary of Teleconference Held on September 21, 2016, 

Between the NRC and Entergy Co., concerning Containment Leak 

Rate Program pertaining to the Grand Gulf Nuclear Station Unit 1 

(TAC Nos. ME7493)

October 19, 2016 ML16280A506 Summary of Teleconference Held on September 28, 2016, 

Between the NRC and Entergy Co., concerning Containment Leak 

Rate Program pertaining to the Grand Gulf Nuclear Station Unit 1 

(TAC Nos. ME7493)

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

Andersen, James Management Oversight

Auluck, Rajender Management Oversight

Brittner, Don Reviewer – Mechanical

Buford, Angela Reviewer – Structural

Casto, Greg Management Oversight

Davidson, Evan Reviewer – Scoping & Screening

Daily, John Project Management

Dennig, Robert Management Oversight

Doutt, Cliff Reviewer – Electrical

Erickson, Alice Reviewer – Structural

Ferrer, Nathaniel Project Management

Fu, Bart Reviewer – Mechanical

Gall, Jennifer Reviewer – Scoping & Screening

Galloway, Melanie Management Oversight

Gavula, Jim Reviewer – Mechanical

Ghasemian, Shahram Management Oversight

Green, Kim Reviewer – Mechanical

Hiser, Allen Management Oversight

Holston, Bill Reviewer – Mechanical

Hovanec, Christopher Reviewer – Mechanical

Iqbal, Naeem Reviewer – Fire Protection

Jackson, Christopher Management Oversight

Kalikian, Roger Reviewer – Mechanical

Kichline, Michelle Reviewer – Mechanical

Klein, Alex Management Oversight

Klos, John Reviewer – Mechanical

Kulesa, Gloria Management Oversight

Lehman, Bryce Reviewer – Structural

Li, Rui Reviewer – Electrical

Marshall, Michael Management Oversight

Medoff, Jim Reviewer – Mechanical

Min, Seung Reviewer – Mechanical and Neutron Fluence

Morey, Dennis Management Oversight

Murphy, Martin Management Oversight

Ng, Ching Reviewer – Mechanical

Nguyen, Duc Reviewer – Electrical
C-2

APPENDIX C: PRINCIPAL CONTRIBUTORS

Name Responsibility

Obadina, Sarah Reviewer – Neutron Fluence

Obodoako, Alyoysius Reviewer – Mechanical

Parks, Benjamin Reviewer – Neutron Fluence

Patel, Amrit Reviewer – Neutron Fluence

Pham, Bo Management Oversight

Prinaris, Andrew Reviewer – Structural

Raval, Janak Reviewer – Scoping & Screening

Richardson, Rebecca Project Management

Rogers, Bill Reviewer – Scoping & Screening Methodology

Rosenberg, Stacey Management Oversight

Sheikh, Abdul Reviewer – Structural

Smith, Ed Reviewer – Scoping & Screening

Sun, Robert Reviewer – Mechanical

Torres, Roberto Reviewer= Scoping & Screening

Wise, John Reviewer – Mechanical

Wong, Emma Reviewer – Mechanical

Yee, On Reviewer – Mechanical

CONTRACTORS

Idoneous Consulting, Inc. SER Support

Oak Ridge National Laboratory Review – Structural
D-1

APPENDIX D

REFERENCES

This appendix lists the references used throughout this safety evaluation report (SER) for review 

of the license renewal application (LRA) for Grand Gulf Nuclear Station, Unit 1 (GGNS).

APPENDIX D: REFERENCES

NRC Documents

U.S. Nuclear Regulatory Commission (U.S. NRC) Bulletin 80-11, “Masonry Wall Design,” May 1980.

– – – Generic Letter (GL) 88-01, “NRC Position On Intergranular Stress Corrosion Cracking (IGSCC) In BWR 

Austenitic Stainless Steel Piping,” January 1988.

– – – GL 80-09, “Generic Activity A-10,” November 1980

– – – GL 88-14, “Instrument Air Supply System Problems Affecting Safety-Related Equipment,” August 1988.

– – – GL 89-13, “Service Water System Problems Affecting Safety-Related Equipment,” July 1989.

– – – GL 96-04, “Boraflex Degradation in Spent Fuel Pool Storage Rack,” June 1996.

– – – GL 2007-01, “Inaccessible or Underground Power Cable Failures that Disable Accident Mitigation Systems or 

Cause Plant Transients,” February 2007.

– – – Generic Safety Issue No. 190 (GSI-190), “Fatigue Evaluation of Metal Components for 60-Year Plant Life,”

December 1999.

– – – Information Notice (IN) 87-67, “Lessons Learned from Regional Inspections of Licensee Actions in Response 

to IE Bulletin 80-11,” December 1987.

– – – IN 94-63, “Boric Acid Corrosion of Charging Pump Casings Caused by Cladding Cracks,” August 1994.

– – – IN 2004-08, “Reactor Coolant Pressure Boundary Leakage Attributable to Propagation of Cracking in Reactor 

Vessel Nozzle Welds,” April 2004.

– – – IN 2005-23, “Vibration-Induced Degradation of Butterfly Valves,” August 2005.

– – – IN 2006-15, “Vibration-Induced Degradation and Failure of Safety-Related Valves,” July 2006.

– – – IN 2009-26, “Degradation Of Neutron-Absorbing Materials in the Spent Fuel Pool,” October 2009.

– – – IN 2011-15, “Steel Containment Degradation and Associated License Renewal Aging Management Issues,”

August 2011.

– – – IN 2011-20, “Concrete Degradation by Alkali Silica Reaction,” November 2011.

NUREG-0313, “Technical Report On Material Selection And Processing Guidelines For BWR Coolant Pressure 

Boundary Piping,” Revision 2, 1988.

NUREG-0612, “Control of Heavy Loads at Nuclear Power Plants,” July 1980.

NUREG-0619, “BWR Feedwater Nozzle and Control Rod Driven Return Line Nozzle Cracking,” November 1980.

NUREG-0737, “Clarification of TMI Action Plan Requirements,” November 1980.

NUREG-1339, “Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants,”

June 1990.

NUREG-1437, “Generic Environmental Impact Statement for License Renewal of Nuclear Plants (GEIS),”

May 1996.

NUREG-1557, “Summary of Technical Information and Agreements from Nuclear Management and Resources 

Counci1 Industry Reports Addressing License Renewal,” October 1996.

NUREG-1800, “Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants,”

Revision 2, December 2010.

NUREG-1801, “Generic Aging Lessons Learned (GALL) Report,” Revision 2, December 2010.

NUREG-1924, “Electrical Raceway Fire Barrier Systems in U.S. Plants,” April 2010.

NUREG/CR 4652, “Concrete Component Aging and Its Significance Relative to Life Extension of Nuclear Power 

Plants.” 
D-2

APPENDIX D: REFERENCES

NUREG/CR-5704, “Effects of LWR Coolant Environments on Fatigue Design Curves of Austenitic Stainless Steels,”

April 1999.

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

Components,” February 1995.

NUREG/CR-6583, “Effects of [Light-Water Reactor] LWR Coolant Environments on Fatigue Curves of Carbon and 

Low-Alloy Steels,” February1998.

NUREG/CR-6909, “Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials,” February 2007.

U.S. NRC Regulatory Guide (RG) 1.36, “Nonmetallic Thermal Insulation for Austenitic Stainless Steel.”

– – – RG 1.43, “Control of Stainless Steel Weld Cladding of Low-Alloy Steel Components.”

– – – RG 1.45, “Guidance on Monitoring and Responding to Reactor Coolant System Leakage.”

– – – RG 1.54, “Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.”

– – – RG 1.65, “Materials and Inspections for Reactor Vessel Closure Studs.”

– – – RG 1.75, “Physical Independence of Electric Systems.”

– – – RG 1.89 “Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power 

Plants.”

– – – RG 1.99, “Radiation Embrittlement of Reactor Vessel Materials.”

– – – RG 1.127, “Inspection of Water-Control Structures Associated with Nuclear Power Plants.”

– – – RG 1.147, “Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1.”

– – – RG 1.160, “Monitoring the Effectiveness of Maintenance at Nuclear Power Plants.”

– – – RG 1.163, “Performance-Based Containment Leak-Test Program.”

– – – RG 1.188, “Standard Format and Content for Applications to Renew Nuclear Power Plant Operating 

Licenses.”

– – – RG 1.190, “Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence.”

U.S. NRC Regulatory Issue Summary 2008-30, “Fatigue Analysis Of Nuclear Power Plant Components,” December 

2008.

Regulations

U.S. Code of Federal Regulations (CFR), “Domestic Licensing of Production and Utilization Facilities,” Part 50, Title 

10, “Energy,” Office of the Federal Register, National Archives and Records Administration, 2012.

CFR, “Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions,” Part 51, 

2012.

CFR, “Requirements for Renewal of Operating Licenses for Nuclear Power Plants,” Part 54, 2012.

Industry Documents

Boiling Water Reactor Owners’ Group (BWROG)-94037, “BWR Owners’ Group Topical Report on Upper Shelf 

Energy Equivalent Margin Analysis – Approved Version,” March 21, 1994.

Electric Power Research Institute (EPRI) Boiling-Water Reactor Vessels Internal Program (BWRVIP)-05, “Reactor 

Vessel Shell Weld Inspection Guidelines,” EPRI, Palo Alto, CA, September 1995. Proprietary information. Not 

publicly available.

– – – BWRVIP-14-A “BWR Vessel and Internals Project, Evaluation of Crack Growth in BWR Stainless Steel RPV 

Internals,” September 2008. Proprietary information. Not publicly available.

– – – BWRVIP-18 A, “BWR Vessel and Internals Project, BWR Core Spray Internals Inspection and Flaw Evaluation 

Guidelines,” February 2005. Proprietary information. Not publicly available.

– – – BWRVIP-25, “BWR Core Plate Inspection and Flaw Evaluation Guidelines,” December 1996. Proprietary 

information. Not publicly available.

– – – BWRVIP-26-A, “BWR Top Guide Inspection and Flaw Evaluation Guidelines,” November 2004. Proprietary 

information. Not publicly available.

– – – BWRVIP-38, “BWR Shroud Support Inspection and Flaw Evaluation Guidelines” (EPRI TR-108823), 

September 1997. Proprietary information. Not publicly available.

– – – BWRVIP-41, “BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines,” October 1997. 

Proprietary information. Not publicly available.
D-3

APPENDIX D: REFERENCES

– – – BWRVIP-42-A, “BWR Vessel and Internals Project Boiling Water Reactor Low Pressure Coolant Injection and 

Flaw Evaluation Guidelines,” February 2005. Proprietary information. Not publicly available.

– – – BWRVIP-47-A, “BWR Lower Plenum Inspection and Flaw Evaluation Guidelines,” November 2004. 

Proprietary information. Not publicly available.

– – – BWRVIP-48-A, “Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines,” November 2004. 

Proprietary information. Not publicly available.

– – – BWRVIP-49-A, “Instrument Penetration Inspection and Flaw Evaluation Guidelines,” March 2002. Proprietary 

information. Not publicly available.

– – – BWRVIP-74-A, “Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines,” June 2003. Proprietary 

information. Not publicly available.

– – – BWRVIP-75-A, “Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules,” October 2005. 

Proprietary information. Not publicly available.

– – – BWRVIP-76-A, “BWR Core Shroud Inspection and Flaw Evaluation,” December 2009. Proprietary information. 

Not publicly available.

– – – BWRVIP-86-A, “Updated BWR Integrated Surveillance Program (ISP) Implementation Plan,” October 2002. 

Proprietary information. Not publicly available.

– – – BWRVIP-99-A, “Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components,”

October 2008. Proprietary information. Not publicly available.

– – – BWRVIP-100-A, “BWR Vessel and Internals Project, Updated Assessment of the Fracture Toughness of 

Irradiated Stainless Steel for BWR Core Shrouds,” August 2006. Proprietary information. Not publicly available.

– – – BWRVIP-116, “Integrated Surveillance Program,” July 2003. Proprietary information. Not publicly available.

– – – BWRVIP-126, “BWR Vessel and Internals Project, RAMA Fluence Methodology Software,” 2003. Proprietary 

information. Not publicly available.

– – – BWRVIP-130, “BWR Water Chemistry Guidelines 2004 Revisions” (EPRI 1008192), October 2004. Proprietary 

information. Not publicly available.

– – – BWRVIP-183 “BWR Vessel and Internals Project, Top Guide Grid Beam Inspection and Flaw Evaluation 

Guidelines,” December 2007. Proprietary information. Not publicly available.

– – – BWRVIP-190, “BWR Water Chemistry Guidelines 2008 Revisions,” October 2008. Proprietary information. Not 

publicly available.

– – – EPRI 1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline” April 2004.

– – – EPRI 1013013, “An Evaluation of Flow-Accelerated Corrosion in the Bottom Head Drain Lines of Boiling Water 

Reactors,” March 2006.

– – – EPRI 1011694, “BWR Vessel and Internals Project, Evaluation of Susquehanna Unit 2 Top Guide and Core 

Shroud Material Samples Using RAMA Fluence Methodology (BWRVIP-145),” November 2005. Proprietary 

information. Not publicly available.

– – – EPRI 1016949, “BWRVIP-191: BWR Vessel and Internals Project, Flow-Accelerated Corrosion in BWR 

Bottom Head Drain Lines: 2008 Update.” July 2008. Proprietary information. Not publicly available.

– – – EPRI NP-5769, “Degradation and Failure of Bolting in Nuclear Power Plants,” Volumes 1 and 2, May 1988.

– – – EPRI Nuclear Safety Analysis Center (NSAC)-202L-R3, “Recommendations for an Effective Flow-Accelerated 

Corrosion Program.” Non-proprietary version, August 2007.

– – – EPRI TR-1007820, “Closed Cooling Water Chemistry Guideline, Revision 1: Revision 1 to TR-107396, Closed 

Cooling Water Chemistry Guideline.” April 2004.

– – – EPRI TR-104213, “Bolted Joint Maintenance and Applications Guide,” December 1995.

– – – EPRI TR-112657, “Revised Risk-Informed Inservice Inspection Evaluation Procedure,” Revision B-A, 

January 2000.

“Bridge Scour and Stream Instability Countermeasures: Experience, Selection, and Design Guidance,” 3rd Edition, 

U.S. Department of Transportation, Federal Highway Administration, September 2009, 

<http://www.fhwa.dot.gov/engineering/hydraulics/pubs/09111/page00.cfm> (15 June 2012).

Crane Manufacturers Association of America (CMAA), Inc., Specification 70, “Specifications for Top Running Bridge 

& Gantry Type Multiple Girder Electric Overhead Traveling Cranes,” CMAA, Charlotte, NC, December 2008.
D-4

APPENDIX D: REFERENCES

Eastman, “Tentite Plastics, Weathering of Tentite Butyrate.” Eastman Publication PP104B, May 1999, 

<http://www.eastman.com/Literature_Center/P/PP104.pdf> (15 June 2012).

General Electric Nuclear Energy, GE-NE-523-A71-0594-A, “Alternate BWR Feedwater Nozzle Inspection 

Requirements,” Revision 1, August 1999.

– – – NEDC-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,”

December 2001. Proprietary information. Not publicly available.

– – – NEDO-32983P-A, “General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluations,”

December 2001.

– – – NEDO-32205, “10 CFR 50 Appendix G Equivalent Margin Analysis for Low Upper-Shelf Energy in BWR-2 

through BWR-6 Vessels.” February 1994.

Connecticut Department of Environmental Protection, “Guidelines for Inspection and Maintenance of Dams,”

September 2001. 

<http://www.ct.gov/dep/lib/dep/water_inland/dams/guidelinesforinspectionandmaintenanceofdams.pdf> 

(15 June 2012)

McKeen L., Fluorinated Coatings and Finishes Handbook: The Definitive Users Guide, William Andrew Publishing, 

Norwich, NY, 2006.

Nuclear Energy Institute (NEI) 94-01 “Industry Guidance for Implementing Performance-Based Options of 

10 CFR Part 50, Appendix J,” July 1995.

– – – NEI 95-10, “Industry Guideline for Implementing the Requirements of 10 CFR Part 54—The License Renewal 

Rule,” Revision 6, June 2005.

– – – NEI 03-08, “Guideline for the Management of Materials Issues,” January 2010.

NUMARC 93-01, “Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,”

Revision 2, April 1996.

Plastics Design Library Staff, The Chemical Resistance of Plastics and Elastomers, (4th Electronic Edition), William 

Andrew Publishing/Plastics Design Library, 2008. 

<http://www.knovel.com/web/portal/browse/display?_EXT_KNOVEL_DISPLAY_bookid=2883&VerticalID=0> 

(15 June 2012)

Industry Codes and Standards

American Concrete Institute (ACI) 201.1R, “Guide for Making a Condition Survey of Existing Buildings,” July 2008.

– – – ACI 201.2R, “Guide to Durable Concrete,” June 2008.

– – – ACI 301-66, “Specifications for Structural Concrete for Buildings,” July 1966.

– – – ACI 318-71, “Building Code Requirements for Reinforced Concrete,” August 1972.

– – – ACI 349.3R-02, “Evaluation of Existing Nuclear Safety Related Concrete Structures,” June 2002.

– – – ACI 605, “Recommended Practice for Hot Weather Concreting,” July 1959.

American National Standards Institute (ANSI)/American Nuclear Society (ANS) 56.8, “Containment System 

Leakage Testing Requirements,” 2002.

ANSI/American Society of Mechanical Engineers (ASME) B30.10, “Hooks,” 2009.

– – – ANSI/ASME B30.11, “Monorails and Underhung Cranes,” 2010.

– – – ANSI/ASME B30.16, “Overhead Hoist (Underhung) Inspection,” 2007.

– – – ANSI/ASME B30.2, “Overhead and Gantry Cranes—Top Running Bridge, Single or Multiple Girder, Top 

Running Trolley Hoist,” 2011.

– – – ANSI/ASME B31.1, “Power Piping.”

ANSI/ISA-S7.0.01, “Quality Standard for Instrument Air,” 1996.

ANSI/American Society of Civil Engineers (ASCE) 11-99, “Guideline for Structural Condition Assessment of Existing 

Buildings,” 2000.

American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, Section III, “Rules for 

Construction of Nuclear Power Plant Components,” American Society of Mechanical Engineers, New York, NY.

– – – ASME Code, Section XI, “Rules for Inservice Inspection of Nuclear Power Plant Components.”

– – – ASME Code Case N-513, “Evaluation Criteria for Temporary Acceptance of Flaws in Moderate Energy 

Class 2 or 3 Piping.”
D-5

APPENDIX D: REFERENCES

– – – ASME OM-S/G-1998, Part 17, “Performance Testing of Instrument Air Systems Information Notice Light-Water 

Reactor Power Plants,” American Society of Mechanical Engineers, New York, NY, 1998.

ASM International, Metals Handbook, Volume 13, 9th edition, ASM International, Materials Park, OH, 1987.

– – – Metals Handbook, Desk Edition, 2nd Edition, 1998.

American Society for Testing and Materials, International (ASTM) C-33, “Standard Specification for Concrete 

Aggregates,” ASTM International, West Conshohocken, PA, January 2011.

– – – ASTM C289, “Standard Test Method for Potential Alkali Silica Reactivity of Cement Aggregates (Chemical 

Method),” 2007.

– – – ASTM C295, “Standard Guide for Petrographic Examination of Aggregates for Concrete,” April 2012.

– – – ASTM C449, “Standard Specification for Mineral Fiber Hydraulic-Setting Thermal Insulating and Finishing 

Cement,” 2007.

– – – ASTM D4057-95 (2000), “Standard Practice for Manual Sampling of Petroleum and Petroleum Products,”

April 2000.

– – – ASTM D5163-08, “Standard Guide for Establishing a Program for Condition Assessment of Coating Service 

Level I Coating Systems in Nuclear Power Plants,” 2008.

– – – ASTM D7108, ‘Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist,” 2005.

National Association of Corrosion Engineers (NACE) International SP0169-2007, “Control of External Corrosion on 

Underground or Submerged Metallic Piping Systems,” NACE International, Houston, TX, March 2007.

National Fire Protection Association (NFPA) 25, “Standard for Inspection, Testing, and Maintenance of 

Water-Based Fire Protection Systems,” NFPA, Quincy, MA, 2008.





NUREG

-2211 Safety Evaluation Report Related to the License Renewal of 

Grand Gulf Nuclear Station, Unit 1